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Air Quality Plan Approval Application
Petrochemicals Complex Shell Chemical Appalachia LLC
Beaver County, Pennsylvania
May 2014
Prepared for Submittal to:
Pennsylvania Department of Environmental Protection Bureau of Air Quality Southwest Regional Office
400 Waterfront Drive Pittsburgh, PA 15222-4745
Prepared by:
RTP Environmental Associates, Inc. 304-A West Millbrook Rd.
Raleigh, NC 27609
Shell Chemical Appalachia LLC Plan Approval Application
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Table of Contents
1.0 Introduction .................................................................................. 1-1
1.1 Project Description ........................................................................................................ 1-1 1.2 Overview of Process...................................................................................................... 1-5 1.3 Site Description ............................................................................................................. 1-7 1.4 Project Schedule .......................................................................................................... 1-10 1.5 Document Overview ................................................................................................... 1-10
2.0 Permit Application Requirements .............................................. 2-1
3.0 Process and Emission Source Descriptions ............................ 3-1
3.1 Ethylene Manufacturing Process .................................................................................. 3-2 3.1.1 Process Description ................................................................................................ 3-2 3.1.2 Ethylene Manufacturing Emissions Sources ........................................................ 3-6
3.2 Polyethylene Manufacturing – Gas Phase Technology ............................................... 3-8 3.2.1 Process Description ................................................................................................ 3-8 3.2.2 Gas Phase Technology Process Emissions ......................................................... 3-11
3.3 Polyethylene Manufacturing – Slurry Technology.................................................... 3-12 3.3.1 Process Description .............................................................................................. 3-12 3.3.2 Slurry Technology Process Emissions ................................................................ 3-16
3.4 Combustion Turbines and Duct Burners (Cogen Units) ........................................... 3-17 3.5 Utilities and General Facilities Process Descriptions ................................................ 3-18
3.5.1 Diesel Engines ...................................................................................................... 3-18 3.5.2 Storage Tanks ....................................................................................................... 3-18 3.5.3 Product Loading ................................................................................................... 3-21 3.5.4 Cooling Towers .................................................................................................... 3-22 3.5.5 VOC Control Systems (Flares and Incinerators) ................................................ 3-22 3.5.6 Wastewater Treating ............................................................................................ 3-24
4.0 AIR REGULATORY REQUIREMENTS ........................................ 4-1
4.1 Pennsylvania Air Pollution Control Regulations ......................................................... 4-1 4.1.1 25 Pa. Code Ch. 121. General Provisions ............................................................. 4-1 4.1.2 25 Pa. Code Ch. 122 National Standards of Performance for New Stationary
Sources .................................................................................................................... 4-7 4.1.3 25 Pa. Code Ch. 123. Standards for Contaminants .............................................. 4-7 4.1.4 25 Pa. Code Ch. 124. National Emissions Standards for Hazardous Air
Pollutants ................................................................................................................ 4-7 4.1.5 25 Pa. Code Ch. 127. Construction, Modification, Reactivation and
Operation of Sources ............................................................................................ 4-10 4.1.6 25 Pa. Code Ch.129. Standards for Sources ....................................................... 4-13
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4.1.7 25 Pa. Code Ch. 131. Ambient Air Quality Standards ....................................... 4-17 4.1.8 25 Pa. Code Ch. 135. Reporting of Sources ....................................................... 4-17 4.1.9 25 Pa. Code Ch. 137. Air Pollution Episodes ..................................................... 4-18 4.1.10 25 Pa. Code Ch. 139. Sampling and Testing ...................................................... 4-18 4.1.11 25 Pa. Code Ch. 145. Interstate Pollution Transport Reduction ........................ 4-19
4.2 Federal Regulations ..................................................................................................... 4-19 4.2.1 40 CFR Part: New Source Performance Standards ........................................... 4-19 4.2.2 40 CFR Part 61: National Emissions Standards for Hazardous Air
Pollutants (NESHAP) .......................................................................................... 4-37 4.2.3 40 CFR Part 63: National Emissions Standards for Hazardous Air
Pollutants for Source Categories (NESHAP) ..................................................... 4-40 4.2.4 40 CFR Part 64: Compliance Assurance Monitoring ........................................ 4-46 4.2.5 40 CFR Part 68: Chemical Accident Prevention Provisions ............................ 4-46 4.2.6 40 CFR Parts 72, 73, 74, 75, and 76: Acid Rain Programs ................................ 4-47 4.2.7 40 CFR Part 82: Protection of Stratospheric Ozone ........................................... 4-47 4.2.8 40 CFR Part 98: Mandatory Greenhouse Gas Reporting .................................. 4-48
5.0 Control Technology Analysis ..................................................... 5-1
5.1 Control Technology Background ................................................................................. 5-1 5.1.1 Control Technology Analyses Definitions ........................................................... 5-1 5.1.2 Methodology for LAER and BACT Analyses ..................................................... 5-2 5.1.3 Achieved in Practice and Technical Feasibility Criteria ...................................... 5-4 5.1.4 Control Technology Analysis Organization ......................................................... 5-7 5.1.5 Summary of Proposed BACT/LAER ................................................................... 5-8
5.2 Ethane Cracking Furnaces .......................................................................................... 5-21 5.2.1 Cracking Furnace NOx/NO2 LAER/BACT Analysis ........................................ 5-21 5.2.2 Cracking Furnace VOC LAER Analysis ............................................................ 5-50 5.2.3 Cracking Furnace PM/PM10/PM2.5 BACT/LAER Analyses ............................. 5-53 5.2.4 Cracking Furnace CO BACT Analysis............................................................... 5-57 5.2.5 Cracking Furnace Greenhouse Gas (GHG) Emissions BACT .......................... 5-61
5.3 Combustion Turbines & Duct Burners ...................................................................... 5-70 5.3.1 Combustion Turbine NOx/NO2 LAER/BACT Analyses .................................. 5-70 5.3.2 Combustion Turbine VOC LAER Analysis ....................................................... 5-78 5.3.3 Combustion Turbine PM/PM10/PM2.5 BACT/LAER Analyses ........................ 5-82 5.3.4 Combustion Turbine CO BACT Analysis .......................................................... 5-87 5.3.5 Combustion Turbine GHG BACT Analyses ...................................................... 5-93
5.4 Diesel Engines ........................................................................................................... 5-102 5.4.1 Diesel Engine NOx and VOC LAER Analyses ............................................... 5-102 5.4.2 Diesel Engine PM/PM10/PM2.5 BACT/LAER Analyses ................................. 5-110 5.4.3 Diesel Engine Carbon Monoxide BACT Analysis .......................................... 5-123 5.4.4 Diesel Engine GHG BACT Analysis................................................................ 5-132
5.5 Equipment Leaks ....................................................................................................... 5-134 5.5.1 Equipment Leaks of VOC LAER Analysis ...................................................... 5-134 5.5.2 Equipment Leaks of GHG BACT Analysis ..................................................... 5-139
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5.6 Evaluation of the Potential Use of Carbon Capture and Sequestration (CCS) as
BACT for CO2 .................................................................................................................... 5-143 5.6.1 Technical Feasibility of Potential CCS Process Alternatives .......................... 5-144 5.6.2 Step 3: CCS Control Technology Hierarchy ................................................... 5-160 5.6.3 Step 4: Evaluate the Most Effective Controls. ................................................. 5-161 5.6.4 Step 5: Proposed CO2 BACT ........................................................................... 5-165
5.7 Polyethylene Process, Storage, and Handling Vents ............................................... 5-167 5.7.1 Polyethylene Process, Storage and Handling Vent VOC LAER Analysis ..... 5-167 5.7.2 Polyethylene Process, Storage, and Handling Vent PM/PM10/PM2.5
LAER/BACT Analysis ...................................................................................... 5-176 5.8 VOC Emissions from Storage Tanks and Vessels................................................... 5-184
5.8.1 Tank Emissions Control Technology Baseline ................................................ 5-184 5.8.2 Step 1: Identify Tank VOC Control Options ................................................... 5-184 5.8.3 Step 2: Eliminate Technically Infeasible Tank VOC Controls ....................... 5-188 5.8.4 Step 3: Establish Tank VOC LAER ................................................................. 5-188
5.9 PM and VOC Emissions from Cooling Towers ...................................................... 5-192 5.9.1 Cooling Tower PM/PM10/PM2.5 BACT/LAER Analysis ................................ 5-192 5.9.2 Cooling Tower VOC LAER.............................................................................. 5-198
5.10 VOC Emissions from Wastewater Treatment Plant .............................................. 5-204 5.10.1 VOC LAER Analysis ........................................................................................ 5-204
5.11 Loading Operations ................................................................................................. 5-210 5.11.1 Polyethylene Loading PM/PM10/PM2.5 BACT/LAER Analysis ..................... 5-210 5.11.2 VOC LAER Analysis For Liquids Loading Operations .................................. 5-214
5.12 VOC Control Systems............................................................................................. 5-220 5.12.1 VOC Control Systems LAER Analyses ........................................................... 5-223 5.12.2 VOC Control System CO, NOx, PM, and GHG BACT/LAER Analyses ..... 5-243
5.13 Plant Roads .............................................................................................................. 5-247 5.13.1 Plant Road Fugitive PM LAER/BACT Analysis ............................................. 5-248
5.14 PaBAT Analyses for Pollutants Not Subject to BACT or LAER ........................ 5-250 5.14.1 SO2 ...................................................................................................................... 5-251 5.14.2 Ammonia (NH3) ................................................................................................. 5-256 5.14.3 Hazardous Air Pollutants (HAPs) ..................................................................... 5-258
6.0 Air Quality Modeling Analysis .................................................... 6-1
7.0 Additional Impacts Analysis ....................................................... 7-1
7.1 Analysis of Impacts Due to Growth ............................................................................. 7-1 7.1.1 Overview ................................................................................................................ 7-1 7.1.2 Growth in Population ............................................................................................. 7-2 7.1.3 Growth in Air Pollutant Emissions ....................................................................... 7-3 7.1.4 Air Quality Impacts ................................................................................................ 7-4
7.2 Analysis of Impacts to Visibility .................................................................................. 7-5 7.3 Analysis of Impacts to Soils and Vegetation ............................................................... 7-5
7.3.1 Overview ................................................................................................................ 7-5 7.3.2 Effects on Soil ........................................................................................................ 7-5
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List of Tables
Table 1-1. Summary of the Proposed Project’s Annual Potential to Emit Pollutants
(tons) 1 ........................................................................................................... 1-4 Table 3-1. Summary of Project Tanks and Vessels ...................................................... 3-19 Table 4-1. Summary of Regulatory Applicability .......................................................... 4-2 Table 4-2. Summary of Compliance with the Standards of Containment at 25
Pa.Code Ch. 123. .......................................................................................... 4-8 Table 4-3. Summary of Federal Regulatory Applicability ........................................... 4-20 Table 4-4. Tanks Not Subject to Control Under NSPS Subpart Kb ............................. 4-30 Table 5-1. Proposed Control Technology Evaluation Limits ......................................... 5-9 Table 5-2. Summary of RBLC Ethylene Cracking Furnace NOx Emissions Limits
(prior to the past two years) ........................................................................ 5-34 Table 5-3. Summary of Recent Ethylene Cracking Furnace NOx Emission Limits .... 5-35 Table 5-4. Summary of VOC BACT/LAER Limits for Ethylene Cracking
Furnaces ...................................................................................................... 5-52 Table 5-5. Summary of Proposed PM/PM10/PM2.5 BACT Limits for Ethylene
Cracking Furnaces ...................................................................................... 5-55 Table 5-6. Summary of CO BACT Limits for Ethylene Cracking Furnaces ................ 5-60 Table 5-7. CO2e Formed When Combusting Fossil Fuels ............................................ 5-62 Table 5-8. Summary of Texas Ethylene Cracking Furnace GHG BACT
Determinations ........................................................................................... 5-67 Table 5-9. Summary of NOx BACT Precedent Found in the RBLC Database For
40 to 50 MW Turbines ............................................................................... 5-72 Table 5-10. Summary of Recent NOx BACT Precedents ............................................. 5-73 Table 5-11. BAAQMD BACT Review for Authority to Construct Plant
Number 13289 ............................................................................................ 5-74 Table 5-12. Regulatory Agencies with NOx BACT Guidelines/Requirements for
Combustion Turbines ................................................................................. 5-77 Table 5-13. Summary of VOC BACT/LAER Precedents for Turbines with
Oxidation Catalyst ...................................................................................... 5-79 Table 5-14. Regulatory Agencies with VOC BACT Guidelines/Requirements for
Combustion Turbines ................................................................................. 5-82 Table 5-15. Summary of Particulate Matter BACT Precedents for Combustion
Turbines with Oxidation Catalyst ............................................................... 5-84 Table 5-16. Regulatory Agencies with PM BACT Requirements/Guidelines for
Combustion Turbines ................................................................................. 5-87 Table 5-17. Summary of CO BACT Precedent for Turbines with Oxidation
Catalyst ....................................................................................................... 5-89 Table 5-18. GHG Emissions for Combustion Turbine Fuels ....................................... 5-94 Table 5-19. Summary of Combustion Turbine Cogeneration GHG BACT
Determinations ........................................................................................... 5-98 Table 5-20. RBLC Summary of NOx and VOC Precedents for Emergency
Generator Diesel Engines ......................................................................... 5-104 Table 5-21. RBLC Summary of NOx and VOC Precedents for Emergency
Firewater Diesel Engines .......................................................................... 5-106
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Table 5-22. Regulatory Agencies with NOx and VOC Guidelines/Requirements
for Emergency Stationary Diesel Engines .............................................. 5-111 Table 5-23. RBLC Summary of PM BACT Precedents for Emergency Generator
Diesel Engines ........................................................................................ 5-113 Table 5-24. RBLC Summary of PM BACT Precedent for Emergency Firewater
Diesel Engines ........................................................................................ 5-115 Table 5-25. Regulatory Agencies with PM Guidelines/Requirements for
Emergency Stationary Diesel Engines .................................................... 5-119 Table 5-26. Basis for Removing PM Precedents from Consideration ........................ 5-121 Table 5-27. RBLC Summary of CO BACT Precedents for Emergency Diesel
Engines .................................................................................................... 5-125 Table 5-28. RBLC Summary of CO BACT Precedent for Firewater Emergency
Diesel Engines ........................................................................................ 5-127 Table 5-29. Regulatory Agencies with CO Guidelines/Requirements for
Emergency Stationary Diesel Engines .................................................... 5-130 Table 5-30. LAER Components and References ............................................................138 Table 5-31. SCAQMD Rule 1173 Equipment Leak Rates and Repair Periods 1 ....... 5-140 Table 5-32. TCEQ LAER Equipment Leak Rates and Repair Periods 1 .................... 5-140 Table 5-33. BAAQMD Best Available Control Technology Guideline ..................... 5-141 Table 5-34. Summary of Texas Ethylene/Polyethylene Manufacturing GHG
BACT Determinations ............................................................................ 5-142 Table 5-35. Amine Based CO2 Capture Plants ≥ 200 TPD 1 ...................................... 5-150 Table 5-36. CO2 BACT Hierarchy and Emissions ..................................................... 5-162 Table 5-37. Summary of CCS Impacts Analysis for the Cracking Furnaces and
Cogen Units ............................................................................................ 5-164 Table 5-38. Summary of VOC BACT Precedents for Polyethylene Unit Vents ........ 5-169 Table 5-39. Summary of Recent Determinations for Polyethylene Process Vents .... 5-178 Table 5-40. Summary of BACT Guidelines for Bay Area Air Quality Management
District and Texas Pertaining to Manufacturing Process Particulate
Emissions ................................................................................................ 5-183 Table 5-41. Summary of Storage Tanks and Vessels in VOC Service ....................... 5-185 Table 5-42. Summary of VOC BACT/LAER Precedents for Tanks .......................... 5-190 Table 5-43. RBLC Summary of Cooling Tower Emission Limits for PM ................. 5-194 Table 5-44. RBLC Summary of Cooling Tower Emission Limits for VOC .............. 5-200 Table 5-45. RBLC Summary of VOC RACT/BACT/LAER Precedent for
Wastewater Treatment ............................................................................ 5-205 Table 5-46. Summary of the State Implementation Plan Review for Loading
Operations PM Requirements ................................................................. 5-213 Table 5-47. Summary of the State Implementation Plan Review for Loading
Operations VOC Requirements for Loading of Low Organic Vapor
Pressure Liquid ....................................................................................... 5-218 Table 5-48. Summary of the State Implementation Plan Review for Loading
Operations VOC Requirements for Loading of C3+ or LPG ................... 5-220 Table 5-49. Summary of RBLC and Other Flare Related Permitting Precedents
and Regulatory Requirements .................................................................. 5-224 Table 5-50. Summary of RBLC Incinerator Related Permitting Precedents .............. 5-236
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Table 5-51. Summary of SIP Regulations for Plant Road Particulate ........................ 5-248 Table 5-52. Summary of RBLC Survey Results for Plant Road Particulate .............. 5-250 Table 5-53. Proposed Limitations to Meet SO2 BAT ................................................. 5-252 Table 5-54. Summary of Proposed PaBAT for HAP from the Proposed Project
Sources ..................................................................................................... 5-258 Table 7-1. Nine Counties Considered in Population Growth Impact Area .................... 7-3 Table 7-2. Other Area Source Emissions Increases Compared to Current Inventory .... 7-4 Table 7-3. Commercially Significant Vegetation in Ten-County Study Area
(Acres) ............................................................................................................12 Table 7-4. Pennsylvania-Listed Plant Species with Potential to Occur in Vicinity
of Beaver Valley Nuclear (BVN) Plant (7 miles from the Proposed
Project Site) ................................................................................................ 7-15
List of Figures
Figure 1-1. General Location of the Shell Facility ......................................................... 1-8 Figure 1-2. Proposed Facility Location .......................................................................... 1-9 Figure 3-1. Ethane Cracker Process Flow....................................................................... 3-3 Figure 3-2. Polyethylene Gas Phase Technology Process Flow Diagram ..................... 3-9 Figure 3-3. PE Unit 3 - Polyethylene Slurry Technology Simplified Process Flow
Diagram ...................................................................................................... 3-13 Figure 5-1. CO2 Capture and Concentration System .................................................. 5-147
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1.0 Introduction
1.1 Project Description
Shell Chemical Appalachia LLC (Shell) is proposing to construct a petrochemicals
complex (the Project) near Pittsburgh, Pennsylvania that will convert ethane (derived as a
byproduct from shale gas production in the region) into ethylene and subsequently
polyethylene, which is the key building block for many plastic products used every day.
The proposed complex will be the first major U.S. project of its type built outside the
Gulf Coast region in 20 years. The facility will leverage the plentiful new supplies of
ethane in the region to produce polyethylenes used extensively by the area’s
manufacturing base. This will reduce economic and environmental transportation costs
while providing regional manufacturers with more flexibility, shorter supply chains, and
enhanced supply dependability.
The proposed Project site is located within an industrial area adjoining the Ohio River in
Potter and Center Townships in Beaver County, Pennsylvania. The site offers strategic
advantages including access to marine, rail and road transportation, and pipelines;
proximity to both ethane supply and polyethylene markets; access to a skilled workforce;
a prior history of industrial use; appropriate zoning and compatible adjoining land uses;
and a positive business climate.
Shell Chemical Appalachia LLC is committed to keeping people safe, protecting the
environment and being a good neighbor. The proposed manufacturing facility would
deliver a number of benefits for the community including employment, economic growth,
and redevelopment of an existing industrial site. As the company continues with project
planning, it is working with the community and other interested parties to enhance the
proposed project’s potential benefits while identifying and addressing potential impacts.
With the increase in North American shale gas production, particularly in the “wet gas”
portions of the Marcellus and Utica shale in western Pennsylvania, West Virginia and
Ohio, there has been an accompanying increase in ethane production. The resultant
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availability of increased supplies of ethane at favorable prices has caused ethane to
become a highly competitive feedstock for use by the petrochemical industry.
The proposed Project, expected to employ 400 workers, will be comprised of an ethylene
manufacturing plant with an average capacity of 1,500,000 metric tons per year.1 The
ethylene that is produced will be used to supply feed to three polyethylene manufacturing
units with a combined annual production of approximately 1,600,000 metric tons of
polyethylene.2 Steam and electricity required for the process will be supplied by natural-
gas-fired combined cycle cogeneration units (Cogen Units). The Project includes all of
the ancillary units needed to support a new standalone complex including effluent
treatment, storage, logistics, cooling water facilities, emergency flares, buildings, and
warehouses. Excess electricity produced by the cogeneration units at the Project will be
sold for distribution within the PJM grid for regional use.
Shell is submitting an Air Quality Plan Approval pursuant to the Pennsylvania Air
Pollution Control Act and 25 Pa. Code Ch. 127, Subch. B, to obtain approval for
construction of an “air contamination source” and installation of associated air cleaning
devices, including review pursuant to the pre-construction permitting requirements under
the PSD and NSR programs.
The analysis provided in this application addresses the requirements governing air
emissions from the proposed facility including: 1) New Source Performance Standards
(“NSPS”), 2) National Emission Standards For Hazardous Air Pollutants (“NESHAPS”);
3) Prevention Of Significant Deterioration (PSD)/ Best Available Control Technology
(BACT) analysis for applicable pollutants for which the Project is classified as a major
source located within an attainment area for such pollutant; 4) Nonattainment New
Source Review (NNSR) / Lowest Achievable Emission Rate (LAER) analysis for those
applicable pollutants for which the Project is classified as a major source located within a
non-attainment area for such pollutant; 5) demonstration that the Project will not cause or
1 Assumes 7,500 hours per year of operation at the design capacity. 2 Assumes each of the polyethylene units will operate 8,000 hours per year at their design capcity.
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contribute to an exceedance of an applicable air quality standard or increment; 6)
quantification of the emissions reduction credits (i.e., offsets) required for certain
pollutants in accordance with the nonattainment NSR requirements; 7) demonstration that
emissions from the new sources will be the minimum attainable through use of best
available technology pursuant to 25 Pa. Code §127.12(a)(5) (“PaBAT”), 8) an additional
impacts analysis under 40 C.F.R. §52.21(o), and 9) an analysis as required by 25 Pa.
Code §127.205(5) of alternative sites, sizes, production processes and environmental
control techniques, showing that Project benefits outweigh the Project’s environmental
and social costs.
The Project site is located within an area that is designated as nonattainment for SO2 (1-
hr), PM2.5 (annual), ozone,3 and lead (Pb) and attainment or unclassified for all other
criteria pollutants under the Clean Air Act. A summary of the proposed facility’s
potential to emit regulated NSR pollutants is presented in Table 1-1. As shown,
emissions of NOx, PM2.5, and VOC, which are nonattainment pollutants, are above the
major facility thresholds of 100, 100, and 50 tons per year, respectively. As a result, the
proposed Project is subject to the nonattainment NSR requirements at 25 Pa. Code
§127.201 for NOx, PM2.5, and VOC. The Project is a major facility and emissions of
PM, PM10, NO2, and CO are above their respective significance thresholds of 25, 15, 40,
and 100 tons per year. As a result, the Project is subject to the prevention of significant
deterioration (PSD) requirements at 25 Pa. Code §127.81 for PM, PM10, NO2, and CO.
The proposed Project will have CO2e emissions above the major facility threshold of
100,000 tons per year and greenhouse gas (GHG) emissions greater than the significance
threshold; and as a result, the Project is subject to the PSD/BACT requirements for
GHGs. Increases in sulfur dioxide (SO2) and lead (Pb) emissions are less than the major
source threshold (100 tons/yr) and emissions of sulfuric acid mist are less than the PSD
significance threshold (7 tons/yr).
3 All of Pennsylvania is designated nonattainment for ozone because it is a part of the Northeast Ozone
Transports Region (NOTR), that was defined in the 1990 Clean Air Act Amendments.
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Table 1-1. Summary of the Proposed Project’s Annual Potential to Emit Pollutants (tons) 1
Pollutant Cracking
Furnaces
PE
Units
Cogen
Units
Flares &
Incinerators
Tanks &
Loading Fugitives
Support
Units Total
Significance
Threshold
Subject to
NSR/PSD
Carbon Monoxide 670 - 43.5 277 - - 0.6 991 100 Yes
Nitrogen Oxides 181 - 67.9 74.8 - - 2.8 327 100/40 Yes
PM 34.1 15.3 16.9 4.6 - - 8.3 79 25 Yes
PM10 86.8 4.9 59.8 8.2 - - 4.7 164 15 Yes
PM2.5 86.8 4.9 59.8 8.2 - - 0.1 160 100 Yes
Sulfur Dioxide 3.6 - 13.3 5.0 - - 0.0 22 100 No
VOC 32.4 96.6 31.9 219 14.1 47.5 42.7 484 50 Yes
CO2e 1,048,668 - 1,061,680 147,708 - 138 1,272 2,259,466 100,000 Yes
Sulfuric Acid Mist 0.1 - 0.5 0.2 - - 0.0 0.9 7.0 No
Total HAP 18.2 0.0 9.3 3.4 1.8 5.4 3.9 41.9 N/A N/A
Polyethylene (PE) Units: includes emissions from PE processing equipment but not fugitives, flare, and thermal incinerator emissions.
Support Units: includes emissions from firewater pump and emergency generator engines, cooling tower, wastewater treatment and plant roads
1. This Project may also increase emissions of other pollutants, but in minimal quantities. Appendix B includes the detailed
emissions increase calculations for the proposed Project.
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Under non-attainment NSR regulations, the proposed Project’s emissions of NOx, PM2.5,
and VOC will be subject to the emissions offset requirement at 25 Pa. Code §127.205(3).
As a result, in accordance with the offset ratios of 1.15, 1.1, and 1.15, respectively, at
25 Pa. Code §127.210(a), Shell will secure the following amounts of emissions reduction
credits (ERCs):
NOx: 376 tons = (1.15) x (327 tons)
PM2.5: 176 tons = (1.1) x (160 tons)
VOC: 557 tons = (1.15) x (484 tons)
In accordance with 25 Pa. Code §127.206(d)(1), Shell will not operate the sources until
the required ERCs are provided to and processed through the ERC registry, and the
Department certifies the required ERCs.
A summary of the potential to emit for hazardous air pollutant (HAP) emissions is
presented in Table 1-1. As shown, the total annual HAP emissions from the Project are
estimated to be approximately 42 tons. The largest individual source of HAP will be the
Cracking Furnaces, which will have the potential to emit 18.2 tons of total HAP.
1.2 Overview of Process
Ethane, the primary raw material for the proposed Project, is a natural gas liquid, or
NGL, that exists in certain natural gas deposits including the Marcellus and Utica Shales.
(Propane and butane are examples of other NGLs.) Natural gas companies remove NGLs
from natural gas, with the natural gas (mainly methane) to be shipped by pipeline for use
as a fuel by residences, power plants, and industry. The NGLs are used for a variety of
industrial, residential, and commercial uses. Ethane’s primary use is as a feedstock used
to create ethylene.
Ethylene is an important first step in creating many of the products in everyday use. This
facility will process the ethylene to make different types of polyethylene. Different
grades of polyethylene are used to make different types of products:
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low-density polyethylene (LDPE) and linear low density polyethylene (LLDPE)
are the raw materials for flexible items like food packaging, film, trash bags,
diapers, toys, and housewares;
high density polyethylene (HDPE) is used to create “stiffer” products such as
crates, drums, bottles, food containers, and other types of housewares.
The proposed Project will consist of an ethylene manufacturing process, three (3)
polyethylene manufacturing units, three Cogen Units, and a variety of ancillary
equipment required to support the overall plant operations.
The proposed Project’s cracking funaces units will “crack” ethane (C2H6) to create
ethylene (C2H4). This is accomplished by heating the ethane to very high temperatures,
greater than 1500°F (800°C). “Tail gas,” a byproduct from the cracker furnaces that
contains methane and a high percentage of hydrogen, will be recycled to fuel the process,
with natural gas used to supplement the process’s energy requirements.
The ethylene manufacturing process will consist of seven (7) cracking furnaces that will
be capable of converting ethane into ethylene at a maximum rate of 1,500,000 metric tons
per year.4 The ethylene that is produced will be used to feed two gas phase polyethylene
manufacturing units and one slurry technology unit. The two gas phase units will be
designed to produce 550,000 metric tons per year of polyethylene each, while the slurry
unit will be designed to produce 500,000 metric tons per year.5 Both technologies
employ catalyst, but use different equipment and operating parameters to produce each
specific grade of polyethylene. Each unit will have separate pellet handling systems prior
to blending. Common storage equipment, rail car, and truck loading operations will
follow the blending.
To support the overall plant operations, three on-site natural gas-fired combustion
turbines/duct burners and heat recovery steam generators (HRSGs) will be used to
generate electricity and steam. Other ancillary equipment will include four emergency
diesel generators and three diesel-driven firewater pumps, two cooling towers, numerous
4 Assumes 7,500 hours per year of operation at the design capacity. 5 Each polyethylene unit is assumed to operate 8,000 hours per year at its design capcity.
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storage tanks and pressure vessels for raw materials and by-products, and a wastewater
treatment facility. Additionally, the Project will include the necessary air pollution
control devices to meet all applicable federal and state requirements.
For a more detailed description of the processes and supporting equipment proposed for
this Project, please refer to Section 3.0.
1.3 Site Description
The Shell facility will occupy approximately 400 acres on the site of the zinc smelter
currently owned by the Horsehead Corporation. The site is located adjacent to the Ohio
River in Beaver County, Pennsylvania.. The approximate Universal Transverse Mercator
(UTM) coordinates of the facility are 556,129 meters east and 4,502,450 meters north
(UTM Zone 17, NAD 83). Figure 1-1 shows the general location of the facility. Figure
1-2 shows the specific facility location on a 7.5-minute U.S. Geological Survey (USGS)
topographic map.
Beaver County is located in western Pennsylvania, with its western boundary bordering
the Ohio State line. The Ohio River generally runs through the center of the county and
flows in a westerly direction. The Beaver River drains the northern portion of the county,
converging with the Ohio approximately 5km upstream of the proposed site location.
The cutting of these rivers has formed the hills and valleys of this region, whose local
difference in elevation constitutes the relief of the county. Thus, north of the Ohio the
highest land, or main divide, rises about 600 feet above the river. The relief of the area
lying between Beaver River and Crow Run is about 550 feet above the Ohio River. The
tributaries south of the Ohio form a main divide which rises at most 650 feet above the
river.
Winters are cold and snowy at high elevations in Beaver and Lawrence Counties. In the
valleys it is also frequently cold, but intermittent thaws preclude a long-lasting snow
cover. Summers are fairly warm on mountain slopes and very warm with occasional very
hot days in the valleys. Rainfall is evenly distributed throughout the year, but it is
appreciably heavier on the windward, west facing slopes than in the valleys. Normal
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Figure 1-1. General Location of the Shell Facility
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Figure 1-2. Proposed Facility Location
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annual precipitation is adequate for all crops, although summer temperature and growing
season length, particularly at higher elevations, may be inadequate. The lowest
temperature on record, which occurred at New Castle on January 29, 1963, is -23
degrees. In summer the average temperature is 70 degrees, and the average daily.
maximum temperature is 80 degrees. The highest recorded temperature, which occurred
at New Castle on September 2, 1953, is 100 degrees. The total annual precipitation is 38
inches. Of this, 22 inches, or 60 percent, usually falls in April through September, which
includes the growing season for most crops. In two (2) years out of 10, the rainfall in
April through September is less than 17 inches. The heaviest 1-day rainfall during the
period of record was 3.70 inches at New Castle on October 16, 1954. Thunderstorms
occur on about 36 days each year and most occur in summer. Heavy rains, which occur
at any time of the year, and severe thunderstorms in summer sometimes cause flash
flooding, particularly in narrow valleys. Average seasonal snowfall is 42 inches. The
greatest snow depth at any one time during the period of record was 19 inches. On
average, there are 24 days a year with at least 1 inch of snow on the ground. The number
of such days varies greatly from year to year. The average relative humidity in mid
afternoon is about 60 percent. Humidity is higher at night, and the average at dawn is
about 80 percent. The sun shines 60 percent of the time possible in summer and 35
percent in winter. The prevailing wind is from the southwest. Average wind speed is
highest, 12 miles per hour, in winter.
1.4 Project Schedule
Construction activities are planned to start in late 2015 and to continue for approximately
24 months. Operation is planned to commence in 2018.
1.5 Document Overview
The contents of this document are organized as follows:
Section 1.0 provides an overview of the Project, a description of the proposed
site’s location and surrounding terrain and local climate in Beaver County,
Pennsylvania, and a summary of the pollutant-by-pollutant emissions increases.
Section 2.0 contains a summary of the permit application requirements.
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Section 3.0 contains the process description. Each of the manufacturing
processes which comprise the proposed Project are described along with the
points and types of emissions from each point. Also included is a description of
the various outside the boundary limits (OSBL) elements of the Project.
Section 4.0 contains an overview of all of the air regulatory requirements to
which the proposed Project is subject. This includes a description of both state
and federal requirements.
Section 5.0 contains the Lowest Achievable Emissions Rate (LAER), Best
Available Control Technology (BACT) and Pennsylvania Best Available
Technology (PaBAT) analyses required in support of the plan approval process.
Section 6.0 contains a summary of the results from the air dispersion modeling
analysis performed in support of the plan approval process for the PSD criteria
pollutant for which the Project is subject to review (i.e., NO2, CO, and PM10).
Section 7.0 contains the additional impacts analysis required under 40 CFR
§52.21(o).
Appendices
A – Plan Approval Application Forms
B – Detailed Emissions Increase Calculations
C – Air Dispersion Modeling Report
D – Trade Secret and/or Confidential Proprietary Information (Not in
Public Version)
E – 25 Pa. Code §127.205(5) Analysis
F – Additional Support Material
G – Summary of Compliance Demonstration
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2.0 Permit Application Requirements
Pursuant to the requirements of Title 25 of the Pennsylvania Code Chapter 127,
Construction, Modification, Reactivation, and Operation of Sources, this application
contains the following:
Identification of the location of the source and the name, title, address, and
telephone number of the individual responsible for the operation of the
source. This general information is provided in Section 1.0, in the Plan
Approval forms located in Appendix A, and in the General Information Form
located in Appendix F.
Information that is requested by the Department and is necessary to perform a
thorough evaluation of the air contamination aspects of the source is provided
in the Plan Approval forms located in Appendix A or in this document as
referenced within the forms.
A demonstration that the source will be equipped with reasonable and
adequate facilities to monitor and record the emissions of air contaminants
and operating conditions which may affect the emissions of air contaminants
and that the records are being and will continue to be maintained and that the
records will be submitted to the Department at specified intervals or upon
request. Compliance information is provided in the Plan Approval forms, as
well as, Appendix G. Specific equipment in many cases is still to be
determined, however, the criteria for the design and/or purchase of equipment
is set forth by the compliance requirements of the applicable regulations noted
in Section 4.0.
A demonstration that the source will comply with applicable requirements of
this article and requirements promulgated by the Administrator of the EPA
under the Clean Air Act (42 U.S.C.A. §§ 7401-7706). The applicability of
Federal regulations under the Clean Air Act are presented in Section 4.0. A
detailed listing of the compliance requirements and demonstration cited by
each applicable regulation is provided in Appendix G on an affected source
basis. This listing also provides citations for recordkeeping and reporting
requirements.
A demonstration that the emissions from a new source will meet the control
technology and emission limitations of applicable federal and state regulations
is presented in Section 5.0. This section contains a full control technology
review for all pollutants and contaminants subject to PSD/NSR, BACT/LAER
and PaBAT, respectively.
A demonstration that the source will not prevent or adversely affect the
attainment or maintenance of ambient air quality standards. A summary of
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the results from an air quality analysis performed for the proposed Project is
presented in Section 6.0. A report detailing the analysis is included as
Appendix C;
A plan of action for the reduction of emissions during each level specified in
Chapter 137 (relating to air pollution episodes), when required by the
Department. As noted in Section 4.0, a plan will be developed and
implemented when requested by the Department.
Copies of letters of notification to local municipalities and proof that the
notices were received are contained in Appendix F.
A plan for dealing with air pollution emergencies, when requested by the
Department, or when required by the Clean Air Act. A plan will be developed
and implemented as required.
A demonstration that the source and the air cleaning devices are capable of
being and will be operated and maintained in accordance with good air
pollution control practices. As described in Section 5.0, Shell proposes to
satisfy the applicable BACT, LAER, and PaBAT requirements through the
design,installation, and operation of air cleaning devices capable of achieving
the proposed limits and/or the operation of process equipment to minimize air
contamination through accepted work practices.
A completed compliance review form is presented in Appendix F.
In addition to the requirements of 25 Pa. Code § 127, the DEP plan approval application
must also include a completed Cultural Resource Notice (CRN) and return receipt. The
Pennsylvania State History Code (Title 37, § 507) requires a completed Cultural
Resource Notice and return receipt as part of the DEP plan approval process where more
than 10 acres of earth will be disturbed. To meet this criteria, URS Coprporation on
behalf of Horsehead Corporation and Shell previously filed a CRN for a joint water
permit amendment. A copy of this CRN and return receipt are provided in Appendix F.
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3.0 Process and Emission Source Descriptions
This section presents the process description and emission source descriptions for the
proposed Project. The description is organized by processing areas as follows:
Ethylene Manufacturing
Polyethylene Manufacturing
Combustion Turbines and Duct Burners
Utilities & General Facilities
The objective of the Project is to convert ethane into ethylene and then to convert
ethylene into linear, low density polyethylene (LLDPE) and high-density polyethylene
(HDPE) pellets that can be shipped to plastic manufacturing facilities. Typical
manufacturing uses for LLDPE include:
Plastic bags and sheets,
Plastic wrap,
Stretch wrap,
Toys,
Covers and lids,
Pipes,
Buckets and containers,
Covering of cables,
Geo-membranes, and
Flexible tubing.
Typical manufacturing uses for HDPE include:
3-D printer filament,
Arena board (puck board),
Bottle caps,
Chemical resistant piping systems,
Coax cable inner insulator,
Food storage containers,
Fuel tanks for vehicles,
Electrical and plumbing boxes,
Folding chairs and tables,
Hard hats,
Plastic bags,
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Plastic bottles suitable both for recycling (such as milk jugs) or re-use,
Storage sheds, and
Water pipes for domestic water supply and agricultural processes
The manufacturing process for LLDPE and HDPE begins with pyrolysis of a
hydrocarbon to make ethylene. Ethylene is then converted into LLDPE and HDPE
pellets. The Project will take ethane, a product of shale gas production in Pennsylvania
and neighboring states, and convert it to ethylene by pyrolysis in large furnaces.
Ethylene in the pyrolysis gas exiting the furnaces will be separated from the pyrolysis gas
and purified for the manufacture of LLDPE and HDPE. A number of utilities are
required to support these processes including: steam, electricity, process water, cooling
water, wastewater treatment, tanks, flares, storage and loading operations. The following
subsections describe each process in more detail and characterize the air emissions
sources.
3.1 Ethylene Manufacturing Process
3.1.1 Process Description
Figure 3-1 presents the process flow diagram for the ethylene manufacturing process.
Ethane is thermally cracked into ethylene, propylene, methane, hydrogen, and other by-
products in the pyrolysis furnaces at temperatures up to ~1560°F in the presence of
steam. The furnaces act as pyrolysis reactors in which a wide range of mainly light
hydrocarbons are produced. The general chemical reaction scheme is:
C2H6 + heat → C2H4 + H2
Ethane conversion in the furnaces is typically 65-72% and is optimized depending on the
availability of ethane. Any methane that is contained in the feedstock is not pyrolyzed
and travels through the furnaces unchanged. Thus, it is not included in the equation.
Steam is used as a diluent to control the pyrolysis reactions and is also not shown in the
equation. Several byproducts are produced as part of the ethane cracking process
including carbon, which is deposited as coke in the furnace tubes, unreacted ethane and
polymerized carbon compounds (C3+, gasoline, tar/coke/pitch). The Project includes
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Figure 3-1. Ethane Cracker Process Flow
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seven cracking furnaces, which will be operated in parallel. One hundred percent of the
plant’s annual ethylene production rate (1,500,000 metric tons)6 will be achieved through
six furnaces in cracking operation while the seventh furnace is in either decoking, in hot-
standby or off-line for maintenance.
After leaving each furnace radiant section, the hot cracked gases are cooled while
generating super high pressure (SHP) steam. The SHP-steam is used to drive the
cracker’s main compressor. Next, the cooled cracked gases are quenched with water to
reduce the volume of gas that must be compressed prior to cryogenic separation and
purification of the ethylene product. The quench water is also used to partially absorb
acidic components formed in the furnaces from traces of additives used for equipment
protection and impurities present in the ethane feedstock. In the quench tower the
cracked gas is cooled to ambient temperature. Gasoline as well as process steam is
condensed. The purified and cold cracked gas exiting through the top of the quench
tower is directed to the compression section. Circulating quench water is withdrawn
from the bottom of the quench tower and pumped to the process sections for heat
recovery.
Excess water and gasoline are separated by gravity. The water is cleaned in the process
steam system and then reused as dilution steam. Solid components (coke/pitch/tar) are
removed from the process water by gravitational deposition and sent offsite for either use
or disposal. The pyrolysis tar and light gasoline7 are stored in separate tanks before being
shipped offsite for further processing into products. The possibility of combining the
pyrolysis tar with the coke/pitch/tar is being considered. The combined stream would be
stored in the pyrolysis tar tank prior to being shipped offsite.
6 Assumes 7,500 hours per year of operation at the design capacity. 7 Pyrolysis tar is primarily heavy oil (>85%) with less amounts of C9+ components (4-14 %), water, and
traces of benzene, toluene and styrene (all <0.1%). Light gasoline is primarily benzene, toluene xylene,
ethyl benzene, and styrene (40-45%) with the remainder being compounds in the C2-C5 range.
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After the quench tower, the cracked gases are directed to the compression section where
they are compressed in a five-stage centrifugal compressor; compressing the cracked gas
from a suction pressure of approximately 25 pounds per square inch (absolute) to a
discharge pressure of approximately 500 pounds per square inch (absolute). Between the
4th and 5th stages of the compressor, the cracked gas is scrubbed using caustic to remove
sour components (primarily CO2 and H2S) from the cracked gas. The spent caustic is
sent to a stripper tower where the hydrocarbons are stripped from the spent caustic before
the spent caustic is directed to the caustic oxidation system.
After compression, the cracked gases pass through a cooling and drying section and then
to the separation section where the cracked gases are separated at low temperatures into a
C2/CH4/H2 stream and a C3+ stream. The C2/CH4/H2 stream is selectively hydrotreated to
convert any acetylene to ethylene prior to separation into the main product ethylene,
unconverted ethane and tailgas (hydrogen and methane). The unconverted ethane is
recycled back to the furnaces as feed.
The product streams (from the de-ethanizer bottoms) are sent to storage prior to being
exported to other plants via rail car for further processing and recovery of valuable
components. Most of the hydrogen rich tailgas is sent directly to the fuel gas system for
the cracking furnaces and provides the vast majority of the fuel used for cracking. A
small amount of the tailgas is sent to a pressure swing absorption (PSA) unit where a high
purity hydrogen stream is generated for use at the polyethylene units. Tailgas from the
PSA unit is recycled back to the cracked gas compressor and eventually ends up in the
cracking furnace fuel gas system.
In addition to the main processing sections for ethylene manufacture, the following
support systems are located inside the ethylene manufacturing plant.
Ethylene Refrigerant Cycle: The ethylene refrigeration cycle represents an open
loop system. It generates the reflux for the C2H4/C2H6 separation, supplies the
ethylene coolant for the low temperature section and CH4/C2 separation and
compresses the ethylene product to the required pressure.
Propane Refrigerant Cycle: The propane refrigeration closed cycle provides the
cooling in the intermediate temperature range between cooling water and ethylene
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refrigerant. The propane vapors are compressed by a three-stage propane
compressor.
Gasoline Redistillation: The gasoline from the quench water system is separated
by distillation into a wash oil fraction overhead and a heavy bottom product. The
bottom product is mixed heavy gasoline from the quench water section and is
exported to storage. The overhead liquid product is a light gasoline stream that is
partially re-used in the process, but has a net export to storage.
Steam System: SHP steam is generated when cooling the cracked gases leaving
the cracking furnaces. The system is designed to supply steam to a number of
turbines driving compressors in the plant. Additionally, steam is directed to heat
consumers such as reboilers and process heat exchangers.
Condensate System: Condensates from the condensing turbines and reboilers are
collected in the condensate system. From there, they are returned to the facility
condensate treatment system.
Boiler Feed Water System: Demineralized water from the facility is delivered
to the cracking furnaces and other consumers at the required flow, pressure and
quality.
Fuel Gas System: Natural gas from offsite and tailgas from the separation
section are distributed by the fuel gas system to the cracking furnaces.
Regeneration Gas System: Part of the tailgas is used as regenerating gas for the
molecular sieve driers used in the ethylene manufacturing process to purify
nitrogen. Supply of the required regeneration gas, heating, cooling, and water
condensation is performed in the regeneration gas system.
Chemicals and Wash Oil System: This system provides performance chemicals
to several injection points. These chemicals include methanol, wash oil, ammonia
and dimethyl disulfide (DMDS).
Blow Down System: This system provides the facilities to safely remove process
gases and liquids to the facility flares during upset conditions and shutdowns.
Slop and Sewer System: This system collects all liquids that appear in the plant
in separate collection systems. This ensures that effluents are processed in a safe,
environmentally optimized manner before leaving the facility.
3.1.2 Ethylene Manufacturing Emissions Sources
3.1.2.1 Ethane Cracking Furnace Emissions
Each of the Project’s cracking furnaces will have a firing capability of approximately
620 MMBtu/hr (HHV) per furnace. Pyrolysis gas products, methane and hydrogen, will
be used to provide the heat input. Emissions from the cracking furnace stacks will result
from combustion of methane, hydrogen, and natural gas during normal operation,
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startup/shutdown, decoking, and hot standby. The seven cracking furnaces will be
operated in parallel and have the following operating modes:
Ethane cracking: This is the normal operating mode of the unit during which
ethylene is being produced by cracking ethane.
Cold startup and shutdown: This mode covers both the operation of the unit when
it is initially started up following a turnaround and the period following feed
being taken out of the unit until it is off-line. In a cold start-up situation, where
no furnaces are in ethane cracking mode, natural gas serves as the fuel for the
furnaces until ethane cracking begins and tailgas is available.
Decoking: During the ethane cracking mode, coke is formed within the radiant
coils. Coke build-up eventually leads to high tube wall temperatures requiring
decoking of the furnace. Every 30 to 60 days a furnace will go through decoking,
which will last for approximately 33 hours. The coke buildup is removed during
this mode of operation. The heat input rate required during decoking is about
30% of the furnace’s maximum heat input. Once a furnace has been decoked, it is
placed into hot steam standby until another furnace shuts down or goes into
decoking mode. Additional information related to decoking is provided below.
Hot steam standby: Once a furnace has been decoked, it is placed into hot steam
standby until it is needed for cracking (i.e. one of the other furnaces requires
decoking).
Feed in/Feed out: As part of the process of bringing a furnace down for purposes
of decoking or maintenance, the furnace’s firing rate is reduced to a point where
the feed to the furnace can be stopped. Similarly, when a furnace is being brought
back online from hot steam standby, there is is a period during which the firing
rate is increased prior to when feed is placed into the furnace. These periods are
referred to as feed in and feed out.
Decoking: Furnace decoking is a normal and routine part of the ethylene manufacturing
process. High ethane conversion rates (i.e., 72 percent) require more frequent decoking
relative to lower ethane conversion rates (i.e., 65 percent). Decoking is accomplished by
injecting steam into the radiant coils while progressively raising the concentration of air
to achieve controlled combustion of the coke in the furnace tubes. The CO2 (carbon
dioxide) concentration exiting the tubes is used to monitor the decoking process. After
passing through a separator to remove large particulate, the decoking vent will be
redirected back into the furnace where the CO and remaining particulate in this stream
will be combusted.
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Furnace Emissions: The nitrogen oxide (NOx) emissions from the furnaces will be
controlled through the use of low NOx burner technology and selective catalytic
reduction (SCR), The carbon monoxode (CO), volatile organic compound (VOC) and
hazardous air pollutant emissions from the furnaces will be controlled through the use of
low carbon fuel and good combustion control.
3.1.2.2 Ethylene Manufacturing Equipment Leak Emissions
Methane and VOC emissions may result from equipment leaks in the ethylene
manufacturing process area. Processes within the ethylene manufacturing unit with
potential for fugitive methane and VOC emissions include:
Cracking furnace fuel system and process equipment;
Quench water system;
Cracked gas compression, acid gas removal and drying process area;
Cryogenic separation area;
C2 fractionation;
C2 hydrogenation unit, and
Spent caustic oxidation unit.
3.2 Polyethylene Manufacturing – Gas Phase Technology
3.2.1 Process Description
Figure 3-2 presents a simplified process flow diagram of the gas phase polyethylene
manufacturing process. Two units (PE Units 1 and 2) are proposed; each designed to
produce 550,000 metric tons per year of polyethylene (PE).
The gas phase technology polyethylene plants consist of the following process sections:
ethylene purification, raw material supply and purification, catalyst system, reactor
system, resin degassing and vent recovery, granular resin seed bed storage system, and
additive handling and pelleting sections. The main feeds to the polyethylene process are
ethylene, co-monomer and hydrogen. Gas phase technology polyethylene plants are
designed to produce different grades of linear low density polyethylene (LLDPE) and
high density polyethylene (HDPE) polymers from polymer grade ethylene.
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Figure 3-2. Polyethylene Gas Phase Technology Process Flow Diagram 8
8 The stream definitions corresponding to the R-x references constitute trade secret and/or confidential
proprietary information as defined in the Pennsylvania Right to Know Law. These stream definitions are
provided in Table D-1 of Appendix D.
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The following is a brief description of the proposed gas phase technology polyethylene
plant. References such as R-1 are used to describe process streams within the process.
The stream definitions corresponding to these references are considered trade secret
and/or confidential proprietary information as defined in the Pennsylvania Right to Know
Law, and as a result are provided as Table D-1 in Appendix D.
3.2.1.1 Purification
Ethylene Purification: Fresh ethylene feed (R-1) flows through a series of purifiers
where trace quantities of impurities are removed. The purifiers are vented to a VOC
Control System before and during regeneration. The VOC Control System is described
in more detail in Section 3.5.5. The fresh ethylene is injected into the Reaction Systems.
Raw Material Purification: R-2 or R-3 as well as R-32 are passed through a degassing
column and then flow through purifiers to remove impurities and are injected into the
Reaction System. R-4 is injected directly into the Reaction System. R-8 is passed
through a series of purifiers where trace quantities of impurities are removed. The
purifiers are vented to the atmosphere or flare before and during regeneration. A portion
of R-8 is compressed and is then routed to the reactor. The remaining R-8 is used
throughout the plant. R-7 is routed directly to the reactor.
3.2.1.2 Reaction Systems
The Reaction System consists of two fluidized bed Reactors, Cycle Gas Compressors and
Coolers, and Product Discharge Tanks related to each Reactor. Ethylene (R-1), Raw
Materials (R-2, R-3, R-4, R-7, R-8 and R-32), and catalyst (R-9) are fed continuously to
the Reactors. Polyethylene resin is removed from the Reactors and is separated from
most of the small amount of gas accompanying it in the discharge tanks. The separated
gas is fed back to the reactors. A mixture of resin and residual gas (R-11) is then sent to
Resin Degassing and Vent Recovery.
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Slurry catalyst is prepared by mixing precursor (R-16) with additives (R-17 & R-18).
The prepared catalyst (R-19) is transferred to the Reaction System. To prevent catalyst
release to the atmosphere, the vessels vent to a disposal tank and seal pot.
3.2.1.3 Resin Degassing and Vent Recovery
Resin from the Reactors (R-11) is conveyed to two purge bins where the dissolved
hydrocarbons are stripped from the resin and returned to the process (R-15, R-20). Any
excess gas not used in the process is vented to the VOC Control System. Resin from both
purge bins (R-13) flows to Additive Handling and Pelleting.
3.2.1.4 Granular Resin Seed Bed Storage System
Granular Resin (R-37) flow can be routed to the Granular Resin Seed Bed Storage
System. From the seed bed storage system, resin can be conveyed to the Reaction System
(R-38) for seed bed use or conveyed back to the Additive Handling and Pelleting area
(R-40).
3.2.1.5 Additive Handling and Pelleting
Using feeders, the resin (R-13) and additives (R-31) are metered to the Pelleting Systems.
The additives and resin are thoroughly mixed, melted, and pelleted in the Pelleting
Systems. The pellets (R-27) are dried, cooled, and conveyed from the pelletizing section
to homogenization silos. Pellets are blended in the homogenization silos. From the
blender, the pellets are transferred to silos for loading trucks and railcars.
3.2.2 Gas Phase Technology Process Emissions
Two types of pollutant emissions result from the gas phase polyethylene process: VOC
and particulate. A detailed listing of the points of emissions and pollutant type emitted is
presented in Table D-2 in Appendix D. All of the vents with VOC containing gases
located upstream of and including the Product Purge Bin will be directed to the VOC
Control System. All of the vents with particulate containing gases located upstream of
and including the Product Purge Bin will be directed through filters prior to release to the
atmosphere. Control of VOC emissions resulting from vents located downstream of the
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Product Purge Bin will be accomplished by maintaining the residual VOC content in the
resin exiting the Product Purge Bin below a level of 50 ppmw. Except for the pellet
dryer, particulate filters (i.e., sintered metal, fabric, or HEPA) will be used to control the
non-fugitive particulate matter emissions from all vents located downstream of the
Product Purge Bin. In addition to VOC emissions associated with vents, fugitive VOC
emissions may also result from equipment leaks.
3.3 Polyethylene Manufacturing – Slurry Technology
3.3.1 Process Description
One slurry based technology unit (PE Unit 3) designed to produce 500,000 metic tons per
year of polyethylene (PE) is proposed. Figure 3-3 presents a simplified process flow
diagram of the polyethylene slurry technology HDPE process. As shown, the plant will
consist of catalyst activation and feed systems, a reactor system followed by
separation/degassing, solvent recovery and a pelletizing section. The main feeds to the
polyethylene process are ethylene, co-monomer (Butene-1 and/or Hexene-1), hydrogen,
and light hydrocarbon diluent (isobutane). The reaction slurry is continuously withdrawn
from the reactor and the HDPE powder is separated from the hydrocarbon diluent and un-
reacted monomers.
The hydrocarbons are recycled to the reactors in a simple recovery system. The HDPE
powder that leaves the reactor enters a degassing system designed to remove traces of
diluent and residual monomer, then the powder is transferred to the finishing section. In
the finishing section, the powder is mixed with additives and is pelletized.
3.3.1.1 Catalyst Activation and Feed Systems
PE Unit 3 will use Ziegler and chromium based catalysts to manufacture polyethylene.
When Ziegler catalyst is needed, a drum is tumbled to mix the solution and then the
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Figure 3-3. PE Unit 3 - Polyethylene Slurry Technology Simplified Process Flow Diagram
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slurry is pumped into a day tank with a mixer.9 From the mixing day tank the catalyst.
slurry flows into the catalyst slurry tank where further dilution is achieved by diluent
addition. The chromium catalyst delivered by trucks to the site will be activated in an
electic heater. The Project includes as part of its design two (2) activation heaters. Each
catalyst activation system has a vent to the atmosphere through which air, nitrogen,
moisture, and catalyst fines are exhausted after passing through a knockout pot and
HEPA type filter system. Once the catalyst has been activated, it is transferred into tote
bins that are unloaded to the catalyst day tank, similar to the Ziegler catalyst. All of the
vents in this system will be controlled using particulate filters.
Triethylaluminum (TEAL) and Triethylborane (TEB) will be used as cocatalysts with the
Ziegler catalyst. TEAL and TEB are volatile, colorless liquids and highly pyrophoric.10
Nitrogen is used to transfer cocatalyst from the on-site delivery containers to the
cocatalyst feedpot. When transfer from a new delivery container is first initiated the
nitrogen used for the transfer process, is exhausted through a mineral oil seal pot prior to
being directed to a remote sand pit for safe, managed destruction. During process upsets,
the cocatylst feedpot will be vented directly to the sand pit. The sand pit will be fenced,
weather-protected, and accessed by authorized personnel only.
Co-monomer Injection: Co-monomer (hexene or butane, alternatively) is fed to a dryer
to remove impurities and introduced with recovered hydrocarbon into the polymerization
process.
3.3.1.2 Reactor Section
The reactor is based on the slurry loop principle. The reaction takes place in an isobutane
diluent. Ethylene is dissolved in the diluent. Catalyst, comonomer and hydrogen are also
9 The Ziegler type catalyst is purchased in 55 gallon drums. 10 Pyrophoric means that the material is capable of igniting spontaneously in air.
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fed into the reactor. The ethylene comes into contact with the catalyst in the diluent and
polymer “grows” into a white powder.
Depending on the characteristics of the HDPE being manufactured, two reactors will be
used in series for both mono-modal and bi-modal operation. Intermediate treatment is in
service for the bi-modal process. The intermediate system is used to generate differences
in the reaction conditions in each reactor to enable different HDPE properties (i.e.,
polymer molecular weight).
The slurry from the second reactor is discharged to hydroclones where the concentration
of the polyethylene powder is increased prior to separation from the slurry liquid. After
the hydroclones, the thickened slurry is heated up to the solvent vaporization temperature
prior to discharge to the high pressure separator.
3.3.1.3 High Pressure/Low Pressure Solvent Recovery
In the PE Unit 3 process there are two hydrocarbon/diluent recycle systems: High
Pressure Solvent Recovery (HPSR) and Low Pressure Solvent Recovery (LPSR).
High Pressure Solvent Recovery (HPSR): Nearly all of hydrocarbon recovery/recycle
occurs in the HPSR system. The high pressure separator makes the main separation
between vaporized hydrocarbon and powder. The PE powder is transferred to the low
pressure system.
Low Pressure Solvent Recovery (LPSR): Powder enters the LPSR degasser from the
HPSR via the product discharge system. The powder is “dry” but still saturated with
monomer and hydrocarbon. As the powder enters the degasser, extra gas slip from the
discharge system goes to the low pressure recovery system. The powder in the degasser
is stripped by two counter flow gas streams; one is a mixture of nitrogen and light
hydrocarbons. The other, fed at a lower level in the vessel, is a fresh pure nitrogen
stream. Degassed powder is pneumatically transferred to finishing.
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3.3.1.4 Additives and Pelletizing
In the additives and pelletizing section, virgin powder (i.e., resin) from the
polymerization section is received and blended with additives for extrusion and
pelletizing. The extruder consists of a continuous mixer with gear pump and is fitted
with a screen pack changer, diverter valve, die plate and an underwater face cutting
system. Pellets are extruded from the pelletizer and cut under water. Then the pellets are
separated from the water and dried in the pellet dryer. Finally, pellets are collected in a
hopper before being pneumatically conveyed to pellet blending. Water recovered in the
pellet drier is recycled through the water tank to the pelletizer.
The pellets conveyed from the pelletizing section are blended in the static
homogenization silos. From the blender, the pellets are transferred to silos for loading
into trucks and railcars.
3.3.2 Slurry Technology Process Emissions
Three types of emissions result from the polyethylene slurry process:
VOC and particulate from process vents,
Emissions from the sand pit, and
Fugitive emissions from equipment leaks.
A detailed listing of the points of emissions and pollutant type emitted is presented in
Table D-3 in Appendix D. All of the vents with VOC containing gases located upstream
of the Degasser will be directed to the VOC Control System. All of the vents with
particulate containing gases located upstream of the Degasser will be directed through
particulate filters (i.e., sintered metal, fabric, or HEPA) prior to release to the atmosphere.
Control of VOC emissions resulting from vents located downstream of the Degasser will
be accomplished by maintaining the residual VOC content in the pellets below a level of
50 ppmw. Except for the pellet dryer, particulate filters (i.e., sintered metal, fabric, or
HEPA) will be used to control the non-fugitive particulate matter emissions from
Pelleting System and downstream vents. In addition to VOC emissions associated with
vents, fugitive VOC emission may also result from equipment leaks.
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3.4 Combustion Turbines and Duct Burners (Cogen Units)
Three natural gas-fired combustion turbines (CTs), each coupled with a dedicated heat
recovery steam generator (HRSG), will supply the electricity and steam required to
support the site. Excess electricity produced by the Project will be available for sale to
the local electric utility grid. The combustion turbines will be either General Electric
Frame 6Bs or Siemens SGT-800s. The General Electric CTs have a baseload rating at
the average ambient site conditions of 40.6 MW. The heat input to each GE CT at
baseload at the average ambient site conditions is expected to be 475 MMBtu/hr (HHV).
The Siemens SGT-800 CTs have a baseload rating at the average ambient site conditions
of 48.7 MW. The heat input to each Siemens CT at baseload at the average ambient site
conditions is expected to be 492 MMBtu/hr (HHV). Each combined cycle CT will be
equipped with duct burners capable of firing natural gas up to rated capacity of
189 MMBtu/hr (HHV) if the GE turbine is selected, or 197 MMBtu/hr (HHV) if the
Siemens turbine is selected. Two steam turbines each rated at 64.3 MW will be used to
generate electricity using the steam produced by the HRSGs and excess steam from the
ethane cracking unit. For purposes of presentation the combustion turbines and duct
burners are refered to as Cogen Units.
Emissions from the Cogen Units will result from the combustion of natural gas. Methane
emissions may result from equipment leaks in the natural gas supply system used to
deliver fuel to the Cogen Units. When tailgas is in excess at the cracking furnaces, a
small quantity of the tailgas may be combusted in the duct burners in combination with
natural gas.
The nitrogen oxide (NOx) emissions from the Cogen Units will be controlled through the
use of dry low NOx combustion technology and SCR. The carbon monoxode (CO),
volatile organic compound (VOC) and hazardous air pollutant emissions from the
furnaces will be controlled through the use of a combination of good combustion control
and CO oxidation catalyst.
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3.5 Utilities and General Facilities Process Descriptions
3.5.1 Diesel Engines
Seven diesel-fired reciprocating internal combustion engines are included as part of the
Project. Three of these engines, each rated at 700 BHP/0.52 MW, will be used to drive
the emergency firewater pumps. The remaining four, each rated at 5028 BHP/3 MW,
will be used to drive emergency electrical generators. Emissions from the diesel engines
will result from the combustion of diesel fuel. Additionally, fugitive VOC emissions
may result from equipment leaks in the diesel fuel supply system. Emissions of NOx,
VOC, CO, and particulate will be controlled through the use of engine design. In
addition, low sulfur Tier 2 diesel will be used to control SO2 and particulate emissions.
3.5.2 Storage Tanks
A summary of the tanks that will be constructed to support the Project is presented in
Table 3-1. The pressurized storage vessels (i.e., spheres or bullets) are not sources of
emissions. Emissions from storage/equalization tanks occur as a result of displacement
of headspace vapor during filling operations in the case of fixed roof and internal floating
roof tanks or from tank rim seals in the case of external floating roof tanks (i.e., “working
losses”). To a lesser degree, diurnal temperature variations and solar heating cycles also
result in emissions from storage tanks (i.e., “breathing losses”). The equipment
components (i.e., flanges, valves, and tank seals) associated with each tank are
considered to be sources of fugitive VOC emissions and will be controlled as part of the
facility’s leak detection and repair (LDAR) program. As shown in Error! Reference
source not found., breathing losses from the internal floating roof tanks will be directed
to the VOC control system which includes a thermal incinerator. The tanks used to store
the emergency diesel engine fuel will be vented to carbon canisters.
As shown, ethylene storage will comprise two ethylene storage vessels and an
atmospheric refrigerated storage tank. As part of the site’s waste gas minimization plan,
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Table 3-1. Summary of Project Tanks and Vessels
Service Tank/Vessel Description No. Equipment ID Capacity
(m3) VOC
Ethylene Spherical Pressure Vessel 2 V-64201, V-64202 7,238
Ethylene Atmospheric Refrigerated 1 1 T-64201 30,000
C3+(propane and heavier hydrocarbons) Spherical Pressure Vessel 2 V-64205, V-64206 2,300
Butene Spherical Pressure Vessel 2 V-64301, V-64302 1,200
Isopentane Horizontal Pressure Vessel 2 V-64401, V-64402 600
Isobutane Horizontal Pressure Vessel 2 V-64501, V-64502 200
C3+ Refrigerant Horizontal Pressure Vessel 1 V-64203 300
Pyrolysis Tar Heated Cone Roof 2 1 T-64201 130
Light Gasoline Internal Floating Roof 3 2 T-64207, T-64208 650
Hexene Internal Floating Roof 4 2 T-64301, T-64302 2,300
Recovered Oil Storage 8 Internal Floating Roof 5 1 T-59708 90
Flow Equalization Wastewater 8 Internal Floating Roof 5 2 T-59707A, T-59707B 2,810
Biotreater Aeration 8 Tank 5 1 T-59709 5,210
Secondary Clarifier 8 Tank 2 T-59710A, T-59710B 1,466
Biosludge (WAS) Holding 6, 8 Tank 1 T-59711 43
Sand Filter Backwash Receiver 8 Tank 1 T-59713 143
Spent Caustic Internal Floating Roof 5 2 T-53501, T-53502 900/8,630 7
Aqueous Ammonia Pressure Vessel 2 V-59601, V18835 91/114
Fresh Caustic Cone Roof 1 T-64701 300
Generator Diesel Fixed Roof 2 4 T-58901A, T-58901B, T-
58901C, T-58901D 38
Fire Pump Diesel Fixed Roof 2 3 T-59101A, T-59101B, T-59101C 7
Locomotive Diesel Fixed Roof 2 1 T-4000 38
Sulfuric Acid Cone Roof 2 T-53503A, T-53503B 150
Dimethyl disulfide (DMDS)4 Pressure Vessel 1 V-18831 25
Demineralized Water Storage Cone Roof 2 T-59601A, T-59601B 4,100
SAC Resin Maintenance Open Top 1 T-59603 18
WBA and SBA Resin Maintenance Open Top 1 T-59604 15
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Service Tank/Vessel Description No. Equipment ID Capacity
(m3) VOC
Suspect Condensate Storage Cone Roof 1 T-58201 3,120
Normally Clean Condensate Storage Cone Roof 1 T-58202 10,670
Primary Raw Water Clarifier Open Top 2 T-59301A, T-59301B 5,080
Clearwells for Clarifier Open Top 2 T-59302A, T-59302B 300
RW Sludge Holding Open Top 1 T-59304 150
Reclaim Water Cone Roof 1 T-59306 520
Filtered Water Storage Cone Roof 2 T-59303A, T-59303B 13,650
Potable Water Storage Cone Roof 1 T-59501 90
1. Emergency release to atmospheric refrigeration tank flare
2. Tank vapors vented to carbon canister
3. Tank vapors vented to LP Thermal Incinerator
4. Includes nitrogen blanketing. Tank vapors vented to LP Thermal Incinerator
5. Tank vapors vented to Spent Caustic Vent Incinerator
6. WAS = Waste Activated Sludge
7. Two spent caustic scenarios
8. Included as part of the WWTP (see Section 3.5.6)
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these tanks will be managed such that there is available storage space to accommodate an
off-spec product incident and recycle this material back as feed to the furnaces for
reprocessing.
3.5.3 Product Loading
Rail Loading: PE pellet loading will be the primary operation followed by C3+ and
light gasoline loading operations. Hopper cars will be gravity loaded with PE pellets
from the loading silos using a loading arm. The C3+ will be loaded into pressurized
railcars. Three types of emissions may result from this operation: 1) fugitive component
related VOC emissions and 2) emissions resulting from connecting and disconnecting the
loading hoses and 3)particulate emissions resulting from loading of polyethylene pellets.
Some of the raw materials used to manufacture PE and caustic will be offloaded at the
railcar rack. There will be six (6) spots for hydrocarbon and one for caustic offloading
from railcars.11 Any emissions associated with offloading of hydrocarbon will be
controlled via the emission controls located on the receiving tanks. Fugitive emissions
components (i.e., valves and flanges) will be controlled through the facility’s LDAR
program.
Truck Loading: Pitch will be loaded into drums and trucked from the site. Spent
caustic will either be oxidized and sent to the waste water treatment plant (WWTP) or
shipped via truck from the site. PE pellets will be transported from the site via truck.
The pellets will be conveyed from the homogenization silos to the loading silos. PE
pellets will be either gravity loaded directly from the silos or conveyed loaded into
trucks. A separate truck loading rack will be built for pyrolysis tar loading. This rack
will be designed with a single loading arm.
11 Offloading means that materials are being brought into the facility
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3.5.4 Cooling Towers
Two counter-flow mechanical draft recirculating cooling water towers (CWT) will be
constructed at the site to provide cooling water. A twenty-six (26) cell cooling tower will
be used to provide cooling water for the process units and another four (4) cell tower will
support the Cogen Units. Clarified, multimedia-filtered water will be used as makeup to
account for the cooling water that is lost due to evaporation and blowdown. The
blowdown will be directed to the wastewater treatment plant (WWTP). The process unit
cooling tower will be sized for a flow of 57,000 tonnes/hr (metric) and the Cogeneration
Plant tower will be sized for a flow of 10,000 tonnes/hr. The cooling towers will be a
source of particulate and VOC emissions. Particulate is formed when the water portion
of the cooling tower’s mist evaporates and the dissolved solids agglomerate to form
particulate. The VOC that may be emitted by a cooling tower are the result of
hydrocarbon leakage from heat exchangers.
Cooling tower particulate emissions will be controlled through the use of a high
efficiency demister and VOC emissions will be controlled by monitoring for VOC in the
cooling tower inlet water.
3.5.5 VOC Control Systems (Flares and Incinerators)
The proposed Project includes four header systems that will be used to gather and control
VOC emissions during normal operation, startup, shutdown, and unforeseeable events at
the facility as follows:
High Pressure (HP) Header System,
Low Pressure (LP) Header System,
Refrigerated Storage Relief System, and
Spent Caustic Vent Incinerator.
The HP Header system will be used to control VOC emissions resulting from startup,
shutdown, maintenance, and unforeseeable relief at the ethane cracking unit. Similar
vents will be routed to this system from the polyethylene units. This system will have a
total relieving capacity of 1500 tons/hr. The HP Header system comprises two ground
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flares (HP ground flares), each rated at 150 tons/hr, one elevated flare (HP elevated
flare), rated at 1200 tons/hr, and ancillary equipment such as knockout pots. The HP
elevated flare will be a secondary system used only when the combined capacities of the
two HP ground flares is exceeded due to an emergency (e.g., power failure). The HP
elevated flare will be steam assisted. The two HP ground flares will be unassisted.
All of the continuous and intermittent vents prior to and including the Product Purge Bin
at the gas phase technology PE units and prior to the Degasser at the slurry technology
PE unit and the tank emission control systems will be routed to the Low Pressure (LP)
Header system, which will include a thermal incinerator (i.e., LP Thermal Incinerator)
and a ground flare (LP Ground Flare). This system will be designed to handle a total
relieving capacity of 57 tons/hr. During normal operation, the gases in this system will
be directed to the LP Thermal Incinerator where they will be combusted. The rated
capacity of the LP Thermal Incinerator will be 12 tons/hr. When the amount of gas in the
system exceeds the capacity of the LP Thermal Incinerator, the excess gas in the system
will be directed to the LP Ground Flare. The rated capacity of the LP ground flare will
be 45 tons/hr. The LP ground flare will be unassisted.
The Ethylene Refrigerated Atmospheric Storage Header system will be used as follows:
1) during the initial start-up of the facility while nitrogen is being removed from the
ethylene storage tanks, 2) following inspections of the ethylene storage tanks, and 3) for
emergency relief from the ethylene storage tanks. This system will be sized for
22 tons/hr of relieving capacity and will be comprised of an elevated flare.
There will be an additional thermal incinerator (Spent Caustic Vent Incinerator) installed
as part of the spent caustic system. The Spent Caustic Vent Incinerator will be used to
control VOC and reduced sulfur compound emissions in the Spent Caustic Oxidation unit
offgas and from the Wastewater Treatment Plant’s (WWTP’s) flow equalization and oil
removal tank vents. This incinerator will be rated for 8 tons/hr. The Spent Caustic Vent
Incinerator will have an approximate average annual heat release rate of 10 MMBtu/hr.
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The flares and incinerators will emit combustion pollutants: SO2, NOx, PM/PM10/PM2.5,
CO, VOC and HAP. Control of these emissions will be accomplished by operating the
facility in accordance with a waste gas minimization plan. In addition, the flares will be
operated to ensure that the flares are operated in accordance with a net heating value in
the combustion zone limit.
3.5.6 Wastewater Treating
The Wastewater Treatment Plant (WWTP) will consist of primary flow equalization and
oil removal, followed by a secondary activated sludge bioreactor (including clarifiers),
and a tertiary sand filter to treat the wastewater streams from process units and potentially
contaminated storm water runoff from process paved areas. Several wastewater streams
from the facility, including those streams containing VOC, will flow into one of two
Flow Equalization and Oil Removal (FEOR) tanks. Each tank will be a fixed roof tank
equipped with an internal floating roof vented to the Spent Caustic Vent Incinerator. Oil
rising to the top of these tanks will be skimmed off and will flow to a recovered oil
holding tank for off-site disposal. The Recovered Oil Tank will be a fixed roof tank
equipped with an internal floating roof vented to the Spent Caustic Vent Incinerator.
Effluent from the FEOR tanks will then be routed to the Biotreater Aeration Tank.
Internal WWTP recycle streams will also flow into this tank, as well as small nutrient
additive and pH adjustment streams. Biotreater effluent will flow to two Secondary
Clarifier Tanks. The clarifiers’ overflow stream will be pumped through a Sand Filter.
Clarifier underflow will be pumped to a biosludge holding tank that will feed a centrifuge
used for concentrating clarifier solids into a cake. Cooling tower blowdown will be
pumped directly to the Sand Filter. Effluent from this filter will be discharged through an
outfall to the Ohio River. Sand filter backwash will be pumped into a tank and will be
recycled back to the Biotreater Aeration Tank.
Internal WWTP recycle streams that will be pumped to the Biotreater Aeration Tank
include:
Centrifuge centrate from the biosludge plant
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Return activated sludge
Sand filter backwash
The WWTP will be a source of VOC emissions. Emissions will be controlled by venting
the Recovered Oil Storage and Equilization Wastewater tanks to the Spent Caustic
Incinerator.
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4.0 Air Regulatory Requirements
This section addresses the applicability of Pennsylvania and Federal air quality
regulations to the proposed Project. A complete review was performed of the
Pennsylvania regulations and Federal regulations, including New Source Review
(NSR),12 New Source Performance Standards (NSPS), National Emissions Standards for
Hazardous Air Pollutants (NESHAP), and other federal rules. The results of this review
are documented herein identifying the State and Federal regulations applicable to the
Project. A full and complete listing of affected emission units and citations for the
requirements of compliance and recordkeeping and reporting is provided in
Appendix G.13
4.1 Pennsylvania Air Pollution Control Regulations
The Commonwealth of Pennsylvania has promulgated ambient air quality standards and
pollution control regulations under Title 25 of the Pennsylvania Code.14 The proposed
Project is subject to the Title 25 Code Pennsylvania Chapters 121 through 145. The
specific applicability of each of these regulations in Chapters 121 through 145, and how
Shell will address these requirements is presented below. The applicable requirements
that will be discussed in this section are summarized in Table 4-1.
4.1.1 25 Pa. Code Ch. 121. General Provisions
This chapter provides for the control and prevention of air pollution anywhere in the
Commonwealth of Pennsylvania. Included in this chapter are definitions, purpose,
applicability, organization of the Department of Environmental Quality (Department), the
12 New Source Review includes the Prevention of Significant Deterioration (PSD) review for attainment
pollutants, non-attainment (NA) review for non-attainment pollutants, and minor source review for
pollutants that are less than the applicable threshold values for PSD and NA review. 13 A number of the unit designations in this table constitute trade secret and/or confidential proprietary
information as defined under the Pennsylvania Right to Know Law, and hence the full table is being
provided in Appendix D. 14 The Pennsylvania Code is an official publication of the Commonwealth of Pennsylvania. Title 25.
Environmental Protection; Subpart C. Protection of Natural Resources; Article III. Air Resources;
Chapters 121 – 145.
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Table 4-1. Summary of Regulatory Applicability
Applicable Regulation Regulatory Applicability Project Subject Unit &
Pollutants
Chapter 121. General provisions
25 Pa. Code §121.1-121.10
Provides for the control and prevention of air pollution anywhere in this Commonwealth,
except as expressly excluded in the act or otherwise noted in this article. Entire Facility
Chapter 122. National Standards
of Performance for New
Stationary Sources
25 Pa. Code §122.1-122.3
Adopts NSPS regulations at 40 CFR Part promulgated by the United States
Environmental Protection Agency under the Clean Air Act (42 U.S.C.A. § § 7401—
7642), regulating the construction or modification of stationary sources.
See Table 5-2 for discussion of
applicable 40 CFR 60 – New
Source Performance Standards
Chapter 123. Standards for
Contaminants
25 Pa. Code §§123.1, 123.2,
123.11-123.12, 123.21-123.22,
123.31, 123.41, 123.46, 123.51
This chapter contains standards for sources of particulate matter, sulfur compounds,
odors, visible emissions, and nitrogen compounds. Additionally, this chapter contains
NOx allowance requirements.
See Table 4.2 below for
detailed description of Ch. 123
requirements and applicable
sources.
Chapter 124. National Emissions
Standards for Hazardous Air
Pollutants
25 Pa. Code §§124.1-124.3
Adopts National Emission Standards for Hazardous Air Pollutants promulgated by the
United States Environmental Protection Agency under the Federal Clean Air Act (42
U.S.C.A. § 7412).
See Table 5-2 at 40 CFR 61 &
63 National Emissions
Standards for Hazardous Air
Pollutants
Chapter 127. Construction,
Modification, Reactivation and
Operation of Sources
Subchapter A. General
25 Pa. Code §127.1-127.3
General declaration of purposes.
Designed to insure that new sources conform to the applicable standards of this article
and that they do not result in producing ambient air contaminant concentrations in excess
of those specified in Chapter 131 (relating to ambient air quality standards).
New sources shall control the emission of air pollutants to the maximum extent,
consistent with the best available technology as determined by the Department as of the
date of issuance of the plan approval for the new source.
Entire Facility - applies to
Criteria and Hazardous Air
Pollutants
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Applicable Regulation Regulatory Applicability Project Subject Unit &
Pollutants
25 Pa. Code §127.3 Provides for operational flexibility, with cross-reference to other provisions Entire facility
Chapter 127. Construction,
Modification, Reactivation and
Operation of Sources
Subchapter B. Plan Approval
Requirements
25 Pa. Code §127.11-127.52
Requires Department approval of the construction or modification of an air
contamination source, the reactivation of an air contamination source after the source has
been out of operation or production for 1 year or more, or the installation of an air
cleaning device on an air contamination source, unless the construction, modification,
reactivation or installation has been approved by the Department.
Entire Facility
25 Pa. Code §127.12(a)
Show that source to be equipped with reasonable and adequate facilities to monitor and
record emissions of air contaminants
Emissions from new source must be minimum attainable through use of the best
available technology (PaBAT)
Show source will comply with applicable EPA requirements
Show that source and air cleaning devises will be operated and maintained in accordance
with good air pollution control practices
All emission sources at facility
Chapter 127. Construction,
Modification, Reactivation and
Operation of Sources
Subchapter B. Plan Approval
Requirements
25 Pa. Code §127.35
Incorporates by reference performance or emission standards promulgated under section
112 of the Clean Air Act (42 U.S.C.A. § 7412) at 40 CFR Part 63 (relating to National
Emission Standards for Hazardous Air Pollutants for Source Categories). If the
Administrator of the EPA has not promulgated a standard to control the emissions of
HAPs for a category or subcategory of major stationary sources Clean Air Act §112(c),
the Department will establish a performance or emission standard on a case-by-case
basis for individual sources or a category of sources for those major stationary sources.
The Department has the authority to require, in the plan approval, reasonable monitoring,
recordkeeping and reporting requirements for sources which emit hazardous air
pollutants.
Combustion Turbines - HAP,
Part 63, Subpart YYYY
(stayed)
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Applicable Regulation Regulatory Applicability Project Subject Unit &
Pollutants
Chapter 127. Construction,
Modification, Reactivation and
Operation of Sources
Subchapter D. Prevention of
Significant Deterioration of Air
Quality
25 Pa. Code §§127.81-127.83
Adopts by cross-reference Prevention of Significant Deterioration (PSD) requirements
promulgated by the USEPA under the Clean Air Act.
Entire Facility - CO, PM,
PM10, and GHGs
Chapter 127. Construction,
Modification, Reactivation and
Operation of Sources
Subchapter E. New Source
Review
25 Pa. Code §§127.201-218
Provides for regulation of construction or modification of an air contamination facility in
a nonattainment area or have an impact on a nonattainment area, imposing LAER and
offset requirements
Entire Facility - NOx, VOC,
PM2.5
25 Pa. Code §127.205(5)
Requires that a major new facility provide an analysis of alternative sites, sizes,
production processes and environmental control techniques, which demonstrates that the
benefits of the proposed facility significantly outweigh the environmental and social
costs imposed within this Commonwealth as a result of its location, construction or
modification.
Entire facility. See
Appendix E for the related
analysis.
Chapter 127. Construction,
Modification, Reactivation and
Operation of Sources
Subchapter G. Title V Operating
Permits
25 Pa. Code §127.502(a)
Operating permit requirements for major sources (Title V facilities), requiring that
applicable requirements for stationary air contamination sources in the Title V facility be
included in the operating permit.
Entire Facility - All regulated
pollutants
Chapter 127. Construction,
Modification, Reactivation and
Operation of Sources
Subchapter J. General Conformity
25 Pa. Code §§127.801-127.802
Adopts the general conformity rule promulgated by the United States Environmental
Protection Agency under section 176(c) of the Clean Air Act (42 U.S.C.A. § 7506(c))
and the regulations codified at 40 CFR Part 93, Subpart B (relating to determining
uniformity of general Federal actions to state or Federal implementation plans), with
respect to the conformity of general Federal actions to the Commonwealth’s State
Implementation Plan.
Entire Facility - All regulated
pollutants
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Applicable Regulation Regulatory Applicability Project Subject Unit &
Pollutants
Chapter 129. Standards for
Sources
25 Pa. Code §§129.51, 129.56,
129.57, 129.65, 129.71, 129.91-
129.95
This chapter contains emission standards for VOCs and NOx for numerous emission
sources including storage tanks, ethylene production, SOCMI manufacturing, and
combustion units.
VOCs and NOx from: Storage
tanks, ethylene production,
SOCMI manufacturing, and
combustion units
Chapter 129. Standards for
Sources
25 Pa. Code §129.56. Storage
tanks greater than 40,000 gallons
capacity containing VOCs.
No person may permit the placing, storing or holding in a stationary tank, reservoir or
other container with a capacity greater than 40,000 gallons of volatile organic
compounds with a vapor pressure greater than 1.5 psia (10.5 kilopascals) under actual
storage conditions unless the tank, reservoir or other container is a pressure tank capable
of maintaining working pressures sufficient at all times to prevent vapor or gas loss to
the atmosphere or is designed and equipped with an appropriate device.
Facility Storage Tanks storing
VOCs
Chapter 129. Standards for
Sources
25 Pa. Code §129.57. Storage
tanks less than or equal to 40,000
gallons capacity containing
VOCs.
Applies to above ground stationary storage tanks with a capacity equal to or greater than
2,000 gallons that contain volatile organic compounds with vapor pressure greater than
1.5 psia (10.5 kilopascals) under actual storage conditions. Petroleum liquid storage
vessels that are used to store produced crude oil and condensate prior to lease custody
transfer are exempt from the requirements.
Facility Storage Tanks storing
VOCs
Chapter 129. Standards for
Sources
25 Pa. Code §129.65. Ethylene
production plants.
Waste gas stream from an ethylene production plant or facility must be properly burned
at no less than 1,300°F for at least 0.3 seconds; except that no person may permit the
emission of volatile organic compounds in gaseous form into the outdoor atmosphere
from a vapor blowdown system unless these gases are burned by smokeless flares.
Ethane Cracker/Fractionation-
VOCs
Chapter 129. Standards for
Sources
25 Pa. Code §129.71. Synthetic
organic chemical an d polymer
manufacturing—fugitive sources
Requires certain design, equipment and leak detection program requirements, applicable
to surface active agent manufacturing facilities subject to § 129.72 and to a facility with
design capability to manufacture 1,000 tons per year or more of one or a combination of
the following: (1) Synthetic organic chemicals listed in 40 CFR 60.489 (relating to list of
chemicals provided by affected facilities). (2) Methyl tert-butyl ether. (3) Polyethylene.
(4) Polypropylene. (5) Polystyrene.
VOCs from
Ethane Cracking/Fractionation
Polyethylene manufacturing
Chapter 129. Standards for
Sources
25 Pa. Code §§129. 91-129.95.
Stationary Sources of NOx and
VOCs
Establishes reasonably available control technology (RACT) requirements for major
NOx emitting facilities or major VOC emitting facilities for which no RACT
requirement has been established.
NOx & VOC emissions from
combustion sources,
equipment leaks, wastewater
treating plant, transfer
operations, and process vents.
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Applicable Regulation Regulatory Applicability Project Subject Unit &
Pollutants
Chapter 131. Ambient Air Quality
Standards
25 Pa. Code §§ 131.1 - 131.3
Establishes the maximum ambient air concentrations of air contaminants. Adopts by
cross-reference National Ambient Air Quality Standards. Adopts additional ambient
standards for settled particulate, beryllium, fluorides, and hydrogen sulfide.
Entire Facility - CO, SO2,
NO2, PM, PM10, PM2.5, Ozone,
lead, beryllium, fluorides, and
hydrogen sulfide
Chapter 135. Reporting of
Sources
25 Pa. Code §§ 135.1-135.5
Provides for recordkeeping and submission of emission statements from most stationary
sources.
Entire Facility - all regulated
pollutants
Chapter 137. Air Pollution
Episodes
25 Pa. Code §137.1-137.14
Provides for Department determination of air pollution episodes and requires preparation
and submission of standby plans for certain industries including chemical and allied
products industries, located in counties designated by PaDEP.
Entire Facility - CO, SO2,
NO2, PM10 and Ozone
Chapter 139. Sampling and
Testing
25 Pa. Code §§139.1-139.101
Establishes the sampling and testing methods and procedures, monitoring duties for
certain sources, and requirements for source monitoring for stationary sources.
Entire Facility - all regulated
pollutants
Chapter 145. Interstate Pollution
Transport Reduction
25 Pa. Code §145.8
Establishes provisions for the NOx Budget Trading Program as a means of mitigating the
interstate transport of ozone and nitrogen oxides, an ozone precursor. § 145.8 transitions
the state program over to CAIR as of 2010.
NOx: Cogen Units
Chapter 145. CAIR NOx and
SO2 Trading Programs
25 Pa. Code § 145.201
Incorporates by reference the CAIR NOx Annual Trading Program and CAIR NOx
Ozone Season Trading Program. The subchapter also establishes general provisions and
the applicability, allowance and supplemental monitoring, recordkeeping and reporting
provisions.
SO2: Cogen Units
NOx: Cogen Units
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prohibition of air pollution, responsibility to comply with other provisions of Title 25,
and prohibiting the circumvention of Article III rules through the use of a device (e.g.,
stack height) which would otherwise be in violation of Article III rules. The proposed
Project will comply with these provisions by obtaining all applicable permits, and
complying with the requirements of these permits.
4.1.2 25 Pa. Code Ch. 122 National Standards of Performance for New Stationary Sources
This chapter adopts NSPSs (40 CFR Part) promulgated by the United States
Environmental Protection Agency under the Clean Air Act (42 U.S.C.A. § § 7401-7642),
regulating the construction or modification of stationary sources. The standards are
adopted to make them independently enforceable by the Department implementing the
delegation of Federal authority under section 111(c) of the Federal Clean Air Act
(42 U.S.C.A. § 7411). The applicability of these standards is addressed in Section 4.2.
4.1.3 25 Pa. Code Ch. 123. Standards for Contaminants
This chapter contains standards for sources of particulate matter, sulfur compounds,
odors, visible emissions, nitrogen compounds, and NOx allowance requirements. As
presented in Table 4-2, sources that are specifically affected include: fugitive particulate
matter sources, combustion units, incinerators, and processes vents. The Project’s
emission sources that are affected by this chapter include the incinerators, flares,
furnaces, combustion turbines, process vents, and loading emissions. The proposed
Project will comply with the provisions in this chapter as presented in Table 4-2.
4.1.4 25 Pa. Code Ch. 124. National Emissions Standards for Hazardous Air Pollutants
This chapter adopts NESHAPs at 40 CFR Part 61 and 63 promulgated by the United
States Environmental Protection Agency under the Federal Clean Air Act (42 U.S.C.A. §
7412). The applicability of these standards is addressed in Section 4.2
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Table 4-2. Summary of Compliance with the Standards of Containment at 25 Pa.Code Ch. 123.
Standards for
Contaminants Affected Source(s) Regulatory Requirement Compliance
25 Pa Code § 123.1
Prohibition of certain
fugitive emissions
Fugitive sources of air
contaminants other than those
allowed in § 123.1 (i.e.,
construction activities, grading,
clearing of land, et. al).
Fugitive air emissions prohibited
except for certain listed sources and
emissions determined to be of minor
significance after appropriate
controls.
Emissions do not prevent or interfere
with attainment or maintenance of
ambient air quality standard.
Best management practices to be
followed for construction, demolition,
grading, paving and maintenance of
roads, and other activities.
Fugitive VOCs and particulate from
processes subject to controls, and are of
minor significance after controls.
Fugitives are included in the potential to
emit determination. Therefore the
impacts of fugitives with respect to air
pollution are considered in the New
Source Review. See Section 5.0
25 Pa Code § 123.2
Fugitive particulate
matter
All fugitive PM sources No fugitive particulate emissions
visible outside the property boundary
Fugitive PM emissions to be minimized
as presented in Section 5.0 to prevent
visibility outside the property boundary.
25 Pa Code § 123.11
PM - Combustion units Combustion Units
Emission limits on PM for various
sized units See Section 5.0
25 Pa Code § 123.12
PM – Incinerators Incinerators 0.1 grain/dscf @ 12% CO2
25 Pa Code § 123.13
PM – Processes
Processes except combustion
units and incinerators
Emission limit on PM by formula or
0.02 grains/dscf whichever is greater
25 Pa Code § 123.21
Sulfur Compound -
General
Combustion Units 500 ppmvd effluent gas limit
25 Pa Code § 123.22(d)
Sulfur Compound –
Combustion Units
Combustion Units Specific fuel dependent Lower Beaver
Valley limit on SO2
25 Pa Code § 123.31
Odor Emissions
Combustion Units, Process
Vents, Fugitives
No malodors detectable outside the
property boundary
Emissions will be minimized to avoid
detectable malodors outside the
property boundary
25 Pa Code § 123.41
Visible Emissions
Combustion Units, Fugitive
Sources of PM Visible emissions/opacity limitations
Visible emissions will be minimized as
presented in Section 5.0 to comply with
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Standards for
Contaminants Affected Source(s) Regulatory Requirement Compliance
opacity limits.
25 Pa Code § 123.46
Visible Emissions
Monitoring Requirements
Combustion Units Continuous opacity monitors Per 123.46(c), Shell will apply for an
exemption from this requirement
25 Pa Code § 123.51
Nitrogen Compound Combustion Units Continuous NOx monitoring See Section 5.0
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4.1.5 25 Pa. Code Ch. 127. Construction, Modification, Reactivation and Operation of Sources
This chapter contains the regulations applicable to construction, modification,
reactivation, and operation of applicable sources.
4.1.5.1 25 Pa. Code §§ 127.1 and 127.12 Best Available Technology
In stating the purpose of the Ch. 127 rules, Section 127.1 states the objective of
maintaining at existing levels in areas where the existing ambient air quality is better than
the applicable ambient air quality standards, and improving to achieve the applicable
ambient air quality standards in areas where the existing air quality is worse than the
applicable ambient air quality standards. The Ch. 127 rules require new sources conform
to the applicable standards and not result in producing ambient air contaminant
concentrations in excess of those specified in Chapter 131 (relating to ambient air quality
standards). These requirements are substantially addressed via PSD requirements.
Sections 127.1 and 127.12(a)(5) require that new sources control emission of air
pollutants to the maximum extent, consistent with the best available technology as
determined by the Department as of the date of issuance of the plan approval for the new
source. Shell will comply with the best available technology requirements where
applicable for all pollutants.
4.1.5.2 25 Pa. Code § 127.35 Maximum Achievable Control Technology Standards for Hazardous Air Pollutants (HAP)
Section 127.35 establishes the process that the Department will follow in establishing
maximum achievable control technology (MACT) standards in plan approvals.
Regulations promulgated under section 112 of the Clean Air Act (42 U.S.C.A. § 7412) at
40 CFR Part 63 are incorporated by reference into the plan approval program. These
standards regulate specific categories of stationary sources that emit or have the potential
to emit 10 tons per year of any HAP or 25 tons per year of any combination of HAP. As
presented in Table 1-1, HAP emissions from the proposed Project will exceed a
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combined 25 tons per year, rendering the Project a major source for HAP. NESHAP
standards applicable to the Project’s affected sources are presented in Section 4.2.2.
25 Pa. Code § 127.35(c) states that if the EPA has not promulgated a standard to control
emissions of hazardous air pollutants (HAP) from a category or subcategory of major
stationary sources under CAA Section 112 pursuant to the schedule established under
CAA Section 112(c), the Department will establish standards on a case-by-case basis as
required by section 112(g) of the CAA. These standards are to be incorporated into the
plan approval of each source within the category for which a MACT requirement has
been established. In essence, 25 Pa. Code §127.35(d) implements the Clean Air Act
Section 112(g) case-by-case MACT rule.
For the Project’s proposed natural gas-fired combustion turbines, EPA has promulgated a
MACT standard for stationary combustion turbines, (40 CFR 63 Subpart YYYY) which
would potentially regulate HAP emissions from these units. However, on April 7, 2004,
EPA published in the Federal Register a proposal to delist the gas-fired subcategory from
the source category list. On August 18, 2004, EPA published a final rule staying the
effectiveness of 40 CFR 63, Subpart YYYY for this subcategory of source. As a result, a
Case-by-Case MACT for this subcategory is not required because EPA did promulgate a
standard pursuant to the schedule established under section 112(c) of the Clean Air Act.
The now stayed provisions of Part 63 Subpart YYYY establish limits for
formaldehyde. Using the provisions of 25 Pa. Code § 127.12b, the formaldehyde limits
contained in Part 63 Subpart YYYY (91 ppmvd @ 15% O2) and the use of an oxidation
catalyst have been proposed for this Plan Approval application. As presented in Table 2
in Subpart YYYY of 40 CFR 63, for a stationary combustion turbine using an oxidation
catalyst, the owner/operator must maintain the 4-hour rolling average of the catalyst inlet
temperature within the range suggested by the catalyst manufacturer to demonstrate
continuous compliance with the emissions limit. These conditions also assure the proper
operation to meet the PaBAT provisions of 25 Pa. Code § 127.1 and § 127.12(a)(5).
Shell will comply with this requirement and other monitoring and recordkeeping
requirements associated with Part 63 Subpart YYYY as discussed in Section 4.2.3.
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4.1.5.3 25 Pa. Code § 127.83 Prevention of Significant Deterioration
Section 127.83 of the Pennsylvania air quality regulations adopts by reference the
Prevention of Significant Deterioration (PSD) requirements promulgated in 40 CFR 52
by the Administrator of the EPA under section 161 of the Clean Air Act (42 U.S.C.A. §
7471) in their entirety. In accordance with the PSD requirements, the proposed Project
belongs to a listed source category (chemical processing plant) and has potential
emissions of greater than 100 tons per year of a PSD regulated pollutant; thus, it is
subject to the PSD rules codified at 40 CFR 52.21. For a new source such as the
proposed Project, the source must estimate the potential to emit for the NSR pollutants
(CO, NO2/NOx, VOC, SO2, H2SO4, PM/PM10/PM2.5, and Pb) and CO2e. 15 If the
potential to emit for one or more NSR regulated pollutants is found to be significant
(greater than 100 tons per year) or the amount of CO2e emitted is greater than 100,000
tons per year and the amount of GHGs is greater than 100 tons per year, the source must
undergo PSD review, which includes applying Best Available Control Technology
(BACT), demonstrating compliance with air quality standards, assessing secondary
impacts, and undergoing public participation for each pollutant for which there is a
significant increase.
As documented in Section 1.0, the proposed Project constitutes a major new source under
PSD (emissions of at least one NSR regulated pollutant exceed the 100 tons per year
major source threshold), and the following pollutants have potential to emit greater than
their pollutant specific PSD significance thresholds: NO2, PM/PM10, CO, and GHG. As
such, project related emissions of these pollutants require PSD review. Shell will comply
with the requirements of this Part by documenting BACT analyses for each affected
emissions unit/pollutant combination, demonstrating compliance with air quality
standards, assessing secondary impacts, and undergoing public participation.
15 The Project will not emit quantities of the other NSR pollutants, which include hydrogen sulfide, total
reduced sulfur compounds, fluorides, and beryllium.
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4.1.5.4 25 Pa. Code § 127.201 New Source Review
Ch. 127, Subchapter E, (25 Pa. Code §§127.201-127.218) contains the nonattainment
NSR regulations incorporated into the Pennsylvania air quality regulations in accordance
with the federal requirements at 40 CFR §51.165. Nonattainment NSR applies to new
major sources or major modifications at existing major stationary sources for pollutants
where the area the source is located in is not in attainment with the National Ambient Air
Quality Standards (NAAQS). All nonattainment NSR programs must require (1) the
installation of the lowest achievable emission rate (LAER), (2) emission offsets, (3)
alternative sites evaluation, and (4) opportunity for public involvement.
Currently Beaver County, Pennsylvania is nonattainment for ozone, PM2.5, and SO2.
Ozone has defined precursors of VOC and NOx. PM2.5 has defined precursors of SO2
and NOx. As documented in Section 1.0, the proposed Project’s potential to emit is
greater than the major source threshold for NOx, VOC, and PM2.5. As a result, Shell will
comply with all the requirements listed above for obtaining a nonattainment NSR permit
for ozone (NOx and VOC) and PM2.5.
4.1.5.5 25 Pa. Code §127.205(5) Alternatives, Costs and Benefits Analysis
Pennsylvania air regulations, 25 Pa. Code §127.205(5), require that a major new or
modified facility provide an “analysis … of alternative sites, sizes, production processes
and environmental control techniques, which demonstrates that the benefits of the
proposed facility significantly outweigh the environmental and social costs imposed
within this Commonwealth as a result of its location, construction or modification.”
Appendix E of this application provides the required §127.205(5) analysis.
4.1.6 25 Pa. Code Ch.129. Standards for Sources
Chapter 129 contains regulations for specific sources and emissions units which emit
NOx and VOCs. The proposed Project will comply with the provisions in this chapter by
obtaining all applicable permits and complying with the requirements of these permits.
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4.1.6.1 25 Pa. Code § 129.14 Open burning operations
The proposed Project will be located in an area of Beaver County designated in § 121.1
as an air basin, which pursuant to 25 Pa. Code § 129.14, has a restriction on open
burning. Open burning is defined in 25 Pa. Code § 121.1 as a fire, the air contaminants
from which are emitted directly into the outdoor atmosphere and not directed thereto
through a flue. As part of the proposed Project, triethylaluminum (TEAL) and
triethylborane (TEB) will be used as cocatalysts in the polyethylene manufacturing
process. TEAL and TEB are highly pyrophoric, igniting immediately upon exposure to
air. During routine cocatalyst transfer and process upsets, the lines containing these
pyrophoric materials in nitrogen will be routed to a remote sand pit for safe, managed
destruction. These releases cannot be sent to the VOC Control System due to the oxygen
in the gases from other sources vented to the system.
Sending the TEAL and TEB vapors to the sand pit meets the exception to the open
burning ban in the air basin as it is a fire set to abate a fire hazard per § 129.14(c). Shell
requests the Department approve this exception. The sand pit will be fenced, weather-
protected, and accessed by authorized personnel only.
4.1.6.2 25 Pa. Code § 129.56. Storage tanks greater than 40,000 gallons capacity containing VOCs.
Section 129.56 requires that any stationary tank, reservoir or other container with a
capacity greater than 40,000 gallons used to store volatile organic compounds with a
vapor pressure greater than 1.5 psia (10.5 kilopascals) under actual storage conditions be
a pressure tank capable of maintaining working pressures sufficient at all times to prevent
vapor or gas loss to the atmosphere or be designed and equipped with an appropriate
device:
An external or an internal floating roof. This control equipment is not permitted if
the volatile organic compounds have a vapor pressure of 11 psia (76 kilopascals) or
greater under actual storage conditions.
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Vapor recovery system. A vapor recovery system, consisting of a vapor gathering
system capable of collecting the volatile organic compound vapors and gases
discharged and a vapor disposal system capable of processing such volatile organic
vapors and gases so as to prevent their emission to the atmosphere. Tank gauging
and sampling devices shall be gas-tight except when gauging or sampling is taking
place. The vapor recovery system shall be maintained in good working order and
recover at least 80% of the vapors emitted by such tank.
The Project will have a number of tanks containing volatile organic compounds with a
vapor pressure greater than 1.5 psia, such as 1-hexene, pentane, and gasoline. These
tanks will be equipped with controls that will, at a minimum, meet the requirements of
this section and meet lowest achievable emission rates (LAER) requirements.
4.1.6.3 25 Pa. Code § 129.57. Storage tanks less than or equal to 40,000 gallons capacity containing VOCs.
The provisions of this section apply to above ground stationary storage tanks with a
capacity equal to or greater than 2,000 gallons but less than 40,000 gallons, that contain
volatile organic compounds with vapor pressure greater than 1.5 psia (10.5 kilopascals)
under actual storage conditions. Storage tanks subject to this section must have pressure
relief valves which are maintained in good operating condition and which are set to
release at no less than 0.7 psig (4.8 kilopascals) of pressure or 0.3 psig (2.1 kilopascals)
of vacuum or the highest possible pressure and vacuum in accordance with state or local
fire codes or the National Fire Prevention Association guidelines or other national
consensus standards acceptable to the Department. Section 129.56(g) requirements also
apply to these smaller tanks. If the Project has any of these tanks, they will be equipped
with controls that at a minimum will meet the requirements of this section and will meet
LAER requirements.
4.1.6.4 25 Pa. Code § 129.65. Ethylene production plants.
Section 129.65 requires that waste gas streams from an ethylene production plant or
facility be properly burned at no less than 1,300°F for at least 0.3 seconds; except that
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emission of volatile organic compounds in gaseous form into the outdoor atmosphere
from a vapor blowdown system may be burned by smokeless flares. The Project’s
Ethane Cracker and distillation section will be equipped with the above controls or
equivalent and will meet LAER requirements.
4.1.6.5 25 Pa. Code § 129.71. Synthetic organic chemical and polymer manufacturing—fugitive sources
This section applies to synthetic organic chemicals listed in 40 CFR 60.489, which
includes ethylene. As such, the Project will:
Install a second valve, blind flange, plug, cap or other equivalent sealing system
on open ended lines, except for safety pressure relief valves.
Develop and initiate a leak detection program including liquid leaks for pumps,
valves, compressors, vessels and safety pressure relief valves and a repair
program for these components that cause a hydrocarbon detection instrument
reading equal to or greater than 10,000 ppm.
The Project will comply with the above requirements and will have a more stringent leak
detection program as part of the LAER requirements.
4.1.6.6 25 Pa. Code § § 129.91-95. Stationary Sources of NOx and VOCs
This section requires the owner and operator of a major NOx or VOC emitting facility to
apply Reasonably Available Control Technology (RACT)16. This section applies to
facilities for which no RACT requirement has been established in § § 129.51, 129.52,
129.54 - 129.72, 129.81 and 129.82. The proposed Project will be a major source for
both NOx and VOC and the NOx and/or VOC-emitting sources with no existing RACT
requirement include: combustion sources, equipment leaks, the wastewater treating plant,
organic liquid transfer operations, and process vents and storage vessels. Given that
these sources are also subject to LAER for NOx and VOC, a case-by-case RACT analysis
is not required pursuant to the presumptive RACT emission limitations set forth in 25 Pa
16 RACT is lowest emission limit for VOCs or NOx that a particular source is capable of meeting by the
application of control technology that is reasonably available considering technological and economic
feasibility per 25 Pa. Code § 121.1
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Code § 129.93(c)(6). Sources that meet the LAER requirements and install, maintain,
and operate the source in accordance with manufacturing specifications satisfy the
presumptive RACT requirement. The proposed Project will comply with this provision
by complying with the proposed LAER limitations presented in Section 5.0.
4.1.7 25 Pa. Code Ch. 131. Ambient Air Quality Standards
This chapter establishes ambient air quality standards by incorporating by reference the
National Ambient Air Quality Standards (NAAQS), and by setting State Ambient Air
Quality Standards for settled particulate, beryllium, fluorides and hydrogen sulfide. The
NAAQS are applicable to the entire facility for the emissions of CO, SO2, NO2, PM,
PM10, PM2.5, ozone, and lead. For the PSD applicable pollutants, an air quality impacts
analysis demonstrating compliance with the NAAQS is included in Section 6.0.
Based on previous conversations with PaDEP, only significant sources of beryllium,
fluorides, and hydrogen sulfide, such as coal-fired emission sources, need to conduct an
analysis against the state standards. The Project is not expected to be a significant source
of beryllium, fluorides, or hydrogen sulfide based on the fuel to be combusted at the plant
(i.e., natural gas and low sulfur diesel). As a result, these pollutants are not included in
the ambient impacts analysis. Ambient impacts of settled particulate will be assessed as
part of the PM10/PM2.5 NAAQS modeling analysis.
4.1.8 25 Pa. Code Ch. 135. Reporting of Sources
Ch. 135 provides a means of obtaining data required to evaluate the effectiveness of
regulations, identify available or potential emission offsets, and maintain an accurate
inventory of air contaminant emissions for air quality assessment and planning activities.
It requires most stationary sources to submit annual emission inventories. Shell will
comply with the requirements of this chapter initially by providing emission factors and
emissions calculations as part of this application, and thereafter, Shell will submit by
March 1 of each year a source emissions inventory report for the preceding calendar year.
The report shall include information for all previously reported sources, new sources
which were first operated during the preceding calendar year, and sources modified
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during the same period which were not previously reported. Shell will provide to the
Department source reports that contain sufficient information to enable the Department to
complete its emission inventory. Shell will provide the report information in the format
specified by the Department. As part of this report, Shell will provide the Department
with a statement showing the actual emissions of NOx and VOCs from that source for
each reporting period, a description of the method used to calculate the emissions, and the
time period over which the calculation is based. The statement will contain a certification
by a company officer or the plant manager that the information contained in the statement
is accurate.
Shell will maintain and make available upon request by the Department records,
including computerized records that may be necessary to comply with reporting and
emission statements. These may include records of production, fuel usage, maintenance
of production or pollution control equipment, or other information determined by the
Department to be necessary for identification and quantification of potential and actual
air contaminant emissions. If direct recordkeeping is not possible or practical, sufficient
records will be kept to provide the needed information by indirect means.
4.1.9 25 Pa. Code Ch. 137. Air Pollution Episodes
Ch. 137 provides for the Department to declare air pollution episodes to prevent the
excessive buildup of air pollutants during an episode. The Ch. 137 rules require that
particular industries, including chemical industry facilities, in designated counties prepare
standby plans for implementation in such episodes. Shell will develop standby plans and
will implement plans when requested by the Department.
4.1.10 25 Pa. Code Ch. 139. Sampling and Testing
This chapter contains provisions for:
Subchapter A. Sampling and Testing Methods and Procedures,
Subchapter B. Monitoring Duties of Certain Sources, and
Subchapter C. Requirements for Source Monitoring For Stationary Sources.
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Shell will follow the methods and procedures contained in this chapter as laid out in the
Project’s permit, and as directed by the Department.
4.1.11 25 Pa. Code Ch. 145. Interstate Pollution Transport Reduction
Ch. 145 establishes a NOx Budget Trading Program as a means of mitigating the
interstate transport of ozone and nitrogen oxides, an ozone precursor. Subchapter 145.8
transitions the NOx Budget Trading Program over to the CAIR NOx and SO2 Trading
Program (40 CFR Part 97) starting May 1, 2010, and for each control period thereafter.
Subchapter 145.201 incorporates by reference the CAIR NOx Annual Trading Program
and CAIR NOx Ozone Season Trading Program as a means of mitigating the interstate
transport of fine particulates and NOx, and the CAIR SO2 Trading Program as a means of
mitigating the interstate transport of fine particulates and SO2.
The proposed Cogen units will each serve a generator with nameplate capacity of more
than 25 MWe supplying in any calendar year more than one-third of the unit's potential
electric output capacity or 219,000 MWh, whichever is greater, to a utility power
distribution system for sale.
Shell will obtain NOx and SO2 budget allowances for the Cogen Units from the CAIR
NOx and SO2 Trading Program.
4.2 Federal Regulations
The applicability of Federal regulations to the Project is presented by federal rule citation
below. Table 4-3 presents a summary of the applicable Federal regulations, and the
following subsections provide additional detail.
4.2.1 40 CFR Part: New Source Performance Standards
The New Source Performance Standards (NSPS) are codified at 40 CFR 60, and adopted
by reference under Chapter 122 of the Commonwealth of Pennsylvania.
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Table 4-3. Summary of Federal Regulatory Applicability
Applicable Regulation Regulatory Applicability Project Subject Unit & Pollutants
40 CFR Part – New Source Performance Standards
Subpart A: General Provisions, except 60.18 Facilities subject to subsequent subparts of Part 60
Subpart Kb - Tanks
Subpart VV - Equipment Leaks
Subpart VVa - Equipment Leaks
Subpart DDD - Polymer Manufacturing
Subpart NNN - Distillation Process Vents
Subpart RRR - Reactor Process Vents
Subpart YYY - Wastewater (stayed)
Subpart IIII - Diesel Engines
Subpart KKKK - Combustion turbine/duct burners
Subpart TTTT – GHGs for New Electric Utilities
Subpart A: 60.18 - Control Device Requirements
Applies to flare(s) used to routinely combust VOC
from Subparts Kb, VV, VVa, DDD, NNN, and
RRR equipment
Flare(s) used as control devices for VOCs from
new or modified equipment as defined in the NSPS
subparts Kb, VV, VVa, DDD, NNN, and RRR
Subpart Kb – Standards of Performance for
Volatile Organic Liquid Storage Vessels for
Which Construction, Reconstruction, or
Modification Commenced after July 23, 1984.
Subject to certain exceptions, applies to storage
vessels with a capacity greater than or equal to 75
cubic meters (m3) that is used to store volatile
organic liquids (VOL). Does not apply to storage
vessels with a capacity greater than or equal to
151 m3 storing a liquid with a maximum true
vapor pressure less than 3.5 kilopascals (kPa) or
with a capacity greater than or equal to 75 m3 but
less than 151 m3 storing a liquid with a maximum
true vapor pressure less than 15.0 kPa. Does not
apply to pressure vessels designed to operate in
excess of 204.9 kPa and without emissions to the
Control of VOCs from:
VOL Storage Tanks (> 151 m3 & > 3.5 kPa) or
(>75m3 but < 151m3 & > 15kPa)
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Applicable Regulation Regulatory Applicability Project Subject Unit & Pollutants
atmosphere.
Subpart VV- Standards of Performance for
Equipment Leaks of VOC in the Synthetic
Organic Chemicals Manufacturing Industry for
which Construction, Reconstruction, or
Modification Commenced after January 5, 1981,
and on or Before November 7, 2006
Applies to new, modified, or reconstructed
components assembled and connected by pipes or
ducts to process raw materials and to produce, as
intermediate or final products, one or more of the
chemicals listed in 40 CFR §60.489. Process unit
includes any feed, intermediate and final product
storage vessels (except as specified in §60.482–
1(g)), product transfer racks, and connected ducts
and piping. A process unit includes all equipment
as defined in this subpart: pumps, compressors,
connectors, valves, etc.
Control of VOCs from:
Equipment leaks from polyethylene manufacturing
- Note that Subpart VV applies because Subpart
DDD refers to Subpart VV, not VVa.
Subpart VVa- Standards of Performance for
Equipment Leaks of VOC in the Synthetic
Organic Chemicals Manufacturing Industry for
Which Construction, Reconstruction, or
Modification Commenced After November 7,
2006
Applies to new, modified, or reconstructed
components assembled and connected by pipes or
ducts to process raw materials and to produce, as
intermediate or final products, one or more of the
chemicals listed in 40 CFR §60.489a. Process unit
includes any feed, intermediate and final product
storage vessels (except as specified in §60.482–
1a(g)), product transfer racks, and connected ducts
and piping. A process unit includes all equipment
as defined in this subpart: pumps, compressors,
connectors, valves, etc.
Control of VOCs from:
Equipment leaks from ethylene manufacturing
Equipment leaks from polyethylene
manufacturing - Note that Subpart VV applies
because Subpart DDD refers to Subpart VV, not
VVa.
Subpart DDD- Standards of Performance for
Volatile Organic Compound (VOC) Emissions
from the Polymer Manufacturing Industry.
(manufacture of polypropylene, polyethylene,
polystyrene, or polyethylene terephthalate)
Applies to new, modified, or reconstructed
components inclusive of all equipment used in the
manufacture of these polymers.
Control of VOCs from:
Polyethylene manufacturing facilities beginning
with raw materials preparation and ending with
product storage, and covering all emissions
emanating from such equipment. Also, VOCs
from equipment leaks and process vents.
Subpart NNN- Standards of Performance for
Volatile Organic Compound (VOC) Emissions Applies to new, modified, or reconstructed Control of VOCs from:
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Applicable Regulation Regulatory Applicability Project Subject Unit & Pollutants
from Synthetic Organic (SOCMI) Chemical
Manufacturing Industry Distillation Operations.
SOCMI distillation units. Ethylene manufacturing - Distillation columns
De-C1, DeC2, and C2 splitter.
Polyethylene manufacturing - Subpart NNN
does not apply to any distillation unit that is
subject to the NSPS provisions of subpart DDD.
Subpart RRR- Standards of Performance for
Volatile Organic Compound (VOC) Emissions
from Synthetic Organic Chemical Manufacturing
Industry Reactor Processes
Applies to new, modified, or reconstructed
SOCMI reactor not discharging its vent stream
into a recovery system.
Control of VOCs from:
Ethylene manufacturing - Reactors
Polyethylene manufacturing - Subpart RRR does
not apply to any reactor unit that is subject to
NSPS provisions of subpart DDD.
Subpart YYY (proposed)- Standards of
Performance for Volatile Organic Compound
(VOC) Emissions from Synthetic Organic
Chemical Manufacturing Industry (SOCMI)
Wastewater
An affected facility is a designated chemical
process unit (CPU) in the synthetic organic
chemical manufacturing industry which
commences or commenced construction,
reconstruction or modification after September 12,
1994. An affected facility that does not generate a
process wastewater stream, a maintenance
wastewater stream, or an aqueous in-process
stream, is not subject to the control requirements
of this subpart.
Never promulgated
Subpart IIII - Standards of Performance for
Stationary Compression Ignition Internal
Combustion Engines
Standards of Performance for emissions of NOx,
VOC, CO, and PM from Stationary Compression
Ignition Internal Combustion Engines
Control of NOx, NMHC, CO, and PM from:
Emergency diesel firewater pump engines,
emergency diesel electric generators, and any
miscellaneous diesel engine driven equipment.
Subpart KKKK- Standards of Performance for
Stationary Combustion Turbines
Standards of Performance for Stationary
Combustion Turbines with and without duct
burners for emissions of NOx and SO2
Control of NOx and SO2 from:
Combustion turbines and duct burners
(Cogeneration Units)
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Applicable Regulation Regulatory Applicability Project Subject Unit & Pollutants
Subpart TTTT- Standards of Performance for
Greenhouse Gas Emissions for New Stationary
Sources: Electric Utility Generating Units
(proposed)
Standards of Performance for GHG emissions
from Electric Utility Generating Units with a
design heat input to the turbine engine greater
than 73 MW (250 MMBtu/h), combusting natural
gas supplying one-third or more of its potential
electric output and more than 219,000 MWh net-
electrical output to a utility distribution system.
Control of GHG emissions from:
New electric utility generating units as defined in
NSPS subpart TTTT
40 CFR Part 61 – National Emission Standards for Hazardous Air Pollutants
Subpart A – General Provisions
The general provisions include list of pollutants,
definitions, construction and modification
approvals, notification, reporting, and monitoring
requirements.
Control of benzene emissions from:
Equipment leaks as defined in NESHAP
subparts J and V
Benzene waste operations as defined in
NESHAP subpart FF
Subpart J – National Emission Standard for
Equipment Leaks (Fugitive Emission Sources) of
Benzene
The provisions of this subpart apply to each of the
following sources that are intended to operate in
benzene service: pumps, compressors, pressure
relief devices, sampling connection systems,
open-ended valves or lines, valves, connectors,
surge control vessels, bottoms receivers, and
control devices or systems required by this
subpart.
Control of benzene emissions from:
Equipment leaks as defined in NESHAP Subpart J
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Applicable Regulation Regulatory Applicability Project Subject Unit & Pollutants
Subpart V – National Emission Standard for
Equipment Leaks (Fugitive Emission Sources)
Applies to each of the following sources that are
intended to operate in volatile hazardous air
pollutant (VHAP) service: pumps, compressors,
pressure relief devices, sampling connection
systems, open-ended valves or lines, valves,
connectors, surge control vessels, bottoms
receivers, and control devices or systems required
by this subpart.
Control of benzene emissions from:
Equipment leaks as referenced by NESHAP
subpart J
Subpart FF – National Emissions Standards for
Benzene Waste Operations
Applies to chemical manufacturing plants where
the total annual benzene quantity from facility waste is the sum of the annual benzene quantity for each waste stream at the facility that has a flow-weighted annual average water content greater than 10 percent or that is mixed with water, or other wastes, at any time and the mixture has an annual average water content greater than 10 percent.
The total annual benzene quantity from facility
waste is greater than 10 Mg/yr (11 tons per year)
for the facility to be subject to 40 CFR §61.342(c)
through (h). If not, then testing, recordkeeping
and reporting are required to demonstrate
exemption from the Subpart FF control
requirements.
Control of benzene emissions from:
Benzene waste operations
It is not anticipated that the facility will have a
total annual benzene quantity in the facility waste
equal or greater than 10 mega grams per year (11
tons per year).
40 CFR Part 63 - National Emission Standards for Hazardous Air Pollutants for Source Categories
Subpart A – General Provisions
Facilities subject to subsequent subparts of 40
CFR Part 63; Flares used to routinely combust
HAP from 40 CFR Part 63-affected equipment
Control of HAP emissions from:
Ethylene manufacturing - NESHAP subparts SS,
UU, WW, XX, YY
Miscellaneous Organic NESHAP manufacturing
– NESHAP subpart FFFF
Combustion Turbines – NESHAP subpart
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Applicable Regulation Regulatory Applicability Project Subject Unit & Pollutants
YYYY- (stayed for natural gas-fired turbines)
Engines – NESHAP subpart ZZZZ
Subpart SS - National Emission Standards for
Closed Vent Systems, Control Devices, Recovery
Devices and Routing to a Fuel Gas System or a
Process
Applies when another subpart references the use
of this subpart for such air emission control (e.g.,
Subpart YY).
Includes requirements for closed vent systems,
control devices and routing of air emissions to a
fuel gas system or process.
Control of HAP emissions from:
Ethylene manufacturing - Closed vent systems,
control devices and routing of air emissions to a
fuel gas system or a process
Subpart UU - National Emission Standards for
Equipment Leaks
Applies to the control of air emissions from equipment leaks for which another subpart references the use of this subpart for such air emission control (e.g., Subpart YY).
Applies to pumps, compressors, agitators, pressure relief devices, sampling connection systems, open-ended valves or lines, valves, connectors, instrumentation systems, and closed vent systems and control devices used to meet the requirements of this subpart.
Control of HAP emissions from:
Ethylene manufacturing - Equipment leaks
Subpart WW - National Emission Standards for
Storage Vessels
Applies to the control of air emissions from storage vessels for which another subpart references the use of this subpart for such air emission control (e.g., Subpart YY).
Control of HAP emissions from:
Ethylene manufacturing - Storage vessels
Subpart XX - National Emission Standards for
Ethylene Manufacturing Process Units: Heat
Exchange Systems and Waste Operations
Establishes requirements for controlling emissions of hazardous air pollutants (HAP) from heat exchange systems and waste streams at new and existing ethylene production units.
Control of HAP emissions from:
Ethylene manufacturing - Heat exchange systems
and waste operations
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Applicable Regulation Regulatory Applicability Project Subject Unit & Pollutants
Subpart YY – National Emission Standards for
Hazardous Air Pollutants for Source Categories:
Generic Maximum Achievable Control
Technology Standards
Provides for the control of HAP emissions from
the following emission points: storage vessels,
process vents, transfer racks, equipment leaks,
waste streams, and other (heat exchange systems
for ethylene production)
Control of HAP emissions from:
Ethylene manufacturing - Storage vessels, process
vents, transfer racks, equipment leaks, waste
streams, and heat exchange systems
Subpart FFFF – National Emission Standards for
Hazardous Air Pollutants: Miscellaneous Organic
Chemical Manufacturing
Provides for the control of HAP emissions from
the following emission points: continuous process
vents, batch process vents, storage tanks, transfer
racks, equipment leaks, waste streams, and heat
exchange systems in miscellaneous organic
chemical manufacturing
Control of HAP emissions from:
Polyethylene manufacturing - storage tanks,
process vents, transfer racks, equipment leaks,
waste streams, and heat exchange systems
Subpart YYYY - National Emission Standards for
Hazardous Air Pollutants for Stationary
Combustion Turbines
Establishes national emission limitations and
operating limitations for hazardous air pollutants
(HAP) emissions from stationary combustion
turbines located at major sources of HAP
emissions, and requirements to demonstrate initial
and continuous compliance with the emission and
operating limitations.
The HAP standard required by this subpart for
natural gas-fired combustion turbines is currently
stayed.
Subpart ZZZZ - National Emission Standards for
Hazardous Air Pollutants for Stationary
Reciprocating Internal Combustion Engines
Establishes national emission limitations and
operating limitations for hazardous air pollutants
(HAP) emitted from stationary reciprocating
internal combustion engines (RICE) located at
major and area sources of HAP emissions. This
subpart also establishes requirements to
demonstrate initial and continuous compliance
with the emission limitations and operating
limitations.
Control of HAP emissions from:
Emergency diesel firewater pump engines,
emergency diesel electric generators, and any
miscellaneous diesel engine driven equipment.
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Applicable Regulation Regulatory Applicability Project Subject Unit & Pollutants
OTHER 40 CFR REGLATIONS
40 CFR Part 64: Compliance Assurance
Monitoring
Applicable to any pollutant specific emissions unit
with an add-on control device, that has the
potential to emit, before controls, more than 100
tpy of indicated pollutant, with the exception of
control devices that meet certain exemptions
The proposed facility’s Compliance Assurance
Monitoring Plan for this project must be submitted
as part of an application for a Title V permit.
40 CFR Part 68: Chemical Accident Prevention
Provisions
Mandates that facilities with more than a
threshold quantity of a regulated substance in a
single process must develop a Risk Management
Program that includes a hazard assessment, an
accident prevention program and an emergency
response program
Ethylene manufacturing, polyethylene units, tanks,
and pressure vessels
40 CFR Part 72: Permits Regulation
40 CFR Part 73: Sulfur Dioxide Allowance
System
40 CFR Part 74: Sulfur Dioxide Opt-Ins
40 CFR Part 75: Continuous Emissions
Monitoring
40 CFR Part 76: Acid Rain Nitrogen Oxides
Emissions Reduction Program
These parts pertain to the Acid Rain Program.
Part 72 is the permitting requirements, Part 73 is
the SO2 allowance system, Part 74 is the SO2 Op-
Ins system, Part and Part 75 contains the
continuous monitoring requirements, and Part 76
is the NOx emissions reduction program.
Cogen- Parts 72, 73, and 75
Part 74 and 76 are not applicable.
40 CFR Part 82: Protection of Stratospheric
Ozone
Subpart F- Recycling and Emissions Reduction
The purpose of this subpart is to reduce emissions
of class I and class II refrigerants and their
substitutes to the lowest achievable level by
maximizing the recapture and recycling of such
refrigerants during the service, maintenance,
repair, and disposal of appliances and restricting
the sale of refrigerants consisting in whole or in
part of a class I and class II ozone depleting
substances (ODS) in accordance with Title VI of
the Clean Air Act
Refrigerant equipment leaks where ozone
depleting substances are employed
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Applicable Regulation Regulatory Applicability Project Subject Unit & Pollutants
40 CFR Part 98: Mandatory Greenhouse Gas
Reporting
Mandatory reporting of greenhouse gases (GHG)
from sources that in general emit 25,000 metric
tons or more of carbon dioxide equivalent per year
in the United States.
Combustion sources emitting CO2, CH4 and
N2O
Equipment leaks of CH4
Equipment leaks of SF6
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4.2.1.1 Part 60, Subpart A, General Provisions:
The NSPS general provisions in Subpart A are applicable to facilities subject to any
standard promulgated under Part 60. The Project’s new facilities will be subject to NSPS
Subparts Kb, VV, VVa, DDD, NNN, RRR, YYY (proposed), IIII, KKKK, and TTTT
(proposed). Therefore, some of the provisions of Subpart A are applicable to the Project.
In general, Subpart A provisions specify performance test, performance evaluation
(monitoring systems), notification, recordkeeping, reporting, and control device
requirements for affected facilities.
The NSPS emission control devices will comply with 40 CFR § 60.11(d), which requires
a facility to maintain and operate any affected facility including associated air pollution
equipment in a manner consistent with good air pollution control practice for minimizing
emissions. Additionally, any flares used as a VOC control devices under Subparts Kb,
VV, VVa, DDD, NNN, and RRR will comply with the applicable control device
requirements in 40 CFR §60.18.
4.2.1.2 Subpart Kb - Standards of Performance for Volatile Organic Liquid Storage Vessels for Which Construction, Reconstruction, or Modification Commenced After July 23, 1984
Subpart Kb applies is each storage vessel with a capacity greater than or equal to 75 cubic
meters (m3) that is used to store volatile organic liquids (VOL) for which construction,
reconstruction, or modification is commenced after July 23, 1984. This subpart does not
apply to storage vessels with a capacity greater than or equal to 151 m3 storing a liquid
with a maximum true vapor pressure less than 3.5 kilopascals (kPa) or with a capacity
greater than or equal to 75 m3 but less than 151 m3 storing a liquid with a maximum true
vapor pressure less than 15.0 kPa. This subpart also does not apply to pressure vessels
designed to operate in excess of 204.9 kPa and without emissions to the atmosphere.
The two hexene storage tanks are affected tanks because their storage volume exceeds
151 m3 and the storage vapor pressure exceeds 3.5 kPa. As such, these tanks will be
equipped with a fixed roof in combination with an internal floating roof, or a closed vent
system and control device, or a system equivalent to those described in paragraphs (a)(1)
or (a)(3) as provided in § 60.114b. The tanks presented in Table 4-4 are not subject to the
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Table 4-4. Tanks Not Subject to Control Under NSPS Subpart Kb
Service Tank/Vessel Description Capacity
(m3)
Reason Not
Affected 2
Ethylene Spherical Pressure Vessel 7,238 PV
Ethylene Full Containment-
Refrigerated 30,000 VP
C3+(propane and heavier
hydrocarbons) Sphere 2,300 PV
Butene Spheres 1,200 PV
Isopentane Bullet 600 PV
Isobutane Bullet 200 PV
C3+ Refrigerant Bullet 300 PV
Pyrolysis Tar Cone Roof/Heat Coil 130 VP
Light Gasoline Storage Tank (IFR) 650 NESHAP YY
Recovered Oil Storage Tank (IFR) 90 VP
Equalization Wastewater Tank (IFR) 2,810 NVOLS
Biotreater Aeration Tank (Open Top) 5,650 NVOLS
Secondary Clarifier Tank (Open Top) 1,650 NVOLS
Biosludge Cone Roof Tank 50 NVOLS Sand Filter Clarifier
Backwash Cone Roof Tank 160 NVOLS
Spent Caustic Tank (IFR) 900/8,630 1 NESHAP YY
Aqueous Ammonia Pressure Vessel 91/114 PV
Caustic Cone Roof 300 VP
Generator Diesel Fixed Roof 38 S
Fire Pump Diesel Fixed Roof 7 S
Locomotive Diesel Fixed Roof 38 S
Sulfuric Acid Cone Roof Tank/N2 Blanket 150 NVOLS
DMDS Pressure Vessel 26 S
Demin Water Cone Roof Tank 4,100 NVOLS
SAC Resin Tank (Open Top) 18 S
WBA and SBA Resin Tank (Open Top) 15 S
Process Condensate Cone Roof Tank 3,120 NVOLS Surface Condensers
Condensate Cone Roof Tank 10,670 NVOLS
Primary Raw Water Clarifier Tank (Open Top) 5,080 NVOLS
Clearwells Tank (Open Top) 300 NVOLS
Raw Water (RW) Tank (Open Top) 150 NVOLS
Reclaimed Cone Roof Tank 520 NVOLS
Filtered Cone Roof Tank 13,650 NVOLS
Potable Cone Roof Tank 90 NVOLS 1. Two spent caustic scenarios are being considered.
2. S- size, VP- vapor pressure, PV- pressure vessel, NVOLS- not in VOL service
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control requirements of 40 CFR 60 Subpart Kb either due to size or vapor pressure, are
pressure vessels, are not in VOL service, or are subject to 40 CFR 63 Subpart YY.
4.2.1.3 Subpart VV - Standards of Performance for Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry (SOCMI) for which Construction, Reconstruction, or Modification Commenced After January 5, 1981, and on or Before November 7, 2006
Subpart VV is applicable to the polyethylene units as specifically referenced by 40 CFR
60 Subpart DDD, where the polyethylene units process raw materials to produce, as
intermediate or final products, one or more of the chemicals listed in §60.489. For the
purpose of this subpart, process unit includes any feed, intermediate and final product
storage vessels (except as specified in §60.482–1(g)), product transfer racks, and
connected ducts and piping. For the purpose of this subpart, a process unit includes all
equipment including each pump, compressor, pressure relief device, sampling connection
system, open-ended valve or line, valve, and flange or other connector in VOC service,
and any devices or systems required by this subpart.
Shell will demonstrate compliance with the requirements of §§60.482–1 through 60.482–
10 or §60.480(e) for all equipment within 180 days of initial startup. Compliance with
§§60.482–1 to 60.482–10 will be determined by review of records and reports, review of
performance test results, and inspection using the methods and procedures specified in
§60.485. Equipment that is in vacuum service is excluded from the requirements of
§§60.482–2 to 60.482–10 if it is identified as required in §60.486(e)(5). Equipment that
is in VOC service less than 300 hrs/yr is excluded from the requirements of §§60.482–2
through 60.482–10 if it is identified as required in §60.486(e)(6) and it meets any of the
conditions specified in paragraphs (e)(1) through (3) of §60.486. Shell may request a
determination of equivalent means of emission limitation to the requirements of
§§60.482–2, 60.482–3, 60.480-4, 60.482–5, 60.482–6, 60.482–7, 60.482–8, and 60.482–
10 as provided in §60.484 in order to put all of the facility equipment on the most
stringent equipment leak requirements to demonstrate LAER.
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4.2.1.4 Subpart VVa - Standards of Performance for Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry (SOCMI) for which Construction, Reconstruction, or Modification Commenced After November 7, 2006
This subpart applies to new, modified, or reconstructed components assembled and
connected by pipes or ducts to process raw materials and to produce, as intermediate or
final products, one or more of the chemicals listed in §60.489a. For the purpose of this
subpart, process unit includes any feed, intermediate and final product storage vessels
(except as specified in §60.482–1a(g)), product transfer racks, and connected ducts and
piping. A process unit includes all equipment as defined in this subpart: pumps,
compressors, connectors, valves, etc.
Shell will demonstrate compliance with the requirements of §§60.482–1a through
60.482–11a or §60.480a(e) for all equipment within 180 days of initial startup.
Compliance with §§60.482–1a to 60.482–11a will be determined by review of records
and reports, review of performance test results, and inspection using the methods and
procedures specified in §60.485a. Equipment that is in vacuum service is excluded from
the requirements of §§60.482–2a to 60.482–11a if it is identified as required in
§60.486a(e)(5). Equipment that is in VOC service less than 300 hrs/yr is excluded from
the requirements of §§60.482–2a through 60.482–11a if it is identified as required in
§60.486a(e)(6) and it meets any of the conditions specified in paragraphs (e)(1) through
(3) of §60.486a. Shell may request a determination of equivalent means of emission
limitation to the requirements of §§60.482–2a, 60.482–3a, 60/480-4a, 60.482–5a,
60.482–6a, 60.482–7a, 60.482–8a, 60.482-10a and 60.482–11a as provided in §60.484a
in order to put all of the facility equipment on the most stringent equipment leak
requirements, to demonstrate LAER.
4.2.1.5 Subpart DDD - Standards of Performance for Volatile Organic Compound (VOC) Emissions from the Polymer Manufacturing Industry.
This subpart applies to new, modified, or reconstructed components inclusive of all
equipment used in the Polymer Manufacturing Industry (manufacture of polypropylene,
polyethylene, polystyrene, or polyethylene terephthalate). For the proposed polyethylene
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manufacturing plants, the components include raw materials preparation, polymerization
reaction, material recovery, product finishing, and end with product storage. This subpart
addresses control of VOCs from continuous and intermittent process vents, and from
equipment leaks. Shell will comply with the standards specified under §60.562–1 with
one or more of the following control devices: incinerator, boiler, process heater, flare,
absorber, condenser, or carbon adsorber or if by other means will provide to the
Administrator information describing the operation of the control device and the process
parameter(s) which would indicate proper operation and maintenance of the device. Shell
will also comply with the equipment leak provisions of under § 60.562-2, which
references Subpart VV, or a more stringent leak detection program resulting from the
LAER analysis.
4.2.1.6 Subpart NNN - Standards of Performance for Volatile Organic Compound (VOC) Emissions from SOCMI Distillation Operations.
This subpart applies to new, modified, or reconstructed SOCMI distillation units. This
subpart in not applicable to polyethylene manufacturing because any distillation unit that
is subject to the provisions of Subpart DDD is not an affected facility. Subpart NNN
applies to the following sources or units whose construction, modification, or
reconstruction is commenced after December 30, 1983: (1) each distillation unit not
discharging its vent stream into a recovery system; (2) each combination of a distillation
unit and the recovery system into which its vent stream is discharged; and (3) each
combination of two or more distillation units and the common recovery system into
which their vent streams are discharged. Distillation unit means a device or vessel in which
distillation operations occur, including all associated internals (such as trays or packing) and accessories
(such as reboiler, condenser, vacuum pump, steam jet, etc.), plus any associated recovery system. To
comply with this subpart, Shell will either:
Reduce emissions of TOC (total organic carbon less methane and ethane) by
98 weight-percent, or to a TOC (less methane and ethane) concentration of
20 ppmv, on a dry basis corrected to 3 percent oxygen, whichever is less
stringent. If a boiler or process heater is used to comply with this paragraph, then
the vent stream shall be introduced into the flame zone of the boiler or process
heater; or
Combusting the emissions in a flare that meets the requirements of §60.18; or
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Maintaining a TRE index value greater than 1.0 without use of VOC emission
control devices.
TRE index value means a measure of the supplemental total resource requirement per
unit reduction of TOC associated with an individual distillation vent stream, based on
vent stream flow rate, emission rate of TOC net heating value, and corrosion properties
(whether or not the vent stream is halogenated), as quantified by the equation given under
§60.664(e).
4.2.1.7 Subpart RRR - Standards of Performance for Volatile Organic Compound (VOC) Emissions from SOCMI Reactors
This subpart applies to a new, modified, or reconstructed SOCMI reactor not discharging
its vent stream into a recovery system. This subpart is not applicable to polyethylene
manufacturing because Subpart RRR excludes any reactor vent that is subject to the
provisions of Subpart DDD. Subpart RRR applies to any of the following units or
sources whose construction, modification, or reconstruction commenced after
June 29, 1990: 1) each reactor process not discharging its vent stream into a recovery
system; 2) each combination of a reactor process and the recovery system into which its
vent stream is discharged; and 3) each combination of two or more reactor processes and
the common recovery system into which their vent streams are discharged. Reactor
processes are unit operations in which one or more chemicals, or reactants other than air,
are combined or decomposed in such a way that their molecular structures are altered and
one or more new organic compounds are formed.
The Project has a number of reactor systems including the ethane cracking furnaces and a
C2 hydrogenation unit. These reactor systems do not vent to the atmosphere under
normal operation. During startup, shutdown, or malfunction these reactor systems will
vent to the HP flare system.
Shell will comply with this subpart by either:
Reducing emissions of TOC (carbon less methane and ethane) by 98 weight-
percent, or to a TOC (less methane and ethane) concentration of 20 ppmv, on a
dry basis corrected to 3 percent oxygen, whichever is less stringent. If a boiler or
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process heater is used to comply with this paragraph, then the vent stream shall be
introduced into the flame zone of the boiler or process heater; or
Combusting the emissions in a flare that meets the requirements of §60.18; or
Maintaining a TRE index value greater than 1.0 without use of a VOC emission
control device.
The TRE index value is a measure of the supplemental total resource requirement per unit
reduction of TOC associated with an individual distillation vent stream, based on vent
stream flow rate, emission rate of TOC net heating value, and corrosion properties
(whether or not the vent stream is halogenated), as quantified by the equation given under
§60.664(e).
4.2.1.8 Subpart YYY (Proposed) - Standards of Performance for Volatile Organic Compound (VOC) Emissions from SOCMI Wastewater
The provisions of this proposed regulation would apply to a designated chemical process
unit (CPU) in the synthetic organic chemical manufacturing industry, which commences
or commenced construction, reconstruction, or modification after September 12, 1994.
An affected facility that does not generate a process wastewater stream, a maintenance
wastewater stream, or an aqueous in-process stream, is not subject to the control
requirements of this subpart.
Subpart YYY was proposed but never promulgated. When promulgated, if applicable,
Shell will comply with the final promulgated subpart.
4.2.1.9 Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines
The provisions of this subpart are applicable to manufacturers, owners, and operators of
stationary compression ignition (CI) internal combustion engines (ICE). For the purposes
of this subpart, the date that construction commences is the date the engine is ordered by
the owner or operator. There are different emission standards and requirements
depending on the use of the CI ICE (non-emergency, emergency, and fire pump engines),
model year, and size as follows:
Table 1 to Subpart IIII of Part 60—Emission Standards for Stationary Pre-2007
Model Year Engines With a Displacement of <10 Liters per Cylinder and 2007-
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2010 Model Year Engines >2,237 KW (3,000 HP) and With a Displacement of
<10 Liters per Cylinder
Table 3 to Subpart IIII of Part 60—Certification Requirements for Stationary Fire
Pump Engines
Table 4 to Subpart IIII of Part 60—Emission Standards for Stationary Fire Pump
Engines
Shell will comply with the emission standards, fuel, certification, testing, monitoring,
recordkeeping and reporting requirements of Subpart IIII.
4.2.1.10 Subpart KKKK- Standards of Performance for Stationary Combustion Turbines
This subpart establishes emission standards and compliance schedules for the control of
emissions from stationary combustion turbines that commenced construction,
modification, or reconstruction after February 18, 2005, where the turbine has a heat
input at peak load equal to or greater than 10.7 gigajoules (10 MMBtu) per hour, based
on the higher heating value of the fuel. Only heat input to the combustion turbine should
be included when determining whether or not this subpart is applicable. Any additional
heat input to the associated heat recovery steam generators (HRSG) from the duct burners
should not be included when determining peak heat input. However, this subpart does
apply to emissions from any associated HRSG and duct burners. Heat recovery steam
generators and duct burners regulated under this subpart are exempted from the
requirements of subparts Da, Db, and Dc of this part.
There are different emission standards and requirements depending on the turbine type,
heat input at peak load, and fuel (natural gas and other than natural gas). Table 1 to
Subpart KKKK of Part 60—Nitrogen Oxide Emission Limits for New Stationary
Combustion Turbines presents these limits.
The SO2 -related limits are:
SO2 emission limit of 110 nanograms per Joule (ng/J) (0.90 pounds per megawatt-
hour (lb/MWh)) gross output; or
Do not burn any fuel which contains total potential sulfur emissions in excess of
26 ng SO2 /J (0.060 lb SO2 /MMBtu) heat input. If a turbine simultaneously fires
multiple fuels, each fuel must meet this requirement.
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Shell will comply with the emission standards, testing, monitoring, recordkeeping, and
reporting requirements of Subpart KKKK.
4.2.1.11 Subpart TTTT- Standards of Performance for Greenhouse Gas Emissions for New Stationary Sources: Electric Utility Generating Units (Proposed)
On January 8, 2014, US EPA re-proposed new source performance standards for
emissions of carbon dioxide (CO2) for new affected fossil fuel-fired electric utility
generating units (EGUs). The proposed requirements, which are strictly limited to new
sources, would require new fossil fuel-fired EGUs greater than 25 megawatt equivalent
(MWe) to meet the following output-based standards:
New combustion turbines with a heat input rating greater than 850 MMBtu/hr
would be required to meet a standard of 1,000 lb CO2/MWh, or
New combustion turbines with a heat input rating less than or equal to 850 MMBtu/hr
would be required to meet a standard of 1,100 lb CO2/MWhr.
Shell will comply with the final emission standards, testing, monitoring, recordkeeping,
and reporting requirements of Subpart TTTT for new combustion turbines with a heat
input rating less than or equal to 850 MMBtu/hr.
4.2.2 40 CFR Part 61: National Emissions Standards for Hazardous Air Pollutants (NESHAP)
4.2.2.1 40 CFR Part 61 – Subpart A, General Provisions:
The NESHAP general provisions in 40 CFR 61 Subpart A are applicable to stationary
sources with facilities subject to any standard promulgated under Part 61. Although
benzene will be produced by the ethylene manufacturing process, it is not anticipated that
the Project will be subject to any control requirements under NESHAP Subpart FF.
However, some of the provisions of 40 CFR 61 Subpart A will be applicable to the
Project with respect to testing, recordkeeping, and reporting. In general, 40 CFR 61
Subpart A provisions specify performance testing, performance evaluation (monitoring
systems), notification, recordkeeping, reporting, and control device requirements for
affected facilities.
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4.2.2.2 40 CFR Part 61 - Subpart J, Equipment Leaks (Fugitive Emission Sources) of Benzene
40 CFR 61 Subpart J applies to each of the following sources that are intended to operate
in benzene service: pumps, compressors, pressure relief devices, sampling connection
systems, open-ended valves or lines, valves, connectors, surge control vessels, bottoms
receivers, and control devices or systems required by this subpart. In benzene service
means that a piece of equipment either contains or contacts a fluid (liquid or gas) that is
at least 10 percent benzene by weight as determined according to the provisions of
§61.245(d). The provisions of §61.245(d) also specify how to determine that a piece of
equipment is not in benzene service.
The ethane cracker wash water system and gasoline distillation systems contain benzene
as a byproduct of ethylene manufacturing. Shell will comply with the equipment leak
provisions of this subpart by complying with the requirements of 40 CFR 61 Subpart V
of this part.
4.2.2.3 40 CFR Part 61 - Subpart V, Equipment Leaks (Fugitive Emission Sources)
Subpart V applies to each of the following sources that are intended to operate in volatile
hazardous air pollutant (VHAP) service: pumps, compressors, pressure relief devices,
sampling connection systems, open-ended valves or lines, valves, connectors, surge
control vessels, bottoms receivers, and control devices or systems required by this
subpart. In VHAP service means that a piece of equipment either contains or contacts a
fluid (liquid or gas) that is at least 10 percent by weight a volatile hazardous air pollutant
(VHAP) as determined according to the provisions of §61.245(d). The provisions of
§61.245(d) also specify how to determine that a piece of equipment is not in VHAP
service. For fugitive emitting components, monitoring of all VHAP containing
components is proposed as part of the VOC LAER (see Section 5.5).
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4.2.2.4 40 CFR Part 61 - Subpart FF, Benzene Waste Operations NESHAP:
The requirements of 40 CFR 61 Subpart FF apply to chemical manufacturing plants, coke
by-product recovery plants, and petroleum refineries as well as hazardous waste
Treatment Storage and Disposal Facilities (TSDF) treating wastes from such facilities.
40 CFR 61 Subpart FF applies to the testing, recordkeeping, and reporting requirements
for benzene waste operations. The total annual benzene quantity from benzene waste
must be greater than 10 Mg/yr (11 tons per year) for the facility to be subject to 40 CFR
61.342(c) through (h). The total annual benzene quantity from facility waste is the sum
of the annual benzene quantity for each waste stream at the facility that has a flow-
weighted annual average water content greater than 10 percent or that is mixed with
water, or other wastes, at any time and the mixture has an annual average water content
greater than 10 percent. The benzene quantity in a waste stream is to be counted only
once without multiple counting if other waste streams are mixed with or generated from
the original waste stream.
Shell will comply with the provisions of 40 CFR 61 Subpart FF by being exempt because
Shell will design and operate the facility such that the total annual benzene quantity from
the facility waste will be less than 11 tons per year (i.e., 10 mega grams) for the facility.
Shell will comply with the 40 CFR 61 Subpart FF exemption by following the testing,
recordkeeping, and reporting requirements as follows:
If the total annual benzene quantity from facility waste is less than 10 Mg/yr (11 ton/yr)
but is equal to or greater than 1 Mg/yr (1.1 ton/yr), then the Project will:
1) Comply with the recordkeeping requirements of §61.356 and reporting
requirements of §61.357 of this subpart; and
2) Repeat the determination of total annual benzene quantity from facility waste at
least once per year and whenever there is a change in the process generating the
waste that could cause the total annual benzene quantity from facility waste to
increase to 10 Mg/yr (11 ton/yr) or more.
If the total annual benzene quantity from facility waste is less than 1 Mg/yr (1.1 ton/yr),
then the Project will:
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1) Comply with the recordkeeping requirements of §61.356 and reporting
requirements of §61.357 of this subpart; and
2) Repeat the determination of total annual benzene quantity from facility waste
whenever there is a change in the process generating the waste that could cause
the total annual benzene quantity from facility waste to increase to 1 Mg/yr
(1.1 ton/yr) or more.
4.2.3 40 CFR Part 63: National Emissions Standards for Hazardous Air Pollutants for Source Categories (NESHAP)
40 CFR Part 63 contains National Emission Standards for Hazardous Air Pollutants
(NESHAP) established pursuant to section 112 of the Act as amended November 15,
1990. These standards regulate specific categories of stationary sources that emit (or have
the potential to emit) one or more hazardous air pollutants listed in this part pursuant to
section 112(b) of the Act. This part is independent of NESHAP requirements contained in
40 CFR Part 61, discussed above.
4.2.3.1 40 CFR Part 63, Subpart A - General Provisions:
The general provisions in 40 CFR 63 Subpart A are applicable to stationary and area
sources with facilities subject to any standard promulgated under 40 CFR Part 63. The
following Project facilities are subject to relevant subparts of 40 CFR Part 63:
Ethylene Manufacturing - Subparts SS, UU, WW, XX, YY,
Polyethylene Manufacturing – Subpart FFFF,
Combustion turbines - Subpart YYYY, and
Reciprocating Internal Combustion Engines - Subpart ZZZZ.
In general, Subpart A contains requirements related to notification, recordkeeping,
monitoring and performance testing. Subpart A also contains control device requirements
similar to the requirements in 40 CFR §60.18.
4.2.3.2 40 CFR Part 63, Subpart SS - National Emission Standards for Closed Vent Systems, Control Devices, Recovery Devices and Routing to a Fuel Gas System or a Process
40 CFR 63 Subpart SS applies when another subpart of 40 CFR Part 63 references the
use of this subpart for HAP emission control. 40 CFR 63 Subpart YY refers to this
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subpart for the control of closed vent systems, control devices, recovery devices, and
routing to a fuel gas system or a process as follows:
Closed vent system and flare. Owners or operators that vent emissions through a
closed vent system to a flare must meet the requirements in §63.983 for closed
vent systems; §63.987 for flares; §63.997(a), (b) and (c) for provisions regarding
flare compliance assessments; the monitoring, recordkeeping, and reporting
requirements referenced therein; and the applicable recordkeeping and reporting
requirements of §§63.998 and 63.999. No other provisions of this subpart apply to
emissions vented through a closed vent system to a flare.
Closed vent system and nonflare control device. Owners or operators who control
emissions through a closed vent system to a nonflare control device must meet the
requirements in §63.983 for closed vent systems, the applicable recordkeeping
and reporting requirements of §§63.998 and 63.999, and the applicable
requirements listed in paragraphs (c)(1) through (3) of §63.982.
Route to a fuel gas system or process. Owners or operators that route emissions to
a fuel gas system or to a process shall meet the requirements in §63.984, the
monitoring, recordkeeping, and reporting requirements referenced therein, and the
applicable recordkeeping and reporting requirements of §§63.998 and 63.999. No
other provisions of this subpart apply to emissions being routed to a fuel gas
system or process.
Shell will comply with the provisions of 40 CFR 63 Subpart SS where applicable by
designing and operating the closed vent systems, control devices, recovery devices and
routing to a fuel gas system or a process in compliance with this subpart, and by
complying with all of the subpart requirements for testing, recordkeeping, and reporting.
4.2.3.3 40 CFR Part 63, Subpart UU - National Emission Standards for Equipment Leaks
40 CFR 63 Subpart UU applies to the control of air emissions from equipment leaks for
which another subpart references the use of this subpart for such air emission control. 40
CFR 63 Subpart YY (discussed below) refers to this subpart for the control of equipment
leaks. 40 CFR 63 Subpart UU applies to equipment leaks from pumps, compressors,
agitators, pressure relief devices, sampling connection systems, open-ended valves or
lines, valves, connectors, instrumentation systems, and closed vent systems and control
devices used to meet the requirements of this subpart. The following equipment is
exempt from the requirements of 40 CFR 63 Subpart UU:
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Equipment in vacuum service,
Equipment intended to be in regulated material service less than 300 hours per
calendar year.
Lines and equipment not containing process fluids, such as utilities, other non-
process lines, and heating and cooling systems that do not combine their materials
with those in the processes they serve.
Shell will comply with the provisions of 40 CFR 63 Subpart UU where applicable by
designing and operating the pumps, compressors, agitators, pressure relief devices,
sampling connection systems, open-ended valves or lines, valves, connectors,
instrumentation systems, and closed vent systems and control devices in compliance with
this subpart, and by complying with all of the subpart requirements for testing,
monitoring, repair, recordkeeping, and reporting.
4.2.3.4 40 CFR Part 63, Subpart WW - National Emission Standards for Storage Vessels
40 CFR 63 Subpart WW applies to the control of air emissions from storage vessels for
which another subpart references the use of this subpart for such air emission control.
40 CFR 63 Subpart YY refers to this subpart for the control of storage vessels. For each
storage vessel to which this subpart applies, the owner or operator shall comply with one
of the requirements:
Operate and maintain an internal floating roof (IFR) tank.
Operate and maintain an external floating roof (EFR) tank.
Comply with an equivalent to the requirements as provided in §63.1064.
Shell will comply with the provisions of Subpart WW where applicable by designing and
operating the storage vessels with IFRs or EFRs or closed vent systems with control
devices and by complying with all of the subpart requirements for testing, repair
recordkeeping, and reporting.
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4.2.3.5 40 CFR Part 63, Subpart XX - National Emission Standards for Ethylene Manufacturing Process Units: Heat Exchange Systems and Waste Operations
40 CFR 63 Subpart XX establishes requirements for controlling emissions of HAPs from
heat exchange systems and waste streams at new and existing ethylene production units.
This subpart requires monitoring the cooling water for the presence of substances that
indicate a leak in the heat exchange system and repairing the leak. This subpart requires
compliance with 40 CFR Part 61, Subpart FF, National Emission Standards for Benzene
Waste Operations. There are some differences between the ethylene production waste
requirements and those of 40 CFR 61 Subpart FF. The waste stream provisions of 40
CFR 63 Subpart XX apply to the Project’s ethylene manufacturing process as this subpart
is expressly referenced from 40 CFR 63 Subpart YY.
40 CFR 63 Subpart XX subpart requires management and treatment of continuous
butadiene waste streams that contain greater than or equal to 10 ppmw 1,3-butadiene and
have a flow rate greater than or equal to 0.02 liters per minute. If the total annual
benzene quantity from waste at the facility is less than 10 Mg/yr, as determined according
to 40 CFR 61.342(a), additional requirements apply. For waste streams that contain
benzene, the source must comply with the requirements of 40 CFR Part 61 Subpart FF,
except as specified in Table 2 to 40 CFR 63 Subpart XX.
Shell will comply with the provisions of 40 CFR 63 Subpart XX relating to equipment
design/operation, testing, recordkeeping, and reporting.
4.2.3.6 40 CFR Part 63, Subpart YY – National Emission Standards for Hazardous Air Pollutants for Source Categories: Generic Maximum Achievable Control Technology Standards
40 CFR 63 Subpart YY controls HAP emissions from the following emission points:
storage vessels, process vents, transfer racks, equipment leaks, waste streams, and other
(heat exchange systems for ethylene production) from certain source categories. One of
the source categories covered by this subpart is ethylene production. The affected
sources include:
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All storage vessels (as defined in §63.1101) that store liquids containing organic
HAP.
All ethylene process vents from continuous unit operations.
All transfer racks that load HAP-containing material.
Equipment (as defined in §63.1101) that contains or contacts organic HAP.
All waste streams associated with an ethylene production unit.
All heat exchange systems associated with an ethylene production unit.
All ethylene cracking furnaces and associated decoking operations, while
considered affected sources, are exempt from any control requirements under this
subpart.
Shell will comply with the provisions of 40 CFR 63 Subpart YY where applicable by
designing and operating the storage vessels, process vents, transfer racks, equipment
leaks, waste streams, and heat exchange systems associated with the ethylene
production source category in compliance with all of the subpart requirements, and by
complying with all of the subpart requirements for testing, recordkeeping, and
reporting.
4.2.3.7 40 CFR Part 63, Subpart FFFF - National Emission Standards for Hazardous Air Pollutants: Miscellaneous Organic Chemical Manufacturing
40 CFR 63 Subpart FFFF establishes national emission standards for hazardous air
pollutants (NESHAP) for miscellaneous organic chemical manufacturing. This subpart
also establishes requirements to demonstrate initial and continuous compliance with the
emission limits, operating limits, and work practice standards. The three polyethylene
units are affected facilities. Processes covered by this subpart include:
continuous process vents,
batch process vents,
storage tanks,
transfer racks,
equipment leaks,
wastewater streams and liquid streams in open systems, and
heat exchange systems.
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Shell will comply with the provisions of 40 CFR 63 Subpart FFFF where applicable by
designing and operating the storage vessels, process vents, transfer racks, equipment
leaks, waste streams, and heat exchange systems associated with the affected source in
compliance with all of the subpart requirements, and by complying with all of the subpart
requirements for testing, recordkeeping, and reporting.
4.2.3.8 40 CFR Part 63, Subpart YYYY - National Emission Standards for Hazardous Air Pollutants for Stationary Combustion Turbines
40 CFR 63 Subpart YYYY establishes national emission limitations and operating
limitations for hazardous air pollutant (HAP) emissions from stationary combustion
turbines located at major sources of HAP emissions, and requirements to demonstrate
initial and continuous compliance with the emission and operating limitations. Duct
burners and waste heat recovery units are considered steam generating units and are not
covered under this subpart. In some cases, it may be difficult to separately monitor
emissions from the turbine and duct burner, so sources are allowed to meet the required
emission limitations with their duct burners in operation. This subpart applies to each
new or reconstructed stationary combustion turbine which is a lean premix gas-fired
stationary combustion turbine, a lean premix oil-fired stationary combustion turbine, a
diffusion flame gas-fired stationary combustion turbine, or a diffusion flame oil-fired
stationary combustion turbine. Stationary combustion turbines used for emergency
purposes are exempt from this subpart.
Currently, the standards for gas-fired subcategories have been stayed (69 Fed. Reg.
51184 (August 18, 2004), and EPA has proposed to delist from the MACT requirements
four categories of stationary combustion turbines, including the category that would
cover the Project’s proposed turbines. Projects that start up a new or reconstructed
stationary combustion turbine that is a lean premix gas-fired stationary combustion
turbine or diffusion flame gas-fired stationary combustion turbine as defined by this
subpart, must comply with the Initial Notification requirements set forth in § 63.6145 but
need not comply with any other requirement of this subpart until EPA takes final action
to require compliance and publishes a document in the Federal Register.
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4.2.3.9 40 C.F.R. Part 63, Subpart ZZZZ - National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines
40 CFR 63 Subpart ZZZZ establishes national emission limitations and operating
limitations for HAPs emitted from stationary reciprocating internal combustion engines
(RICE) located at major and area sources of HAP emissions. This subpart also establishes
requirements to demonstrate initial and continuous compliance with the emission
limitations and operating limitations.
An affected source must meet the requirements of 40 CFR Part 60 Subpart IIII, for
compression ignition engines. Shell will comply with the provisions of 40 CFR 63
Subpart ZZZZ by complying with the requirements for equipment design/operation,
testing, recordkeeping, and reporting.
4.2.4 40 CFR Part 64: Compliance Assurance Monitoring
40 CFR Part 64, Compliance Assurance Monitoring (CAM), applies to units subject to
federally enforceable emission standards at major Part 70 (Title V) sources with
uncontrolled emissions above major source thresholds. Where the basis of the emission
standard is a regulation proposed after November 15, 1990, additional monitoring
requirements under CAM are not applicable. The proposed Project will comply with the
CAM requirements.
4.2.5 40 CFR Part 68: Chemical Accident Prevention Provisions
This regulation mandates that facilities with more than a threshold quantity of a regulated
substance in a single process must develop a Risk Management Program that includes a
hazard assessment, an accident prevention program and an emergency response program.
It also requires that owners or operators of subject facilities submit a summary of their
program called a risk management plan (RMP), detailing these program elements to the
Environmental Protection Agency. The proposed Project will have a number of regulated
substances that may exceed the threshold quantity. If applicable, Shell will develop a
Risk Management Program that includes hazard assessment, an accident prevention
program and an emergency response program.
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4.2.6 40 CFR Parts 72, 73, 74, 75, and 76: Acid Rain Programs
These parts pertain to the Acid Rain Program. 40 CFR Part 72 is the permitting
requirements, 40 CFR Part 73 is the SO2 allowance system, and 40 CFR Part 75 contains
the continuous monitoring requirements. 40 CFR Part 74 is the SO2 Opt-In System for
units that are not affected units under 40 CFR Part 72. 40 CFR Part 76 is the NOx
emissions reduction program.
The proposed Cogen Units will sell more than one-third of their potential electric output
capacity and are greater than 25 MWe in capacity. Thus, these units will be subject to the
Acid Rain Program requirements found in 40 CFR Parts 72, 73, and 75. 40 CFR Part 74
does not apply because the Cogen Units are affected units under Part 72. 40 CFR Part 76
does not apply because the regulation only applies to coal-fired units. Shell will comply
with the Acid Rain Program requirements for the Cogen Units.
4.2.7 40 CFR Part 82: Protection of Stratospheric Ozone
4.2.7.1 40 CFR Part 82, Subpart F- Recycling and Emissions Reduction
40 CFR 82 Subpart F seeks to reduce emissions of Class I and Class II refrigerants and
their substitutes to the lowest achievable level by maximizing the recapture and recycling
of such refrigerants during the service, maintenance, repair, and disposal of appliances
and restricting the sale of refrigerants consisting in whole or in part of a Class I and
Class II ozone depleting substances (ODS) in accordance with Title VI of the Clean Air
Act. Appliance means any device which contains and uses a refrigerant and which is
used for household or commercial purposes, including any air conditioner, refrigerator,
chiller, or freezer. This subpart applies to any person servicing, maintaining, or repairing
appliances, or disposing of appliances, including small appliances and motor vehicle air
conditioners. In addition, this subpart applies to refrigerant reclaimers, technician
certifying programs, appliance owners and operators, manufacturers of appliances,
manufacturers of recycling and recovery equipment, approved recycling and recovery
equipment testing organizations, persons selling Class I or Class II refrigerants or
offering Class I or Class II refrigerants for sale, and persons purchasing Class I or
Class II refrigerants.
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This subpart prohibits, after June 13, 2005, any person maintaining, servicing, repairing,
or disposing of appliances knowingly venting or otherwise releasing into the environment
any prohibited refrigerant or substitute from such appliances. Releases associated with
good faith attempts to recycle or recover refrigerants or non-exempt substitutes that are
deminimis are not subject to this prohibition.
Other requirements of this subpart include repair of leaks for systems containing over
50 pounds of refrigerant. Shell will comply with the prohibition on venting non-exempt
refrigerants, and the leak monitoring, repair and reporting requirements for equipment
containing over 50 pounds of refrigerant.
4.2.8 40 CFR Part 98: Mandatory Greenhouse Gas Reporting
EPA promulgated this rule for the mandatory reporting of greenhouse gases (GHG) from
sources that in general emit 25,000 metric tons or more of carbon dioxide equivalent per
year in the United States. For the proposed Project, this rule applies to any combustion
source emitting CO2, CH4, and N2O, equipment leaks of CH4, and equipment leaks of
SF6. The Project’s combustion sources include the cracking furnaces, Cogen Units,
incinerators, flares, and emergency diesel engines. Equipment leaks of CH4 would occur
from the natural gas fuel system, the ethane cracker fuel system, and the ethylene
manufacturing cracked gas system including the quench towers, heat exchangers,
compressors, pumps, and distillation towers processing methane.
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5.0 Control Technology Analysis
5.1 Control Technology Background
Two primary types of control technology analyses are presented in this section.17 For
those pollutants for which the proposed project is a major source in an attainment area
requiring PSD review (CO2e/GHG, CO, NO2, and PM/PM10), best available control
technology (BACT) analyses are provided. For those pollutants for which the proposed
project is a major source in a non-attainment area (NOx, VOC, and PM2.5), lowest
achievable emission rate (LAER) technology analyses are provided. Where it is logical
to do so, analyses are combined on a pollutant/source basis (e.g., the NO2 BACT and
NOx LAER analyses). In addition, this section evaluates Pennsylvania best available
technology requirements under 25 Pa. Code §127.12(a)(5) (PaBAT). Where appropriate,
reference is provided to applicable New Source Performance Standards (NSPS), and
National Emission Standards for Hazardous Air Pollutants (NEHAPS), which provide a
baseline of technology requirements.
5.1.1 Control Technology Analyses Definitions
The federal PSD regulations, which are adopted by reference in the Pennsylvania air
quality regulations,18 define BACT at 40 CFR § 52.21(b)(12) as follows:
“[BACT] means an emissions limitation (including a visible emission standard)
based on the maximum degree of reduction for each pollutant subject to regulation
under Act which would be emitted from any proposed major stationary source or
major modification which the Administrator, on a case-by-case basis, taking into
account energy, environmental, and economic impacts and other costs, determines is
achievable for such source or modification through application of production
processes or available methods, systems, and techniques, including fuel cleaning or
treatment or innovative fuel combustion techniques for control of such pollutant. In
no event shall application of best available control technology result in emissions of
any pollutant, which would exceed the emissions allowed by any applicable standard
under 40 CFR parts 60 and 61. If the Administrator determines that technological or
economic limitations on the application of measurement methodology to a particular
17 For the purposes of the control technology analyses, the State Best Available Technology (BAT)
requirements are assumed to be met by either the BACT or LAER analyses contained herein. 18 25 Pa. Code §127.83.
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emissions unit would make the imposition of an emissions standard infeasible, a
design, equipment, work practice, operational standard, or combination thereof, may
be prescribed instead to satisfy the requirement for the application of best available
control technology. Such standard shall, to the degree possible, set forth the
emissions reduction achievable by implementation of such design, equipment, work
practice or operation, and shall provide for compliance by means which achieve
equivalent results.”
LAER, as defined in 25 Pa Code § 121.1, means the following:
LAER—Lowest Achievable Emission Rate—
(i) The rate of emissions based on the following, whichever is more stringent:
(A) The most stringent emission limitation which is contained in the
implementation plan of a state for the class or category of source unless the
owner or operator of the proposed source demonstrates that the limitations
are not achievable.
(B) The most stringent emission limitation which is achieved in practice by the
class or category of source.
(ii) The application of the term may not allow a new or proposed modified source
to emit a pollutant in excess of the amount allowable under an applicable new
source standard of performance.
Per 25 Pa. Code 127.12(a)(5), applicants must show that emissions from a new source
will be the minimum attainable through use of the best available technology
(PaBAT). For sources also subject to BACT or LAER requirements, 25 Pa. Code
127.205(7) stipulates that the Pennsylvania Department of Environmental Protection
(PaDEP) may determine that PaBAT requirements are equivalent to BACT and LAER
determined under the new source review program. Thus, a separate PaBAT discussion is
provided below only for pollutants not subject to the BACT or LAER requirements.
5.1.2 Methodology for LAER and BACT Analyses
The LAER analyses conducted in this section will follow the following three steps:
Step 1: Identify existing permit limits and SIP limits;
Step 2: Identify existing permit limits and SIP limits that have been achieved in
practice; and
Step 3: Propose LAER based on the most stringent limit that has been achieved
in practice.
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The federal and state new source review (NSR) regulations do not prescribe a procedure
for conducting BACT analyses. U.S. EPA and Pennsylvania Department of
Environmental Protection (“PaDEP”) have interpreted the BACT requirement as
containing two core criteria. First, the BACT analysis must include consideration of the
most stringent available technologies (i.e., those that provide the “maximum degree of
emissions reduction”). Second, any decision to define BACT on the basis of a control
alternative that is less effective than the most stringent available must be justified by an
analysis of objective indicators showing that energy, environmental, and economic
impacts render the more stringent alternative(s) unreasonable or otherwise not
achievable.
U.S. EPA has developed and PaDEP has followed what is referred to as a “top-down”
approach for conducting BACT analyses and has indicated that this approach will
generally yield a BACT determination satisfying the two core criteria. Under the “top-
down” approach, analysis starts with the most stringent control technologies that are both
available and technically feasible for a particular source. Each control technology, in
order of stringency, is evaluated to determine whether its environmental, energy or
economic impacts render that alternative inappropriate as BACT. The energy impact
analysis considers direct energy consumption associated with the control technology.
Cost and economic analyses considers capital and annual costs of the control technology
in relation to the technology’s effectiveness in removing the pollutant(s) of concern,
considering both total and incremental cost-effectiveness. Economic impact analysis
considers the environmental impacts associated with a control technology, such as waste
generation, wastewater discharges, visibility impacts or emissions of unregulated
pollutants. Such “top-down” approach is utilized for the BACT analyses presented in this
application.
The five basic steps of a “top-down” BACT analysis are listed below:
Step 1: Identify all available control technologies with practical potential for
application to the specific emission unit for the regulated pollutant under
evaluation;
Step 2: Eliminate technically infeasible control technologies;
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Step 3: Rank the remaining control technologies by effectiveness and tabulate a
control hierarchy;
Step 4: Evaluate the control technologies in order of effectiveness to determine
environmental, economic, and energy impacts, and document the results;
and
Step 5: Select BACT, which will be the most effective control option not rejected
as inappropriate based on the economic, environmental, and/or energy
impacts.
5.1.3 Achieved in Practice and Technical Feasibility Criteria
5.1.3.1 Achieved in Practice
One of the LAER criteria is to identify the most stringent emission limitation that has
been achieved in practice by the class or category of source. The "achieved-in-practice"
component of the LAER definition is not defined in the federal statutes and regulations,
and several interpretations have been formulated by various permitting agencies.
For example, EPA Region IX has taken a position that the successful operation of a new
control technology for six months constitutes “achieved-in-practice”.19 This
interpretation leaves open several key points, including the most important question as to
what demonstrates “successful operation.”
In a draft document, the San Joaquin Valley Air Pollution Control District defined
“achieved in practice” as an emission level or an emission control technology or
technique that is has been identified by the District, CARB, EPA, or any other air
pollution control District as having been “achieved in practice” for the same class and
category of source provided: 20
The rating and capacity for the unit where the control was achieved must be
approximately the same as that for the proposed unit.
The type of business (i.e. class of source) where the emissions units are utilized
must be the same.
19 Howekamp, David, U.S. EPA, Region IX, to Mohsen Nazemi, SCAQMD, August 25, 1997. 20 DRAFT San Joaquin Valley Air Pollution Control District Best Available Control Technology Policy,
March 1, 2010.
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The availability of resources (i.e. fuel, water) necessary for the control technology
must be approximately the same.
The San Joaquin District’s draft guidance indicates that in addition to the criteria above,
an emission control technology or technique is considered “achieved in practice”
provided all of the following are satisfied:
At least one vendor must offer this equipment for regular or full-scale operation.
A performance guarantee should be (but is not required to be) available with the
purchase of the control technology.
The control technology must have been installed and operated reliably in at least
one commercial facility for at least 180 days.
The control technology must be verified to perform effectively over the range of
operation expected for that class and category of source. The verification shall be
based on a performance test or tests, when possible, or other performance data.
Just because a permit or SIP emission limit has been issued does not mean that the limit
is “achievable-in-practice” unless an emissions unit in the same class or category of
source has operated under normal operating mode and has demonstrated through testing
that the limit is achieved. This is why the definition of LAER includes the caveat “unless
the owner or operator of the proposed source demonstrates that the limitations are not
achievable.” For the purposes of this control technology analysis, a permit or SIP limit is
considered “achieved-in-practice” when testing has successfully demonstrated
compliance with the limit and averaging period. For example, if the permit limit is based
on a 12-month rolling average period excluding periods of startup, shutdown,
maintenance, and malfunction (SSMM), then at least 12-months of operation is required
to demonstrate that the limit is “achieved in practice.”
5.1.3.2 Technical Feasibility
Under Step 2 of a BACT analysis, each of the available control technologies identified
under Step 1 are evaluated to determine their technical feasibility. A control technology
is determined to be technically feasible if it has previously been installed and operated
successfully at a similar emission source, or if there is agreement that the technology can
be applied to the emission source that is under evaluation. Technical infeasibility is
shown through physical, chemical, or other engineering principles that demonstrate that
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technical difficulties preclude the successful use of the control option for the particular
source under consideration.
A technology must be commercially available for it to be considered as a candidate for
BACT. The EPA 1990 Draft Workshop Manual, at page B.12, states: “Technologies
which have not yet been applied to (or permitted for) full scale operations need not be
considered available; an applicant should be able to purchase or construct a process or
control device that has already been demonstrated in practice.”
In general, if a control technology has been "demonstrated" successfully for the type of
emission source under review, then it would be considered technically feasible. For an
undemonstrated technology, “availability” and “applicability” must be considered in
determining technical feasibility. Page B.17 of the 1990 Draft Workshop Manual states:
Two key concepts are important in determining whether an undemonstrated
technology is feasible: "availability" and "applicability." As explained in more detail
below, a technology is considered "available" if it can be obtained by the applicant
through commercial channels or is otherwise available within the common sense
meaning of the term. An available technology is "applicable" if it can reasonably be
installed and operated on the source type under consideration. A technology that is
available and applicable is technically feasible.
Availability in this context is further explained using the following process commonly
used for bringing a control technology concept to reality as a commercial product:
concept stage;
research and patenting;
bench scale or laboratory testing;
pilot scale testing;
licensing and commercial demonstration; and
commercial sales.
The 1990 Draft Workshop Manual, at page B.18, states, “A control technique is
considered available, within the context presented above, if it has reached the licensing
and commercial sales stage of development. A source would not be required to
experience extended time delays or resource penalties to allow research to be conducted
on a new application. Neither is it expected that an applicant would be required to
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experience extended trials to learn how to apply a technology on a totally new and
dissimilar source type.”
It should be noted that some vendors will provide guarantees and commercial sale of
technology that has not been sufficiently demonstrated commercially. This can and has
led to significant compliance issues. Applicability involves not only commercial
availability (as evidenced by past or expected near-term deployment on the same or
similar type of emission source), but also involves consideration of the physical and
chemical characteristics of the gas stream to be controlled. A control method applicable
to one emission source may not be applicable to a similar source due to differences in
physical and chemical gas stream characteristics (such as the sulfur content of the flue
gas from a coal-fired boiler verses a natural gas-fired boiler, or the range and variability
of temperature characteristics of flue gas impacting the effectiveness of controls).
Vendor guarantees alone do not constitute technical availability. The 1990 Draft
Workshop Manual, at page B.20, notes:
Vendor guarantees may provide an indication of commercial availability and
the technical feasibility of a control technique and could contribute to a
determination of technical feasibility or technical infeasibility, depending on
circumstances. However, EPA does not consider a vendor guarantee alone to
be sufficient justification that a control option will work.
This is because there are many instances where vendor guarantees for emission control
equipment have not been met. Vendor guarantees rarely cover the cost of major
equipment modifications or the installation of new equipment required to attain
compliance, the cost of lost production and the legal cost of addressing enforcement
actions from regulatory agencies.
5.1.4 Control Technology Analysis Organization
The control technology analyses included in this section are organized by emissions unit
type and then by pollutant, except for the Greenhouse Gas (GHG) pollutants. The GHG
BACT analyses are addressed with a separate Section 5.6 addressing potential control of
CO2e by carbon capture and sequestration across the entire facility, with separate
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discussion of other CO2e control methods addressed in the sections on particular
emissions unit types. This is because the top control technology option, carbon capture
and sequestration (CCS), is the “top” control option for all combustion sources and
process vents. Section 5.6 provides the control technology analyses for CCS.
5.1.5 Summary of Proposed BACT/LAER
Table 5-1 presents a summary of the proposed BACT and LAER limits for each of the
project’s emissions units and emissions points.
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Table 5-1. Proposed Control Technology Evaluation Limits
Emissions Unit Pollutant Control Technology Limit/Averaging Time Compliance Method
Cracking Furnaces
NOx Low NOx Burners (LNB) &
Selective Catalytic Reduction
(SCR)
0.01 lb/MMBtu (12-mth roll)
0.015 lb/MMBtu (24-hr roll)
31.1 lb/hr during startup,
shutdown, decoking, hot
steam standby, feed in and
feed out modes
NOx Continuous
Emissions Monitoring
System (CEMS)
VOC Good Combustion Design &
Operation 1.07 lb/hr Performance test once
every 5 years using EPA
Reference Methods (RM)
18 & 25 and
PM/PM10/PM2.5 Good Combustion Design &
Operation 3.1 lb/hr
0.005 lb/MMBtu at rated heat
input
Performance test once
every 5 years using EPA
RM 5 & 202
CO Good Combustion Design &
Operation 035 lb/MMBtu (12-mth roll)
52.2 lb/hr during startup,
shutdown, and decoking
CO CEMS
CO2e/GHG Highly energy efficient
design & operation Only tailgas & pipeline
quality natural gas shall be
fired
Routine furnace tune up in
accordance with NESHAP
subpart DDDDD
Exhaust gas temperature shall
be limited to less than 350 oF
12-mth rolling per furnace
Fuel flow rate, heating
value (HHV), carbon
content, molecular
weight determined
hourly using online gas
chromatograph or
40 CFR 98.34(b)(3)
Exhaust gas temperature
HAP Good Combustion Design & Sections 5.2.2 & 5.2.5 VOC Sections 5.2.2 & 5.2.5
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Emissions Unit Pollutant Control Technology Limit/Averaging Time Compliance Method
Operation & GHG LAER VOC & GHG LAER
Combustion Turbines/Duct Burners
NOx Dry low NOx Burners &
SCR 2 ppmvd @ 15% O2 (1-hr
roll)
22.6 tons/yr (12-mth roll)
including startup & shutdown
113 lb/hr during startup and
shutdown
LAER Limit
NOx CEMS
25 Pa Code § 25
Monitoring
§ 145.70 (Part 75
Subpart H)
§ 145.70 - Heat input
(Part 75 Subpart H)
§ 145.213 - Gross
electric output
VOC CO Oxidation Catalyst & use
of Good Combustion Design
& Operation
1 ppmvd @ 15% O2 (1-hr
roll)
Performance test once
every 5 years using EPA
RM 18 & 25 and
PM/PM10/PM2.5 Use of Natural Gas & Good
Combustion Design &
Operation
0.0066 lb/MMBtu
0.75 grains sulfur/100 dscf
Performance test once
every 5 years using EPA
RM 5 & 202
CO CO Oxidation Catalyst 2 ppmvd @ 15% O2 (1-hr
roll)
14.5 tons/yr 12-mth roll
including startup & shutdown
276 lb/hr during startup &
shutdown
CO CEMS
CO2e/GHG Use of Natural Gas & Energy
Efficient Design
GE G6581
1,030 lb CO2e/MWh (30-day
roll) total facility
340,558 tpy (365-day roll)
Siemens SGT-800
CO2 using Part 75
Appendix G
Calculate CO2e from
CO2 using a factor of
1.0010 as a multiplier
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Emissions Unit Pollutant Control Technology Limit/Averaging Time Compliance Method
978 lb CO2e/MWh (30-day
roll)
353,893 tpy (365-day roll)
total facility
HAP CO oxidation catalyst Comply with requirements in
stayed 40 CFR 63
subpart YYYY
Installation of CO
oxidation catalyst
Operation above vendor
required design operating
temperature
Diesel Engines – Emergency Generators
NOx + VOC Combustion Control
Techniques 4.6 g/hp-hr Use of an engine
certified to achieve this
level
PM/PM10/PM2.5 Combustion Control
Techniques & the use of low
sulfur fuel
0.15 g/hp-hr
Fuel with less than 15 ppmw
sulfur content
Use of an engine
certified to achieve this
level
CO Combustion Control
Techniques 2.6 g/hp-hr Use of an engine
certified to achieve this
level
CO2e/GHG Combustion Control
Techniques 1,151.6 tons/yr (all engines) Fuel usage & emissions
factor
HAP Combustion Control
Techniques 40 CFR 63 subpart ZZZZ 40 CFR 63 subpart ZZZZ
Diesel Engines – Firewater Pumps
NOx + VOC Combustion Control
Techniques 3.0 g/hp-hr Use of an engine
certified to achieve this
level
PM/PM10/PM2.5 Combustion Control
Techniques & the use of low 0.15 g/hp-hr Use of an engine
certified to achieve this
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Emissions Unit Pollutant Control Technology Limit/Averaging Time Compliance Method
sulfur fuel Fuel with less than 15 ppmw
sulfur content
level
CO Combustion Control
Techniques 2.6 g/hp-hr Use of an engine
certified to achieve this
level
CO2e/GHG Combustion Control
Techniques 120.3 tons/yr (all engines) Fuel usage & emissions
factor
HAP Combustion Control
Techniques 40 CFR 63 subpart ZZZZ 40 CFR 63 subpart ZZZZ
Equipment Leaks – Fugitive Components
VOC Enhanced Leak Detection
and Repair
See Section 5.5.1
CO2e/GHG Enhanced Leak Detection
and Repair
See Section 5.5.2
HAP Enhanced Leak Detection
and Repair
See Section 5.5.1
PE Manufacturing Process Vents, Storage, and Handling
VOC VOC containing vents
directed to control system &
limit on residual VOC in
pellets
All VOC containing PE Units
1 & 2 vents located upstream
of and including Product
Purge Bin will be directed to
a VOC control system
All VOC containing PE Unit
3 vents located upstream of
the degasser will be directed
to a VOC control system
The VOC control system
shall achieve a 99.5% VOC
destruction removal
See VOC Control System
Requirements below
VOC content of the
pellets shall be
determined once weekly
using either the beverage
can method (Method 24)
or heated headspace
analysis (Method 3810)
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Emissions Unit Pollutant Control Technology Limit/Averaging Time Compliance Method
efficiency
The residual VOC content in
the resin exiting the Product
Purge Bins at PE Units 1 & 2
shall be less than 50 ppmw
The residual VOC content in
the resin exiting the degasser
at PE Units 3 shall be less
than 50 ppmw
Applicable vents are listed in
Appendix D
PM/PM10/PM2.5 All of the particulate
containing vents in PE Units
1, 2 and 3 shall have
emissions of less than
0.005 g/dscf
Applicable vents are listed in
Appendix D
Baghouses
Performance test once
every 5 years using EPA
Reference Method 5 &
202
HEPA Filters
Manufacturer
specification
Visual inspection
Sintered Metal Filters
Manufacturer
specification
Visual inspection
HAP Section 5.7.1 VOC
LAER
Section 5.7.2 PM LAER
Tanks and Vessels
VOC Tank design and vent Light gasoline and hexene LP Thermal Incinerator
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Emissions Unit Pollutant Control Technology Limit/Averaging Time Compliance Method
controls tanks will be equipped with
internal floating roofs & vent
to LP Thermal Incinerator
Flow equalization, recovered
oil storage, and spent caustic
tanks will vent to the Spent
Caustic Vent Thermal
Incinerator
Pyrolysis tar, diesel
locomotive, and small diesel
fuel tanks (each <20,000
gallons) will vented to carbon
canisters
Destruction Rate
Efficiency 99.5%
Spent Caustic Vent
Thermal Incinerator
Destruction Rate
Efficiency 99%
Carbon canisters shall be
monitored for
breakthrough at times
when there is actual flow
to the carbon canister.
For a single carbon
canister, "breakthrough"
is defined as any VOC
reading above
background. For all
canisters that are
operated as part of a
primary and secondary
system, "breakthrough"
is defined as any reading
of 50 ppm volatile
organic compound
("VOC").
HAP Spent Caustic Vent Thermal
Incinerator 99% Destruction Rate
Efficiency
Cooling Tower
PM/PM10/PM2.5 Mist/drift eliminators 0.0005% drift rate
TDS 2400 ppm (12-mth roll)
Demister specification
TDS measurement in
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Emissions Unit Pollutant Control Technology Limit/Averaging Time Compliance Method
accordance with EPA
Method 160.1
VOC VOC content of circulating
water in process cooling
water tower heat exchange
system
0.5 lb/MMgal
Determine the
concentration of VOC in
the cooling water using
any method listed in 40
CFR Part 136.
HAP VOC content of circulating
water in process cooling
water tower heat exchange
system
40 CFR 63 Subparts XX and
FFFF
40 CFR 63 Subparts XX
and FFFF
Loading Operations
PE Loading PM/PM10/PM2.5 Fabric filter sock (i.e., filter
material designed to inhibit
emissions during loading)
0.01 g/dscf Manufacturer
specification
Visible emissions
Liquid Loading VOC Design and work practices Low Vapor Pressure Organic
Liquids
Vapor pressure of the low
vapor pressure organic liquids
loaded shall not exceed 0.5
psia
Submerged filling or bottom
loading shall be used for
loading of all low vapor
pressure organic liquids
All transport vehicles loaded
shall either be in dedicated
service or shall be cleaned
prior to loading
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Emissions Unit Pollutant Control Technology Limit/Averaging Time Compliance Method
C3+ Liquids
Low leak couplings
Pressurized loading of C3+
liquids
HAP Section 5.11 VOC LAER
VOC Control System LP Thermal
Incinerator VOC/HAP Waste gas minimization &
operation to achieve good
destruction removal
efficiency
Operation in accordance with
approved waste gas
minimization plan
LP Thermal Incinerator
designed and operated to
achieve a 99.5% destruction
rate efficiency
Designed and operated to
achieve 99.5%
Destruction Rate
Efficiency
LP Ground Flare VOC/HAP Waste gas minimization &
operation to achieve good
destruction removal
efficiency
Operation in accordance with
approved waste gas
minimization plan
Root cause analysis for
flaring events that exceed
baseload by 500,000 scf in 24
hour period
Corrective actions consistent
with good engineering
practice
Flare designed to meet
limitations on maximum exit
velocity, as set forth in the
general provisions at 40 CFR
Flaring Vent flowrate
measurement
Steam rate measurement
(if applicable)
Total hydrocarbon
analysis (optional)
40 CFR §60.18 and
§63.11
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Emissions Unit Pollutant Control Technology Limit/Averaging Time Compliance Method
§60.18 & §63.11
Flare operated to meet
minimum net heating value
requirements for gas streams
combusted in the flares, as set
forth at 40 CFR § 60.18 & §
63.11 HP Ground Flares
(2) VOC/HAP Waste gas minimization &
operation to achieve good
destruction removal
efficiency
Operation in accordance with
approved waste gas
minimization plan
Root cause analysis for
flaring events that exceed
baseload by 500,000 scf in 24
hour period
Corrective actions consistent
with good engineering
practice
Flare designed to meet
limitations on maximum exit
velocity, as set forth in the
general provisions at 40 CFR
§60.18 & §63.11
Flare operated to meet
minimum net heating value
requirements for gas streams
combusted in the flares, as set
forth at 40 CFR § § 60.18 &
63.11
Each flare shall be equipped
Flaring Vent flowrate
measurement
Steam rate measurement
(if applicable)
GC analysis to determine
molecular weight and
heating value of the vent
gas
40 CFR §60.18 and
§63.11
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Emissions Unit Pollutant Control Technology Limit/Averaging Time Compliance Method
with automated controls for
supplemental gas flow rate &
steam mass rate (is used for
assist) to the flare
The net heating value of the
combustion gases shall be
determined no less frequently
than once every 15 minutes
when the flare is in use
The net heating value in the
combustion zone shall be
equal to or greater than 500
Btu/scf
A net heating value of 1212
BTU/scf shall be used for
hydrogen HP Elevated Flare VOC/HAP Waste gas minimization &
operation to achieve good
destruction removal
efficiency
Operation in accordance with
approved waste gas
minimization plan
Root cause analysis for
flaring events that exceed
baseload by 500,000 scf in 24
hour period
Corrective actions consistent
with good engineering
practice
Flare designed to meet
limitations on maximum exit
velocity, as set forth in the
Flaring Vent flowrate
measurement
Steam rate measurement
(if applicable)
Total hydrocarbon
analysis (optional)
40 CFR §60.18 and
§63.11
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Emissions Unit Pollutant Control Technology Limit/Averaging Time Compliance Method
general provisions at 40 CFR
§60.18 & §63.11
Flare operated to meet
minimum net heating value
requirements for gas streams
combusted in the flares, as set
forth at 40 CFR § 60.18 & §
63.11
LP Thermal
Incinerator/LP
Ground Flare/HP
Ground Flares
(2)/HP Elevated
Flare
NOx 0.068 lb/MMBtu
PM/PM10/PM2.5 0.0075 lb/MMBtu
CO 0.37 lb/MMBtu
CO2e/GHG 132 lb/MMBtu
HAP Section 5.12 VOC LAER
Spent Caustic Vent
Thermal Incinerator VOC 99% Destruction Rate
Efficiency
Performance test once
every 5 years using EPA
Reference Method 18 [40
CFR 61.355(e) as
referenced by
63.1095(b)(1)].
NOx 0.068 lb/MMBtu
PM/PM10/PM2.5 0.0075 lb/MMBtu
CO 0.37 lb/MMBtu
CO2e/GHG 132 lb/MMBtu
HAP 99% Destruction Rate
Efficiency
Performance test once
every 5 years using EPA
Reference Method 18 [40
CFR 61.355(e) as
referenced by
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Emissions Unit Pollutant Control Technology Limit/Averaging Time Compliance Method
63.1095(b)(1)].
Plant Roads
PM Work Practices Pavement of all roads
Implementation of a road dust
control program
Other Contaminants
SO2 Fuel standard Natural gas containing less
than 0.5 gr/100 dscf sulfur
Use of pipeline natural
gas Appendix D of
40 CFR 75
Ammonia Furnaces
10 ppmvd @ 3% O2
Combustion Turbines
5 ppmvd @ 15% O2
Ammonia monitoring in
accordance with 30 TAC
§117.8130
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5.2 Ethane Cracking Furnaces
As described in Section 3.1, ethane cracking furnaces are large process heaters specially
designed to produce high furnace box temperatures. The high furnace box temperatures
(2,100 to 2,200°F) heat the specially designed furnace tubes up to the temperatures
needed to thermally crack ethane in the presence of steam into ethylene (which occurs at
~1560°F) and byproducts (i.e., tailgas consisting of 85% by volume hydrogen with the
remainder being methane and other gaseous products). During normal operation, the
project’s ethane cracking furnaces will be fired with tailgas containing up to 85% by
volume hydrogen with the remainder being natural gas. As part of the cracking process,
coke is formed on the process side of the furnace tubes. As a result, the tubes in each
cracking furnace are decoked once every 30 to 60 days.21 The actual run length between
furnace tube decoking varies by licensor, design residence time used for the cracking
coils, and the operating severity (percent ethane conversion). During normal operation
and decoking, the furnaces are fired primarily on self-produced tailgas (hydrogen and
methane) with a small quantity of supplemental natural gas. When no ethane cracking is
taking place (e.g., start-up), the furnaces are fired on natural gas until ethane cracking is
started and self-produced tailgas becomes available. During normal operation and
decoking, NOx, CO, VOC, PM, PM10, PM2.5, and trace amounts of SO2 are emitted from
the furnaces. Accordingly, BACT/LAER analyses are included for NOx, VOC,
PM/PM10/PM2.5, and CO. (The project is not subject to BACT or LAER analysis for SO2
because it is not a major source of SO2).
5.2.1 Cracking Furnace NOx/NO2 LAER/BACT Analysis
Nitrogen oxides (NOX) are formed during combustion by two major mechanisms:
thermal NOX and fuel NOX. Thermal NOX results from the high temperature oxidation of
molecular nitrogen in combustion air. As its name implies, thermal NOX formation is
21 The furnace decoking process is described in Section 3.1.2.
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primarily dependent on combustion temperature. Fuel NOX is formed from the direct
oxidation of organic nitrogen compounds in the fuel. Since tailgas (hydrogen and
methane from the cracking process), and natural gas will be combusted in the cracking
furnaces, fuel nitrogen levels will be negligible. As a result, thermal NOX is the primary
NOx formation mechanism.
This control technology analysis addresses emissions of NOx and NO2 from the ethane
cracking furnaces. The proposed project is located in an ozone nonattainment area so a
LAER analysis is provided for the precursor pollutant, NOx. The area is
attainment/unclassified with respect to NO2, so a BACT analysis is required for NO2 as a
PSD pollutant. From a control technology review perspective, emissions of NOx and
NO2 are the same. As a result, the more stringent three-step LAER methodology is used
to determine the proposed LAER limits for NOx and BACT limits for NO2. No
applicable NOx standards have been promulgated for cracking furnaces under 40 CFR
parts 60 and 61.
5.2.1.1 Step 1: Identify Cracking Furnace NOx/NO2 Controls/Limits
A review of the U.S. EPA’s RACT/BACT/LAER Clearinghouse (RBLC) database
identified fourteen process heaters with the following control technologies and techniques
for the control of NOx/NO2 emissions:22
Good combustion practices,
Latest generation low-NOX burners (LNB),23 and
Selective catalytic reduction (SCR).
22 U.S. EPA maintains a database documenting the permitted emissions limits for Reasonably Achievable
Control Technology (RACT) determinations, Best Available Control Technology (BACT)
determinations, and Lowest Achievable Emission Rate (LAER) determinations. This information is
input by the permitting authority and provides some information on the emissions unit and controls. 23 The terminologies for low NOx burner applications for use on boilers and process heaters have evolved
with time and performance, transitioning from low NOx burners (LNBs), to ultra low NOx burners
(ULNB), to current or next generation low NOx burners. For this application, LNBs means the lowest
emitting burner that can currently or in the near future be installed in the furnaces and heaters proposed
for the Project. These burners will include some or all of the combustion control methods including low
NOx burners, internal flue gas recirculation, stage air combustion, over-fire air, and steam injection. The
various burner options will depend on burner-furnace vendor design considerations.
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Other potential NOx control technologies that have been applied at natural gas-fired
boilers and combustion turbines, and which may be considered for applicability through
technology transfer, include:
Flue gas recirculation (FGR) and over-fire air (OFA),
Selective non-catalytic reduction (“SNCR”), and
EMx™.
A brief description of the above listed NOx/NO2 controlled technologies follows. The
potential applicability and technical feasibility of each of these NOX/NO2 control options
are discussed in Step 2.
Good Combustion Practices: Good combustion practice addresses the three “Ts” of
combustion through the design and operation of the combustion device. The three “Ts”
are a summary of fluid flow and chemical reaction principles:
Temperature is the required energy for the initiation of a chemical reaction, in
this case combustion.
Turbulence is the interaction between two fluid streams required to achieve
intermixing of the two, fuel and air in the case of combustion.
Time is the period for the reaction to reach completion.
With respect to the cracking furnaces this means a burner temperature high enough to
ignite the fuel (tailgas), burner turbulence vigorous enough for the fuel constituents to be
exposed to the oxygen in the air and burner/firebox residence time long enough to assure
complete combustion (minimal CO, VOCs and products of incomplete combustion). In
addition to proper design and operation, advanced control systems are employed to
ensure good combustion practices.
Low NOx Burners (LNB): Low NOx burners reduce NOx emissions by managing and
controlling:
The oxygen level in the primary combustion zone to limit fuel NOx formation;
The flame temperature to limit thermal NOx formation; and/or
The residence time at peak temperature to limit thermal NOx formation.
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The most common design approach is to control NOx formation by carrying out the
combustion in stages:24
Staged air burners, or delayed combustion LNBs, are two-stage combustion
burners that are fired fuel-rich in the first stage. They are designed to reduce
flame turbulence, delay fuel/air mixing, and establish fuel-rich zones for initial
combustion. The reduced availability of oxygen in the primary combustion zone
inhibits fuel NOx formation. Radiation of heat from the primary combustion zone
results in reduced temperature. The longer, less intense flames resulting from the
staged combustion lower flame temperatures and reduce thermal NOx formation.
Staged fuel burners also use two-stage combustion, but mix a portion of the fuel
and all of the air in the primary combustion zone. The high level of excess air
greatly lowers the peak flame temperature achieved in the primary combustion
zone, reducing thermal NOx formation. The secondary fuel is injected at high
pressure into the combustion zone through a series of nozzles, which are
positioned around the perimeter of the burner. Because of its high velocity, the
fuel gas entrains furnace gases and promotes rapid mixing with first stage
combustion products. The entrained gases simulate flue gas recirculation. This
approach is referred to as internal or burner flue gas recirculation. Heat is
transferred from the first stage combustion products prior to the second stage
combustion, and as a result, combustion in the second stage is achieved with
lower concentrations of oxygen and lower temperatures than would normally be
encountered. The reduced oxygen concentration and temperature results in
decreased thermal NOx formation.
The early low NOx burner design used the staged air approach to reduce NOx emissions,
while current generation or ultra low NOx burners rely upon staged fuel and burner flue
gas recirculation.
Selective Catalytic Reduction (SCR): SCR is the most widely applied post-
combustion/add-on control technique used to control NOx emissions. A selective
reducing agent (ammonia or urea), diluted with either steam or air is injected through a
grid system into the flue gas upstream of a catalyst bed. On the catalyst surface, the
reagent (reducing agent) reacts with the NOx to form molecular nitrogen and water. The
reaction rate is increased by the presence of excess oxygen. SCR is “selective” in that a
24 How to Incorporate Effects of Air Pollution Control Device Efficiencies and Malfunctions into Emission
Inventory Estimates. Volume II: Chapter 12. July 2000; Eastern Research Group, Inc. Page 12-4.7;
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selective reagent (ammonia or urea) is used to reduce the NOx. The performance of an
SCR system is influenced by five factors:
Flue gas temperature;
Reagent-to-NOx ratio;
NOx concentration at the SCR inlet;
Space velocity (measure of the volumetric feed capacity of a continuous-flow
reactor per unit residence time); and
Condition (activity) of the catalyst.
Below the optimal temperature range, which is defined by the type of catalyst used (i.e.,
platinum versus vanadium based), the catalyst activity is greatly reduced, allowing
unreacted reagent to slip through. Operation at high temperatures can result in catalyst
deactivation.
Flue Gas Recirculation (FGR) and Over-Fire Air (OFA): In applications where
external FGR is installed, a portion of the flue gas is recycled back to the primary
combustion zone. FGR reduces NOx formation through two mechanisms:
Heating in the primary combustion zone of the inert combustion products
contained in the recycled flue gas lowers the peak flame temperature, thereby
reducing thermal NOx formation, and
FGR reduces thermal NOx formation by lowering the oxygen concentration in the
primary flame zone.
The recycled flue gas is either pre-mixed with the combustion air or injected directly into
the flame zone. Direct injection allows more precise control of the amount and location
of FGR. FGR is primarily applied to boilers.
Over-fire air (OFA) is a form of staged air combustion where only part of the required
amount of combustion air enters with the burners, and the remaining air needed to
complete the fuel’s combustion enters in the upper firebox. Lowering the concentration
of combustion air at the burners results in fuel rich combustion, which reduces the
availability of oxygen in the primary combustion zone, inhibiting NOx formation.
Injecting the air needed to complete the fuel combustion in the upper portion of the
firebox has the effect of extending the time of combustion and reducing the overall peak
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combustion temperature. OFA systems are primarily used on coal-fired boilers due to the
large furnace volumes required to completely combust solid fuels.
Selective Non-Catalytic Reduction: SNCR is a post-combustion NOx control
technology in which a selective reagent, either ammonia or urea, is injected into the
exhaust gases to react with NOx/NO2, forming elemental nitrogen and water without the
use of a catalyst. This process is effective in reducing NOx/NO2 emissions within
specific constraints, requiring uniform mixing of the reagent into the flue gas within a
zone of the exhaust path where the flue gas temperature is within a narrow temperature
range of approximately 1600 to 2000°F. To achieve the necessary mixing and reaction,
the residence time of the flue gas within this temperature window must be at least one
half second. The consequences of operating outside the optimum temperature range are
severe. Above the upper end of the temperature range the reagent will convert to
NOx/NO2 and below the lower end of the temperature range the desired chemical
reactions will not proceed and the injected reagent will be emitted as ammonia slip.
EMx™: The EMx™ system (formerly referred to as SCONOX™) is an add-on control
device that simultaneously oxidizes CO to CO2, VOCs to CO2 and water, NO to NO2 and
then adsorbs the NO2 onto the surface of a potassium carbonate coated catalyst. The
EMx™ system does not require injection of a reactant, such as ammonia, as required by
SCR and SNCR and operates most effectively at temperatures ranging from 300°F to
700°F. The overall chemical reaction between NO2 and the potassium carbonate catalyst
is as follows:
2NO2 + K2CO3 → CO2 + KNO2 + KNO3
The catalyst has a finite capacity to react with NO2. As a result, to maintain the required
NOx/NO2 removal rate, the catalyst must be periodically regenerated. Regeneration is
accomplished by passing a reducing gas containing a dilute concentration of hydrogen
across the surface of the catalyst in the absence of oxygen. Hydrogen in the regeneration
gas reacts with the nitrites and nitrates adsorbed on the catalyst surface to form water and
molecular nitrogen. Carbon dioxide in the regeneration gas reacts with the potassium
Shell Chemical Appalachia LLC Plan Approval Application
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nitrite and nitrates to form potassium carbonate, the original form of the chemical in the
catalyst coating. The overall chemical reaction during regeneration is as follows:
KNO2 + KNO3 + 4H2 + CO2 → K2CO3 + 4H2O + N2
The regeneration gas is produced in a gas generator using a two-stage process to produce
molecular hydrogen and carbon dioxide. In the first stage, natural gas and air are reacted
across a partial oxidation catalyst to form carbon monoxide and hydrogen. Steam is
added to the mixture and then passed across a low temperature shift catalyst, forming
carbon dioxide and more hydrogen. The regeneration gas mixture is diluted to less than
four percent hydrogen using steam. To accomplish the periodic regeneration, the EMx™
system is constructed in numerous modules which operate in parallel so that one module
can be isolated and regenerated while the remaining modules are lined up for treatment of
the exhaust gas stream.
5.2.1.2 Step 2: Achieved/Demonstrated Cracking Furnace NOx/NO2 Limits
The application of good combustion practices, LNB, and SCR, separately or in
combination, are well established and demonstrated in process heaters and in cracking
furnaces used to manufacture ethylene. The primary issue related to the application of
these technologies to the ethane cracking furnaces is defining the achievable emission
rate for a specific cracking furnace; and Section 5.2.1 addresses this issue. The technical
feasibility of FGR/OFA, SNCR, and EMx™ are addressed in subsequent sections.
Good Combustion Practices and LNB Technology for Ethane Cracking Furnaces:
Good combustion practices and LNBs are considered to be technically feasible and as a
result applicable to cracking furnaces. Good combustion practices (design and operation)
are an integral part of the design and operation of all current cracking furnaces.
The following parameters affect the level of NOx/NO2 emissions that can be achieved by
a gaseous fuel-fired LNB in heater and furnace applications:
Fuel type,
Combustion air preheat,
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Firebox temperatures, and
Furnace/heater design.
The impact of these parameters on the NOx/NO2 emissions from the proposed ethane
cracking furnaces is discussed below.
Fuel Type: Most gaseous fuel-fired process heaters are fired with natural gas, petroleum
refinery fuel gas, or a combination of the two. These fuels contain a high percentage of
methane (usually greater than 85 percent), which is the primary source of fuel heat
content (Btu per standard cubic feet).
In contrast, the tailgas that will be combusted in the proposed project’s cracking furnaces
will contain up to 85 percent by volume hydrogen with the remaining 15% being
methane. Because the proposed project is a standalone facility, and there are no nearby
facilities to which hydrogen can be exported, all of the byproduct tailgas (hydrogen and
methane) will be used as fuel in the ethane cracking furnaces.
The increased hydrogen concentration in the tailgas to the furnace burners will increase
the formation of NOx/NO2 from the proposed ethane cracking furnaces relative to other
ethylene manufacturing facilities that do not use ethane as a feedstock, or have customers
to which they export hydrogen. Hydrogen has a higher flame temperature, so hydrogen-
containing fuels generate more thermal NOx/NO2.25 For example, at a three percent
excess oxygen concentration, the adiabatic flame temperature for a mixture fuel
containing 80% hydrogen and 20% methane is approximately 3,450°F. In contrast, the
approximate adiabatic flame temperature for 100% methane is approximately 3260°F.
The net result is an increased level of thermal NOx formation because at temperatures
above 2800°F, thermal NOx formation increases exponentially with increases in
25 Figure C.3. Adiabatic Flame Temperatures for CH4 / H2 Mixtures, Ambient Combustion Air;
Appendix C. Burner NOx From Ethylene Cracking Furnaces, Robert G. Kunz, Environmental
Calculations: A Multimedia Approach, by Robert G. Kunz; Copyright 2009 John Wiley & Sons, Inc.
http://onlinelibrary.wiley.com/doi/10.1002/9780470925386.app3/pdf
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temperature.26 The tailgas that will be fired in the proposed project’s cracking furnaces is
expected to generate NOx emission at the burners that are approximately 60 percent
higher than the emissions expected from firing low hydrogen content fuels.27 It should be
noted that the use of higher percentage hydrogen fuel has the advantage of lowering GHG
CO2 emissions.
Tailgas (methane and hydrogen) is a byproduct of the cracking process used to produce
ethylene. The relative amount of hydrogen produced as a byproduct from the process and
as a result burned in the furnace is a function of: 1) the hydrocarbon raw material that is
being cracked, and 2) whether the hydrogen that is generated by the cracking process is
recovered and sold or is used as a fuel. As noted in Section 3.0, ethane is the
hydrocarbon feedstock that will be used by the Project to produce ethylene. Feedstocks
used to produce ethylene at other locations include gas oil, naphtha (the predominate
feedstock), natural gas condensate, and liquefied petroleum gases. The relative amount
of hydrogen that is produced is a function of the hydrogen to carbon ratio of the
feedstock. Liquid feedstocks generate less hydrogen as a byproduct relative to ethane.28
However, a primary purpose of this project is to utilize ethane generated as a byproduct
from natural gas production in the Marcellus/Utica region, and use of alternative
feedstocks to reduce hydrogen are not consistent with the project’s purpose.
Combustion Air Preheat: Combustion air preheat is an effective method for reducing
fuel consumption for process heaters, but in some situations (as here) it may contribute to
increased production of NOx/NO2. Preheating the combustion air using the hot flue
gases from the heater reduces fuel consumption. This is typically accomplished by
installing an air to flue gas heat exchanger prior to the stack. Although the heat recovery
26 Page 4-1; USEPA Alternative Control Techniques Document—NOx Emissions from Process Heaters,
EPA-453/R-93-034. 27 Burner NOx From Ethylene Cracking Furnaces, Robert G. Kunz, Environmental Calculations: A
Multimedia Approach, by Robert G. Kunz; Copyright 2009 John Wiley & Sons, Inc.
http://onlinelibrary.wiley.com/doi/10.1002/9780470925386.app3/pdf 28 Ethane cracking generates four times more hydrogen and one-third less methane than naphtha cracking.
See Table 2 of “Olefins from conventional and heavy feedstocks: Energy use in steam cracking and
alternative processes”; Received June 1, 2004. http://igitur-archive.library.uu.nl/chem/2007-0621-
201429/NWS-E-2006-3.pdf
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reduces fuel consumption, preheating the combustion air increases the formation of
NOx/NO2 emissions because the preheated air increases the temperature in the
combustion zone.
However, increasing the combustion air temperature in an ethane cracking furnace from
ambient to 350°F would increase the formation of NOx/NO2 from the furnace by
55 percent when burning high hydrogen containing fuel (which is the normal expected
tailgas fuel) and by 65 percent when burning natural gas or methane (the backup fuel).29
For the proposed ethane cracking furnaces, the heat recovered from the furnace’s hot flue
gases will be used to generate high pressure steam and preheat water for steam
generation. Thus, good overall process thermal efficiencies will be obtained without
preheating the combustion air and increasing the NOx/NO2 emissions rate from the
cracking furnaces.
Firebox Temperature: Firebox temperature is the average temperature within the
process heater or boiler where combustion takes place. As noted above, thermal NOx
formation increases exponentially with increasing flame temperature, and the flame
temperature is directly related to the firebox temperature. Therefore, applications
requiring high firebox temperatures, such as steam-methane-reformers and ethane
cracking furnaces, have higher inherent NOx emissions rates relative to applications with
medium to low firebox temperatures.30 Steam-methane-reformer (SMR) heaters operate
with firebox temperatures of 1800 to 1900 ºF. In contrast, ethane cracking furnaces
operate with firebox temperatures of 2100 to 2200 ºF.31 For comparable furnaces (i.e., a
comparison of SMR furnaces to ethane cracking furnaces), this increase in firebox
29 Id. Table C.3. 30 Maryland Industrial Boilers Emissions Report, September 2005. Maryland Department of Natural
Resources report DNR 12-10212005-70 (PPRP-134), at page 18. 31 Approximate Temperatures in Process Furnaces; Appendix C. Burner NOx From Ethylene Cracking
Furnaces, Robert G. Kunz, Environmental Calculations: A Multimedia Approach, by Robert G. Kunz;
Copyright 2009 John Wiley & Sons, Inc., at Table C.2.
http://onlinelibrary.wiley.com/doi/10.1002/9780470925386.app3/pdf
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temperature has been shown to result in a doubling of the NOx emissions (50 to 100 ppm
at 3% excess oxygen).32
As previously noted, to remove the coke deposited on the furnace tubes, ethane cracking
furnaces are decoked once every 30 to 60 days. Because coke inhibits the rate of heat
transfer, the cracking furnace firebox temperatures must be increased over the run length
as the amount of coke deposited increases. A typical start-of-run (SOR) temperature is
2160°F and a typical end-of-run (EOR) is 2185°F. Thus, NOx/NO2 formation increases
over the run period as the firebox temperatures are increased to overcome the deposition
of coke. To protect the tubes from thermal damage, furnace decoking is initiated when
the cracking tube skin temperature reaches a predetermined limit.
Furnace/Heater Design: Ethane cracking furnaces are very different from boilers and
other process heaters in both their design and operation. As one burner vendor states
“Cracking furnaces subject burners to the most abusive firing environment of all process
heaters.”33 The proposed cracking furnaces will have very high firebox temperatures for
two reasons: 1) the use of ethane as a feedstock requires higher cracking temperatures
relative to other feedstocks, and 2) the previously discussed high hydrogen content of the
fuel.
To obtain and operate at the high firebox temperatures required to crack hydrocarbons,
the burner/furnace designs for cracking furnaces differ significantly from boilers and
other process heaters. Typical boiler and process heater designs have an open firebox
with the radiant tubes located along the sidewalls of the firebox. The burners in these
applications fire into the center of the firebox. In contrast, ethane-cracking furnaces have
taller fireboxes with the radiant (cracking) tubes in the center of the firebox. In a
cracking furnace, floor and wall burners fire up along the refractory sidewalls to
minimize the possibility of flame impingement on the cracking tubes.
32 Id. Figures C.5 and C.6 for conventional burners and with no air preheat. 33 https://www.callidus.com/Documents/Burner_bro.pdf
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Due to the differences in design, firebox temperatures and hydrogen content of the fuel,
the proposed cracking furnaces will have higher NOx emission rates than a typical boiler
or process heater. The current low NOx burner technology being used in a typical boiler
or process heater can achieve NOx emission rates of 0.03 pound per million Btu
(lb/MMBtu) or less. However, as discussed below, emission rates from well designed
and well operated ethane cracking furnaces are much higher.
The higher firebox operating temperatures required by ethane cracking furnaces and
higher flame temperatures due to the high hydrogen content of the fuel result in burner
operating issues not seen in boilers and other types of process heaters. As a result, the
staged burners that are used to achieve reduced NOx/NO2 in other types of boilers and
process heaters can plug and be thermally damaged at these higher temperatures. Staged
fuel burners have small diameter nozzles arranged around the perimeter of the burner that
accomplish the fuel staging required to reduce NOx/NO2 emissions by injecting fuel into
the primary combustion flame. This placement of small diameter nozzles close to the
primary combustion flame exposes the small diameter nozzles to high heat intensities,
making these nozzles much more prone to plugging and thermal damage. The resultant
damage to the small diameter nozzles impedes the burner’s ability to reduce NOx/NO2.
Industry experience with staged fuel burners in cracking furnace applications has
identified the following issues that impact the achievable NOx/NO2 emissions rates:
When the gas velocity in the primary combustion zone is lower than the flame
velocity, the flame front recedes into the burner tips (flashback) causing
mechanical/structural thermal damage. The potential flashback is increased when
the fuel contains hydrogen, which has a very high flame velocity.
At increased temperatures, hydrocarbons in the fuel are more likely to undergo
pyrolysis and form coke in the burner nozzle tips and plug the tips.
Too large of an exposed burner area inside the firebox with insufficient or
damaged insulation, in combination with insufficient cooling from the fuel gas
inside the burner riser, can result in high internal burner riser temperatures and
coke formation/carburization in the riser with subsequent plugging. High
hydrogen content in the fuel reduces the fuel’s specific heat capacity, which in
turn reduces the amount of cooling provided by the fuel.
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Heat transfer through the nozzle tip is a function of velocity as well as mass flow.
During conditions of low mass flow (turndown or plugging), the external burner
tips can become severely fouled.
As a result, the LNBs installed in cracking furnaces are chosen with these operational and
maintenance issues in mind and do not achieve the deep reductions achieved by the LNBs
that can be installed in process heater and boiler applications.
Permit Limits: To exemplify the NOx/NO2 levels achievable by LNBs, the permitting
precedents were divided into two groups: 1) permits where only LNBs were used for
control, which were found in the precedents ten years prior to 2012 and 2) permits where
both LNB and SCR are used (recent permits). Table 5-2 presents a summary of the
results from a review of the RBLC database with respect to limits established for cracker
furnace installations during the ten year period prior to 2012. All three of the
determinations identified are based on the use of burner technology. The hourly NOx
limits range from 0.075 to 0.08 lb/MMBtu and annual limit is the same for all three,
0.06 lb/MMBtu. The BASF FINA cracking furnaces are fired with a combination of
natural gas and refinery gas.34,35 This facility is known to supply hydrogen to the pipeline
and to a nearby refinery for use in the refinery’s hydrotreaters. In addition, the feedstock
for two facilities identified in Table 5-2 is naphtha, where the amount of hydrogen
produced per unit of ethylene production is much less than for the proposed ethane
cracking project. As a result, the amount of hydrogen in the fuel used by these cracking
furnace precedents is much less than the proposed Shell project.
During the past two years, at least five companies have filed air permit applications for
olefin (ethylene) plant expansion or new plant projects located in the Houston-Galveston-
Brazoria ozone nonattainment area. Three of these companies recently received their
permits from the Texas Commission on Environmental Quality (TCEQ). The
information obtained from a review of the permit applications and permits issued for
34 The TOTAL petroleum refinery formerly the FINA petroleum refinery. 35 See Figure 3 of “Upgrade of a Tail-End Acetylene Converter BASF FINA Petrochemicals Limited
Partnership Naphtha Cracker”, April 25, 2006.
http://kolmetz.com/pdf/Upgrade%20NROC%20Converter_2006%20EPC%20Meeting.pdf
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Table 5-2. Summary of RBLC Ethylene Cracking Furnace NOx Emissions Limits (prior to the past two years)
RBLC
ID Facility Name
Permit
Date Primary Fuel
Heat Input
(MMBtu/hr)
Control
Technology
Hourly Limit
(lb/MMBtu)
TX-
0511
BASF FINA
Ethylene/Propylene
Cracker
02/03/2006
Not indicated,
probably refinery or
natural gas – see
text
302
(1 furnace) Burner Technology 1 0.08
TX-
0511
BASF FINA
Ethylene/Propylene
Cracker
02/03/2006
Not indicated,
probably refinery
or natural gas – see
text
441.7
(8 furnaces) Burner Technology 1 0.08
TX-
0475
FORMOSA
Point Comfort, TX 5/9/2005 Fuel Gas
250
(3 pyrolysis
furnaces)
Internal Flue Gas
Recirculation and
Staged Fuel Gas
Ultra Low-NOx
Burners
0.075 2
1. From TCEQ permit number 36644, PSD-TX-903, and N-007; February 2010.
2. TCEQ permit 19169 MAERT verified RBLC lb/hr and tpy rates.
Shell Chemical Appalachia LLC Plan Approval Application
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Table 5-3. Summary of Recent Ethylene Cracking Furnace NOx Emission Limits
Permit Date
Facility Name &
Location Permitted Fuel
Heat Input
(MMBtu/hr)
Hourly Limit
(lb/hr)
LNB+SCR Short
Term Limit
(lb/MMBtu)
LNB+SCR
Annual Limit
(lb/MMBtu)
5/2012 1
(2/2103
draft permit)
ExxonMobil
Baytown, TX
Natural gas or blend
of natural gas and
tailgas
575 2
(8 furnaces) 143.79
0.015
24-hour rolling
(8 furnace cap)
0.01
(8 furnace cap)
08/06/2013 3
(permit)
Chevron/Phillips
Cedar Bayou, TX
Plant fuel gas,
ethane, or natural
gas.
500
(8 furnaces)
32.50 (SCR not
operating &
decoking)
(~
0.065 lb/MMBtu)
0.015 (24-hr roll)
12.5 lb/hr (hourly)
(~0.025 lb/MMBtu)
0.010
(8 furnace cap)
11/14/2012 4
(permit)
Equistar
Channelview, TX
OP-2
Natural gas &
limited use of
hydrogen 5
640
(1 furnace) 38.4 None found
25.71 tpy
(~0.01 lb/MMBtu)
1/23/2013 6
(permit)
Equistar
Channelview, TX
OP-1
Natural gas &
limited use of
hydrogen 7
640 max
587 annual 7
(2 furnaces)
12 6 lb/hr 0.01
7/16/2012
(permit) 8
BASF FINA
Port Arthur, TX
Natural gas or
cracker off gas
(tailgas)
487.5
(1 furnace)
48.75 (startup &
short term spikes)
(~ 0.1 lb/MMBtu)
0.025 hourly 0.01
1. ExxonMobil Chemical Company; New Source Review Permit Application for Ethylene Expansion Project; Baytown Olefins Plant,
Baytown, TX; May 2012. TCEQ Draft Special Conditions & Maximum Allowable Emission Rates Permit Number 102982 (no dates).
2. Based on 5,037,000 MMBtu/yr / 8760 hr/yr; Appendix A; ExxonMobil Greenhouse Gas Prevention of Significant Deterioration Permit
Application for Ethylene Expansion Project, Baytown, TX.
3. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Numbers 1504A, PSDTX748M1, and N148.
4. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Numbers 2933/PSDTX1270/N140 (11/2012).
5. Permit Amendment Application Greenhouse Gas Emissions, Equistar Chemicals, Channelview, TX; Olefins Production Unit No. 2,
September 2011.
6. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Numbers 18978 PSDTX752M5, N162, 1/2013.
7. Permit Amendment Application Greenhouse Gas Emissions, Equistar Chemicals, Channelview, TX; Olefins Production Unit No. 1,
September 2011.
8. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Numbers 36644, PSDTX903M3, and N007M1, 7/2012.
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these projects is summarized in Table 5-3. Not presented is the information for a project
at the Dow Chemical Freeport, Texas facility for which the application is currently
pending. Because of the relationship of fuel composition to the rate of NOx emissions
achievable through the use of low NOx burner technology, the fuels that will be fired by
the proposed new ethane cracking furnaces are also presented.
The permit application for the ExxonMobil Baytown Olefins Plant covers the
construction of eight new ethane cracking furnaces equipped with ultra low NOx burners
and SCR. A combined draft state and PSD permit has been issued by TCEQ. 36 This
permit was appealed and the results from the contested case hearing are now available. 37
During normal operation, the fuel for the ExxonMobil furnaces will be “imported natural
gas or a blend of process gas that consists of imported natural gas and tailgas.”38 The
draft permit for the ExxonMobil project includes the proposed NOx limits of
0.015 lb/MMBtu as a 24-rolling average of eight furnaces, and 0.01 lb/MMBtu as an
average of eight furnaces on a 12-month rolling basis. These lb/MMBtu limits are the
same as those included in the Chevron/Phillips permit and as proposed by Dow Chemical
in its permit application.
As noted, the lb/MMBtu limits for ExxonMobil and Chevron/Phillips precedents are not
applicable during the following activities:39
Hot Steam Standby Mode, defined as the period when the furnace is firing at 50%
or less of the maximum allowable firing rate and no hydrocarbon feed is being
charged to the furnace.
36 Draft special conditions and maximum allowable emission rate documents for permit 102982 are not
dated. The final permit was pending as of December 30, 2013. 37 State Office of Administrative Hearings, Cathleen Parsley. Chief Administrative Law Judge, SOAH
Docket No. 582-13-4611; TCEQ Docket No. 2013-0657-AIR; In Re: Application 0/ Air Quality Permit
No. 102892 for the Construction of a New Ethylene Production Unit at ExxonMobil's Baytown Olefins
Plant, located in Harris County, Texas, December 18, 2013. 38 ExxonMobil Greenhouse Gas Prevention of Significant Deterioration Permit Application for Ethylene
Expansion Project; May 2012, page 2-1. 39 Draft special conditions and maximum allowable emission rate documents for permit 102982 are not
dated. Special Condition No. 21, page 15.
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Decoking Mode, defined as the period that starts when air is introduced to the
furnace for the purpose of decoking and ends when air is removed from the
furnace.
Start-up Mode, defined as the period beginning when fuel is introduced to the
furnace and ending when the SCR catalyst bed reaches its stable operating
temperature. A planned startup for each furnace is limited to 24 hours at 25% or
less of the maximum allowable firing rate, except during startups requiring
refractory dry out which is limited to 72 hours at 25% or less of the maximum
allowable firing rate.
Shutdown Mode, defined as the period beginning when the SCR catalyst bed first
drops below its stable operating temperature and ending when the fuel is removed
from the furnace.
Feed in Mode, defined as the period beginning when hydrocarbon feed is
introduced to the furnace and ending when the furnace reaches 70% of the
maximum allowable firing rate.
Feed out Mode, defined as the period beginning when a furnace drops below 70%
of the maximum allowable firing rate and ending when hydrocarbon feed is
isolated from the furnace.
During these periods of operation, the eight ExxonMobil furnaces are subject to a mass
emissions rate of 143.79 lb/hr. At full load, which is equal to 575 MMBtu/hr, this mass
rate is roughly equivalent to 0.25 lb/MMBtu if only one of the two furnaces are
experiencing one of the listed activities. For two furnaces experiencing one of the listed
activities (i.e., the more likely scenario), the rough equivalency would be
0.125 lb/MMBtu. The concentration of hydrogen in the fuel gas that will be fired by the
ExxonMobil furnaces will be much lower than will be fired by the proposed Shell project
furnaces.
In August 2013, Chevron/Phillips received state and PSD permits from TCEQ for the
addition of eight cracking furnaces at the Cedar Bayou, TX facility. The permit
application states that LNBs and SCR will be used to control NOx emissions. The fuel
used to fire the furnaces will be process off gases (i.e., tailgas) supplemented with natural
gas when necessary. “Typically, the ethane steam cracking furnaces will combust plant
tailgas (“fuel gas”); however, the furnaces may also operate on pipeline quality natural
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gas.” 40 During decoking, there is a short-term mass emissions limit of 48.75 lb/hr when
the SCR is not operating. This rate appears to fulfill the same objective as the
ExxonMobil activities based condition.
Equistar submitted two separate applications covering the addition of new cracking
furnaces at each of its Olefins Plants located at the Channel View, TX facility (i.e., OP-1
and OP-2). State and PSD permits were issued by TCEQ for new cracking furnaces at
OP-1 and OP-2 in January 2013 and November 2012, respectively. The primary fuel for
these cracking furnaces is natural gas with limited use of hydrogen. The annual permit
limits for both the OP-1 and OP-2 furnaces is 0.01 lb/MMBtu. Based on the available
information, there appear to be two hourly limits for the new furnaces at OP-1: 6 lb/hr
and 12 lb/hr covering normal and startup operations, respectively. No information related
to the other activities defined by the ExxonMobil permit was identified in the Equistar
permit. Based on a review of the maximum emissions rate table for the Equistar permit,
it appears that there is also a short-term limit of 38.4 lb/hr intended to cover operation of
the furnaces when the SCR is not in service. No information related to the other
activities defined by the ExxonMobil permit was identified in permitting records for
either of the other two projects presented in Table 5-3.
In July 2012, BASF FINA received state and PSD permits for an additional cracking
furnace equipped with LNBs and SCR.41 The permit limits for the new furnace are:
0.01 lb/MMBtu as an annual average, 0.025 lb/MMBtu/hr for a maximum hourly during
normal operation, and 48.75 lb/hr during startup and short term spikes. The form of the
limits for the BASF FINA permit are similar to the ExxonMobil and Chevron/Phillips
precedents in that there are hourly and annual lb/MMBtu limits for normal operation and
an hourly mass emissions limit covering alternate operating scenarios. Of note is the fact
that the 0.01 lb/MMBtu annual limit is consistent with the other precedents and the
40 Chevron Phillips Chemical Company LP; Cedar Bayou Plant; New Ethylene Unit 1594; Greenhouse Gas
PSD Permit Application; December 2011, page 17, 41 BASF FINA Petrochemicals LP, Application for Air Permit Amendment for the 10th Furnace Project;
March 11, 2011.
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0.025 lb/MMBtu hourly rate that is consistent with the Chevron/Phillips facility. The
BASF FINA furnace will use natural gas or cracker off gas as its fuel. The hydrogen
produced by the cracking process will be exported to Port Arthur Refinery (PAR) and to
a pipeline. Thus, the level of hydrogen in the fuel-fired in the new BASF FINA cracking
furnace will be much lower than is proposed by Shell.
In summary, the past and recent precedents for ethane cracking furnaces indicate the
following:
All of the prior (pre-2012) precedents (i.e., Table 5-2) covering 12 cracking
furnaces are fired with a fuel that is much lower in hydrogen content than the
proposed Project. The short-term, hourly NOx limit for these furnaces range from
0.075 to 0.08 lb/MMBtu. The annual NOx limit for all of the furnaces is
0.06 lb/MMBtu.
All of the six most recent precedents (i.e., Table 5-3) covering over 20 furnaces
have some form of an annual NOx limit (single furnace or group cap) of
0.01 LB/MMBtu.42
The most stringent short-term limit based on these recent precedents is
0.015 lb/MMBtu on rolling 24-hr average basis.
All of the precedents use mass rate hourly limits during alternate activities,
similar to those defined by the draft ExxonMobil and Chevron/Phillips permits.
None of the recently permitted projects have begun operation, so none of these
limits have been demonstrated in practice.
In considering the above precedents, it is notable that a number of factors result in the
high level of hydrogen in the process gas (~85% by volume) produced by the Project’s
cracking furnaces, resulting in a higher level of hydrogen in the tailgas that will serve as
the primary fuel for the cracking furnaces. The main factors are:
1) Hydrogen will be produced in large quantities as a co-product with ethylene.
Nearly all of the co-produced hydrogen and methane will be burned in the ethane
cracking furnaces. This will result in a large volume of hydrogen in the fuel gas
that is combusted in the cracking furnaces (~85 volume percent of hydrogen with
the balance being almost entirely methane). By contrast, natural gas usually
contains no hydrogen and is composed primarily of methane with other light
42 Based on a review of the technical support documents for these precedents, this level is considered to be
LAER for this class or category in Texas.
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hydrocarbons. At sites where refinery fuel gas is available, the hydrogen content
in the refinery fuel gas is usually less than 15 volume percent.
2) The proposed facility will be a self-contained, ethane to chemicals manufacturing
site for producing finished chemicals such as polyethylene from ethane feedstock.
The facility will be located at an isolated site and will not be integrated with other
petrochemical or oil refining sites. Accordingly, nearly all intermediate chemicals
produced will be used at the site to manufacture finished chemicals.
It should be noted that hydrogen has many favorable combustion characteristics,
including zero CO2 emissions and extremely high flame speed, which results in
exceptional combustion stability. In many respects, it is an excellent fuel; however it also
has a high flame temperature that together with other combustion characteristics results in
an increased rate of NOx emissions. Robert G. Kunz describes this effect in detail in his
paper entitled “NOx From Ethylene Cracking Furnaces” (included in Appendix F).43
More specifically, in that paper, “Table C.3. Predicted Ethylene Furnace NOx Peak
Values, Burners and Air Preheat as Shown” can be used to predict NOx emissions as a
function of fuel gas hydrogen content.
When the hydrogen is recovered for sale or other use and not used as fuel for the
furnaces, the hydrogen content in the tailgas that is combusted in the cracking furnaces is
in a range between 10 and 30 volume percent. Table C.3 shows that a fuel gas with 10 to
30 volume percent hydrogen has a predicted NOx emission rate of 0.041 to 0.043 lb
NOx/MMBtu (HHV) from LNBs (without air preheat). This is a design number though,
not a permit limit. Because burners foul over time, NOx emissions increase over the run
length between turnarounds. As a result, permit limits must account for this impact.
The cracking furnace precedents presented and discussed above, which had short-term
NOx limits of 0.06 lb/MMBtu to 0.065 lb/MMBtu for burners fired with lower level
hydrogen fuel (i.e., 10 to 30 volume percent), illustrate this fact. Based on the
information presented in Table 5-3 (for the case of no air preheat), the Project’s cracking
43 Burner NOx From Ethylene Cracking Furnaces, Robert G. Kunz, Environmental Calculations: A
Multimedia Approach, by Robert G. Kunz; Copyright 2009 John Wiley & Sons, Inc.
http://onlinelibrary.wiley.com/doi/10.1002/9780470925386.app3/pdf
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furnaces, which will be fired with a fuel having ~85 volume percent hydrogen, will
produce NOx at a rate of ~0.06 lb/MMBtu where the same LNBs are used.
Selective Catalytic Reduction Technology for Ethane Cracking Furnaces: SCR
systems have been applied at several ethane cracking furnaces in the United States, and
are considered to be technically feasible for application on the proposed project’s
cracking furnaces. Although not in the RBLC database, Shell Chemical has extensive
experience using LNBs and SCR for NOx control on cracking furnaces. Shell received a
permit for the restart of the Deer Park, TX Olefins Plant Number 2 in August 2000.
These ten naphtha based cracking furnaces were retrofitted with low NOx burners to
meet permit limits of 0.08 lb NOx/MMBtu on an hourly basis, 0.06 lb/NOx/MMBtu on
an annual basis, and Selective Catalytic Reduction (SCR) to meet a limit of 0.03 lb
NOx/MMBtu on an annual basis averaged across all ten furnaces.44
As presented in Table 5-3, more recent precedents have been set with annual emission
limits of 0.01 lb NOx/MMBtu on a rolling 12-month basis, the TCEQ presumptive
BACT requirement for process furnaces and heaters.45,46 Three of the precedents establish
limits for individual cracking furnaces, and two have limits based on caps across eight
cracking furnaces.
Based on a comparison of the permitted limits for LNB only in Table 5-2 to recent
projects listed in Table 5-3 based on LNB and SCR, the expected average annual
performance of the SCR system ranges from 75 to 85 percent.47 There are two reasons for
the apparent somewhat low SCR performance. At end of run before shutdown for burner
maintenance, the burners are fouled with coke and the LNB emission rates are higher
44 Texas permit 3219 & PSD-TX-974; August 2000; Condition 14. 45 TCEQ Chemical Sources Current Best Available Technology (BACT) Requirements Process Furnaces
and Heaters, last revision Date 08/01/2011.
http://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bact/bact_processfu
rn.pdf 46 In Texas if the proposed NOx limit for a process furnace or heater is greater than 0.01 lb NOx/MMBtu,
the applicant must undergo case-by-case review, and submit cost data to justify a higher NOx limit. 47 77% = [1 - 0.015 lb/MMBtu/0.06 lb/MMBtu]*100% and 85% = [1 - 0.010 lb/MMBtu/0.065 lb/MMBtu]
*100%.
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than 0.06 and 0.065 lb/MMBtu. The other reason is as previously discussed, ethane
cracking furnaces operate at high temperatures to provide the heat necessary to thermally
crack hydrocarbons such as ethane. These high furnace temperatures translate into high
radiant tube skin temperatures in the furnace radiant section (lower part of the furnace).
As a result, the radiant tubes are made of special metal alloys and must be replaced every
two to three years. Ethane cracking furnaces typically employ radiant tube-metal alloys
containing upwards of 35 percent chromium.48
Ethane cracking furnaces controlled with SCR in Japan and the United States have
experienced a more rapid decline in SCR catalyst activity than would be expected for a
clean fuel/flue gas application (natural gas and refinery gas-fired process heaters, boilers,
and combustion turbines). At one Japanese ethylene plant, deactivation of 70% to 80%
from initial conditions was observed after one year of operation, versus an originally
anticipated deactivation rate of less than 10%. The premature loss of SCR catalyst
activity in that case was ascribed to chromium compounds condensing on the catalyst
surface. The exact mechanism is unknown at this time, but steam-methane reformers
equipped with SCR have a similar high rate of catalyst deactivation, as the process tube
metallurgy for steam-methane reformers is similar to that of ethane cracking furnaces.49
The chromium compounds that pass through the SCR are deposited on the downstream
convection section tubes in the form of black chromium oxide scale.
The more rapid SCR catalyst deactivation has two important impacts on ethane cracking
furnace applications. First, the expected catalyst life is reduced, and second the catalyst
performance (control efficiency) will drop over the three to four years of operation before
a furnace rebuild or a major maintenance shutdown of the plant. As a result, unlike
process heaters, boilers, or combustion turbines, special considerations must be given to
the NOx reductions achievable by an SCR in a cracking furnace application.
48 SCR Treatment of Ethylene Furnace Flue Gas, ICAC (Institute of Clean Air Companies) Forum ’02,
February 2002; Robert G. Kunz and T. Robert von Alten; Cormetech, Inc, page 5.
http://www.cormetech.com/brochures/ICAC2001%20Paper%20-
%20SCR%20Treatment%20of%20Ethylene%20Furnace%20Flue%20Gas.pdf 49 Ibid. page 8 & 9.
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SCR system design considers many variables. The major variables include the amount of
catalyst, type of catalyst, operating temperature of catalyst, catalyst life, the allowable
ammonia slip, and the desired NOx reduction. For the proposed Project’s cracking
furnace SCR systems, there are two end-of-run (EOR) periods that must be
accommodated over the three to four years of operation for radiant coil life. As
previously noted, cracking furnaces go through a decoking process every 30 to 60 days.
As coke builds up on the inside of the radiant tubes over the 30 to 60 day cycle, firebox
and tube temperatures must be increased to overcome the insulating effect of the coke
deposits in the radiant tubes at constant yield. As a result, the NOx emissions at EOR,
just before decoking, are higher due to the increased firebox and tube temperatures. This
requires a higher percentage NOx removal by the SCR just before decoking to maintain
compliance with the NOx permit limits. There is a three to four year EOR cycle for the
SCR system catalyst replacement. As a result of the two EOR cycles for the cracking
furnace decoking and SCR catalyst replacement, actual NOx reduction levels for ethylene
cracking furnaces are less than 90 percent on a short term and annual basis.
The degradation of the SCR catalyst with time is recognized in the proposed permit limits
for one of the Texas ethylene expansion project applications. The draft permit for the
ExxonMobil Baytown facility contains a combined limit of 0.015 lb/MMBtu over the
eight (8) furnaces on a 24-hour rolling basis, and an annual combined limit of
0.010 lb/MMBtu over the eight (8) furnaces. The combined limits allow the SCR units,
which have recently undergone catalyst upgrades, to compensate for other units where
the SCR catalyst is approaching the end of its useful life.
Flue Gas Recirculation and Over-Fire-Air: Although external FGR and OFA have
been used extensively on natural gas-fired boilers, this technology has not been
demonstrated to function efficiently on cracking furnaces. This is because unlike natural
gas-fired boilers, which typically have a few burners (one to four), cracking furnaces
have hundreds of burners. In addition, the low NOx burners used in furnaces are
designed with internal flue gas recirculation and internal air/fuel staging. As a result, the
benefit of external FGR and OFA is negated. Additionally, boilers and typical process
heaters have open fireboxes; the tubes are on the firebox walls. Cracking furnaces have
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tubes hanging down the center of the firebox, making the injection of flue gas or air
across the firebox without causing flame impingement on the tubes impractical. Due to
these significant technical differences between gas-fired boilers and the proposed ethane
cracking furnaces, external FGR and OFA have not been demonstrated to function
effectively on ethane cracking furnaces. Thus, external FGR and OFA are removed from
further consideration.
Selective Non-Catalytic Reduction: The SNCR reaction occurs in the temperature
window of 1,600°F to 2,000°F. For large utility boilers where most SNCR systems have
been installed, this temperature window is in the upper furnace section before the
convection tubes. This area of a typical utility boiler is clear of convective tube
obstructions, allowing for injection of the reagent across the upper furnace area. Even
under ideal conditions, the NOx removal capability of SNCR (30 to 70 percent) is much
less than that of SCR.
For the proposed Project’s cracking furnaces, the ideal temperature window for an SNCR
reaction is in the convective tube section of the furnace. This makes it difficult to inject
the SNCR reagent (ammonia or urea) across the furnace, significantly limiting good
mixing of the reagent with the flue gases. In turn, this limits the potential NOX/NO2
reduction, and increases the amount of unreacted ammonia in the flue gases going to the
atmosphere. Additionally, injection of the reagent into the tube sections of the furnace
can result in accelerated corrosion and erosion of the process tubes. Due to the very
limited NOX/NO2 reduction achievable and potentially high ammonia slip emissions, the
use of SNCR is considered to be technically infeasible for cracking furnaces. The RBLC
database review and the review of recent permit applications submitted in Texas for new
cracking furnaces did not identify the use of SNCR for NOx control on cracking
furnaces.
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EMx™: There are currently six EMx™/SCONOX™ units in commercial installations
worldwide. All are on natural gas-fired combustion turbines of 45 MW or less.50 There
are no known installations on process heaters or cracking furnaces. There are a number
of differences between the operation and flue gas characteristics of combustion turbines
and the proposed cracking furnaces. Specifically, combustion turbines are essentially
constant flue gas flow combustion devices no matter what the load. Process
heater/furnace flue gas flow rates are directly proportional to load. The impact on the
load following ability of the EMx™/SCONOX™ is unknown with respect to cracking
furnaces. Additionally, the concentration of NOx/NO2 in the flue gases from the
cracking furnaces is much higher than that of the combustion turbine flue gases. This is
due to the high oxygen content of the combustion turbine flue gas (~15% O2) relative to
the cracking furnace flue gas (~3% O2). The impact of the flue gas oxygen content and
NOx/NO2 concentration on the EMx™/SCONOX™ is unknown with respect to cracking
furnaces. Additionally, the flue gas flow from the cracking furnaces and NOx/NO2
concentration during furnace tube decoking are significantly different from that during
normal operation. The impact on the load following ability of the EMx™/SCONOX™
during tube decoking is unknown.
Because the SCR technology demonstrated on cracking furnaces can achieve reductions
in NOx/NO2 comparable to EMx™ / SCONOX™, taking on the risk of an
undemonstrated technology is not warranted. In addition, the EMx™ / SCONOX™
regeneration process is mechanical in nature and the associated maintenance practices are
much different (higher cost) from that of the SCR technology, which relatively speaking
has very low maintenance requirements. For these reasons, the EMx™/SCONOX™
technology is not considered further by this analysis.
50 The heat input for a 45 MW combined cycle combustion turbine would be approximately 300
MMBtu/hr, assuming an efficiency of 50 percent.
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5.2.1.3 Step 3: Establish Cracking Furnace NOx LAER Limits
Based on the permit precedents presented in Table 5-3, the following NOx/NO2 emission
limits are proposed as LAER/BACT for the proposed ethane cracking furnaces:
0.010 lbs/MMBtu per furnace on a 12-month rolling average basis for each furnace,
and
0.015 lbs/MMBtu per furnace on an hourly average basis.
The annual and hourly lb/MMBtu limits would not apply during the following
activities; instead, each furnace shall not exceed a mass hourly NOx emissions rate of
31.1 lbs/hr.51
Cold Start-up Mode, defined as the period beginning when fuel is introduced
to the furnace and ending when the SCR catalyst bed reaches its design
operating temperature.
Shutdown Mode, defined as the period beginning when the SCR catalyst bed
first drops below the catalyst bed design operating temperature and ending
when the fuel is removed from the furnace.
Decoking Mode, defined as the period beginning when air is introduced to the
furnace for the purpose of decoking and ends when air is removed from the
furnace.
Hot Steam Standby Mode, defined as the period when the furnace is firing at
50% or less of the maximum allowable firing rate and no hydrocarbon feed is
being charged to the furnace.
Feed in Mode, defined as the period beginning when hydrocarbon feed is
introduced to the furnace and ending when the furnace reaches 70% of the
maximum allowable firing rate.
Feed out Mode, defined as the period beginning when a furnace drops below
70% of the maximum allowable firing rate and ending when hydrocarbon feed
is isolated from the furnace.
The proposed emission limits for the ethane cracking furnaces must meet two criteria to
be considered LAER:
1) The limit must be at least as stringent as the most stringent emission limitation
which is contained in the implementation plan of a state for the class or category
of source unless the owner or operator of the proposed source demonstrates that
such limitations are not achievable, and
51 Basis: expected NOx emission rate prior to reaching the SCR operating temperature during a cold
startup. (0.18 lb/MMBtu)*(157 MMBtu/hr)*(1.1) = 31.1 lb/hr
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2) The limit must reflect the most stringent emission limitation, which is achieved in
practice by the class or category of source.
To determine if the proposed limit is as stringent as the most stringent emission limitation
which is contained in an implementation plan, a review of the 2011 copy of the Oil &
Gas Journal International Survey of Ethylene from Steam Crackers was performed to
identify states where ethylene cracking furnaces are located. The results of that analysis
are presented in the table below.
State Number of Plants
Illinois 1
Iowa 1
Kentucky 1
Louisiana 9
Texas 25
As a result, the review of various state and local agency rules, regulations and permit
limits focused on the states of Louisiana and Texas. The proposed Project’s cracking
furnace emission limits meet the first criterion because a review of the Texas and
Louisiana SIP approved regulations found NOx regulations with emission rates higher
than those proposed here for the Project’s cracking furnaces. Thus, the proposed
emissions limits meet both of the LAER criteria.
More specifically, the TCEQ rule at Tex. Admin. Code tit. 30, Chapter 117 Subchapter B
contains specific emission limits for control of nitrogen compound emissions from
process heaters and boilers located in ozone nonattainment areas. There are three
nonattainment areas (Beaumont-Port Arthur, Dallas-Fort Worth, and Houston-Galveston-
Brazoria) with regulations that address NOx emissions from process heaters and boilers.
Only the Houston-Galveston-Brazoria nonattainment area regulations have a specific
category for ethane cracking furnaces; referred to in the regulation as a pyrolysis reactor
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process heater.52 The NOx emission limit for a pyrolysis reactor process heater is
0.036 lb/MMBtu.
The Louisiana Department of Environmental Quality (LDEQ) rule at La. Admin. Code
tit. 33, Part III Chapter 22 has specific emission limits for control of nitrogen compounds
from process heaters/furnaces in the Baton Rouge ozone nonattainment area. The
regulation has a specific category for process heaters/furnaces that are not ammonia
reformers. The NOx emission limit for “All Others” is 0.08 lb/MMBtu.53 This regulation
also has an adjustment multiplier to apply to the emission factor for process
heaters/furnaces that fire gaseous fuel containing hydrogen and/or carbon monoxide. The
total hydrogen and/or carbon monoxide volume in the fuel is divided by the total fuel
flow volume to determine the volume percent of hydrogen and/or carbon monoxide in the
fuel. For fuels containing greater than 50 percent hydrogen + carbon monoxide, the fuel
multiplier is 1.25. The purpose of the fuel multiplier is to adjust the emission factor due
to the presence of hydrogen in the fuel, recognizing that high hydrogen fuels have higher
NOx emission rates relative to methane/natural gas. For the proposed Project’s ethane
cracking furnaces, the corresponding emission limit in the Baton Rouge ozone
nonattainment area would be 0.10 lb/MMBtu (0.08 x 1.25 = 0.10).
The emissions limit proposed matches the most stringent precedent identified by a review
of the permit limits for recently permitted ethane cracking furnaces, summarized in Table
5-3. It should be noted that none of these limits have yet been demonstrated in practice,
which is a key component of the second criteria. As previously noted, no applicable NOx
standards have been promulgated for cracking furnaces under 40 CFR Parts 60 and 61.
In accordance with 25 Pa. Code §127.205(7), the proposed NOx LAER limit is
equivalent to and satisfies the PaBAT requirements of 25 Pa. Code §127.12(a)(5).
52 Pyrolysis reactor is one of several terms used to describe the manufacture of ethylene. Other terms
include cracker, cracking, thermal cracking, steam cracking, ethylene cracker, ethylene unit, ethylene
heater, ethylene furnace, and pyrolysis furnace. 53 See Table D-1A on page 224 of Title 33, Part III.
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5.2.1.4 Cracking Furnace NO2 BACT Considerations
The criteria for determining a BACT limit are somewhat different than the criteria for
determining a LAER limit. LAER is based in part on the most stringent limit that has
been demonstrated in practice, while the BACT methodology requires consideration of
potential technology transfer from other classes and categories of sources, with
evaluation of applicability, technical feasibility, and whether environmental, energy or
economic factors render a particular technology inappropriate.
In this case, the proposed LAER limit discussed above is based on the application of
LNB and SCR technologies, which are the same control technologies that would be used
to control NOx emission from other combustion sources. The NOx emissions from the
proposed ethane cracking furnaces are a function of the feedstock, fuel fired, firebox
temperatures required to crack ethane into ethylene, burner/furnace design and
application of SCR. These factors significantly influence the achievable NOx emission
rates from the proposed ethane cracking furnaces as follows.
The proposed feedstock is ethane, recovered as a byproduct of natural gas
production. This feedstock requires very high firebox temperatures to crack the
ethane into ethylene.
Cracking ethane instead of an alternative feedstock makes a significantly greater
amount of hydrogen as a byproduct of the cracking process. Because there is not
a market for the hydrogen near the proposed site, the byproduct hydrogen and
methane will be fired in the cracking furnaces to provide the thermal energy
necessary to crack ethane into ethylene. Fuels with high hydrogen content
generate higher quantities of NOx relative to natural gas and typical refinery gas
because hydrogen has a higher adiabatic flame temperature than does methane,
the predominate gas found in natural gas and refinery gas. The proposed Project’s
cracking furnace fuel gas will contain approximately 85 volume percent
hydrogen. This high concentration of hydrogen in the fuel gas results in
approximately 60% higher NOx production at the burners compared to a furnace
firing typical fuel gas with hydrogen concentration at 15% volume or less.
Ethylene cracking furnaces have very high firebox temperatures relative to typical
gas-fired boilers, process heaters and steam/methane reformers. These high
temperatures are required to heat the ethane to its cracking temperature. As a
result, the burner/furnace NOx/NO2 emissions are higher than for typical gas-fired
boilers and process heaters.
Ethane cracking burners/furnaces are designed to generate the high firebox
temperatures necessary to heat the cracking (radiant) tubes to the ethane cracking
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temperature. Operation is challenging due to the very high temperatures. In
particular, the burners are subject to plugging and thermal damage. The plugging
results from carbonization of hydrocarbons in the fuel. The thermal damage
occurs primarily to the secondary and tertiary injection nozzle tips used to create
staged fuel firing in the burners. Plugged or thermally damaged fuel nozzle tips
result in less burner NOx reduction and higher emission rates of NOx.
SCR is proposed to reduce the NOx emissions from the proposed ethane cracking
furnaces. As compared to typical gas-fired boilers and process heaters, the SCR
will have higher inlet NOx concentrations for the reasons described above than
would process heater/boiler applications where LNB and SCR are employed to
control NOx emissions.
Ethane cracking furnaces typically employ radiant tube-metal alloys containing
upwards of 35 percent chromium to withstand corrosion and high temperatures.
Chromium is an SCR catalyst poison. Over time, some of the cracking tube
chromium is released and deposits on the SCR catalyst. This results in decay in
the achievable NOx/NO2 reduction. As a result, very high SCR reductions
(greater than 90% reduction) are not achievable while maintaining acceptable
ammonia slip concentrations over the three to four year run lengths between
major furnace maintenances outages.
The proposed LAER limits are based on application of NLB technology coupled with
87.5 percent control with the SCR system on an annual basis for each furnace. This
proposal is based upon the same technologies as used to control NOx from other
combustion sources and the SCR performance level is as stringent as technically feasible.
As a result, the proposed cracking furnace LAER limits are considered to be equal to or
more stringent than BACT.
5.2.2 Cracking Furnace VOC LAER Analysis
Volatile organic compounds may be emitted from the ethane cracking furnaces due to
incomplete combustion of hydrocarbons in the fuel. This control technology analysis
will address the emissions of VOC from the ethane cracking furnaces. Because VOC is a
non-attainment pollutant (because all of Pennsylvania is considered to be in moderate
non-attainment for ozone), a LAER analysis is required for all of the project’s VOC
sources. No applicable VOC standards have been promulgated for cracking furnaces
under 40 CFR parts 60 and 61.
Shell Chemical Appalachia LLC Plan Approval Application
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5.2.2.1 Step 1: Identify Cracking Furnace VOC Limit Precedents
Table 5-4 presents a summary of the results from a review of past cracking furnace
precedents identified in the RBLC database, recent permits, and one draft permit issued
in Texas. For purposes of comparison, for each of the VOC precedents identified, a
lb/MMBtu emission rate was determined by using the rated heat input of the furnace and
the mass hourly emission rate limit. As shown, the VOC emission limits range from
0.0009 lb/MMBtu to 0.0107 lb/MMBtu. These limits are based on good combustion
design and operation.
A review of the Texas and Louisiana SIP approved regulations found no VOC
regulations for cracking furnaces. The current TCEQ BACT guidance for process heaters
and furnaces only addresses NOx and CO.
5.2.2.2 Step 2: Achieved Cracking Furnace VOC Limits
As shown in Table 5-4, the VOC emission limits reflected in permits or draft permits
range from 0.0009 lb/MMBtu to 0.0107 lb/MMBtu. However, the more recent
determinations are for projects that have not begun construction or are under
construction. As a result, these limits do not meet the “achieved in practice” criteria for
LAER. As noted above, whether a limit has been achieved in practice is key to whether
that limit should be considered as LAER. The VOC emissions limits that are achieved in
practice range from 0.0019 lb/MMBtu to 0.0107 lb/MMBtu, with the 0.0019 lb/MMBtu
limit being derived from the hourly limit of 0.84 lb/hr. If the 0.0019 lb/MMBtu is
applied to the proposed furnace’s maximum heat input capacity of 620 MMBtu/hr the
resultant hourly rate is 1.18 lb/hr.
5.2.2.3 Step 3: Establish Cracking Furnace VOC LAER Limit
Taking into account the precedents that have been demonstrated in practice, the
application of good combustion design and operation is proposed to achieve the
following LAER limit:
VOC emission rate of 1.07 lb/hr, demonstrated through the use of EPA reference
method 18 and 25.
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Table 5-4. Summary of VOC BACT/LAER Limits for Ethylene Cracking Furnaces
Permit
Date/
RBLC No. Facility Name Primary Fuel
Heat Input
(MMBtu/h
r) Control Technology
Calculated
lb/MMBtu Limit
5/2012 1 (draft
permit 2/2013)
ExxonMobil
Baytown, TX
Natural gas or blend of
natural gas and tailgas
575 2
(8 furnaces)
Good design, combustion
practices, and gaseous fuel firing
0.0049
(Basis: 22.66 lb/hr
8 furnace cap)
11/14/12 3
(permit)
Equistar
Channelview, TX OP-2
Natural gas & limited use
of hydrogen 4
640
(1 furnace)
Good combustion practice &
proper furnace design
0.001
(Basis: 0.64 lb/hr limit)
1/23/13 3
(permit)
Equistar
Channelview, TX OP-1
Natural gas & limited use
of hydrogen 4
640 max
(2 furnaces)
Good combustion practice &
proper furnace design
0.0009
(Basis: 0.60 lb/hr limit)
7/16/12
(permit) 5
BASF FINA Ethylene/
Propylene Cracker
Natural gas or cracker off
gas
498 6
(1 furnace) Efficient Combustion No limit
08/06/13 7
(permit)
Chevron/Phillips
Cedar Bayou, TX
Plant fuel gas, ethane, or
natural gas.
500
(8 furnaces)
High hydrogen fuel & efficient
combustion technology
0.0054
(Basis: 2.7 lb/hr based on
natural gas at startup)
02/03/2006
TX-0511
BASF FINA
Ethylene/Propylene Cracker
Not indicated, probably
refinery or natural gas 302
(1 furnace) Pollutant not in RBLC
0.0019 7
(Basis: 0.57 lb/hr)
02/03/2006
TX-0511
BASF FINA
Ethylene/Propylene Cracker
Not indicated, probably
refinery or natural gas 441.7
(8 furnaces) Pollutant not in RBLC
0.0019 7
(Basis: 0.84 lb/hr)
TX-0475
(5/9/05)
Formosa Point Comfort
Plant Fuel Gas
250
(3 furnaces) None indicated
0.0107 (2 furnaces)
0.0092 (1 furnace) 8
1. ExxonMobil Chemical Company; NSR Permit Application for Ethylene Expansion Project; Baytown Olefins Plant, Baytown, TX; May 2012. TCEQ Draft
Maximum Allowable Emission Rates Permit Number 102982 (not dated). 0.0049 lb/MMBtu = 22.66 lb/hr / 8 furnaces / 575 MMBtu/hr. 0.0030 lb/MMBtu =
47.26 tpy VOC / 155.58 tpy NOx * 0.010 lb NOx/MMBtu.
2. Based on 5,037,000 MMBtu/yr / 8760 hr/yr; Appendix A; ExxonMobil Greenhouse Gas Prevention of Significant Deterioration Permit Application for
Ethylene Expansion Project, Baytown, TX.
3. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Numbers 2933/PSDTX1270/N140 (11/2012). & TCEQ Special Conditions &
Maximum Allowable Emission Rates Permit Numbers 18978 PSDTX752M5, N162, 1/2013.
4. NSR Permit Amendment Application - Revised; Equistar Chemicals, LP; Channelview, TX; Olefins Unit No.1&2; Permit Number 1768; February 2012.
5. TCEQ Maximum Allowable Emission Rates Permit Numbers 36644, PSDTX903M5, and N007M1 7/2012.
6. Greenhouse Gas Prevention of Significant Deterioration Preconstruction Permit for the BASF FINA Petrochemicals LP (BFLP), NAFTA Region Olefins
Complex Permit Number: PSD-TX-903-GHG, April 2012.
7. TCEQ Special Conditions Permit Number 36644, PSDTX903M3, and N007M1, 7/2012: Fuel used in the cracking furnaces will be limited to plant fuel gas,
ethane, or to pipeline-quality, sweet natural gas.
8. TCEQ permit 19169 and PSDTX1226 Maximum Allowable Emission Rates (11/2012).
Shell Chemical Appalachia LLC Plan Approval Application
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The proposed VOC emission limit for the cracking furnaces must meet two criteria to be
considered LAER. The proposed cracking furnace emission limits meet the first criterion
because a review of the Texas and Louisiana SIP approved regulations found no VOC
regulations for combustion sources. Current TCEQ BACT guidance for process heaters
and furnaces only addresses NOx and CO. The proposed LAER limit meets the second
criterion because it is as stringent as the lowest emissions limit that has been
demonstrated in practice. As previously noted, no applicable VOC standards have been
promulgated for cracking furnaces under 40 CFR parts 60 and 61. In accordance with 25
Pa. Code §127.205(7), the proposed VOC LAER limit is equivalent to and satisfies the
PaBAT requirements of 25 Pa. Code §127.12(a)(5).
5.2.3 Cracking Furnace PM/PM10/PM2.5 BACT/LAER Analyses
This section addresses the control of PM, PM10, and PM2.5 emissions from the proposed
cracking furnaces. The proposed project is located in an area that is classified as
nonattainment with regard to the annual PM2.5 standard. As a result, a LAER analysis is
required for all of the project’s sources of PM2.5. The area is designated as attainment for
PM10. As a result, a BACT analysis is required for those parameters. No applicable PM
standards have been promulgated for cracking furnaces under 40 CFR parts 60 and 61.
Emissions of particulate matter from gaseous fuel-fired sources result from inert solids
contained in the combustion air, unburned fuel hydrocarbons resulting from incomplete
combustion which agglomerate to form particles and condensable/secondary particulates.
Filterable PM emitted from the cracking furnaces is expected to be less than
10 micrometers in aerodynamic particle size diameter. In addition, for the very low
sulfur clean gas combustion that will occur in the proposed cracking furnaces, the rate of
PM, PM10 and PM2.5 are equivalent. The control technologies applicable to the control of
PM2.5 are the same as the technologies for PM and PM10. Thus, there is no need to
distinguish between the various PM species and throughout this LAER analysis all forms
of PM are referred to as “PM”. As a result, the PM2.5 LAER analysis will meet the
requirements of BACT for PM10 and PM.
Shell Chemical Appalachia LLC Plan Approval Application
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5.2.3.1 Step 1: Identify Cracking Furnace PM Limits
Table 5-5 presents a summary of the results from a review of past cracking furnace
precedents identified from the RBLC database, recent issued permits and one draft permit
proposed in Texas. All of the identified precedents have limits express in terms of
filterable PM, not PM10 or PM2.5. To allow for comparison of the identified PM
precedents, a lb/MMBtu emission rate was determined using the furnace’s rated heat
input and the mass hourly emission rate limit. As shown, the PM emission limits range
from 0.0036 lb/MMBtu to 0.016 lb/MMBtu. Based on a review of the BACT/LAER
precedents for PM emissions from cracking furnaces summarized in the RBLC, the only
controls applied are combustion controls and the use of low ash and low sulfur fuels (e.g.,
use of natural gas).
As previously noted, the Chevron/Phillips permit includes a short-term NOx emissions
rate that allows the SCR’s ammonia injection to be shut off during decoking of a furnace.
To allow for comparison of the identified precedents, the permitted hourly mass based
emission limits were converted to lb/MMBtu rates by using the rated heat input capacity
of the furnace. Because the proposed project’s cracking furnaces will also be decoked to
the furnace and a lb/MMBtu emission limit will be proposed as LAER, the impact of
decoking is considered as part of the LAER proposal.
A review of the Texas and Louisiana SIP approved regulations found no PM regulations
for cracking furnaces. The current TCEQ BACT guidance for process heaters and
furnaces only addresses NOx and CO.
5.2.3.2 Step 2: Achieved/Demonstrated Cracking Furnace PM Limits
As shown in Table 5-5, three of the identified precedents (i.e., TX-0511 for two projects
and TX-0475) are for projects that occurred in 2005 and 2006 and are consider to have
been achieved in practice. The PM limits included in these permits range from
0.005 lb/MMBtu to 0.016 lb/MMBtu. The 0.005 lb/MMBtu rate was derived based upon
the permitted hourly rate for those units. Applying that rate to the proposed furnaces
rated heat input of 564 MMBtu/hr results in an hourly rate of 2.82 lb/hr. The remaining
precedents are for recently permitted projects that have not been constructed or are only
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Table 5-5. Summary of Proposed PM/PM10/PM2.5 BACT Limits for Ethylene Cracking Furnaces1
Permit
Date Facility Name Primary Fuel
Heat Input
(MMBtu/hr) Control Technology
Calculated
lb/MMBtu
Limit 5/12 2 (draft
permit 2/2013)
ExxonMobil Baytown TX
Olefins Plant
Natural gas or blend of
natural gas and tailgas
575 3
(8 furnaces)
Good design & combustion
practices
0.0036
(Basis: lb/hr)
11/14/12 4
(permit)
Equistar
Channelview, TX OP-2
Natural gas & limited
use of hydrogen 4
640
(1 furnace)
Good combustion practice &
combustion of natural gas
and/or plant fuel gas
0.0066
(Basis: 4.23 lb/hr)
1/23/13 4
(permit)
Equistar
Channelview, TX OP-1
Natural gas & limited
use of hydrogen 4
640 max
(2 furnaces)
Good combustion practice &
combustion of natural gas
and/or plant fuel gas
0.0067
(Basis: 4.30 lb/hr)
7/16/12
(permit) 6
BASF FINA
Ethylene/Propylene Cracker
Natural gas or cracker
off gas
487.5
(1 furnace)
Efficient Combustion & Clean
Fuels
0.005
(Basis: 2.49 lb/hr)
08/06/13 7
(permit)
Chevron/Phillips Cedar Bayou,
TX
Plant fuel gas, ethane,
or natural gas.
500
(8 furnaces)
High hydrogen fuel gas &
efficient combustion
technology
0.0075
(Basis: 3.73 lb/hr)
02/03/2006 TX-
0511
BASF FINA
Ethylene/Propylene Cracker
Not indicated, probably
refinery or natural gas 302
(1 furnace) Pollutant not in RBLC
0.005 8
(Basis: 1.51 lb/hr)
02/03/2006 TX-
0511
BASF FINA
Ethylene/Propylene Cracker
Not indicated, probably
refinery or natural gas 441.7
(8 furnaces) Pollutant not in RBLC
0.005 8
(Basis: 2.21 lb/hr)
5/09/2005
TX-0475
FORMOSA
Point Comfort, TX Fuel gas
250
(3 pyrolysis
furnaces)
Not indicated 0.016 9
(Basis: 3.96 lb/hr)
1. All of the identified precedents were for filterable PM, not PM10, or PM2.5
2. ExxonMobil Chemical Company; New Source Review Permit Application for Ethylene Expansion Project; Baytown Olefins Plant, Baytown, TX; May 2012.
TCEQ Draft Special Conditions & Maximum Allowable Emission Rates Permit Number 102982 (not dated). 0.0036 lb/MMBtu = 16.53 lb/hr / 8 furnaces /
575 MMBtu/hr.
3. Based on 5,037,000 MMBtu/yr / 8760 hr/yr; Appendix A; ExxonMobil Greenhouse Gas Prevention of Significant Deterioration Permit Application for
Ethylene Expansion Project, Baytown, TX.
4. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Numbers 2933/PSDTX1270/N140 (14/12) & 18978 /PSDTX752M5/N162
(1/2013).
5. NSR Permit Amendment Applications - Revised; Equistar Chemicals, LP; Channelview, TX; Olefins Production Unit No.1&2; February 2012.
6. TCEQ Maximum Allowable Emission Rates Permit Numbers 36644, PSDTX903M5, and N007M1 7/2012. 0.005 lb/MMBtu = 2.49 lb/hr / 498 MMBtu/hr
7. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Numbers 1504A, PSDTX748M1, and N148.
8. TCEQ Special Conditions Permit Numbers 36644, PSDTX903M3, and N007M1, 7/2012. 0.005 lb/MMBtu = 1.51 lb/hr / 302 MMBtu/hr
9. TCEQ Special Conditions & Maximum Emission Rates Permit Number 19168, PSDTX760M7 (2/15/2008).
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under construction, and thus the permitted rates have not been achieved in practice such
as to qualify for LAER.
5.2.3.3 Step 3: Establish Cracking Furnace PM LAER/BACT Limits
Based on a review of the cracking furnace precedents that have been achieved in practice
(i.e., ranging from 0.005 lb/MMBtu to 0.016 lb/MMBtu) the application of good
combustion design and operation to achieve the following LAER/BACT PM limit is
proposed:
1) PM/PM10/PM2.5 emission rate of 3.10 lb/hr during normal furnace cracking
operation;
2) 1.86 lb/hr PM during decoking operation;
3) Compliance with these limits shall be demonstrated through the use of EPA
reference method 5/202.
For purposes of LAER determination with respect to PM2.5, the proposed emission limits
meet the two criteria to be considered LAER. With respect to the first criterion, a review
of the Texas and Louisiana SIP approved regulations found no PM regulations for
combustion sources. The current TCEQ BACT guidance for process heaters and
furnaces only addresses NOx and CO.
The second LAER criterion is met by proposing the most stringent emission limit
achieved in practice. The mass based emissions rate proposed during decoking is
consistent with this criteria because it is more stringent than the equivalent rate included
in the Chevron/Phillips permit. 54 As previously noted, no applicable PM standards have
been promulgated for cracking furnaces under 40 CFR parts 60 and 61.
As noted in Section 5.1.3, the criteria used to determine a proposed BACT limit are
somewhat different than the LAER criteria. However, in the case of PM emissions from
54 The Chevron/Phillips hourly limit is 3.73 lb/hr and their furnace size is 500 MMBtu/hr, which results in
a rate of 0.0075 lb/MMBtu. The proposed project’s furnaces will have a rated capacity of 564
MMBtu/hr. Using the most stringent level determined to have been achieved in practice,
0.005 lb/MMBtu, yields a mass rate of 2.82 lb/hr. The proposed LAER rate during decoking is
1.86 lb/hr.
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the cracking furnaces, there is no difference in the limit. The proposed LAER limit of
0.005 lb/MMBtu for filterable PM is based on the use of the most-effective feasible PM
control option and the limit is the lowest that has been achieved in practice using that
approach on this type of source. In other words, the proposed LAER limit is consistent
with the top-performing control option in a top-down ranking of the feasible control
options, which is the appropriate basis for establishing a BACT limit. In accordance with
25 Pa. Code §127.205(7), the proposed PM BACT/LAER limit is equivalent to and
satisfies the PaBAT requirements of 25 Pa. Code §127.12(a)(5).
5.2.4 Cracking Furnace CO BACT Analysis
This BACT analysis addresses carbon monoxide emissions from the ethane cracking
furnaces that result from incomplete combustion of hydrocarbons in the fuel gas.
Beaver County is an attainment area for CO, and the proposed Project is subject to major
source review for CO. As a result, the CO analysis included in this section will follow
the five step top-down BACT methodology to determine the proposed BACT limits. No
applicable CO standards have been promulgated for cracking furnaces under 40 CFR
parts 60 and 61.
5.2.4.1 Step 1: Identify Potentially Applicable Cracking Furnace CO Controls
The potentially available control technologies for CO emissions from cracking furnaces
fired with low-sulfur fuel gas are: good combustion practices and the use of oxidation
catalyst.
Good Combustion Practices: Good combustion practices for the proposed Project’s
cracking furnaces fired with tailgas and natural gas include the following:
Proper burner and furnace design; and
Good burner maintenance and operation.
As with other types of fossil fuel-fired systems, combustion control is the most effective
means for reducing CO emissions from ethane cracking furnaces. Good combustion is a
function of the three “T’s” of combustion: Temperature, Turbulence, and Time where:
Shell Chemical Appalachia LLC Plan Approval Application
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Temperature is high enough to ignite the fuel,
Turbulence is vigorous enough for the fuel constituents to be exposed to the
oxygen, and
Time is long enough to assure complete combustion.
These components of combustion efficiency are designed into the furnaces to maximize
fuel efficiency and reduce operating costs. Therefore, combustion control is
accomplished primarily through furnace/burner design and operation.
Changes in excess air affect the availability of oxygen and combustion efficiency. Very
low or very high excess air levels will result in high CO formation and can also affect
NOx formation. Increased excess air levels will reduce CO emissions up to the point that
too much excess air is introduced and the overall combustion temperatures begin to drop.
When combustion temperatures drop enough, furnace efficiency and process
temperatures are negatively affected. Low excess air levels lower combustion
temperature and do not allow sufficient oxygen to minimize the formation of CO.
Cracking furnaces operate within a narrow range of excess air level due to the
interrelationship between oxygen levels, combustion efficiency and the formation of CO
and NOx.
Oxidation Catalyst: Oxidation catalyst is a well-known control technology for CO
emissions and has been widely applied on natural gas-fired combined cycle gas turbines
and to a limited extent on boilers. The oxidation of CO to CO2 utilizes excess air present
in the combustion exhaust. The catalyst lowers the temperature required for the oxidation
reaction to proceed. Products of combustion are passed through a catalytic bed with the
optimum temperature range for the system being 400°F to 1,200°F. No chemical reagent
addition is required.
5.2.4.2 Step 2: Eliminate Technically Infeasible Cracking Furnace CO Controls
Oxidation catalyst technology has been applied at several natural gas-fired boilers and
many combustion turbines, and is thus considered technically feasible for application on
combustion turbines and boilers firing low sulfur fuels.
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However, in the case of cracking furnaces, use of oxidation catalyst technology is not
technically feasible due to leaks that may occur in cracking furnace tubes. Although tube
leaks are common in boilers and combustion turbine heat recovery steam generators, the
fluid leaked is steam or water. Water is not combustible and therefore it passes through
the oxidation catalyst without harming the catalyst. In contrast, when a tube leaks in a
cracking furnace, hydrocarbons leak into the furnace and end up in the combustion flue
gas. If the tube leak occurs in the upper part of the cracking furnace, the combustion
efficiency of the leaking hydrocarbons will be low because cracking furnaces are not
designed to efficiently combust hydrocarbons that do not come through the burner. The
leaked hydrocarbon gases will be oxidized by the catalyst and if present in sufficient
concentration, will release enough heat to damage the oxidation catalyst. Shell is not
aware of any cracking furnaces that have been equipped with oxidation catalyst
For these reasons, only good combustion design and operation is considered to be
technically feasible for the control of CO from ethane cracking furnaces.
5.2.4.3 Steps 3-5: Establish Hierarchy and Propose Cracking Furnace CO BACT Limit
The only technically feasible control option for CO emissions from ethylene cracking
furnaces is good combustion design and operating practices. Therefore, the remainder of
this analysis will focus on the achievable emission rates/limits for ethylene cracking
furnaces firing tailgas and natural gas.
Table 5-6 presents a summary of the results from a review of past cracking furnace
precedents identified from the RBLC database, recent permits, and one draft Texas
permit. As shown, the lowest annual CO limit is 0.034 lb/MMBtu. The Texas BACT
guideline does not specify an averaging period.55
55 TCEQ Chemical Sources Current Best Available Technology (BACT) Requirements Process Furnaces
and Heaters, last revision date 08/01/2011.
http://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bact/bact_processfu
rn.pdf
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Table 5-6. Summary of CO BACT Limits for Ethylene Cracking Furnaces
RBLC
No./
Permit
Date Facility Name Primary Fuel
Heat Input
(MMBtu/hr)
Control
Technology
Hourly Limit
(lb/MMBtu)
Annual Limit
(lb/MMBtu)
5/12 1
(Draft Permit)
ExxonMobil
Baytown TX
Olefins Plant
Natural gas or blend of
natural gas and tailgas
575 2
(8 furnaces)
Good design &
combustion practices,
and gaseous fuel firing
0.567 1 0.035 (8 furnace cap)
(50 ppm at 3% oxygen)
08/06/13 7
(permit)
Chevron/Phillips
Cedar Bayou, TX
Plant fuel gas, ethane &
natural gas.
500
(8 furnaces)
High H2 fuel gas &
efficient comb. Tech.
0.29 7
(Basis: 145.57 lb/hr)
0.035
(8 furnace + boiler cap)7
11/14/12 3
(permit)
Equistar
Channelview, TX
OP-2
Natural gas & limited
use of hydrogen 4
640
(1 furnace)
Good combustion
practice & proper
furnace design
0.053
(Basis: 33.88 lb/hr)
1/23/13 3
(permit)
Equistar
Channelview, TX
OP-1
Natural gas & limited
use of hydrogen 4
640 max
(2 furnaces)
Good combustion
practice & proper
furnace design
0.035
(Basis: 20.36 lb/hr) 0.034
7/16/12
(permit) 5
BASF FINA
Ethylene/Propylene
Natural gas or cracker
off gas
498 6
(1 furnace)
Good combustion
practice & proper
furnace design
0.10
(876 hr/yr startups/spikes)
0.035 (50 ppm@3% O2)
0.035
(50 ppm at 3% oxygen)
TX-0427
(12/6/02)
Equistar Chemicals
La Porte Complex Natural gas
233 9
(1 furnace) None indicated 0.035 9
TX-0475
(5/9/05)
Formosa
Point Comfort Plant Fuel Gas
250
(3 furnaces) None indicated
0.035
(Basis: 8.75 lb/hr) 8
1. ExxonMobil Chemical Company; New Source Review Permit Application for Ethylene Expansion Project; Baytown Olefins Plant, Baytown, TX; May 2012. TCEQ Draft
Special Conditions & Maximum Allowable Emission Rates Permit Number 102982 (not dated). 0.567 lb/MMBtu = 2609.78 lb/hr/8 furnaces/575 MMBtu/hr.
2. Based on 5,037,000 MMBtu/yr/8760 hr/yr; Appendix A; ExxonMobil Greenhouse Gas Prevention of Significant Deterioration Permit Application for Ethylene Expansion
Project, Baytown, TX.
3. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Numbers 2933/PSDTX1270/N140 (11/14/12)&18978 /PSDTX752M5/N162, 1/23/13
4. NSR Permit Amendment Applications - Revised; Equistar Chemicals, LP; Channelview, TX; Olefins Production Unit No.1&2; February 2012.
5. TCEQ Maximum Allowable Emission Rates Permit Numbers 36644, PSDTX903M5, and N007M1 7/12.
6. TCEQ Special Conditions Permit Numbers 36644, PSDTX903M3, and N007M1, 7/12.
7. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Number 36644, PSDTX903M3, and N007M1, 7/2012: 0.29 calculated as ratio of NOx and CO
lb/hr limits times NOx limit of 0.025 lb/MMBtu; equivalent to 400 ppmv at 3% O2. 0.035 calculated as ratio of NOx and CO tpy limits times NOx limit of 0.010 lb/MMBtu;
equivalent to 50 ppmv at 3% O2.
8. TCEQ permit 19169 Special Conditions & Maximum Allowable Emission Rates (2/2008), 0.035 lb/MMBtu = 8.75 lb/hr (MAER hourly value)/250 MMBtu/hr
9. TX permit 18978 Special Conditions (2004) verifies RBLC 0.035 hourly limit.
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To allow for comparison, lb/MMBtu rates were determined for each of the hourly limits
by using the furnace’s rated heat input and the permitted mass emissions rate. The
resultant rates for the recently permitted short-term limits for ExxonMobil
(0.567 lb/MMBtu), Chevron/Phillips (0.29 lb/MMBtu), and BASF FINA
(0.10 lb/MMBtu) are all greater than the BACT guideline rate of 0.035 lb/MMBtu, which
indicates that TCEQ considers alternative furnace operating conditions as part of the
permitting process. In addition, once these alternative operation conditions are
considered, a mass based emissions limits is used for purposes of the short-term
emissions limit.
Based on this review, Shell proposes the application of good combustion design,
operation and maintenance to achieve the following CO BACT limits:
Maximum CO emission rate of 0.035 lb/MMBtu, based on a 12-month rolling
average, excluding periods of startup, shutdown, decoking, and malfunction; and
During periods of startup, shutdown, decoking, or malfunction the CO emission
rate shall not exceed 52.2 lb/hr on an hourly average basis.
These values are consistent with permitted and draft limits for ethylene cracking furnaces
in Texas. As previously noted, no applicable CO standards have been promulgated for
cracking furnaces under 40 CFR parts 60 and 61. In accordance with 25 Pa. Code
§127.205(7), the proposed CO BACT limit is equivalent to and satisfies the PaBAT
requirements of 25 Pa. Code §127.12(a)(5).
5.2.5 Cracking Furnace Greenhouse Gas (GHG) Emissions BACT
The proposed cracking furnaces will combust tailgas (hydrogen and methane), natural gas
and coke (during decoking), emitting three GHGs: CO2, CH4 and N2O. The end product
of combusting the carbon contained in these fuels is CO2. Methane is a product of
incomplete combustion and is emitted in much smaller quantities. Trace quantities of
N2O are generated by oxidation of nitrogen in the combustion air and fuel nitrogen.
Because the amount of CH4 and N2O emitted is very small (much less than one percent)
relative to the amount of CO2 emitted on a CO2e basis, the GHG BACT analyses will
primarily address control of CO2. No applicable GHG standards have been promulgated
for cracking furnaces under 40 CFR parts 60 and 61.
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5.2.5.1 Step 1: Identify Potentially Applicable Cracking Furnace GHG Controls
For the cracking furnaces, there are three broad strategies for reducing GHG emissions:
use of low carbon fuels, energy efficiency and carbon capture and sequestration (CCS).
The application of CCS is addressed for all of the project’s GHG emissions sources in
Section 5.6, which is incorporated by reference into this discussion. The use of low
carbon fuels and energy efficiency to reduce GHG emissions from the ethane cracker
furnaces is discussed below.
Minimize the Production of CO2
Lower-Emitting Fuel: Table 5-7 presents a summary of the expected GHG emissions
associated with the combustion of the fuels that will be combusted in the proposed
Project’s cracking furnaces (i.e., tailgas and natural gas). The GHG emissions from
combustion of coal, No. 6, and No. 2 oil are presented for comparison. As shown,
gaseous fuels such as the tailgas and natural gas proposed as the fuels for the cracking
Table 5-7. CO2e Formed When Combusting Fossil Fuels
Fuel Type Pounds CO2e per Million Btu
Coal 210 1
No. 6 Fuel Oil 167 1
No. 2 Fuel Oil 164 1
Natural Gas 117 1
Ethane Cracking Process Tailgas 44
1. From Tables C-1 and C-2 to subpart C of 40 CFR part 98.
furnace produce the lowest amount of GHG emissions on a per million Btu basis.
Hydrogen is the primary combustible element in the Project’s cracking process tailgas,
which is the primary fuel gas for the Project’s cracker furnaces. When combusted,
hydrogen becomes water vapor, which is not a greenhouse gas. As a result, the energy
produced through the combustion of fuel gas, which is composed of a high percentage of
hydrogen, results in a much lower rate of CO2e generation on a heat input per million Btu
basis. Since the Project’s tailgas contains up to 85 percent volume of hydrogen, its CO2e
value when combusting tailgas is about one-third that produced by burning natural gas.
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Energy Efficiency: The use of a highly efficient design and operation of the furnace to
minimize the fuel required to operate the process will directly impact the amount of CO2
produced. The strategies used for highly efficient design and operation are process and
emissions unit specific, as explained in the subsequent discussion of various elements of
the cracker furnace configuration.
5.2.5.2 Step 2: Eliminate Technically Infeasible Cracking Furnace GHG Controls
Low-Carbon Fuel Feedstocks: As previously discussed, natural gas and ethane
cracking process tailgas have the lowest CO2 emission rates. Accordingly, the
preferential burning of these low-carbon gaseous fuels to meet the ethane cracking
furnaces’ energy needs is considered a CO2 control technique. This control technique is
technically feasible for the ethane cracking furnaces. Any additional gaseous fuel
demand will be met using natural gas.
Energy Efficiency: For a large integrated chemical plant such as the proposed Shell
project, there are several ways to improve energy efficiency. All of the approaches
described below are considered to be technically feasible.
Combustion Air Preheat: Air preheat is a method of recovering heat from the hot
combustion exhaust gas by heat exchange with the combustion air before it enters the
combustion chamber or furnace. Preheating the combustion air reduces the amount of
fuel required in a boiler or furnace because the combustion air does not have to be heated
from ambient temperature to the fuel combustion temperature by combusting fuel. The
amount of CO2 reduction is typically 10 to 15 percent. This heat recovery approach is
commonly used on large process heaters and boilers. To equip a boiler or heater with air
preheat requires the addition of a draft fan and heat exchanger, incurring capital,
operating and maintenance costs. For heaters and boilers of sufficient size these costs
can be offset by the fuel savings. Although combustion air preheat reduces the amount of
CO2 emitted, NOx emissions increase because preheating the combustion air increases
combustion temperature.
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Although technically feasible for application at the Project’s cracking furnaces,
combustion air preheat is not proposed because similar efficiencies will be obtained by
recovery of flue gas energy to generate steam. To make steam the stack temperature will
be reduced to the limits allowed by dew point considerations. In addition, the use of air
preheat has been shown to increase NOx emissions (i.e., in refinery process heater
applications NOx emission rates have increased by 20 percent).
Boiler Feed Water Preheat: Boiler feed water preheat is a method of recovering heat
from the hot combustion exhaust gas emitted by furnaces and boilers through heat
exchange with the boiler feed water or some other process fluid. These systems are
referred to as economizers when used to preheat water. Preheating the boiler feed water
reduces the amount of fuel required in the boiler because the feed water does not have to
be heated from ambient temperature to the required steam temperature by combusting
fuel. There are two principal types of economizers: noncondensing and condensing.
Economizers: Economizers are usually air-to-water heat exchangers. Because these
economizers are not designed to handle flue gas condensation, noncondensing
economizers must be operated at temperatures that are reasonably above the dew points
of the flue gas components. The dew point of the flue gases depends largely on the
amount of water in the gas, which, in turn, is related to the amount of hydrogen in the
fuel. For example, to avoid condensation in the exhaust gases produced by burning
natural gas, the exhaust gas temperature should typically be kept above 250°F.
Noncondensing economizers for heat recovery are commonly used on large boilers, are
technically feasible for the proposed cracking furnaces and will be applied to heat boiler
feed water used to generate steam.
Stack Temperature Reduction: Stack temperature reduction from process heaters and
furnaces results in less heat loss to the atmosphere from combustion exhaust gases.
Methods include options for recovering heat from the combustion exhaust gas such as
steam generation and designing/modifying process heaters to maximize heat recovery in
the heater convection section.
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Steam generation is the primary method that the proposed cracking furnaces will utilize
to maximize heat recover, thereby reducing emissions of CO2. The ethane cracking
process utilizes a significant amount of steam. The majority of this steam will be
provided by recovering heat from the cracking furnace flue gas. The cracking furnace
design is expected to give an overall thermal efficiency of around 93% via maximum heat
integration and recovery of heat from the flue gas as limited by dew point considerations.
Recovering more heat in the heater convection section can be accomplished through
improved convection section tube design and the addition of more convection surface
area. The proposed cracking furnaces will use the most up to date technology design to
minimize the use of energy.
Process Integration and Heat Recovery: Process heat recovery opportunities include
maximizing feed-to-product heat exchange, heat recovery steam generation and advanced
heat exchange equipment design. As a new facility, these features will be utilized in the
design, construction, and operation of the Project.
Utilize Condensate Recovery: Steam is used throughout the site as feed to the cracking
furnaces, to heat process fluids, to drive compressors and for other processing needs.
Efficient recovery of steam condensate reduces energy demand in two ways. First,
recovering the steam condensate reduces the amount of water that needs to be treated for
steam generation. Water treatment is necessary to provide high quality water for use in
the boilers and furnaces. Secondly, recovered steam condensate is typically 100°F
warmer than water from the water treatment plant. As a result, recovering steam
condensate saves the amount of fuel required to heat treated water up by that 100°F. As a
new facility, these features will be utilized in the design, construction and operation of
the Project.
Continuous Excess Air Monitoring and Control: Excessive amounts of combustion
air used in boilers and process heaters results in heat inefficiencies because more fuel
combustion is required to heat the unnecessary air to combustion temperatures. This can
be alleviated by using state-of-the-art instrumentation for monitoring and controlling the
excess air levels in the combustion process. The result is a reduction in the heat input
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because the amount of combustion air needed for safe and efficient combustion is
minimized. This requires the installation of oxygen monitors in the furnace stacks and
damper controls on the combustion air dampers. Lowering excess air levels while
maintaining good combustion reduces CO2 as well as NOx emissions.
The Project’s cracking furnaces will use oxygen analyzers and draft controls to minimize
energy use and emissions of NOx and CO.
5.2.5.3 Step 3: Hierarchy of Cracking Furnace GHG Controls
In order to address CO2 emissions, the Project considered three possible strategies.
1. Reduce the rate of CO2 emissions to the environment via carbon capture and
storage (CCS). The application of CCS is addressed for all of the project CO2
emission sources in Section 5.6.
2. Maximize the energy efficiency, which will minimize the production of CO2. A
highly efficient operation requires less fuel to operate, directly impacting the
amount of CO2 produced. Establishing an aggressive basis for energy recovery
and facility efficiency will reduce CO2 production. All of the options described in
the previous section are technically feasible and are part of the proposed Project.
3. Use of low carbon fuels such as ethane cracking tailgas and natural gas instead of
high carbon fuels and feedstock such as ethane instead of naphtha. This strategy
can be combined with the first strategy and is planned for the proposed Project.
The impacts of strategies 2 and 3 are addressed further in Steps 4 and 5.
5.2.5.4 Step 4: Evaluate Most Effective Cracking Furnace GHG Controls
The use of low-carbon fuels (cracking unit tailgas and natural gas) and various energy
efficiency measures (recovery of furnace flue gas heat down to approximately 284 °F in
new/clean condition) are included in the proposed project. Table 5-8 summarizes the
GHG BACT strategies identified and selected as BACT for a number of the recent
USEPA Region 6 GHG permits issued for cracking furnaces permitted in Texas (which
are the only GHG permits for similar cracking furnaces that have been identified). 56
56 The United States Environmental Protection Agency (USEPA) Region 6 is the review agency for GHG
Prevention of Deterioration permits issued in Texas.
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Table 5-8. Summary of Texas Ethylene Cracking Furnace GHG BACT Determinations
Company/
Project Fuel Control Options Considered Selected Limits
BASF FINA
Petrochemicals
Port Arthur, TX
2012 PSD-TX-
903-GHG SOB
and permit
Pipeline quality
natural gas, low
pressure fuel gas,
high pressure fuel
gas, high hydrogen
fuel
CCS- not technically feasible
EED- steam generation from process waste
heat and periodic decoking of furnace coils
LCF- utilize hydrogen-rich product stream
that is not slated to fulfill contract
commitments
Energy Efficiency/Low-
Emitting Feedstocks/ Lower-
Carbon Fuels selected
CCS rejected: based on high
annual cost and 3-to-17 fold
increase in the total cost of the
project.
Any of the hydrogen-rich product
stream not slated to fulfill contract
commitments shall be utilized to
the maximum extent possible.
Furnace limit flue gas exhaust
temperature ≤ 309oF on a 365-day
average, rolling daily.
256,914 tpy CO2e on a12-month
rolling basis.
Chevron/Phillips,
Cedar Bayou, TX
PSD-TX-748-
GHG October
2012 SOB and
permit
Plant fuel gas
supplemented by
natural gas and
ethane
CCS- post combustion capture, transport,
and EOR considered technically feasible but
rejected for reasons stated in next column.
EED- energy efficient proprietary design
that: recovers refrigeration capacity from
incoming ethane feed, uses lower pressure
separation of ethylene and ethane, uses
optimized distillation tower design
LCF- high-hydrogen plant tailgas as the
primary fuel; the alternate fuel will be
natural gas.
GCP- supports the energy efficient design.
LCF/EED/GCP accepted.
CCS rejected: based on high
annual cost, increased the total
capital project costs by more
than 25%. Would increase
emissions of NOx, CO, VOC,
PM10, SO2, and ammonia by as
much as 30%.
Combust plant tailgas (fuel gas) or
pipeline quality natural gas. Ethane
may be used as an emergency
backup fuel.
Furnace gas exhaust temperature
limit of less than or equal to 350oF
on a 12-month rolling average
basis.
Cap for the furnaces and boiler of
1,579,000 tpy CO2e on a 12-month
total, rolling monthly.
Furnace gas exhaust temperature
to less than or equal to 350oF on a
12-month rolling average basis.
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Company/
Project Fuel Control Options Considered Selected Limits
Equistar
Channelview, TX
(OP-1 & OP-2)
PSD-TX-1272-
GHG May 2013
SOB and permit
Pipeline quality
natural gas and/ or
process gas (fuel
gas).
CCS- post-combustion capture is available
and applicable, but rejected for reasons
stated in next column
EED- selected a furnace design that will
maximize efficiency by incorporating the
latest improvements in heat transfer and
fluid flow to maximize energy efficiency
and energy recovery.
LCF- use hydrogen-rich gas stream as the
secondary fuel for the furnaces.
GCP- periodic tune-ups and oxygen trim
controls.
LNB – Low NOx burners limit the
formation of NOx (including N2O)
emissions.
LCF/EED/GCP/LNB accepted.
CCS rejected: based on high
capital cost increase of 60 to
70% of project. Would increase
emissions of NOx, CO, VOC,
PM10, SO2, and ammonia by
as much as 30%.
Furnace gas exhaust temperature ≤
408 oF on a 365-day rolling
average basis.
Maintain a minimum thermal
efficiency of 89.5% on a 12-month
rolling average basis.
300,706 tpy CO2e on a 12-month
rolling basis.
The cracking furnaces shall
combust pipeline quality natural
gas and/ or process gas (fuel gas).
ExxonMobil,
Baytown, TX
(draft SOB and
permit)
Combust blended
fuel gas (fuel gas)
or pipeline quality
natural gas.
CCS- post-combustion capture, is applicable
to the cracking furnaces but rejected for
reasons stated in next column
EED- energy efficient design will be
equipped with heat recovery systems to
produce steam from waste heat for
use throughout the plant
LCF- use natural gas or a blended fuel gas
that consists of natural gas and tailgas
GCP- maintenance and operating within the
recommended combustion air and fuel
ranges as specified by design, with the
assistance of oxygen trim control
LCF/EED/GCP accepted.
CCS rejected: based on high
annual cost of $205 million per
year. Would increase emissions
of NOx, CO, VOC, PM10, and
SO2 by as much as 11%.
Combust blended fuel gas (fuel
gas) or pipeline
quality natural gas.
Furnace gas exhaust temperature
less than or equal to 340 oF on a
365 day rolling average basis.
987,968 tpy CO2e on a 12-month
total, rolling monthly.
SOB- statement of basis; CCS- carbon capture and sequestration; EED- energy efficient design; LCF- low carbon fuel; GCP- good combustion practices; LNB-
low NOx burners
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As shown, the USEPA Region 6 has issued permits for the identified ethylene
manufacturing projects that require the same GHG controls described as applicable and
available to ethane cracking furnaces in Steps 2 and 3. For all of the identified permit
precedents, the BACT limits include a statement of the permitted:
Low carbon fuels (LCF),
Flue gas exhaust temperatures (EED), and
Ton per year limits for CO2, CH4, N2O, and CO2e.57
5.2.5.5 Step 5: Propose Cracking Furnace GHG BACT
Employing highly energy efficient ethane cracking furnaces will minimize the emissions
of GHGs (CO2, N2O and methane). A highly efficient operation requires less fuel to
operate, which directly impacts the amount of GHGs emitted. Establishing an
aggressivebasis for energy recovery and facility efficiency will reduce GHG emissions
and the costs to mitigate it. Shell has also concluded that the use of low carbon fuels:
tailgas that is high in hydrogen, with natural gas as a backup fuel, is BACT. Shell
proposes the following efficiency based limits:
Only plant tailgas or pipeline quality natural gas shall be combusted in the
cracking furnaces.
Routine furnace tune-ups in accordance with 40 CFR 63 subpart DDDDD
(Process Heaters and Boiler MACT)
Cracking furnace gas exhaust temperature shall be limited to less than or equal to
350 oF on a monthly rolling 12-month average basis on each cracking furnace.
This stack temperature is for normal operations and does not include
commissioning, startup, shutdown, hot steam standby or decoking operations.
Total emissions from seven (7) ethane cracking furnaces shall be limited to, on a
12-month total average basis:
o 1,059,333 tpy CO2,
o 20 tpy CH4,
o 4 tpy N2O, and
o 1,060,946 tpy CO2e.
57 Although listed as limits in the USEPA region 6 GHG permits, the specific limits for CO2, CH4, N2O are
not shown in Table 5-8
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As previously noted, no applicable GHG standards have been promulgated for cracking
furnaces under 40 CFR parts 60 and 61. In accordance with 25 Pa. Code §127.205(7),
the proposed GHG BACT limit is equivalent to and satisfies the PaBAT requirements of
25 Pa. Code §127.12(a)(5).
5.3 Combustion Turbines & Duct Burners
Three natural gas-fired combined cycle units will supply the electricity and steam
required to support the Project. Each combined cycle unit will have a dedicated heat
recovery steam generator (HRSG). Excess electricity produced by the project will be
available for sale to the PJM electric grid.58 Each Cogen Unit will be equipped with duct
burners firing primarily natural gas and used to increase the steam produced by the
HSRGs. Two steam turbines will be used to generate electricity using the steam
produced by the HRSGs and any excess steam from the ethane cracking unit. When
tailgas is in excess at the cracking furnaces, a small quantity of the tailgas may be
combusted in the duct burners in combination with natural gas. As noted in Section 3.4,
the combustion turbines that comprise the three Cogen Units will be either General
Electric Frame 6Bs or Siemens SGT-800s.
5.3.1 Combustion Turbine NOx/NO2 LAER/BACT Analyses
The proposed project will be located in an area that is designated as nonattainment for
ozone. Nitrogen oxides (NOx) are a defined precursor to the formation of ozone. As a
result, a LAER analysis is required for NOx emissions from the proposed Cogen Units.
The area is also designated as attainment/unclassified for nitrogen dioxide (NO2). As a
result, a BACT analysis is required for NO2 emissions from the proposed Cogen UNits.
For purposes of these analyses, the more stringent LAER methodology is followed to
meet the criteria for both LAER and BACT. As noted in Section 4.0, newly constructed
combustion turbines are subject to NSPS subpart KKK NOx requirement of 25 ppm at
15 percent O2 or 150 ng/J of useful output (1.2 lb/MWh).
58 PJM = Pennsylvania, New Jersey, and Maryland electric utility distribution grid.
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NOx formed as part of the combustion process is generally classified in accordance with
the formation mechanism as either thermal NOx or fuel NOx. Thermal NOx is formed
by the thermal dissociation and subsequent reaction of the nitrogen and oxygen in the
combustion air at high temperature. The amount of thermal NOx formation is a function
of the combustion turbine combustor design, flame temperature, residence time at flame
temperature and fuel/air ratio in the primary combustion zone. The rate of thermal NOx
formation is an exponential function of the flame temperature.
Fuel NOx is formed by the gas-phase oxidation of the nitrogen that is chemically bound
(i.e., CN compounds) in the fuel (i.e., char nitrogen). Fuel NOx formation is largely
independent of combustion temperature and the nature of the organic nitrogen compound.
Its formation is dependent on fuel nitrogen content and the amount of excess combustion
air (i.e., the excess oxygen beyond the fuel’s stoichiometric requirement). Natural gas
contains negligible amounts of fuel-bound nitrogen. As a result, the predominant type of
NOx that will be formed by the proposed combustion turbines is thermal NOx.
The control of air/fuel stoichiometry is critical in achieving reduction in thermal NOx.
Thermal NOx formation also decreases rapidly as the combustion temperature drops
below the adiabatic flame temperature for a given stoichiometry. Maximum reduction of
thermal NOx is achieved by simultaneous control of both combustion temperature and
stoichiometry.
5.3.1.1 Step 1: Identify Combustion Turbine NOx/NO2 Limits
Summary results from a review of the NOx BACT/LAER precedents for natural gas-fired
combustion turbines similar in size to the proposed Project’s turbines (i.e., 40 to 50 MW)
with duct burners (DB) are presented in Table 5-9. Table 5-10 presents a summary of
recent permits for projects not listed in RBLC. Each of these precedents is for a natural
gas-fired combustion turbine project where the turbine is greater in size than the proposed
Project’s turbines. The Table 5-10 precedents are presented to illustrate the NOx limits
currently being permitted. Step 2: Achieved/Demonstrated Combustion Turbine
NOx/NO2 Limits
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Table 5-9. Summary of NOx BACT Precedent Found in the RBLC Database For 40 to 50 MW Turbines
RBLC ID
NO. FACILITY NAME
PERMIT
DATE
PROCESS
DESCRIPTION
CAPACITY
(MW) CONTROL
Emissions Limit
ppm@ 15% O2
AK-0071 International Station
Power Plant 3/31/2010
GE LM6000PF-25
Turbines with 140
MMBtu/hr DBs
40-45
(estimate)
SCR and Dry
Low NOx (DLN)
Combustion
5 (4-hr)
WY-0061
Black Hills
Corp./Neil Simpson
Two
4/4/2003
Turbine, Combined
Cycle and Duct Burner
(GE LM6000
Turbines)
40 Dry Low NOx
Burners and SCR 2.5 (24-hr)
IA-0064 Roquette America 1/31/2003 Turbine, Combined
Cycle (with DBs)
~53
(587 MMBtu/hr) SCR
3 (24-hr)
(calc – actual limit
0.012 lb/MMBtu)
OK-0056 Horseshoe Energy
Project 2/12/2002
Turbines and Duct
Burners (GE LM6000
with 185 MMBtu/hr
DB)
45 SCR 12.5
TX-0295 Sam Rayburn
Generation Station 1/17/2002
Combustion Turbines
7,8,9
(no DBs)
45 SCR and Good
Combustion 5
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Table 5-10. Summary of Recent NOx BACT Precedents
State Facility Name
Permit
Date Process Description
Capacity
(MW) Control
Limit
(ppm @ 15% O2)
PA-
0291
Hickory Run Energy
Station 04/23/13
GE 7FA, Siemens SGT6-5000F5,
SGT6-8000H, or Mitsubishi
M501GAC.
900 DLN & SCR 2.0 (3-hr)
PA-
0268
Moxie Energy LLC/
Patriot Generation Plant 01/31/13
Two Mitsubishi M501GAC DLN &
387 MMBtu/hr Duct Burners or Two
Siemens SGT6-8000H DLN &
164 MMBtu/hr Duct Burners
944 DLN & SCR 2.0
CA 1 Pio Pico Energy Center 11/19/2012 GE LMS100
(simple cycle) 100
Water
Injection &
SCR
2.5 (1-hr)
PA-
0278
Moxie Liberty
LLC/Asylum Power 10/10/12
Two Combined Cycle Turbines with
HRSG and Duct Burners. 468 DLN & SCR 2.0
CA 3 Palmdale Hybrid Power
Project 10/18/2011 GE 7FA with 500 MMBtu/hr DB 154 DLN & SCR 2 (1-hr)
CA3 Oakley Generating
Station 5/18/2011 Fast start GE 207FA
624
(total MW
generated)
DLN & SCR 2 (1-hr)
GA 4 Live Oaks Power Plant 4/8/2010
Siemens SGT6-5000F Combustion
Turbines & 359 MMBtu/hr Duct
Burners
200
DLN
COMBUSTO
RS AND SCR
2.5 (3-hr)
1. Not in RBLC. Pio Pico Energy Center PSD Permit SD 11-01. 2. Not in RBLC. Palmdale Hybrid Power Project PSD Permit SE 09-01. 3. Not in RBLC. Oakley Generating Station Final Determination of Compliance, Application 20798, January 2011.
4. Not in RBLC. Live Oaks Power Plant Permit 4911-127-0075-P-02-0.
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A summary of combustion turbine projects developed by the Bay Area Air Quality
Management District (BAAQMD) as part of the Authority to Construct review that
identifies operational projects with low emission limits is presented in Table 5-11.59
Although these precedents are for turbines much larger than those proposed for the
Project, the identified precedents indicate that the application of combustion controls and
SCR to combustion turbines can achieve NOx emission limits as low as 2 ppmv @ 15%
O2 in practice on an hourly basis.
Table 5-11. BAAQMD BACT Review for Authority to Construct Plant
Number 13289
Facility 1,2 NOx ppmvd @
15%O2
Initial
Operational
Palomar Energy Project 2 (1-hr) 2006
Sacramento Municipal Utilities District,
Consumnes 2 (1-hr) 2006
Sithe Mystic, MA-0029 2 (1-hr) 2003
Sithe Fore River, MA 2 (1-hr) 2003
Mountainview, San Bernadino County 2 (1-hr) 2005
Goldendale Energy, WA-0302 2 (3-hr) 2005
Magnolia, SCAQMD 2 (3-hr) 2005
Calpine Facility Sutter, Feather River AQMD 2.5 (1-hr) 2001
La Paloma, SJVAPCD 2.5 (1-hr) 2003
Elk Hills, SJVAPCD 2.5 (1-hr) 2003
Rocky Mountain Energy Center, CO-0056 3.0 (1-hr) 2004
ANP Blackstone, MA-0024 2 (1-hr) No Steam
3.5 (1-hr) Steam Inj. 2001
1. Information presented is from a database search of EPA’s BACT/RACT/LAER Clearinghouse
and CARB’s BACT Clearinghouse for recent permits issued for natural gas-fired combined-
cycle power plants.
2. Facilities from the EPA Clearinghouse are identified with an EPA clearinghouse number,
which is a two-letter state code followed by a four-digit number. All other facilities are from
the CARB Clearinghouse.
59 Authority to Construct for the Los Esteros Critical Energy Facility Combined-Cycle Conversion
(Phase 2) Plant Number 13289, November 2, 2010.
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-75
5.3.1.2 Step 3: Establish Combustion Turbine NOx/NO2 LAER/BACT Limits
The BAAQMD has also considered whether NOx emission limits below 2 ppmv @ 15%
O2 should be required. The BAAQMD concluded that the evidence did not support
imposing a NOx emission limit below 2 ppmv @15% O2 as BACT for the Los Esteros
Critical Energy Facility as follows: 60
“The District also considered whether it would be feasible to implement a NOx permit
limit below 2.0 ppm. Consistent compliance with a limit below 2.0 ppm has never
been demonstrated in practice, and the equipment vendors that the District contacted
regarding this issue stated that they would not be able to guarantee that a lower limit
could be achieved. The District nevertheless considered whether it would be
technologically feasible to do so. The District has concluded that imposing a NOx
emissions limit below 2.0 ppm cannot be justified as BACT at this time.
Additional NOx reductions could potentially be achieved by increasing the amount of
catalyst or size of the catalyst bed in the SCR system. It would be difficult to achieve
any substantial additional reductions, however, because at the very low NOx levels
that are currently being achieved by SCR additional efforts produce diminishing
returns. SCR performance for NOx control is highly dependent on the NOx-to-
ammonia reaction stoichiometry. At stoichiometric conditions, there would be just
enough ammonia to react with the NOx with no additional ammonia slip exhausted
out the stack. It becomes highly challenging to ensure a uniform distribution of
ammonia to NOx over the entire gas turbine operating range when NOx
concentrations are very low. Alternatively, some vendors have considered staging
two separate ammonia injection grids and catalyst beds in series in order to achieve
an optimal distribution of ammonia to NOx that might maintain emissions at less than
2.0 ppm NOx over the entire gas turbine operating range. But this approach has its
own drawbacks, such as increasing the backpressure on the turbine exhaust and
decreasing the efficiency of the turbine resulting in higher emissions per megawatt of
power generated. Moreover, no installation using a staged series of ammonia
injection grids has been demonstrated in practice. Additionally, temperature
variations across the catalyst bed also impact SCR performance. At progressively
lower NOx concentrations, these variations have an increasingly significant impact
on maintaining stoichiometric conditions. For all of these reasons, it becomes
increasingly difficult to gain additional NOx reductions as concentrations are driven
to extremely low levels simply by increasing the amount of catalyst or the size of the
catalyst bed. Increasing the amount of catalyst or size of catalyst bed theoretically
60 Ibid pages 12.
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-76
can provide for more NOx reduction, but for a number of reasons simply adding more
catalyst reaches a point of diminishing returns as NOx levels approach zero.”
Recent precedents in plan approvals issued by PaDEP similarly indicate that a LAER
limit of 2 ppmv @15% O2 is appropriate.
As a result, the use of dry low NOx (DLN) combustors and SCR to achieve the following
BACT/LAER limits is proposed:
2 ppmv @ 15% O2 on a 1 hour average basis,
Total annual emissions from the Cogen Units including startups and
shutdowns shall not exceed more than 22.6 tons of NOx in any 12 consecutive
month period,
Hourly emissions from a given Cogen Unit during startup or shutdown shall
not exceed 113 lb/hr
Startup and shutdown shall be defined as the period during which the SCR is
below the catalyst operating temperature.
The proposed LAER limits for the Project’s Cogen Units must meet two criteria to be
considered LAER. Table 5-12 summarizes the results of a review of states most likely to
have the most stringent emission limits contained in a state implementation plan. The
proposed emission limit of 2 ppmv @ 15% O2 on a 1-hour average basis is more stringent
or equal to the NOx BACT guidelines/requirements for the four agencies identified. As a
result, the proposed emission limit meets the first LAER criterion. The second LAER
criterion is addressed because the most stringent emission limit achieved in practice
identified for combustion turbines from the RBLC and BAAQMD databases and several
recently issued permits is proposed. The proposed NOx LAER limit is more stringent
than the applicable NSPS subpart KKKK limit of 25 ppmvd @ 15% O2. In accordance
with 25 Pa. Code §127.205(7), the proposed NOx LAER limit is equivalent to and
satisfies the PaBAT requirements of 25 Pa. Code §127.12(a)(5).
It should be noted that the application of SCR involves some other considerations.
First, the combustion of sulfur in fuels produces SO2 and SO3 emissions during the
combustion process. Additional SO3 is formed as the SO2 in the flue gas passes through
oxidation catalyst (for CO and VOC control) and the SCR catalyst bed (for NOx control).
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-77
Table 5-12. Regulatory Agencies with NOx BACT Guidelines/Requirements for Combustion Turbines
Regulatory Agency Description Emission Limit Comment Reference Bay Area Air Quality
Management District
Gas Turbine; Combined
Cycle ≥ 40 MW
1. 2.0 ppmvd @ 15% O2
2. 2.5 ppmvd @ 15% O2
(2.0 ppm achieved in practice
for 50 MW LM6000
combined cycle)
1. Technologically
Feasible/ Cost Effective
2. Achieved in Practice
Best Available Control
Technology (BACT)
Guideline (7/18/03)
San Joaquin Valley Air
Pollution Control District
Gas Turbine - = or > 50
MW, Uniform Load,
without Heat Recovery
1. 2.5 ppmvd @ 15% O2,
based on a one-hour average,
excluding startup and
shutdown (SCR or equal).
2. 2.0 ppmvd @ 15% O2,
based on a one-hour average,
excluding startup and
shutdown (SCR or equal).
1. Achieved in Practice or
contained in the SIP
2. Technologically
Feasible/ Cost Effective
Best Available Control
Technology (BACT)
Guideline 3.4.7
Last Update: 10/1/2002 &
2008
New Jersey Department of
Environment Protection
Stationary Combustion
Turbines - Combined
Cycle
2.5 ppmvd @ 15% Oxygen 3-
hour rolling average State of the Art Manual for
Stationary Combustion
Turbines 12/21/2004 2nd
Revision
Texas Commission on
Environmental Quality
Gas-Fired Turbine
Combined Cycle with
Duct Burner
2.0 ppmvd at
15% O2, 24-hr average
TCEQ Combustion
Sources Current Best
Available Control
Technology (BACT)
Requirements Turbines
(7/2012)
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-78
The SO3 then reacts with unreacted ammonia (i.e., slip ammonia) passing through the
HRSG to form ammonium sulfate [(NH4)2 SO4] and ammonium bisulfate (NH4 HSO4)
salts, which are emitted as fine particulates. Because natural gas has very low sulfur
content, emissions of fine particulate (PM2.5) due to the SCR are expected to be minimal.
Second, in the injection of ammonia-based reagent to control NOx, the reaction is not
exact, and maximization of NOx reduction can result in left over ammonia in the exhaust
gas stream (known as ammonia slip). A PaBAT analysis for NH3 and SO2 is presented in
Section 5.14.
5.3.2 Combustion Turbine VOC LAER Analysis
Volatile organic compounds (VOCs) emissions from a natural gas-fired combustion
turbine are a product of incomplete combustion. The formation of VOC is limited by
ensuring complete and efficient combustion of the fuel in the combustion turbine. High
combustion temperatures, adequate excess air and good air/fuel mixing during
combustion minimize VOC emissions. Measures taken to minimize the formation of
NOx during combustion may inhibit complete combustion, which can increase VOC
emissions. Lowering combustion temperatures through staged-combustion can be
counterproductive with regard to VOC emissions. However, improved air/fuel mixing
inherent in newer DLN combustor designs and control systems overcome the impact of
fuel staging on VOC emissions. The Project is located in an ozone nonattainment area.
Because VOC is a defined precursor to the formation of ozone, the combustion turbines
emissions are subject to LAER for VOC. No applicable VOC standards have been
promulgated for combustion turbines and duct burners under 40 CFR Parts 60 and 61.
This section presents the VOC LAER analysis for the proposed combustion turbines.
5.3.2.1 Steps 1: Identify Combustion Turbine VOC Limit Precedents
Table 5-13 presents a summary of the results obtained from a review of the RBLC
database to identify the range of combustion turbine VOC emission limits. For purposes
of comparison, for each of the VOC precedents identified, the limit was converted to a
ppmv @ 15% O2 basis where needed. As shown, the VOC emission limits range from 1
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-79
Table 5-13. Summary of VOC BACT/LAER Precedents for Turbines with Oxidation Catalyst
RBLC ID
N0. Facility Name
Permit
Date Process Description
Capacity
(MW)
Emission Limit
(ppmvd @ 15% O2) 8 Operational Status
PA-0291 Hickory Run
Energy Station 04/23/13
GE 7FA, Siemens SGT6-5000F5, SGT6-
8000H, or Mitsubishi M501GAC. 900 1.5 Pre-construction
PA-0268
Moxie Energy
LLC/ Patriot
Generation Plant
01/31/13
Two Mitsubishi M501GAC DLN &
387 MMBtu/hr Duct Burners or Two
Siemens SGT6-8000H DLN &
164 MMBtu/hr Duct Burners
944 1.9 Pre-construction
PA-0278
Moxie Liberty
LLC/Asylum
Power
10/10/12 Two Combined Cycle Turbines with
HRSG and Duct Burners. 468
1 w/o Duct Burner
1.5 w/Duct Burner Pre-construction
CA 1 Oakley Generating
Station 5/18/11 GE 207FA
624
(total) 1 (as CH4) (1-hr) Under Construction
GA 2 Live Oaks Power
Plant 4/8/10
Siemens SGT6-5000F Combustion Turbines &
359 MMBtu/hr Duct Burners 200 2 (as CH4) (3-hr) Pre-construction
NV-0035 Tracy Substation
Expansion Project 9/12/05 2- Turbine & Duct Burner
306
(total) 4 (3-hr) In Operation 2009
WI-0227 Port Washington
Generating Station 10/13/04
GE 7FAs or Equivalent and Duct Burners
(371 MMBtu/hr) 180 1.2
In Operation
2005/2008
CA 3 Otay Mesa Energy
Center LLC 12/18/03 GE 7FA 172 2 (1-hr) Operating in 2009
MN-0054 Mankato Energy
Center 12/4/03 GE 7FA & Duct Burners (800 MMBtu/hr) 180 3.4 (3-hr) In Operation 2006
CA 3 Smud Consumers
Power Plant 9/9/03 GE 7FA ~172 1.4 (3-hr) In Operation 2006
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
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RBLC ID
N0. Facility Name
Permit
Date Process Description
Capacity
(MW)
Emission Limit
(ppmvd @ 15% O2) 8 Operational Status
CA 3 Magnolia Power
Project 5/27/03 PG7241FA 181 2 (1-hr) In Operation 2005
OR-0035 Port Westward Plant 1/16/22 Combustion Turbines & Duct Burners 650
(total) 4.9 In Operation 2007
CA 4 Metcalf Power Plant 9/24/01 Siemens Westinghouse 600
(total)
1 (as CH4)
(based on 2.7 lb/hr) In Operation 2005
CA 5 Blythe Energy LLC 3/21/01 Two F-class combustion turbine generators 520
(total)
1 (as CH4)
(based on 2.9 lb/hr) In Operation 2003
CA 6 High Desert –
Constellation 5/3/00 Siemens Westinghouse W501FD2 177
1 (as CH4)
(based on 2.51 lb/hr) In Operation 2003
1. Not in RBLC. Oakley Generating Station Final Determination of Compliance, Application 20798, January 2011.
2. Not in RBLC. Live Oaks Power Plant Permit 4911-127-0075-P-02-0.
3. California Air Resources Board (CARB) database.
4. California Energy Commission Metcalf Power Plant Project - Docket # 99-AFC-03 and Metcalf Energy Center, San Jose, California - Power Technology
at http://www.power-technology.com/projects/metcalf
5. California Energy Commission Blythe Energy Power Plant Project, docket 99-AFC-08 and Order Approving A Petition to Modify Air Quality Conditions,
March 30, 2005.
6. California Energy Commission High Desert Power Plant Project - Docket # 97-AFC-01 and Order Approving A Petition to Modify Air Quality Conditions,
October 20, 2004.
7. Projects that were never built are excluded and include: LA-0192, MI-0366, VA-0291, OR-0043, MI-0357, NJ-0043, OH-0248, OK-0070, and OH-0248.
8. Unless otherwise noted parentheses indicate the permitted averaging time.
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-81
to 4.9 ppmv @ 15% O2 based on the use of oxidation catalyst and good combustion
control.
5.3.2.2 Steps 2: Achieved Combustion Turbine VOC Limits
The VOC emissions limits that are achieved in practice range from 1 to 4.9 ppmv @ 15%
O2. Although these precedents are for turbines much larger than the proposed CTs, the
application of combustion controls and oxidation catalyst to CTs is concluded to have
achieved a VOC emission limit as low as 1 ppmv @ 15% O2. This finding is supported
by a recent BAAQMD permit action where a 1 ppmvd @ 15% O2 represented BACT for
two combustion turbine projects.61
5.3.2.3 Step 3: Establish Combustion Turbine VOC LAER
Taking into account the precedents that have been achieved in practice, the use of
oxidation catalyst and good combustion control is proposed to achieve the following
VOC LAER limit:
1 ppmvd @ 15% O2 on a one hour average basis.
Compliance with this limit shall be demonstrated through the use of EPA
reference method 18 and 25.
The proposed emissions limit for the Project’s Cogen Units must meet two criteria to be
considered LAER. To determine if the first criteria was met, a review of states most
likely to have the most stringent emission limits contained in a state implementation plan
was conducted. The results from this survey are presented in Table 5-14. As shown, the
proposed emission limit of 1 ppmvd @ 15% O2 on a one-hour average basis is as
stringent as the VOC BACT guidelines/ requirements for the three agencies identified.
Although the San Joaquin Valley Air Pollution Control District indicates that 0.6 ppmvd
may be technically feasible, this limit has not yet been “achieved in practice”. Thus, the
61 Authority to Construct for the Los Esteros Critical Energy Facility Combined-Cycle Conversion
(Phase 2) Plant Number 13289, November 2, 2010 and Final Determination of Compliance Oakley
Generating Station, January 2011.
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-82
Table 5-14. Regulatory Agencies with VOC BACT Guidelines/Requirements for
Combustion Turbines
Regulatory
Agency Description Emission Limit Comment Reference Bay Area Air
Quality
Management
District
Gas Turbine;
Combined
Cycle ≥ 40
MW
2.0 ppm, Dry @ 15%
O2 (oxidation catalyst
or efficient dry low
NOx combustors)
Achieved in
Practice
Best Available
Control Technology
(BACT) Guideline
(7/18/03)
San Joaquin
Valley Air
Pollution
Control
District
Gas Turbine - =
or > 50 MW ,
Uniform Load,
without Heat
Recovery
1) 2.0 ppmvd @ 15%
O2, based on a
(oxidation catalyst, or
equal).
2) 0.6 ppmvd @ 15%
O2, based on a three-
hour average
(oxidation catalyst).
1) Achieved in
Practice or
contained in the
SIP
2) Technically
Feasible
Best Available
Control Technology
(BACT) Guideline
3.4.7
Last Update:
10/1/2002 & 2008
New Jersey
Dept. of
Environmental
Protection
Stationary
Combustion
Turbines -
Combined
Cycle
4 ppmvd @ 15%
oxygen 3-hour rolling
average
State of the Art
Manual for Stationary
Combustion Turbines
12/21/2004 2nd
Revision
proposed emission limit of 1 ppmvd @ 15% O2 meets the first criterion for being LAER.
The second criterion is addressed by proposing the most stringent emission limit achieved
in practice identified for combustion turbines from the RBLC, CARB databases, and
several recently issued permits. As previously noted, no applicable VOC standards have
been promulgated for combustion turbines or duct burners under 40 CFR parts 60 and 61.
In accordance with 25 Pa. Code §127.205(7), the proposed VOC LAER limit is
equivalent to and satisfies the PaBAT requirements of 25 Pa. Code §127.12(a)(5).
5.3.3 Combustion Turbine PM/PM10/PM2.5 BACT/LAER Analyses
Emissions of PM10 and PM2.5 from combustion turbines result from the inert solids
contained in the combustion air, unburned fuel hydrocarbons resulting from incomplete
combustion which agglomerate to form particles, condensable organic and inorganic
(e.g., sulfuric acid mist) compounds and secondary particulates formed as salts in the
exhaust stream (e.g., ammonium salts related to SCR). The proposed project is located in
an area that is designated as nonattainment for PM2.5. As a result, a LAER analysis is
required for all of the project’s PM2.5 sources. No applicable PM standards have been
promulgated for combustion turbines or duct burners under 40 CFR parts 60 and 61.
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
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All of the filterable PM emitted from a combustion turbine/HRSG exhaust stack is
expected to have an aerodynamic particle size diameter of less than one micrometer. As
a result, from this point forward the LAER analysis will focus on filterable and
condensable particulate matter as measured by EPA Methods 5 or 201, and 202. In
addition, no differentiation will be made between PM, PM10, and PM2.5.
5.3.3.1 Step 1: Identify Combustion Turbine PM Limits
Table 5-15 presents a summary of previous combustion turbine RBLC precedents for PM
emissions.62 The summary includes only the results for projects where oxidation catalyst
and SCR are applied. The reason for including only precedents where oxidation catalyst
and SCR are applied relates to issues associated with potential sulfur reactions. Any
amount of sulfur in the natural gas that is combusted by the turbine and duct burners can
impact the achievable PM emissions rate in several ways. When combusted, the sulfur
present in the natural gas is converted to sulfur dioxide and sulfur trioxide. Although
only a small percentage of sulfur is converted to sulfur trioxide, sulfur trioxide combines
with water vapor in the flue gas to form sulfuric acid mist, which is then measured as
condensable particulate. Combustion turbines equipped with oxidation catalyst and SCR
oxidize sulfur dioxide to sulfur trioxide, increasing the amount of sulfuric acid mist that
is formed. Combustion turbines with SCR systems form fine particulates of ammonium
salts when unreacted ammonia reacts with sulfur trioxide.
The only controls applied to achieve these PM limits are combustion practices and the
use of low ash and low sulfur fuels (e.g., use of natural gas). No add-on controls, such as
electrostatic precipitators (ESP’s), baghouses, or scrubbers have ever been applied to
control PM emissions from a natural gas-fired combustion turbine. In fact, add-on
controls have never been applied in the broader context on natural gas-fired combustion
sources. This is because PM emissions from the subject sources are inherently low
because: 1) gaseous fuels have no ash content that would contribute to the formation of
62 Not included: projects never built, limits can’t be converted to standard units (lb/MMBtu or ppmv), no
oxidation catalyst.
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-84
Table 5-15. Summary of Particulate Matter BACT Precedents for Combustion Turbines with Oxidation Catalyst 1,2,3,4
RBLC
ID No. Facility Name
Permit
Date
Process
Description
Capacity
(MW) Control Description
PM10/PM2.5 Limit
(lb/MMBtu)
Operational
Status
PA-0291 Hickory Run
Energy Station 04/23/13
GE 7FA, Siemens
SGT6-5000F5,
SGT6-8000H, or
Mitsubishi
M501GAC.
900 Natural Gas
17.5 lb/hr (w/duct
burner)
10.0 lb/hr (w/0 duct
burner)
Pre-Construction
PA-0278
Moxie Liberty
LLC/Asylum
Power
10/10/12
Two Combined
Cycle Turbines with
HSRG and Duct
Burners
468
Low Sulfur Content &
Low Ash Content in
Natural Gas (0.4 grains
S/100scf)
0.004 total PM Pre-Construction
PA-0286
Moxie Energy
LLC/ Patriot
Generation Plant
01/31/13
Two Mitsubishi
M501GAC DLN
&387 MMBtu/hr
Duct Burners or
Two Siemens
SGT6-8000H DLN
& 164 MMBtu/hr
Duct Burners
944
High efficiency inlet air
filters; Good combustion
practices
0.0057 total PM Pre Construction
AK-0071
International
Station Power
Plant
3/31/10
GE LM6000PF-25
Turbines with 140
MMBtu/hr DBs
40-45
(estimate)
Good combustion
practices & maximum
total sulfur content of the
fuel is 20 parts per
million by volume
(ppmv) or less 1
0.0066 turbine
filterable &
condensable
0.0075 duct burner
filterable &
condensable
Under
Construction
NV-0035 Tracy Substation
Expansion Project 9/12/05
2- Turbine & Duct
Burner
306
(total)
Best combustion
practices 0.011 filterable In Operation 2009
WI-0227 Port Washington
Generating Station 10/13/04
GE 7FAs or
Equivalent and Duct
Burners (371
MMBtu/hr)
180 Natural Gas; Good
combustion practices
0.013 filterable &
condensable
(based on 33 lb/hr and
2597 MMBtu/hr)
In Operation
2005/2008
MN-
0054
Mankato Energy
Center 12/4/03
GE 7FA & Duct
Burners
306
(total)
Clean Fuels & Good
Combustion 0.009 filterable In Operation 2006
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-85
RBLC
ID No. Facility Name
Permit
Date
Process
Description
Capacity
(MW) Control Description
PM10/PM2.5 Limit
(lb/MMBtu)
Operational
Status
IA-0064 Roquette America 1/31/03 Turbine Combined
Cycle (with DBs)
~53
(587
MMBtu/hr)
Good combustion
practice, natural gas only 0.02 filterable
Unknown;
assumed
operational as in
2008 Title V
permit
OR-0035 Port Westward
Plant 1/16/02
Combustion
Turbines & Duct
Burners
650
(total)
Use of pipeline quality
natural gas
0.1 gr/dscf
(0.44 lb/MMBtu @
15% oxygen)
In Operation 2007
1. Projects without oxidation catalyst are excluded. This includes: IN-0092, IN-0114, OK-0096, and VA-0255.
2. Projects that were never built are excluded. This includes: LA-0192, MI-0357, MI-0366, MN-0071, MS-0059, NC-0101, NJ-0043, NM-0044, NY-0093, OH-
0248, OK-0055, OK-0056, OK-0070, OR-0039, OR- 0040, OR-0043, TX-0469, VA-0287, VA-0289 and VA-0291.
3. Projects where the lb/MMBtu could not be calculated directly and the limit is just for the duct burners are excluded. This includes: LA-0136, LA-0157, LA-
0164, MS-0055, NC-0095, OH-0252, OH-0254, OH-264, TX-0295, TX-0386, TX-0407, TX-0411, TX-0428, TX-0456, TX-0458, TX-0479, TX-0501, TX-
0502, TX-0504, and TX-0511.
4. Natural gas fuel specification requirement of permit (condition 14.5) Permit AQO164CPTO1 Final December 20, 2010. 20 ppmv fuel sulfur content equates
to 1.18 gr S/100 dscf and 0.0033 lb SO2/MMBtu, assuming fuel heating value of 1020 Btu/dscf.
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-86
PM and 2) the potential for PM formation (i.e., soot) is very low because of the high
pressure and excess air conditions under which the fuel is combusted.
5.3.3.2 Step 2: Achieved/Demonstrated Combustion Turbine PM Limits
As shown in Table 5-15, four of the identified precedents are operational and can be
consider to have been achieved in practice. The most stringent PM limits that have been
achieved in practice are as follows:
0.009 lb/MMBtu for a filterable (MN-0064)
0.013 lb/MMBtu for filterable plus condensable
Available data from an initial performance test of the combustion turbines at the Motiva
Port Arthur Refinery where the combustion turbines have oxidation catalyst and SCR
indicates that 0.0066 lb/MMBtu has been achieved in practice for total PM10.
5.3.3.3 Step 3: Establish Combustion Turbine PM BACT/LAER
Taking into account the precedents that have been achieved in practice, the most stringent
PM/PM10/PM/2.5 emission limit is 0.0066 lb/MMBtu for operation with and without duct
firing.
To determine if this emissions limit can be considered LAER two criteria must be
considered. To determine if the first LAER criterion is met, a review of the states
considered most likely to have the most stringent emission limits contained in an
implementation plan was conducted. The results from this effort, summarized in Table
5-16, indicate that a secondary limit on the natural gas sulfur content of less than 0.75
grains/100 dscf should be included as part of a proposed LAER limit. As a result the
following limits are proposed as LAER for PM/PM10/PM2.5 for the combustion turbines
and duct burners:
0.0066 lb/MMBtu with and without duct firing, demonstrated through the use of
EPA reference method 5/202.
The content of sulfur in the natural gas fired by the Cogen Units shall be less than
0.75 grains/100 dscf
Shell Chemical Appalachia LLC Plan Approval Application
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Table 5-16. Regulatory Agencies with PM BACT Requirements/Guidelines for
Combustion Turbines
Regulatory
Agency
Description Emission
Limit
Comment Reference
Bay Area Air
Quality
Management
District
Gas Turbine;
Combined Cycle ≥
40 MW
Natural Gas Fuel
(sulfur content
not to exceed 1.0
grain/100 scf)
Achieved in
Practice
BACT Guideline
(7/18/03)
San Joaquin Valley
Air Pollution
Control District
Gas Turbine ≥ 50
MW Uniform
Load, without Heat
Recovery
PUC regulated
natural gas, LPG,
or non-PUC
regulated gas
with <0.75
grains S/100 dscf
Achieved in
Practice or
contained in the
SIP
BACT Guideline
3.4.7
Last Update:
10/1/2002 & 2008
New Jersey
Department of
Environment
Protection
Stationary
Combustion
Turbines -
Combined Cycle
No specification
or limit State of the Art
Manual for
Stationary
Combustion
Turbines
12/21/2004 2nd
Revision
This proposal meets the second criteria because it is the most stringent limit that has been
achieved in practice.
Given that there is no add-on control applicable to the control of PM/PM10 emissions
from a combustion turbine/duct burner, Shell concludes that the PM/PM10 BACT limit
would be the same as that proposed for LAER. As previously noted, no applicable PM
standards have been promulgated for combustion turbines or duct burners under 40 CFR
parts 60 and 61. In accordance with 25 Pa. Code §127.205(7), the proposed
PM/PM10/PM2.5 BACT/LAER limit is equivalent to and satisfies the PaBAT
requirements of 25 Pa. Code §127.12(a)(5).
5.3.4 Combustion Turbine CO BACT Analysis
The proposed project will be located in an area that is in attainment with the CO
standards. No applicable CO standards have been promulgated for combustion turbines
or duct burners under 40 CFR parts 60 and 61.
Carbon monoxide (CO) is a product of incomplete combustion. The formation of this
pollutant is limited by ensuring complete and efficient combustion of the fuel in the
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combustion turbine. High combustion temperatures, adequate excess air and good
air/fuel mixing during combustion minimize CO emissions. Measures taken to minimize
the formation of NOx during combustion may inhibit complete combustion, which can
increase CO emissions. Lowering combustion temperatures through staged combustion
can also increase the level of CO emissions. However, improved air/fuel mixing inherent
in newer DLN combustor designs and control systems has greatly reduced if not
eliminated the impact of fuel staging on CO emissions. This section presents the CO
BACT analysis for the proposed combustion turbines and duct burners.
5.3.4.1 Steps 1 & 2: Identify Potentially Applicable & Technically Feasible Combustion Turbine CO Controls
Table 5-17 presents a summary of the results from a review of the RBLC database and
other identified permitting actions. Based on this review, the following approached to
control CO emissions were identified:
Oxidation catalyst, and
Good combustion control.
The oxidation catalyst used in combustion turbine applications is typically a precious
metal catalyst (e.g., platinum), which has been applied over a metal or ceramic substrate.
The catalyst is located either before or in the heat recovery steam generator (HRSG),
depending on the turbine/duct burner exhaust temperature. The catalyst lowers the
activation energy for the oxidation of CO so that CO is oxidized at lower temperatures
(400°F to 1100°F) than in the combustors. This technology has been applied to turbines
of all sizes and as such is considered a demonstrated technology. The removal efficiency
for CO is typically greater than 90 percent.
Good combustion control is based upon maintaining good mixing, a proper fuel/air ratio
and adequate time at the required combustion temperature. Based on a review of the
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Table 5-17. Summary of CO BACT Precedent for Turbines with Oxidation Catalyst 1
RBLC
ID No. Facility Name
Permit
Date Process Description
Capacity
(MW)
Emission Limit 6
ppmv @ 15% O2
Operational
Status
PA-0291 Hickory Run Energy
Station 04/23/13
GE 7FA, Siemens SGT6-5000F5,
SGT6-8000H, or Mitsubishi
M501GAC.
900 2.0 (3-hr) Pre Construction
PA-0286
Moxie Energy LLC/
Patriot Generation
Plant
01/31/13
Two Mitsubishi M501GAC DLN &
387 MMBtu/hr Duct Burners or Two
Siemens SGT6-8000H DLN &
164 MMBtu/hr Duct Burners
944 2.0 Pre-Construction
PA-0278 Moxie Liberty
LLC/Asylum Power 10/10/12
Two Combined Cycle Turbines with
HRSG & Duct Burners 468 2.0 Pre-Construction
CA 2 Oakley Generating
Station 5/18/11 GE 207FA
624
(total)
2
(1-hr)
Under
Construction
VA 3 Warren County
Power Station 12/21/10
Mitsubishi Model M501 (2,996
MMBtu/hr) & Duct Burner (500
MMBtu/hr)
299
1.5 without DB
2.4 with DB
1-hr
Under
Construction
GA 4 Live Oaks Power
Plant 4/8/10
Siemens SGT6-5000F Combustion
Turbines & 359 MMBtu/hr Duct
Burners
200
2 without DB
3.2 with DB
(3-hr)
Pre-construction
CT-0151 Kleen Energy
Systems, LLC 2/25/08
Siemens SGT6-5000F (2136
MMBtu/hr)
& Duct Burners (445 MMBtu/hr)
580
(total)
0.9 without DB
1.45 with DB
(1-hr)
In Operation
2011
NV-
0035
Tracy Substation
Expansion Project 9/12/205 2- Turbines/Duct Burners
306
(total)
3.5 with DB
(3-hr)
In Operation
2009
WI-0227 Port Washington
Generating Station 10/13/04
GE 7FAs or Equivalent & Duct
Burners (371 MMBtu/hr) 180
3
(24-hr)
In Operation
2005/2008
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RBLC
ID No. Facility Name
Permit
Date Process Description
Capacity
(MW)
Emission Limit 6
ppmv @ 15% O2
Operational
Status
CA 5 Otay Mesa Energy
Center LLC 12/18/03 GE 7FA 172
6
(3-hr)
Operating in
2009
MN-
0054
Mankato Energy
Center 12/4/03
GE 7FA & Duct Burners (800
MMBTU/HR) 180
4 at full load
4.7 at reduced
load
(3-hr)
In Operation
2006
CA 5 Smud Consumnes
Power Plant 9/9/03 GE 7FA ~172 4
In Operation
2006
CA 5 Magnolia Power
Project 5/27/03 PG7241FA 181
2
(1-hr)
In Operation
2005
1. Projects that were never built are excluded. This includes: LA-0192, MI-0366, VA-0291, OR-0043, MI-0357, NJ-0043, OH-0248, OK-0070,
and OH-0248.
2. Not in RBLC. Oakley Generating Station Final Determination of Compliance, Application 20798, January 2011.
3. Not in RBLC correctly. Warren County Power Station, PSD permit to construct and operate, December 21, 2010.
4. Not in RBLC. Live Oaks Power Plant Permit 4911-127-0075-P-02-0.
5. California Air Resources Board (CARB) database.
6. Unless otherwise noted, the limits presented are for normal operation and are not applicable during start-up and shutdown.
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permit precedents in the RBLC database, the expected CO emissions from a combustion
turbine without oxidation catalyst are between 2 and 15 ppmv @ 15% O2. The level
achieved is dependent on the combustion turbine and DLN combustor technology.
The use of oxidation catalyst combined with good combustion design/operation is
considered demonstrated in practice.
5.3.4.2 Step 3: Ranking of Technically Feasible CO Control Technologies
The CO precedents presented in Table 5-17 can be summarized as follows:
Combustion turbine with duct firing: 1.45 to 6 ppmv @ 15% O2
Combustion turbine without duct firing: 0.9 to 2.0 ppmv @ 15% O2
The most stringent permit precedent identified is the Kleen Energy System with hourly
limits of 1.45 ppmvd and 0.9 ppmvd for operations with and without duct firing,
respectively. This is the only precedent for an operational project that is less than
2.0 ppmvd @ 15% O2. In accordance with the BACT methodology, the cost,
environmental, and economic impacts associated with this precedent must be evaluated
before a less stringent BACT limit can be proposed.
5.3.4.3 Step 4: Evaluate Most Effective Combustion Turbine CO Controls
The current BACT limits for the BAAQMD and SJVAPCD63 are 4.0 ppmvd and
6.0 ppmvd (3-hour average), respectively. The BAAQMD evaluated the cost benefit of
reducing CO emissions from a 7FA combustion turbine from 2 ppmvd to 1 ppmvd with
the following conclusion:64
“The District evaluated the costs and emissions reduction benefits of installing a
larger oxidation catalyst capable of consistently maintaining emissions below
1.0 ppm. Based on these analyses, the cost of achieving a 1.0 ppm permit limit
would be an additional $77,882 per year (above what it would cost to achieve a
2.0 ppm limit), and the additional reduction in CO emissions would be
63 Bay Area Air Quality Management District (BAAQMD) and San Joaquin Valley AQMD (SJVAQMD) 64 Page 41 of Final Determination of Compliance Oakley Generating Station, Application 20798, January
2011.
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approximately 20.11 tons per year, making an incremental cost-effectiveness
value of over $3,874 per ton of additional CO reduction. Moreover, the total cost
of achieving a 1.0 ppm CO limit (as opposed to the incremental costs of going
from 2.0 ppm to 1.0 ppm) would be over $524,959 per year, and the total
emission reductions from 9.0 ppm from the turbine to a 1.0 ppm limit would be
121.01 tons per year, resulting in a total (or “average”) cost effectiveness value
of $4,338. Based on these costs (on a per-ton basis) and the relatively little
additional CO emissions benefit to be achieved (on a per-dollar basis), requiring
a 1.0 ppm CO permit limit cannot reasonably be justified as a BACT limit.
Requiring controls to meet a 1.0 ppm limit would be more expensive, on a per-ton
basis, than what other similar facilities are required to achieve. The District has
not adopted its own cost-effectiveness guidelines for CO, but a review of
guidelines adopted by other districts in California and of BACT determinations
made by agencies around the country found that additional CO controls are not
normally required where the cost per ton exceeds a few hundred to a few
thousand dollars per ton. Additional CO reductions here would not be justified as
BACT given these costs.”
The above BAAQMD cost benefit evaluation associated with reducing combustion
turbine CO emissions from 2 ppmvd to 1 ppmvd was for a larger turbine (GE 7FA
turbines are 175 MW turbine) than the proposed project’s turbines (i.e., the GE 6FB is 41
MW and the Siemens SGT-800 is 49 MW). Due to economies of scale, the cost
effectiveness value (i.e., cost per amount of CO control to achieve a lower ppmvd value)
for the proposed project’s smaller combustion turbines would be higher than for the 175
MW GE 7FA turbine discussed in the above quote from BAAQMD, and the additional
CO reductions would likewise not be justified as BACT given such costs.
5.3.4.4 Step 5: Combustion Turbine and Duct Burner CO BACT Selection
Based on the cost infeasibility associated with achieving a CO level below 2.0 ppmvd @
15% O2, the use of good combustion practices in combination with a CO oxidation
catalyst to achieve the following BACT limits is proposed:
2 ppmv @ 15% O2 on a 1 hour average basis;
Total annual emissions from the Cogen Units including startups and
shutdowns shall not exceed more than 14.5 tons of CO in any 12 consecutive
month period;
Hourly emissions from a given Cogen Unit during startup and shutdown shall
not exceed 276 lb/hr of CO;
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Startup is defined as the period between the commencement of ignition and
when the combustion turbine reaches 55 percent of it’s baseload operating
level;
Shutdown shall not occur for more than 30 minutes in duration;
Shutdown is defined as the period between the time that the combustion
turbine drops below 55 percent operating level and the fuel is cut to the unit.
As previously noted, no applicable CO standards have been promulgated for combustion
turbines or duct burners under 40 CFR Parts 60 or 61. In accordance with 25 Pa. Code
§127.205(7), the proposed CO BACT limit is equivalent to and satisfies the PaBAT
requirements of 25 Pa. Code §127.12(a)(5).
5.3.5 Combustion Turbine GHG BACT Analyses
The proposed Cogen Units will combust natural gas and will emit three GHGs: methane
(CH4), carbon dioxide (CO2), and nitrous oxide (N2O).65 All fossil fuels, including
natural gas, contain carbon and the majority of the heat released comes from the
oxidation of this carbon to form CO2. Methane from the combustion of fossil fuels is a
product of incomplete combustion and is emitted in much smaller quantities. Trace
quantities of N2O are generated by oxidation of nitrogen in the combustion air and fuel
nitrogen. On January 8, 2014, US EPA re-proposed new source performance standards
for emissions of carbon dioxide (CO2) for new affected fossil fuel-fired electric utility
generating units (EGUs). Under those proposed rules, natural-gas fired gas turbine
systems would be subject to CO2 emission limit of 500 kilograms (kg) of CO2 per
megawatt-hour (MWh) of gross output (1,100 lb/MWh) on a 12-operating month rolling
average.66
For fossil fuel combustion turbines and duct burners, there are three broad strategies for
reducing GHG emissions: use of low carbon fuels, energy efficiency and carbon capture
and sequestration (CCS). The use of low carbon fuels and energy efficiency are
65 At times, there may be small amounts of tailgas available as fuel that is in excess of what is consumed
by the ethane cracking furnaces. During these periods these small amounts of tailgas will be burned in
the duct burners. Due to the combustion characteristics of tailgas it is technically infeasible to combust
tailgas in the combustion turbines along with natural gas. 66 79 FR 1430.
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discussed in the section. The application of CCS is addressed in Section 5.6 for all of the
project CO2 emissions sources.
5.3.5.1 Step 1: Identify Potentially Applicable Combustion Turbine GHG Controls
The use of low carbon fuels and energy efficiency to reduce GHG emissions from the
proposed Cogen Units is discussed below.
Lower-Emitting Fuel
Table 5-18 presents a summary of the expected GHG emissions associated with the
combustion of the various fossil fuels, including the natural gas that will be burned by the
proposed Project’s Cogen Units. The GHG emissions from combustion of coal, No. 6
and No. 2 oil are presented for comparison. As shown, the natural gas that will be burned
by the proposed Cogen Units is inherently lower GHG emitting than other fossil fuels.
This is true because natural gas has a low carbon-to-hydrogen ratio. The combustion of
hydrogen and hydrogen containing gaseous fuels such as tailgas reduces GHG emissions
because the combustion of hydrogen forms water vapor, which is not considered by
USEPA as a GHG.
Table 5-18. GHG Emissions for Combustion Turbine Fuels
Fuel Type Pounds CO2e per Million Btu
Coal 210 1
No. 6 Fuel Oil 167 1
No. 2 Fuel Oil 164 1
Natural Gas 117 1
1. From Tables C-1 and C-2 to subpart C of 40 CFR part 98.
Energy Efficiency
An energy efficient combustion turbine, DB, and HRSG design in conjunction with good
operating and maintenance practices allows the required amount of steam and electric
energy to be produced using less fuel, thereby reducing emissions of GHG collectively
and each greenhouse gas individually. In addition, some projects located where weather
conditions allow have installed solar arrays as part of the combustion turbine project.
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Specific measures include the following:
Maximizing the HRSG surface area for heat recovery. This design element
increases the amount of heat recovered from combustion gases, thereby reducing
the amount of heat wasted to the atmosphere. Stack gas temperature is reduced to
the extent possible. Industry practice for HRSGs is to maintain the flue gas
temperature at least 45 °F above the flue gas moisture dew point (i.e., condensing
temperature). This is because condensate is acidic and will corrode the
convection tubes, flue gas ductwork, and stack. The amount of CO2 reduction is
typically one percent per 45 °F flue gas temperature decrease. 67
Flue gas oxygen monitoring. This design element and operational practice aids
in detecting air infiltration. Excess air in the HRSG increases GHG emissions
because less heat can be recovered in the HRSG; so minimizing excess air
reduces GHG emissions. Excess air in the combustion turbine has the same effect
as air infiltration and has the added effects of increasing NOx emissions and
requiring more fuel.
Insulation. Insulation of the combustion turbine combustion section and HRSG
will minimize heat losses, thereby reducing GHG emissions.
Combustor/DB maintenance and HRSG tube cleaning. Without good
maintenance practices, combustors and heat transfer surfaces can wear or become
fouled, lowering thermal efficiency significantly below design levels. Routine
maintenance practices reduce GHG emissions by minimizing these efficiency
losses.
Solar array. A solar array can be used to provide steam to the HRSG during
daylight; there by reducing the amount of duct firing. A solar array installed in
California required 250 acres to generate 50 MW of steam.68
Inlet air-cooling. Inlet air-cooling reduces the combustion air temperature,
allowing for more air mass to be processed through the combustion turbine,
raising the power generation and turbine efficiency. Inlet air cooler technology
includes the use of wetted media, fogging, mechanical chillers, absorption
chillers, etc.69
All of these measures are inherent in the proposed Project’s design except for the
installation of solar arrays.
67 “Energy Efficiency Improvement and Cost Saving Opportunities For Petroleum Refineries: An
ENERGY STAR® Guide for Energy and Plant Managers.” Ernest Orlando Lawrence Berkeley National
Laboratory, Berkeley, Calif. February 2005. 68 Palmdale Hybrid Power Project, Final Staff Report, California Energy Commission, December 2010,
CEC 700-2010-001-FSA, Page 5.3-6. 69 Turbine Inlet Cooling Association-Turbine Inlet Air Cooling Benefits and Technologies.
http://www.turbineinletcooling.org/benefits.html; http://www.turbineinletcooling.org/technologies.html
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5.3.5.2 Step 2: Eliminate Technically Infeasible GHG Controls
The proposed Cogen Units will be fired with natural gas, the lowest CO2e emitting
conventional fuel for power and steam generation.70 This option is technically feasible
and available.
All of the energy efficiency options are considered technically feasible, although
requiring the use of a solar array is considered to be impractical due to weather in western
Pennsylvania (which is considerably different than Palmdale, California), and the use
both solar array and cooling inlet gas would constitute redefining the project. EPA has a
long standing policy of not redefining the source. For example, the USEPA’s response to
comments for the Palmdale Hybrid Power Project states:71
“The incorporation of the solar power generation into the BACT analysis for this
facility does not imply that other sources must necessarily consider alternative
scenarios involving renewable energy generation in their BACT analyses. In this
particular case, the solar component was a part of the applicant’s Project as
proposed in its PSD permit application. Therefore, requiring the applicant to
utilize, and thus construct, the solar component as a requirement of BACT did not
fundamentally redefine the source.”
Even if the addition of a solar array is not considered as redefining the source, there is
insufficient land available at the proposed site for a 250 acre solar array. Additionally, to
generate 50 MW of steam in Beaver County Pennsylvania, a much larger solar array
would be required than that proposed for the Palmdale Hybrid Power Project due to the
different latitude and weather in Beaver County, PA.
The use of inlet air cooling is also considered to be a redefinition of the source. This
technology is employed to keep peaking combustion turbine power generation from
deteriorating during high temperature days when electrical demand is high. These
70 For purposes of this analysis, because the amount of tailgas that is fired by the duct burners will be small
and is not quantifiable based on the current project design basis, it is not considered as a part of this
analysis 71 Comment/Response 40 of Responses to Public Comments on the Proposed Prevention of Significant
Deterioration Permit for the Palmdale Hybrid Power Project, U.S. Environmental Protection Agency,
October 2011.
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applications are typically located in the southern and western states to maintain electric
utility grid stability during the hot summer months. This has little relevance to the
proposed Cogen Units, which will not operate as peaking units. However, when
employed, inlet air-cooling allows for more fuel to be combusted, resulting in increases
in GHG emissions.
5.3.5.3 Step 3-4: Rank Technically Feasible Combustion Turbine Controls
As noted above, the application of CCS is addressed in Section 5.6 for all of the project
CO2 emissions sources. With the elimination of a solar array and inlet air-cooling as
feasible options for the proposed Cogen Units, the top-ranked GHG control option
involves the use of natural gas in combination with energy-efficient HRSG design
including:
Maximizing the HRSG surface area for heat recovery,
Flue gas oxygen monitoring,
Insulation, and
Combustor/DB maintenance and HRSG tube cleaning.
Each of these controls will be included in the combustion turbine HRSG design for either
of the combustion turbines under consideration for the proposed Project.
The proposed CTs will be either General Electric Frame 6Bs or Siemens SGT-800s.
Each of these CTs options, which are natural gas-fired highly efficient designs in
combination with energy-efficient HRSG designs, have comparable performance based
efficiencies.
5.3.5.4 Step 5: Propose Combustion Turbine GHG BACT Limit
There are several recent GHG BACT determinations for combustion turbines used for
electric power generation where the steam produced by the HRSG is used to generate
electricity. A summary of these determinations is presented in Table 5-19. As shown,
the GHG BACT limits are expressed as a function of the electric power generated (i.e.,
Btu/kWh or lb CO2e/MWh). For the proposed project, a small amount of the heat
recovered by the HRSG will be used to generate steam that will be consumed by the
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Table 5-19. Summary of Combustion Turbine Cogeneration GHG BACT Determinations
RBLC ID
/STATE ID
PROJECT NAME/DESCRIPTION MW BACT LIMITS
PA Plan
Approval
67-05009C 1
York Plant Holding
2x LM6000 Simple Cycle
39.788 11,389 Btu/kWh net 30-day rolling
(includes 3.3 % increase for design variations, 6% for
turbine degradation, 1.5% for auxiliary equipment
degradation)
1,330 lb CO2e/MWh net 30-day rolling
WA PSD-
11-05 2
Fredonia Generating Station Expansion
Project
GE &FA.05
209.4
net
1,299 lb CO2e/MW-hr net output, 365-day rolling average
311,382 tpy as CO2e, 12-month rolling total
Fredonia Generating Station Expansion
Project
GE 7FA.04
182.3
net
1,310 lb CO2e/MW-hr net output, 365-day rolling average
274,496 tpy as CO2e, 12-month rolling total
Fredonia Generating Station Expansion
Project
SGT6-5000F4
201.1
net
1,278 lb CO2e/MW-hr net output, 365-day rolling average
301,819 tpy as CO2e, 12-month rolling total
Fredonia Generating Station Expansion
Project
2x GE LMS100
99.8 net
each
1,138 lb CO2e/MW-hr net output per unit, 365-day rolling
327,577 tpy as CO2e, 12-month rolling total
TX-0632 3 Deer Park Energy Center LLC
One SIEMENS CTG5/HRSG5 (FD3-
Series)
180 920 lb CO2/MW-h (30 day rolling)
7,730 Btu/KWh (30 day rolling)
1,044,629 tpy CO2 (365 day rolling)
Also has tpy limits for CH4, N2O, and CO2e.
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RBLC ID
/STATE ID
PROJECT NAME/DESCRIPTION MW BACT LIMITS
TX-0633 4 Channel Energy Center, LLC
One SIEMENS CTG5/HRSG5 (FD3-
Series)
180 920 lb CO2/MW-h (30 day rolling)
7,730 Btu/KWh (30 day rolling)
984,393 tpy CO2 (365 day rolling)
Also has tpy limits for CH4, N2O, and CO2e.
PSD-TX-
1244-GHG 5
Lower Colorado River Authority
2x General Electric 7FA and one steam-
electric generator
195
each
920 lb/MWh net (365-day rolling) combined
7,720 Btu/KWh (365-day rolling) combined
908,957.6 tpy CO2 each (365-day rolling) each
Also has tpy limits for CH4, N2O, and CO2e.
GA 4911-
103-0012-
V-04-1 6
Effingham County Power, LLC
2x nominal 180-MW GE Model 7FA
2x heat recovery steam generators
(HRSGs) each equipped with a natural gas-
fired duct burner
One (1) 325-MW steam turbine generator
668
total
CTG each 863,953 tons CO2e per 12 months 9
DBs each 111,837 tons CO2e per 12 months 9
PSD-TX-
1290-GHG 7
(draft)
El Paso Electric- Montana Power Station
4x GE Model LMS100 Simple Cycle
100
each
1,194 lb CO2/MW-h (12 month rolling) per turbine
250,885.25 tpy each (365-day rolling)
Also has tpy limits for CH4, N2O, and CO2e.
CA 8
No. 15487 Calpine – Russell City Energy Center
2x Siemens/Westinghouse 501F, 2,038.6
MMBtu/hr each
2x Duct Burner Supplemental
Firing System, 200 MMBtu/hr each
612 242 metric tons of CO2E from the S-1 & S-3 Gas Turbines
and S-2 & S-4 HRSGs per hour.
5,802 metric tons of CO2E from the S-1 & S-3 Gas
Turbines and S-2 & S-4 HRSGs per day.
1,928,182 metric tons of CO2E from the S-1 & S-3 Gas
Turbines and S-2 & S-4 HRSGs per year.
S-1 & S-3 Gas Turbines such that the heat rate of each
turbine does not exceed 7,730 Btu/kW-hr
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RBLC ID
/STATE ID
PROJECT NAME/DESCRIPTION MW BACT LIMITS
PA-0291 Hickory Run Energy Station – 2x GE 7FA,
Siemens SGT6-5000F5, SGT
6-8000H, or Mitsubishi M501GAC.
3.4MMMCF/H
900
total
3,665,974 tpy CO2e based on 12-month rolling total for
both units.
1000 lb/MW-hr CO2 on a 12-operating month annual
average basis
PA-0278 Moxie Liberty LLC/Asylum Power – Two
Combined Cycle Turbines with HRSG and
Duct Burners
468
total
1,480,086 tpy CO2e at 468 MW Powerblock; 1,388,540 tpy
CO2e at 454 MW Powerblock. Good Combustion
Practices.
Plan
Approval
41-
00084A10
Moxie Patriot, LLC - Two Mitsubishi
M501GAC DLN &387 MMBtu/hr Duct
Burners or Two Siemens SGT6-8000H
DLN & 164 MMBtu/hr Duct Burners
944
total
BAT limits: Mitsubishi 1,572,362 tpy CO2e or Siemens
1,401,333 tpy CO2e 12 consecutive month period
1. Page 84 of 110; Technical Support Document for Prevention of Significant Deterioration (PSD) Permit, Permit No: PSD-11-05, Department of Ecology
State of Washington, October 21, 2013
2. Page 36 of 110; Technical Support Document for Prevention of Significant Deterioration (PSD) Permit, Permit No: PSD-11-05, Department of Ecology
State of Washington, October 21, 2013.
3. PSD-TX-979-GHG; USEPA Region 6 PSD permit for Calpine Corporation Deer Park Energy Center; 11/29/2012.
4. PSD-TX-955-GHG; USEPA Region 6 PSD permit for Calpine Corporation Channel Energy Center; 11/29/2012.
5. LCRA, Thomas C. Ferguson Power Plant Prevention of Significant Deterioration Permit for GHG Emissions, permit number PSD-TX-1244-GHG; 11/10/11.
6. Part 70 Operating Permit Amendment, Permit Amendment No.: 4911-103-0012-V-04-1, Effective Date: May 30, 2012.
7. PSD-TX-1290-GHG; USEPA Region 6 PSD permit for El Paso Electric Company Montana Power Station; Draft 9/22/2013.
8. Bay Area Air Quality Management District Russell City Energy Center; 1/3/10.
9. As CO2e when firing natural gas. The CTG units have separate CO2e limits when firing fuel oil.
10. Pa.B. 6145 September 9, 2012.
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ethylene and polyethylene manufacturing processes. Because the vast majority of the
steam generated will be used to generate power, the proposed GHG BACT limits are
expressed as a function of electric power generated (i.e., Btu/kWh or lb CO2e/MWh).
All of the determinations except York Plant Holding are for combustion turbines that are
much larger than proposed project’s Cogen Units and all of the determinations include
tons per year, day or hour CO2 or CO2e limits. Three of the determinations have Btu per
kilowatt-hour energy efficiency limits.
Based on the form of the limits associated with the recent precedents and the similarity of
the proposed project with regards to power generation, the following emission limits are
proposed:72
GE G6581 Proposed CO2e BACT Limits:
o 1,030 pounds CO2e/MW-h (30 day rolling) combined turbines/duct
burners/HRSGs/steam-electric generators.
o 340,558 tpy CO2e (365 day rolling) per turbine/duct burner.
Siemens SGT-800 Proposed CO2e BACT Limits:
o 978 pounds CO2e/MW-h (30 day rolling) combined turbines/duct
burners/HRSGs/steam-electric generators.
o 353,893 tpy CO2e (365 day rolling) per turbine/duct burner.
For purposes of demonstrating compliance, the CO2e will be calculated based on CO2
measurements multiplied by 1.0010. As previously noted, US EPA has re-proposed new
source performance standards for emissions of carbon dioxide (CO2) for new affected
fossil fuel-fired electric utility generating units (EGUs). The above values would meet
the proposed NSPS standard, which for these turbines would be 1,100 lb CO2/MWh on a
12-month rolling average basis. In accordance with 25 Pa. Code §127.205(7), the
proposed GHG BACT limit is equivalent to and satisfies the PaBAT requirements of 25
Pa. Code §127.12(a)(5).
72 EPA recently proposed NSPS subpart TTTT. This NSPS would regulate emissions of CO2e from
combustion turbines that are considered electric utility generating units. The final NSPS rule will define
the least stringent CO2e limit that can be proposed as BACT as of the date of initial proposal.
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-102
5.4 Diesel Engines
As part of the proposed Project, four diesel-fired emergency generator engines (same
model) will be installed in the vicinity of the proposed Cogen Units and three diesel-fired
firewater pump engines (same model) will be installed near the river. The rated output of
each of the proposed electric generator engines is 3000 kilowatts (4022 BHP). The rated
output of each of the proposed firewater pump engines is 700 BHP (522 kilowatts). All
of the diesel engines will be compression-ignition, internal combustion engines. The per
cylinder volume for the diesel engines will be less than ten 10 liters. As noted in
Section 4.0, emissions from this type of internal combustion engine are regulated under
NSPS standards set forth in 40 CFR subpart IIII with respect to NOx, non-methane
hydrocarbon (NMHC),73 CO, and PM emissions. By reference in NSPS subpart IIII, the
emission standards at 40 CFR §89.112 apply to the emergency generator diesel engines.
The emission standards for these engine categories are presented below.
Pollutant
Diesel Generators Diesel Firewater Pumps (700 hp)
(g/kw-hr) (g/hp-hr) (g/kw-hr) (g/hp-hr)
NOx+NMHC 6.4 4.8 4.0 3.0
CO 3.5 2.6 3.5 2.6
PM 0.20 0.15 0.20 0.15
The following subsections present the NOx+NMHC (VOC), CO, and PM emission
control technology analyses for the proposed emergency diesel engines.
5.4.1 Diesel Engine NOx and VOC LAER Analyses
BACT permit limits must be at least as stringent as applicable NSPS limits. Based on the
emission standards under Subpart IIII of 40 CFR part 60, the minimum standard that
would meet BACT requirements for NOx + VOC emissions from the proposed stationary
emergency diesel generator engines is 6.4 g/kw-hr (4.8 g/hp-hr) and the minimum that
would meet BACT for the firewater pump engines is 4.0 g/kw-hr (3.0 g/hp-hr).
73 NMHC is assumed to be equivalent to VOC for purposes of the control technology review and proposed
LAER.
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-103
5.4.1.1 Step 1: Identify Diesel Engine NOx & VOC Controls
Table 5-20 and Table 5-21 present summaries of the most recent permit determinations
listed in the RBLC database for stationary emergency generator engines and stationary
emergency firewater engines, respectively. As shown, for both engine categories,
combustion controls (good combustion practices, turbocharging/after cooling, and
compliance with the NSPS Part 60, subpart IIII standards) are used to meet BACT/LAER
requirements.
In addition to combustion controls, the USEPA Alternative Control Techniques (ACT)
document for stationary diesel engines identifies the following potential control
technologies and techniques for NOx and VOC emissions from compression-ignition
engines: 74
Injection Timing Retard, also called ignition timing retard, involves delaying the
fuel injection point in each engine cycle such that the heat release from fuel
combustion occurs during the cylinder expansion. Lower NOx emissions are
achieved by reducing the peak combustion temperature.
Exhaust Gas Recirculation involves retaining or re-introducing a fraction of the
exhaust gases. Lower NOx emissions are achieved by reducing the peak
combustion temperature and by reducing the amount of available molecular
oxygen.
NOx Adsorber Technology typically utilizes alkali or alkaline earth metal
catalysts to adsorb NOx on the catalyst surface under the fuel-lean and oxygen-
rich conditions typical of diesel engine exhaust. Periodically, the catalyst bed is
subjected to fuel-rich exhaust in order to desorb the NOx and regenerate the
catalyst. The desorbed NOx is catalytically reduced over a second catalyst,
typically platinum and/or rhodium active metal.
SCR for NOx reduction, and
Oxidation Catalyst for VOC reduction.
74 Alternative Control Techniques Document: Stationary Diesel Engines. EPA Contract No. EP-D-07-019;
March 2010 Final Report.
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-104
Table 5-20. RBLC Summary of NOx and VOC Precedents for Emergency Generator Diesel Engines
RBLC
ID NO. Facility Name
Permit
Date
Process
Description
Capacity
(hHiclory
Run p)
Control
Description
NOx Limit
(g/hp-hr)
VOC Limit
(g/hp-hr)
NOx+VOC
Limit
(g/hp-hr)
FL-0332 Highlands Biorefinery
and Cogeneration Plant 9/23/11
Emergency
Equipment
2666 (basis
2000 kW)
NSPS 40 CFR 60,
subpart IIII 4.8
4.8
(basis: 0.75 hp/kW)
FL-0322
Sweet Sorghum-to-
Ethanol Advanced
Biorefinery
12/23/10 Emergency
Generators 2682
NSPS 40 CFR 60,
subpart IIII 4.8
4.8
(basis: 0.75
Hp/kW)
NV-0050 MGM Mirage 11/30/09 Diesel Emergency
Generators 3622
Turbocharger & After-
Cooler 4.6 0.1 4.7
NV-0050 MGM Mirage 11/30/09 Emergency
Generators 2206
Turbocharging, After-
Cooling, & Lean-Burn
Technology
5.9 0.1 6.0
LA-0231 Lake Charles Gasification
Facility 6/22/09
Emergency Diesel
Power Generator
Engines
1341 Comply with 40 CFR
60 subpart IIII 5.8
5.8
(basis: lb/hr)
SDAQMD Pacific Bell 12/5/12 Emergency
Generator 3674 Tier 2 certified engine 3.5 4.6 3
SDAQMD San Diego International
Airport 10/3/11
Emergency
Generator 1881 Tier 2 certified engine 3.9 4.6 3
SDAQMD City of San Diego PUD
(Pump Station 1) 7/9/12
Emergency Diesel
(2) 2722 Tier 2 certified engine 4.0 4.6 3
SC-0115 GP Clarendon LP 2/10/09 Diesel Emergency
Generator 1400
Tune-Ups &
Inspections performed
as outlined in Good
Management Practice
Plan.
3.7 1 0.11 3.8
(basis: lb/hr)
SC-0114 GP Allendale LP 11/25/08 Diesel Emergency
Generator 1400 3.7 1 0.1 1 3.8
OK-0129 Chouteau Power Plant 1/23/09 Emergency Diesel
Generator 2200 4.8 2 0.3 2 4.8
OH-0317 Ohio River Clean Fuels,
LLC 11/20/08
Emergency
Generator 2922
Good Comb. Practices
& Engine Design,
Ignition Timing
Retard, Turbocharger,
& Low-Temp.
Aftercooler
4.8
(basis: 0.75
Hp/kW)
OK-0128 Mid American Steel
Rolling Mill 9/8/08
Emergency
Generator 1200 5.9 0.3
6.2
(basis: lb/hr)
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-105
RBLC
ID NO. Facility Name
Permit
Date
Process
Description
Capacity
(hHiclory
Run p)
Control
Description
NOx Limit
(g/hp-hr)
VOC Limit
(g/hp-hr)
NOx+VOC
Limit
(g/hp-hr)
NV-0047 Nellis Air Force Base 2/26/08 Large Internal
Combustion Engines 1350
Turbocharger &
Aftercooler 7.6 0.2 7.8
MD-0037 Medimmune Frederick
Campus 1/28/08
3x Diesel-Fired,
Emergency
Generators Each
(2500 KW)
3604 6.1
(LAER)
LA-0219 Creole Trail LNG Import
Terminal 8/15/07
Diesel Emergency
Generator 2168
Good Comb. Practices
& Engine Design
Incorporating Fuel
Injection Timing
Retardation (ITR)
7.9 0.3 8.2
(basis: lb/hr)
IA-0088 ADM Corn Processing -
Cedar Rapids 6/29/07
Emergency
Generator
2000
(basis:1500
KW)
Engine required to
meet limits established
as BACT (Tier 2
Nonroad).
4.5 0.3 4.8
MN-0071 Fairbault Energy Park 6/5/07 Emergency
Generator
2333 (basis:
1750 KW) 10.9 0.3 12.2
PA-0271 Merck & Co. Westpoint 2/23/07 Mobile Emergency
Generator 2795 6.8 0.3 7.1
PA-0278 Moxie Liberty
LLC/Asylum Power 10/10/12
Emergency
Generator 4.93 0.01 4.94
PA-0286 Moxie Energy LLC/
Patriot Generation Plant 01/31/13
Emergency
Generator 4.93
0.01 (as
THC) 4.94
PA-0291 Hickory Run Energy
Station 04/23/13
Emergency
Generator 1135 bhp
3.96
(based on
9.89 lb/h
limit)
0.28
(based on 0.7
lb/h limit)
4.24
1. Stack testing not required by permit as part of initial compliance demonstration.
2. Based on Standards From § 89.112; NOX and is inclusive of NMHC. VOC emissions are estimated based on AP-42 (10/96), Section 3.4 TOC Factor.
3. The permit information identified for this engine lists a limit of 4.6 g/hp-hr with the compliance based on a Tier 2 Manufacturer certification. The
Tier 2 limit in Subpart IIII is 4.8 g/hp-hr.
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-106
Table 5-21. RBLC Summary of NOx and VOC Precedents for Emergency Firewater Diesel Engines
RBLC
ID NO. Facility Name
Permit
Date
Process
Description
Capacity
(hp) Control Description
NOx
(g/hp-hr)
VOC
(g/hp-hr)
NOx + VOC
(g/hp-hr)
IA-0088
ADM Corn
Processing - Cedar
Rapids
06/29/07 Fire Pump 540
Engine is required to meet
limits established as BACT
(TIER 3 Nonroad).
2.80 0.2 3.00
IA-0095
Tate & Lyle
Ingredients Americas,
Inc.
09/19/08 Fire Pump Engine 575 2.93
calculated
0.75
calculated 3.68
LA-0231 Lake Charles
Gasification Facility 06/22/09 Firewater Pumps (3) 575
Comply with 40 CFR 60
subpart IIII 4.75
VOC not
permitted VOC not permitted
*MI-
0402 Sumpter Power Plant 11/17/11
Diesel Fuel-Fired
Combustion Engine
(RICE)
732 Good combustion practices 4.85 VOC not
permitted VOC not permitted
SC-0114 GP Allendale LP 11/25/08 Firewater Diesel 525
Tune-Ups/Inspections will
be performed as outlined in
Good Management Practice
Plan.
5.10
calculated
0.41
calculated 5.51
LA-0194 Sabine Pass LNG
Terminal 11/24/04
Firewater Booster
Pump Diesel Engines
(2)
300 Good Engine Design &
Proper Operating Practices 5.20 0.15 5.35
LA-0219 Creole Trail LNG
Import Terminal 08/15/07
Firewater Pump
Diesel Engine 525
Good Combustion Practices
& Good Engine Design
Incorporating Fuel Injection
Timing Retardation (ITR)
5.83
calculated
0.048
calculated 5.88
LA-0219 Creole Trail LNG
Import Terminal 08/15/07
Firewater Diesel
Engine 660
Good Combustion Practices
& Good Engine Design
Incorporating Fuel Injection
Timing Retardation (ITR)
6.93
calculated
0.028
calculated 6.96
LA-0194 Sabine Pass LNG
Terminal 11/24/04
Firewater Diesel
Engines 1-3 660
Good Engine Design &
Proper Operating Practices
8.39 1
calculated
0.048
calculated 8.44
PA-0244 First Quality Tissue,
LLC 10/20/04 Fire Pump 575 14.1
No limit in
permit No limit in permit
OH-0254
Duke Energy
Washington County
LLC
08/14/03 Emergency Diesel
Fire Pump Engine 400
Low Sulfur Fuel,
Combustion Control 14.5
VOC not
permitted VOC not permitted
PA-0278 Moxie Liberty
LLC/Asylum Power 10/10/12
Fire Pump
2.6 0.1 2.7
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-107
RBLC
ID NO. Facility Name
Permit
Date
Process
Description
Capacity
(hp) Control Description
NOx
(g/hp-hr)
VOC
(g/hp-hr)
NOx + VOC
(g/hp-hr)
PA-0286
Moxie Energy LLC/
Patriot Generation
Plant
01/31/13
Fire Pump Engine -
460 BHP
460 bhp 2.6 0.1 2.7
PA-0291 Hickory Run Energy
Station 04/23/13
Emergency Firewater
Pump (450 BHP)
450 bhp
1.88
(based on
1.86 lb/h
limit)
1.1
(based on
1.11 lb/h
limit)
3.0
1. RBLC had 0.0185 g/bhp. This should have been labeled as lb/bhp, which converts to 8.39 g/bhp.
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-108
5.4.1.2 Step 2: Eliminate Technically Infeasible NOx and VOC Control Options
Although SCR and oxidation catalyst have been applied and are considered to be
technically feasible for engines that operate under normal conditions, they are not
considered to be technically feasible for engines in emergency service. To ensure that
each engine is in good working order, the proposed engines will be operated infrequently
and for short periods of time (less than one hour/week). The short duration of the
proposed engine’s operation does not provide adequate time for the SCR and/or oxidation
catalyst to come to their required operating temperature where a practical level of
emissions reductions can be achieved. As a result, the use of SCR and oxidation catalyst
is not considered technically feasible and is not considered further by this analysis.
NOx adsorber technology is classified by the USEPA as an emerging control technology.
EPA has classified this technology as emerging because fuel sulfur is converted to stable
sulfates, which compete with NOx for storage sites and poison the catalyst.75 As a result,
NOx adsorber technology is considered to be an undemonstrated technology and is not
considered further by this analysis.
5.4.1.3 Step 3: Establish Diesel Engine NOx and VOC LAER
For any of the emergency diesel engines (i.e., electric generating or firewater pump), the
top-ranked control option for NOx and VOC emissions comprises use of combustion
control techniques. For the proposed emergency generator diesel engines, the most
stringent level of control achieved in practice is the Tier 2 emission standard for non-
road, compression-ignition engines, as codified at 40 CFR § 89.112. This level of control
will result in total NOx + VOC emissions of 10.2 tons per year from all four engines with
each engine operating 100 hours per year. For the proposed firewater pump diesel
engines, the most stringent level of control achieved in practice is the emission standard
for stationary fire pump engines required by 40 CFR Part 60, subpart IIII, Table 4. This
75 IBID. Pages 48 & 49.
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-109
level of control will result in less than 0.7 tons per year total NOx + VOC emissions from
all three engines with each engine operating 100 hours per year.
As LAER for the proposed emergency diesel engines, the following limits are proposed
for NOx + VOC:
Emergency Generators: 4.6 g/hp-hr
Emergency Firewater Pumps: 3.0 g/hp-hr
Compliance with these limits will be based on the purchase of certified engines and
following the manufacturer’s operation/maintenance procedures.
As shown in Table 5-20, there are three permit precedents for emergency generators with
NOx + VOC emissions limits more stringent than the proposed limits of 4.6 g/hp-hr.
These precedents are for two projects located in South Carolina (SC0114 & SC-0115),
with permitted NOx + VOC emissions limits of 3.8 g/hp-hr and the Hickory Run Energy
Station in Pennsylvania. The basis (e.g., BACT analysis) for the lower emission limits is
not presented in the preliminary determination documents for the South Carolina
projects.76 It is not known if the limits have been demonstrated because the permits do
not require compliance testing.77 As a result, these two precedents are eliminated from
consideration. The Hickory Run Energy Station is under construction so this limit has
not yet been achieved in practice. Based on a review of the RBLC precedents, the
proposed NOx + VOC emissions limit of 4.7 g/hp-hr represents the most stringent
emission limitation for an emergency generator engine that has been achieved in practice.
As shown in Table 5-20, the most stringent NOx + VOC emissions limit for an
emergency firewater pump that was identified was 2.7 g/hp-hr for the Moxie Liberty
76 South Carolina Department of Health and Environmental Control Preliminary Determination for Grant
Allendale Inc.; Permit Number 0160-0020-CB; August 14, 2008, and South Carolina Department of
Health and Environmental Control Preliminary Determination for Grant Clarendon, LP; Permit Number
0680-0046-CB; January 2, 2009. 77 South Carolina Department of Health and Environmental Control; Grant Allendale LP; Permit Number
0160-0020-CB; November 25, 2008 and South Carolina Department of Health and Environmental
Control Grant Clarendon, LP; Permit Number 0680-0046-CB ; February 10, 2009.
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-110
Project. This project is under construction so this limit has not yet been achieved in
practice. The next most stringent limit identified is 3.0 g/hp-hr. As a result, based on a
review of the RBLC precedents, the proposed NOx + VOC emissions limit of 3.0 g/hp-hr
represents the most stringent emission limitation for an emergency firewater pump engine
that has been achieved in practice.
The proposed emission limits for the emergency use diesel engines (i.e., generator and
firewater pump) must meet two criteria to be considered LAER. To determine if the first
criterion was met, a review of states most likely to have the most stringent emission
limits contained in the state implementation plan was conducted. The results from the
review are summarized in Table 5-22. As shown, the first criterion is met because the
proposed emission limit meets the requirement of LAER that the most stringent emission
limitation that is contained in the implementation plan of a state be met. The second
criterion is addressed by the proposing the most stringent emission limit achieved in
practice identified in the RBLC. As previously noted, the proposed emergency engines
are subject to the requirements of NSPS subpart IIII. The proposed limits are as stringent
as the standards in this NSPS subpart. In accordance with 25 Pa. Code §127.205(7), the
proposed NOx+VOC LAER limit is equivalent to and satisfies the PaBAT requirements
of 25 Pa. Code §127.12(a)(5).
5.4.2 Diesel Engine PM/PM10/PM2.5 BACT/LAER Analyses
Emissions of particulate from diesel engines result from the inert solids contained in the
combustion air and unburned fuel hydrocarbons resulting from incomplete combustion,
which agglomerate to form particles and condensable organic and inorganic compounds
(e.g., sulfuric acid mist). The proposed project is located in an area that is classified as
nonattainment with regards to the annual PM2.5 standard. As a result, a LAER analysis is
required for all of the project’s sources of PM2.5. For PM and PM10 the analysis is
presented in accordance with the five-step BACT methodology. Because the first two
steps in both the LAER and BACT methodologies are the same (i.e., 1) identify
potentially applicable controls and 2) eliminate technically infeasible controls), a
combined analysis is presented for those steps.
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-111
Table 5-22. Regulatory Agencies with NOx and VOC Guidelines/Requirements for Emergency Stationary Diesel Engines
Regulatory
Agency
Description Emission Limit Comment Reference
South Coast Air
Quality
Management
District
Stationary Diesel-Fueled Internal
Combustion and Other
Compression Ignition Engines;
also Direct Drive Fir Pump
Engines >750 HP
4.8 g/bhp-hr
Tables 2 and 3 Rule 1470. Requirements for
Stationary Diesel-Fueled Internal
Combustion & Other Compression
Ignition Engines (Amended May 4,
2012)
Bay Area Air
Quality
Management
District
IC Engine, Compression Ignition:
Stationary Emergency, non-
Agricultural, non-direct drive fire
pump ≥ 50 BHP
KW> 560 (HP >
750) 4.8 g/bhp-hr
Any engine certified
or verified to
achieve the
applicable standard.
Best Available Control Technology
(BACT) Guideline (12/22/2010)
San Joaquin Valley
Air Pollution
Control District
Emergency Diesel I.C. Engine
Driving a Fire Pump
NOx – 6.9 g/bhp-hr
VOC- no limit
Achieved in Practice
or contained in the
SIP
Best Available Control Technology
(BACT) Guideline 3.1.4 Last Update:
6/30/2001
Emergency Diesel IC Engine NOx/VOC - latest
EPA Tier
Certification level
Achieved in Practice
or contained in the
SIP
Best Available Control Technology
(BACT) Guideline 3.1.1 Last Update:
7/10/2009
New Jersey
Department of
Environment
Protection
Reciprocating Internal
Combustion Engines
SOTA for an emergency generator
application meeting the definition found at
N.J.A.C. 7:27-19.1, "emergency generator,"
is no auxiliary air pollution control.
State of the Art Manual for
Reciprocating Internal Combustion
Engines 2003
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-112
Approximately 77% of the filterable PM emitted from a diesel engine is expected to be
less than 2.5 micrometers in diameter and approximately 97% of the filterable PM10 is
PM2.5. 78 Most of the condensable particulate that is emitted is a result of the sulfur
contained in the fuel and its oxidation to form sulfur dioxide (SO2) and SO3. The SO3
that is formed combines with moisture in the exhaust gas to form sulfuric acid mist,
which is collected as condensable particulate. Because the emergency diesel engines will
use Tier 2 diesel fuel containing less than 15 ppmw sulfur, the amount of condensable
emissions resulting from the emergency diesel-fired engines is expected to be small (i.e.,
<0.00024 lb/MMBtu or <1.4% of the total PM).
BACT permit limits must be at least as stringent as an applicable NSPS limits. Based on
the 40 CFR Part 60, subpart IIII emission standards, the minimum standard that would
meet BACT requirements for PM emissions from the proposed emergency diesel engines
(i.e., generator and firewater pump) is a limit of 0.20 g/kw-hr (0.15 g/hp-hr).
5.4.2.1 Step 1: Identify Diesel Engine PM/PM10/PM2.5 Controls
Table 5-23 and Table 5-24 present summaries of the most recent permit determinations
listed in the RBLC database for stationary emergency generator engines and stationary
emergency firewater engines, respectively. It should be noted that only one precedent
was identified for PM2.5. There are few PM2.5 precedents due in part to EPA’s surrogate
approach (which used PM10 as a surrogate for PM2.5), which was in place until April
2011. As shown, for both engine categories, combustion controls (good combustion
practices and good engineering design, tune-ups, turbocharging/after cooling, and
compliance with NSPS Part 60, subpart IIII) and utilization of low sulfur fuels are used to
meet BACT/LAER requirements. The USEPA ACT document for stationary diesel
engines identifies the following control technologies
78 EPA AP-42, Table 3.4-2.
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-113
Table 5-23. RBLC Summary of PM BACT Precedents for Emergency Generator Diesel Engines
RBLC
ID No.
Facility Name Permit
Date
Process
Description
Capacity
(hp)
Control
Description
Total
PM2.5
(g/hp-hr)
Filterable
PM10
(g/hp-hr)
Total
Filterable
PM
(g/hp-hr)
FL-0332 Highlands Biorefinery
& Cogeneration Plant 9/23/11 Emergency
Equipment 2666 (Basis:
2000 KW) NSPS 40 CFR 60, subpart
IIII 0.15
(Basis: 0.2 g/kw-
hr)
LA-0254 Ninemile Point
Electric Generating
Plant 8/16/11 Emergency
Generator 1250 Ultra Low Sulfur Diesel &
Good Combustion
Practices 0.15 0.15
FL-0322 Sweet Sorghum-to-
Ethanol Advanced
Biorefinery 12/23/10 Emergency
Generators 2682 NSPS 40 CFR 60, subpart
IIII 0.15
(Basis: 0.2 g/kw-
hr)
MI-0389 Karn Weadock
Generating Complex 12/29/09 Emergency
Generators
2666
(Basis: 2000
KW)
Engine Design &
Operation 15 ppm sulfur
fuel
0.25
(Basis: 0.2 g/kw-
hr)
NV-0050 MGM Mirage
Units CC009 - CC015 11/30/09
Caterpillar
Diesel
Generator,
M/N: 3516C,
2,500 kW
3622
Turbocharger & Good
Combustion Practices 0.045
(Basis: 0.0001
lb/hr)
NV-0050 MGM Mirage
Units LX024 &
LX025 11/30/09
Caterpillar
Diesel
Generator,
M/N: 3512C,
1,500 kW
2206 Turbocharger & Good
Combustion Practices 0.08 3
(Basis: 0.38 lb/hr)
LA-0231 Lake Charles
Gasification Facility 6/22/09 Emergency
Power
Generator 1341 Comply With 40 CFR 60
subpart IIII 0.02
(Basis: 0.06 lb/hr)
SC-0114 GP Allendale LP 11/25/08 Emergency
Generator 1400
0.065 2
(Basis:0.2 lb/hr)
SC-0115 GP Clarendon LP 2/10/09 Emergency
Generator 1400
Tune-Ups & Inspections
will be performed as
outlined in the Good
Management Practice
Plan.
0.065 1
(Basis: 0.2 lb/hr)
OK-0129 Chouteau Power Plant 1/23/09 Emergency
Generator 2200 0.15
(Basis: 0.2 g/kw-
hr) OH-0317 Ohio River Clean 11/20/08 Emergency 2922 Good Combustion 0.15
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-114
RBLC
ID No.
Facility Name Permit
Date
Process
Description
Capacity
(hp)
Control
Description
Total
PM2.5
(g/hp-hr)
Filterable
PM10
(g/hp-hr)
Total
Filterable
PM
(g/hp-hr) Fuels, LLC Generator Practice & Good Engine
Design (Basis: 0.2 g/kw-
hr)
OK-0128 Mid American Steel
Rolling Mill 9/8/08 Emergency
Generator 1200 0.32
(Basis: 0.84 lb/hr)
NY-0101 Cornell Combined
Heat & Power Project 3/12/08 Emergency
Generator
1333
(Basis: 1000
KW)
Ultra Low Sulfur Diesel
@ 15 Ppm Sulfur 0.06
(Basis: 0.19 lb/hr)
NV-0047 Nellis Air Force Base 2/26/08 Large Internal
Combustion
Engines 1350 Turbocharger &
Aftercooler 0.08
LA-0219 Creole Trail LNG
Import Terminal 8/15/07 Emergency
Generator 2168
Good Combustion
Practices, Good Engine
Design, & Use of Low
Sulfur & Low Ash Diesel
0.14
(Basis: 0.69 lb/hr)
IA-0088 ADM Corn
Processing - Cedar
Rapids 6/29/07 Emergency
Generator 2000 (Basis:
1500 KW)
Engine is required to meet
limits established as
BACT (Tier 2 Nonroad). 0.15
MN-0071 Fairbault Energy Park 6/5/07 Emergency
Generator 2333 (Basis:
1750 KW) 0.18
PA-0278
Moxie Liberty
LLC/Asylum Power 10/10/12
Emergency
Generator .02 .02
PA-0286
Moxie Energy LLC/
Patriot Generation
Plant
01/31/13 Emergency
Generator .02 .02
PA-0291 Hickory Run Energy
Station 04/23/13
Emergency
Generator 1135
0.13
1 - RBLC incorrectly shows as Total PM10 as 0.25 lbs/hr instead of 0.20 lb/hr (0.065 g/bhp-hr). See PSD Construction Permit 0680-0046-CB.
2 - RBLC incorrectly shows as Total PM10 as 0.25 lbs/hr instead of 0.20 lb/hr (0.065 g/bhp-hr). See PSD Construction Permit 0160-0020-CB.
3 - Clark County Department of Air Quality and Environmental Management, Part 70 Operating Permit, Source 825, December 30, 2010 page 59.
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
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Table 5-24. RBLC Summary of PM BACT Precedent for Emergency Firewater Diesel Engines
RBLC
ID NO. Facility Name
Permit
Date
Process
Description
Capacity
(Hp) Control Description
Total PM2.5
Limit
(g/hp-hr)
Filterable
PM10 Limit
(g/hp-hr)
Total
Filterable
PM Limit
(g/hp-hr)
LA-0231 Lake Charles
Gasification Facility 06/22/09
Firewater Diesel
Pumps (3) 575
Comply with 40 CFR 60
subpart IIII
0.06
calculated
LA-0194 Sabine Pass LNG
Terminal 11/24/04
Firewater Booster
Pump Diesel
Engines (2)
300 Good Engine Design & Proper
Operating Practices 0.09
IA-0088 ADM Corn Processing
- Cedar Rapids 06/29/07 Fire Pump 540
Engine must meet established
BACT limits (Tier 3 Nonroad). 0.15 0.15
IA-0095
Tate & Lyle
Ingredients Americas,
Inc.
09/19/08 Fire Pump Engine 575 0.15
calculated
0.15
calculated
MI-0389 Karn Weadock
Generating Complex 12/29/09 Fire Pump 525
Engine Design & Operation.
15 ppm Sulfur Fuel. 0.15
LA-0219 Creole Trail LNG
Import Terminal 08/15/07
Firewater Pump
Diesel Engine 525
Good Combustion Practices,
Good Engine Design, & Use of
Low Sulfur & Low Ash Diesel)
0.24
calculated
SC-0114 GP Allendale LP 11/25/08 Firewater Diesel
Pump 525
Tune-Ups & Inspections will
be performed as outlined in the
Good Management Practice
Plan.
0.35
calculated
0.35
calculated
LA-0219 Creole Trail LNG
Import Terminal 08/15/07
Firewater Pump
Diesel Engine 660
Good Combustion Practices,
Good Engine Design, & Use of
Low Sulfur & Low Ash Diesel)
0.44
calculated
LA-0194 Sabine Pass LNG
Terminal 11/24/04
Firewater Pump
Diesel Engines 1-3 660
Good Engine Design, Proper
Operating Practices, & Use of
Low Sulfur Diesel
0.85
calculated
PA-0278 Moxie Liberty
LLC/Asylum Power 10/10/12
Fire Pump
0.09 0.09
PA-0286
Moxie Energy LLC/
Patriot Generation
Plant
01/31/13
Fire Pump Engine -
460 BHP
0.09 0.09
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Beaver County, Pennsylvania Petrochemicals Complex
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RBLC
ID NO. Facility Name
Permit
Date
Process
Description
Capacity
(Hp) Control Description
Total PM2.5
Limit
(g/hp-hr)
Filterable
PM10 Limit
(g/hp-hr)
Total
Filterable
PM Limit
(g/hp-hr)
PA-0291 Hickory Run Energy
Station 04/23/13
Emergency
Firewater Pump
(450 BHP) 450 0.06
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
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and techniques for PM emissions: combustion controls discussed for NOx and VOC
control and the use of catalytic diesel particulate filters (CDPF). It should be noted that
each of these controls focuses on the control of filterable PM. As discussed above, use of
low sulfur fuel is identified as the control method for the condensable PM fraction.
5.4.2.2 Step 2: Eliminate Technically Infeasible Controls
CDPF is generally designed around a substrate that captures PM from the diesel engine
exhaust in the catalyst-coated substrates cell walls. As the diesel exhaust gas passes
through the substrate, PM is collected and stored. The collected PM is then oxidized
through the use of a catalyst coating on the substrate. Although CDPF is technically
feasible for engines that operate under normal conditions, it is not considered to be
technically feasible for engines in emergency service. The proposed project’s engines
will be operated infrequently and for short periods of time (less than one hour/week) for
maintenance and testing. The short amount of time that the engine will be operating (i.e.,
less than an hour at a time) will not allow the CDPF oxidation catalyst to come to its
required operating temperature and successfully oxidize any particulate that is collected.
As a result, the use of CDPF is not considered feasible for the proposed engines and is
not considered further by this analysis.
5.4.2.3 Step 3: Establish Diesel Engine PM2.5 LAER
For any of the emergency diesel engines (i.e., electric generator or firewater pump), the
top-ranked control option for PM emissions comprises the use of combustion control
techniques. For the proposed emergency generator diesel engines, the most stringent
level of control achieved in practice is the Tier 2 emission standard for non-road,
compression-ignition engines, as codified at 40 CFR § 89.112.79 This level of control
will result in 0.04 tons per year of total filterable PM emissions from all four engines
with each engine operating no more than 100 hours per year in non-emergency mode,
79 The Hickory Run Energy Project is under construction. As a result, this limit is not yet considered
achieved in practice.
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
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including the 50 hours per year allowed for maintenance and testing. For the proposed
firewater pump diesel engines, the most stringent level of control achieved in practice is
the emission standard for stationary fire pump engines, required by 40 CFR Part 60,
subpart IIII Table 4.80 This level of control will result in 0.035 tons per year a of total
filterable PM emissions from all three engines with each engine operating no more than
100 hours per year in non-emergency mode, including the 50 hours per year allowed for
maintenance and testing. The most stringent level of control identified for the control of
condensable PM is the use of diesel fuel containing less than 15 ppm sulfur.
As LAER for the proposed emergency diesel engines, the following limits are proposed
for PM2.5:
Emergency Generators: 0.15 g/hp-hr
Emergency Firewater Pumps: 0.15 g/hp-hr
For all emergency engines diesel fuel with less than 15 ppmw sulfur shall be used
Compliance with these limits will be based on the purchase of certified engines, low
sulfur diesel fuel and following the manufacturer’s operation/maintenance procedures.
The proposed emission limits for the emergency use diesel engines must meet two
criteria to be considered LAER. To determine if the first criterion was met, a review of
states most likely to have the most stringent emission limits contained in the state
implementation plan was conducted. The results from this review are summarized in
Table 5-25. As shown, the proposed emission limit meets the first requirement of LAER
that the proposed limit be as stringent as any emission limitation that is contained in the
implementation plan of a state. The second criterion has been addressed by proposing the
most stringent emission limit achieved in practice identified in the RBLC. As previously
note, the proposed emergency engines are subject to the NSPS Part 60, subpart IIII PM
80 IBID.
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
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Table 5-25. Regulatory Agencies with PM Guidelines/Requirements for Emergency Stationary Diesel Engines
Regulatory
Agency
Description Emission Limit Comment Reference
South Coast Air
Quality
Management
District
Stationary Diesel-Fueled Internal
Combustion and Other
Compression Ignition Engines
>750 HP
0.075 g/bhp-hr
0.02 g/bhp-hr
Table 1:
1/1/13 – 6/30/15
After 6/31/15
Rule 1470. Requirements for
Stationary Diesel-Fueled Internal
Combustion & Other Compression
Ignition Engines 1
(Amended May 4, 2012)
New Stationary Emergency
Standby Diesel Fueled Direct-
Drive Fire Pump Engines > 750
HP
0.15 g/bhp-hr Table 3
Bay Area Air
Quality
Management
District
IC Engine- Compression Ignition:
Stationary Emergency, non-
Agricultural, non-direct drive fire
pump ≥ 50 BHP Output
0.15 g/bhp-hr Any engine certified or
verified to achieve the
applicable standard.
Best Available Control Technology
(BACT) Guideline (12/22/2010)
San Joaquin Valley
Air Pollution
Control District
Emergency Diesel I.C. Engine
Driving a Fire Pump
0.1 g/bhp-hr (if TBACT
triggered) (corrected 7/16/01)
0.4 g/bhp-hr (if TBACT not
triggered)
Achieved in Practice or
contained in the SIP
Best Available Control Technology
(BACT) Guideline 3.1.4
Last Update: 6/30/2001
Emergency Diesel IC Engine 0.15 g/hp-hr or Latest EPA
Tier Certification level for
applicable hp range,
whichever is more stringent.
Achieved in Practice or
contained in the SIP
Best Available Control Technology
(BACT) Guideline 3.1.1
Last Update: 7/10/2009
New Jersey
Department of
Environment
Protection
Emergency Reciprocating
Internal Combustion Engines
SOTA for an emergency generator application meeting
the definition found at N.J.A.C. 7:27-19.1, "emergency
generator," is no auxiliary air pollution control.
State of the Art Manual for
Reciprocating Internal Combustion
Engines 2003
1. Also limits hours of operation: “New stationary emergency standby diesel-fueled engines (>50 bhp) shall not operate more than 50 hours per year for
maintenance and testing,” excluding new direct-drive emergency standby fire pump engines. Stationary emergency standby direct-drive fire pump
engines shall not operate more than the number of hours necessary to comply with the maintenance and testing requirements of the 2002 edition or the
most current edition of the National Fire Protection Association (NFPA) 25 – “Standard for the Inspection, Testing, and Maintenance of Water-Based
Fire Protection Systems.”
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
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standard. No applicable PM2.5 standard has been promulgated for the emergency engines
under 40 CFR Parts 60 and 61. In accordance with 25 Pa. Code §127.205(7), the
proposed PM2.5LAER limit is equivalent to and satisfies the PaBAT requirements of 25
Pa. Code §127.12(a)(5).
5.4.2.4 Step 3: Ranking of Technically Feasible PM/PM10 BACT Control Technologies
For all of the identified emergency diesel engines (i.e., electric generator or firewater
pump), the top-ranked feasible and applicable control option for PM emissions was based
on the use of combustion control techniques. As previously noted, for the proposed
emergency generator and firewater pump diesel engines, the most stringent level of PM2.5
control achieved is 0.15 g/hp-hr.
Based on the RBLC reviews that are summarized in Table 5-23 and Table 5-24, there are
some permits that have more stringent emission limits for PM and PM10. There is a PM
limit of 0.02 g/hp-hr for the Lake Charles Gasification Project’s (LA-0231) emergency
generator. The permit for this project, issued on June 22, 2009, states the following in the
control description “Comply with 40 CFR 60 subpart IIII.” The BACT analysis basis is
stated as “good engineering design and combustion practices, and burning low sulfur
diesel fuel as BACT for all pollutants.”81 As a result, the stated basis for the Lake Charles
project’s limit is application of the same control technologies as proposed for the Shell
Project’s proposed generator engines. However, although permitted in 2009, the Lake
Charles Gasification Project has not yet begun operation.82 As a result, the PM limit in
the Lake Charles project permit is not demonstrated as achieved in practice and is not
considered further by this analysis.
81 Lake Charles Cogeneration LLC Title V Permit Application and Prevention of Significant Deterioration
Study, September 2008. Page 3-11. 82 http://finance.yahoo.com/news/investor-contracts-show-lake-charles-plant-moving-104347721--
finance.html
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
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An additional evaluation was performed of the PM10 precedents presented in Table 5-23
with limits between 0.045 and 0.14 g/hp-hr. The results from this evaluation are
presented in Table 5-26. As shown below, the MGM and GP Allendale precedents were
removed from consideration because there is no add-on control that can be applied to the
selected engines that can achieve the emissions limits associated with these precedents.
Table 5-26. Basis for Removing PM Precedents from Consideration
Facility
Name
Filterable
PM10 Limit
(g/hp-hr)
Additional
Investigation
Conclusion
MGM Mirage
Units CC009 -
CC015
0.045
(Basis: 0.0001
lb/hr)
Engines included in
construction permit issued
in 2009 but not included in
2010 Title V operating
permit. Engines were never
installed
No demonstration that
the limit was achieve in
practice has occurred
MGM Mirage
Units LX024 &
LX025
0.08
(Basis: 0.38
lb/hr)
Permit does not require
compliance testing of the
engines
No demonstration that
the limit was achieve in
practice has occurred
GP Allendale
LP
SC-0114
0.065
(Basis: 0.2 lb/hr)
Permit does not require
compliance testing of the
engines
No demonstration that
the limit was achieve in
practice has occurred
GP Clarendon
LP
SC-0115
0.065
(Basis: 0.2 lb/hr)
Permit does not require
compliance testing of the
engines
No demonstration that
the limit was achieve in
practice has occurred
In accordance with the top-down BACT methodology the following more stringent
precedents must be considered further before proposing a less stringent limit:
NY-0101: 0.06 g/hp-hr
NV-0047: 0.08 g/hp-hr
LA-0219: 0.14 g/hp-hr
As shown in Table 5-24, the two more stringent emergency firewater pump limits are
0.06 g/hp-hr and 0.09 g/hp-hr for the Lake Charles Gasification and Sabine Pass LNG
Terminal Projects, respectively. The Lake Charles Gasification Project has not finished
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
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construction so these engines have not begun operation.83 As a result, demonstration that
this PM10 limit has been achieved in practice has not occurred and this precedent is not
considered further by this analysis. The Sabine Pass LNG Terminal precedent of
0.09 g/hp-hr has been achieved in practice, so in accordance with the BACT
methodology this precedent must be evaluated based on energy, environmental, or
economic impacts before proposing the less stringent limit.
5.4.2.5 Step 4: Evaluate PM/PM10 Control Options
As previously noted, the proposed emergency diesel generator engines will achieve the
most stringent level of control required by the Tier 2 emission standards for non-road,
compression-ignition engines, as codified at 40 CFR § 89.112 for this type of engine and
the proposed firewater pump engines will achieve the most stringent emission standards
for stationary fire pump engines, required by 40 CFR Part 60, subpart IIII Table 4 for this
type of engine. As a result, the only way to achieve the more stringent emissions rates
identified by RBLC review would be through the use of the previously eliminated (based
on technical feasibility when applied to emergency engines) CDPF technology.
However, if to be conservative the use of CDPF is considered further by this analysis, the
following would be the result. Economic analyses prepared by U.S. EPA indicate that,
for emergency use engines of the size proposed, the cost effectiveness of CDPF is
approximately $1 million per ton of PM reduction.84 The use of CDPF could achieve a
PM emission rate less than 0.01 and 0.001 tons per year from the proposed generator and
firewater engines, respectively. Based on this extremely high cost in relation to the very
small quantity of PM removed, the use of CDPF is rejected as BACT. It should also be
83 http://finance.yahoo.com/news/investor-contracts-show-lake-charles-plant-moving-104347721--
finance.html 84 Alternative Control Techniques Document: Stationary Diesel Engines. EPA Contract No. EP-D-07-019;
March 2010 Final Report. Table 5-3. Adjusted for 100 hours per year operation by multiplying by a
factor of 10 the cost effectiveness value for 1,000 hours per year operation ($99,724) for control of a
Tier 2 emission rate engine.
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
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noted that the use of CDPF has an adverse energy impact. The pressure drop across the
catalyst bed results in a loss in the engine’s efficiency.
5.4.2.6 Step 5: Propose Diesel Engine PM/PM10 BACT Limit
The proposed diesel-fired, compression-ignition internal combustion engine will be
certified by the equipment manufacturer to meet the Tier 2 emission standards for
nonroad, compression-ignition engines, as codified at 40 CFR § 89.112 (generator
engines) and the 40 CFR § 60 subpart IIII Table 4 (firewater pump engines). Due to the
very low emissions from these engines, the fact that the engine will operate only
intermittently, the availability of engines that are certified to achieve this emission level
and considering the nature of the certification test procedure for the nonroad engine
emission standards, the following PM/PM10 BACT limits are proposed:
Emergency Generators: 0.15 g/hp-hr
Emergency Firewater Pumps: 0.15 g/hp-hr
Compliance with these limits will be based on the purchase of certified engines and fuel,
and following the manufacturer’s operation/maintenance procedures.
The proposed PM BACT is as stringent as the applicable NSPS Part 60, subpatrt IIII and
no applicable PM10 standard has been promulgated for the emergency engines under 40
CFR parts 60 and 61. In accordance with 25 Pa. Code §127.205(7), the proposed
PM/PM10 BACT limit is equivalent to and satisfies the PaBAT requirements of 25 Pa.
Code §127.12(a)(5).
5.4.3 Diesel Engine Carbon Monoxide BACT Analysis
Carbon monoxide (CO) is a product of incomplete combustion. The formation of this
pollutant is limited by ensuring complete and efficient combustion of the fuel in the
engine. High combustion temperatures, adequate excess air and good air/fuel mixing
during combustion minimize CO emissions. Measures taken to minimize the formation
of NOx during combustion may inhibit complete combustion, which could increase CO
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
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emissions. For CO, the analysis is presented in accordance with the five-step BACT
methodology.
BACT permit limits must be at least as stringent as applicable NSPS limits. Based on
NSPS subpart IIII, the minimum standards that would meet BACT requirements for CO
emissions from the proposed emergency diesel engines (i.e., both for the generators and
firewater pumps) is a limit of 3.5 g/kw-hr (2.6 g/hp-hr).
5.4.3.1 Step 1: Identify Diesel Engine CO Controls
Table 5-27 and Table 5-28 present summaries of the most recent permit determinations
listed in the RBLC database for stationary emergency generator engines and stationary
emergency firewater engines, respectively. As shown, combustion controls (good
combustion practices, tune-ups, turbocharging/after cooling, and compliance with
Subpart IIII) are used to meet BACT requirements. In summary, the identified control
technologies and techniques for CO emissions are the same as those identified for VOC
and the use of oxidation catalyst.
5.4.3.2 Step 2: Eliminate Technically Infeasible
Although oxidation catalyst has been applied and is considered to be technically feasible
for engines that operate continuously, it is not considered to be technically feasible for
engines in emergency service. To ensure that each engine is in good working order, the
proposed engines will be operated infrequently and for short periods of time (less than
one hour/week). The short duration of the proposed engine’s operation does not provide
adequate time for the oxidation catalyst to reach the required operating temperature
where a practical level of emissions reductions can be achieved. This conclusion is
consistent with the findings in the RBLC database review summarized in Table 5-27 and
Table 5-28. As a result, the use of oxidation catalyst is not considered feasible for the
Project’s emergency engines. However, for purposes of completeness, the impacts
associated with the potential use of oxidation catalyst are considered below. The decision
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Table 5-27. RBLC Summary of CO BACT Precedents for Emergency Diesel Engines
RBLC
ID NO. Facility Name
Permit
Date Process Description
Capacity
(hp) Control Description
CO Limit
(g/hp-hr)
FL-0332 Highlands Biorefinery
& Cogeneration Plant 9/23/11 Emergency Equipment
2666
(Basis:
2000 KW)
NSPS 40 CFR 60, Subpart IIII 2.6
(Basis: 3.5 g/kw-hr)
LA-0254
Nine Mile Point
Electric Generating
Plant
8/16/11 Emergency Diesel
Generators 1250
Ultra Low Sulfur Diesel and Good
Combustion Practices 2.6
FL-0322
Sweet Sorghum-to-
Ethanol Advanced
Biorefinery
12/23/10 Emergency Generators 2682 NSPS 40 CFR 60, Subpart IIII 2.6
(Basis: 3.5 g/kw-hr)
MI-0389 Karn Weadock
Generating Complex 12/29/09 Emergency Generator
2666
(Basis:
2000 KW)
Engine Design & Operation 15 ppm
sulfur fuel
2.6
(Basis: 3.5 g/kw-hr)
NV-0050 MGM Mirage
Units CC009 - CC015 11/30/09
Caterpillar Diesel
Generator, M/N:
3516C, 2,500 kW 3622
Turbocharger & Good Combustion
Practices
0.8
(Other Case-by-Case)
NV-0050 MGM Mirage
Units LX024 & LX025 11/30/09
Caterpillar Diesel
Generator, M/N:
3512C, 1,500 kW 2206
Turbocharger & Good Combustion
Practices
0.8
(Other Case-by-Case)
LA-0231 Lake Charles
Gasification Facility 6/22/09
Emergency Diesel
Power Generator
Engines
1341 Comply with 40 CFR 60, Subpart
IIII
0.2
(Basis: 0.62 lb/hr)
SC-0114 GP Allendale LP 11/25/08 Diesel Emergency
Generator 1400
1.0
SC-0115 GP Clarendon LP 2/10/09 Diesel Emergency
Generator 1400
Tune-Ups & Inspections will be
performed as outlined in Good
Management Practice Plan.
1.0
OK-0129 Chouteau Power Plant 1/23/09 Emergency Diesel
Generator (2200 Hp) 2200
2.6
(Basis: 3.5 g/kw-hr)
OH-0317 Ohio River Clean
Fuels, LLC 11/20/08 Emergency Generator 2922
Good Combustion Practices &
Good Engine Design 2.6
(Basis: 3.5 g/kw-hr)
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RBLC
ID NO. Facility Name
Permit
Date Process Description
Capacity
(hp) Control Description
CO Limit
(g/hp-hr)
OK-0128 Mid American Steel
Rolling Mill 9/8/08 Emergency Generator 1200
0.32
(Basis: 0.84 lb/hr)
NV-0047 Nellis Air Force Base 2/26/08 Large Internal
Combustion Engines 1350 Turbocharger & Aftercooler
0.2
(Other Case by Case)
LA-0219 Creole Trail LNG
Import Terminal 8/15/07
Diesel Emergency
Generator 2168
Good Combustion Practices &
Good Engine Design and use of low
sulfur and low ash fuel
2.6
IA-0088 ADM Corn Processing
- Cedar Rapids 6/29/07 Emergency Generator
2000
(Basis:
1500 KW)
Engine is required to meet limits
established as BACT (Tier 2
Nonroad)
2.6
MN-
0071 Fairbault Energy Park 6/5/07 Emergency Generator
2333
(Basis:
1750 KW)
2.5
PA-0278 Moxie Liberty
LLC/Asylum Power 10/10/12 Emergency Generator
1333
(Basis:
1000ekW
Operate and maintain to achieve the
emission standard over the entire
life of the engine. Limit 100
hours/yr operation.
0.13
PA-0286
Moxie Energy LLC/
Patriot Generation
Plant
01/31/13 Emergency Generator
1333
(Basis:
1000ekW)
Operate and maintain to achieve the
emission standard over the entire
life of the engine. Limit 100
hours/yr operation.
0.13
PA-0291 Hickory Run Energy
Station 04/23/13 Emergency Generator 1135 bhp Good Combustion Practice
2.32
(based on 5.79 lb/hr)
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Table 5-28. RBLC Summary of CO BACT Precedent for Firewater Emergency Diesel Engines
RBLC
ID NO. Facility Name
Permit
Date
Process
Description
Capacity
(hp) Control Description
CO Limit
(g/hp-hr)
LA-0219 Creole Trail LNG
Import Terminal 8/15/07
Firewater Pump
Diesel Engine 660
Good Combustion Practices & Good
Engine Design Incorporating Fuel
Injection Timing Retardation (ITR)
0.21
calculated
LA-0194 Sabine Pass LNG
Terminal 11/24/04
Firewater Booster
Pump Diesel
Engines (2)
300 Good Engine Design & Proper Operating
Practices 0.27
LA-0231 Lake Charles
Gasification Facility 6/22/09
Firewater Diesel
Pumps (3) 575 Comply With 40 CFR 60 subpart IIII
0.29
calculated
MI-0402 Sumpter Power Plant 11/17/11
Diesel Fuel-Fired
Combustion Engine
(RICE)
732 Good Combustion Practices 0.31
LA-0194 Sabine Pass LNG
Terminal 11/24/24
Firewater Pump
Diesel Engines 1-3 660
Good Engine Design & Proper Operating
Practices
0.38 1
calculated
SC-0114 GP Allendale LP 11/25/08 Firewater Diesel
Pump 525
Tune-Ups & Inspections will be
performed as outlined in the Good
Management Practice Plan.
1.1 calculated
LA-0219 Creole Trail LNG
Import Terminal 8/15/07
Firewater Pump
Diesel Engine 525
Good Combustion Practices & Good
Engine Design Incorporating Fuel
Injection Timing Retardation (ITR)
1.38 calculated
IA-0088
ADM Corn
Processing - Cedar
Rapids
6/29/07 Fire Pump 540 Engine is required to meet limits
established as BACT (Tier 3 Nonroad). 2.6
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RBLC
ID NO. Facility Name
Permit
Date
Process
Description
Capacity
(hp) Control Description
CO Limit
(g/hp-hr)
IA-0095
Tate & Lyle
Ingredients
Americas, Inc.
9/19/08 Fire Pump Engine 575 2.6
calculated
MI-0389 Karn Weadock
Generating Complex 12/29/09 Fire Pump 525
Engine Design & Operation. 15 ppm
Sulfur Fuel. 2.6
PA-0244 First Quality Tissue
LLC 10/20/04 Fire Pump 575 3.04 calculated
OH-
0254
Duke Energy
Washington County
LLC
8/14/03 Emergency Diesel
Fire Pump Engine 400 Low Sulfur Fuel, Combustion Control
3.13 2
calculated
PA-0278 Moxie Liberty
LLC/Asylum Power 10/10/12
Fire Pump
460 bhp
Operate and maintain to achieve the
emission standard over the entire life of
the engine. Limit 100 hours/yr
operation.
0.5
PA-0286
Moxie Energy LLC/
Patriot Generation
Plant
01/31/13
Fire Pump Engine -
460 BHP
460 bhp
Operate and maintain to achieve the
emission standard over the entire life of
the engine. Limit 100 hours/yr
operation.
0.5
PA-0291 Hickory Run Energy
Station 04/23/13
Emergency
Firewater Pump
(450 BHP)
1135 bhp Good Combustion Practice
1.03
(based on 2.58 lb/hr
limit)
1. RBLC had 0.0008 g/bhp. This should have been labeled as lb/bhp, which converts to 0.38 g/bhp.
2. RBLC had 1 g/bhp. 2.76 pound per hour and 400 Hp converts to 3.13 g/bhp.
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to include potential consideration of oxidation catalyst results from a review of SIP
provisions which indicate that, as shown in Table 5-29, oxidation catalyst is required
without the need for an emission limit in the San Joaquin AQMD rules.
5.4.3.3 Step 3: Ranking of Technically Feasible CO Control Technologies
Because oxidation catalyst is an add-on control, it can theoretically be coupled with
combustion controls to achieve a more stringent level of emission control. As a result,
the analysis below considers the use of combustion controls both with and without
oxidation catalyst.
As shown in Table 5-26, several of the CO precedents for emergency diesel generators
were removed from consideration because the limits in these permits have not been
demonstrated in practice. The most stringent remaining emergency generator precedents
are for the following projects:
OK-0128: 0.32 g/hp-hr
NV-0047: 0.2 g/hp-hr
MN-0071: 2.5 g/hp-hr
The most stringent emergency firewater pump limit presented in Table 5-28 is 0.21 g/hp-
hr (LA-0219) and the range of other more stringent limits is from 0.21 g/hp-hr 1.38 g/hp-
hr.
In accordance with the BACT methodology, the more stringent limits for both the
emergency generator and firewater engines must be evaluated further before proposing a
less stringent limit.
5.4.3.4 Step 4: Evaluate CO Control Options
Although the use of oxidation catalyst has been determined above to be technically
infeasible for the Project’s emergency engines, for the sake of argument, this technology
is considered further in this Step 4 analysis. The USEPA ACT document provides an
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Table 5-29. Regulatory Agencies with CO Guidelines/Requirements for Emergency Stationary Diesel Engines
Regulatory
Agency
Description Emission Limit Comment Reference
South Coast Air
Quality Management
District
Stationary Diesel-Fueled Internal
Combustion and Other Compression
Ignition Engines >750 HP
2.6 g/bhp-hr Table 2
Rule 1470. Requirements for Stationary
Diesel-Fueled Internal Combustion &
Other Compression Ignition Engines 1
(Amended May 4, 2012)
New Stationary Emergency Standby
Diesel Fueled Direct-Drive Fire Pump
Engines > 750 HP
2.6 g/bhp-hr Table 3
Bay Area Air
Quality Management
District
IC Engine- Compression Ignition:
Stationary Emergency, non-Agricultural,
non-direct drive fire pump ≥ 50 BHP
Output
2.6 g/bhp-hr Any engine certified
or verified to achieve
the applicable
standard.
Best Available Control Technology
(BACT) Guideline (12/22/2010)
San Joaquin Valley
Air Pollution Control
District
Emergency Diesel I.C. Engine Driving a
Fire Pump
Latest EPA Tier
Certification level
for applicable hp
range
Achieved in Practice
or contained in the
SIP
Best Available Control Technology
(BACT) Guideline 3.1.4
Last Update: 6/30/2001
Emergency Diesel IC Engine No limit (oxidation
catalyst considered
technically feasible)
Achieved in Practice
or contained in the
SIP
Best Available Control Technology
(BACT) Guideline 3.1.1
Last Update: 7/10/2009
New Jersey
Department of
Environment
Protection
Emergency Reciprocating Internal
Combustion Engines
SOTA for an emergency generator
application meeting the definition found at
N.J.A.C. 7:27-19.1, "emergency generator,"
is no auxiliary air pollution control.
State of the Art Manual for Reciprocating
Internal Combustion Engines 2003
1 - Also limits hours of operation: “New stationary emergency standby diesel-fueled engines (>50 bhp) shall not operate more than 50 hours per year for
maintenance and testing,” excluding new direct-drive emergency standby fire pump engines. Stationary emergency standby direct-drive fire pump engines
shall not operate more than the number of hours necessary to comply with the maintenance and testing requirements of the 2002 edition or the most current
edition of the National Fire Protection Association (NFPA) 25 – “Standard for the Inspection, Testing, and Maintenance of Water-Based Fire Protection
Systems.”
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economic analysis for emergency engines of the size proposed by this Project. In the
ACT document, the cost effectiveness of oxidation catalyst designed to achieve a 90%
CO reduction is estimated at approximately $98,000 per ton of CO reduction. 85 A
similarly designed CO catalyst would result in a CO control level of 0.26 g/hp-hr, which
is very close to the limit for the most stringent of the identified precedents. Based on this
extremely high cost compared to the marginal (if any) reduction in CO, the use of
oxidation catalyst is rejected as BACT. It should also be noted that the use of oxidation
catalyst also has an adverse energy impact. The pressure drop across the catalyst bed
results in a loss in the engine’s efficiency. The more stringent precedents and their
associated limits identified above are therefore eliminated from consideration based on
the technical feasibility of applying oxidation catalyst to the Project’s emergency engines
and the high cost infeasibility of its application.
5.4.3.5 Step 5: Establish Diesel Engine CO BACT
The Project’s diesel-fired, compression ignition internal combustion engines (generator
and firewater pump) will be certified by the equipment manufacturer to meet the Tier 2
emission standards for nonroad, compression ignition engines (2.6 g/bhp-hr), as codified
at Subpart IIII of 40 CFR part 60 and 40 CFR § 89.112. Due to the very low annual
emissions from these sources, the fact that they will operate as non-emergency engines
only intermittently, the availability of engines that are certified to achieve this emission
level and considering the nature of the certification test procedure for the nonroad engine
emission standards, the following CO BACT limits are proposed:
Emergency Generators: 2.6 g/hp-hr
Emergency Firewater Pumps: 2.6 g/hp-hr
Compliance with these limits will be based on the purchase of certified engines, and
following the manufacturer’s operation/maintenance procedures.
85 Ibid. Table 5-4. Adjusted for 100 hours per year operation by multiplying by 10 (1,000/100) the cost
effectiveness value for 1,000 hours per year operation ($9,837) for control of Tier 2 emission rate
engine.
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The proposed CO BACT limit is as stringent as the NSPS subpart CO standard. In
accordance with 25 Pa. Code §127.205(7), the proposed CO BACT limit is equivalent to
and satisfies the PaBAT requirements of 25 Pa. Code §127.12(a)(5).
5.4.4 Diesel Engine GHG BACT Analysis
GHGs emitted by the diesel engines are the same as emitted by other fossil fuel
combustion sources: CO2, CH4, and N2O, although the emission factors are different, due
to the combustion of a different fuel (diesel instead of natural gas) and a different type of
combustor (reciprocating engine versus a combustion turbine or furnace). As is the case
for all fossil fuel-fired sources, CO2 emissions are the dominant contributor to the CO2e
emission rate. No applicable GHG standards have been promulgated for emergency
engines under 40 CFR parts 60 and 61.
5.4.4.1 Steps 1-4: Identify Technically Feasible Controls
The available control techniques for control of GHGs from the diesel engines include:
Use of low GHG emitting fuels,
Energy efficiency,
Good combustion practices (meeting diesel engine NSPS requirements), and
Carbon capture and sequestration (CCS).
It is typical for emergency use diesel engines to be fired with diesel fuel rather than
natural gas, a lower GHG emitting fuel, as one of the emergencies that can happen at a
facility is the loss of natural gas supply. By storing diesel fuel at the site, the facility has
a backup fuel available for emergency use (electric power generation and firewater
pumping). As a result, requiring the use of natural gas would be considered redefining
the emissions unit, which is inconsistent with USEPA policy with respect to BACT
analyses.
Energy efficiency options for reducing GHG emissions outside of good combustion
practices are considered to be technically infeasible because emergency engines typically
only operate one hour a month for periodic maintenance and testing to ensure operability.
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As a result, the engines never reach steady state operation long enough for a heat
recovery system to warm up and operate.
Meeting the NSPS Part 60, Subpart IIII emission standards requires the use of good
combustion control, thereby minimizing the emissions of methane (CH4). As is the case
for CO and VOC emissions, oxidation catalyst is a potential control option for reducing
CH4 emissions. However, given the much lower emission rate for CH4 (0.026 g/hp-hr)
relative to CO (2.6 g/hp-hr), the use of oxidation catalyst would not be cost effective.86
The use of oxidation catalyst is rejected as BACT due to its adverse energy impacts, the
control system pressure drop, economic impacts and minimal environmental benefit.
While Section 5.6 discusses the potential applicability of CCS to the entire facility, it is
noted here that the application of CCS technology to emergency diesel engines would be
technically impractical. As is the case with a heat recovery system, the emergency diesel
engines do not operate long enough at steady state conditions to effectively capture CO2
emissions. As such, in addition to the analysis presented in Section 5.6, the use of CCS is
rejected as a BACT option for the control of CO2 for such engines.
5.4.4.2 Step 5: Propose Diesel Engine CO2e/GHG BACT Limits
The diesel-fired, compression ignition internal combustion engines will be certified by
the equipment manufacturer to meet the Tier 2 emission standards for nonroad,
compression ignition engines, as codified at Subpart IIII of 40 CFR part 60 and 40 CFR
§89.112. Due to the very low emissions from these sources, the fact that they will
operate only intermittently, the availability of engines that are certified to achieve this
emission level and considering the nature of the certification test procedure for the
nonroad engine emission standards, the following GHG BACT limits are proposed:
86 Application of oxidation catalyst to the control of CH4 in steady-state operations has demonstrated a
reduction of 50%. The level of reduction in an unsteady-state emergency engine application would
further reduce the level of control. In addition, as noted above, in EPA’s ACT document the cost
effectiveness of an oxidation catalyst designed to achieve a 90% CO reduction was estimated at
approximately $98,000 per ton of CO reduction.
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Emergency Generator Engines: Combined emissions of CO2e from the four
emergency generator engines shall not exceed 1,151.6 tons per year on a 12-
month rolling average basis.
Firewater Pump Engines: Combined emissions of CO2e from the three firewater
pump engines shall not exceed 120.3 tons per year on a 12-month rolling average
basis.
Compliance shall be demonstrated using the following factor: 1.15 lb CO2e/bhp-
hr.
As previously stated, no applicable GHG standards have been promulgated for
emergency engines under 40 CFR parts 60 and 61. In accordance with 25 Pa. Code
§127.205(7), the proposed GHG BACT limit is equivalent to and satisfies the PaBAT
requirements of 25 Pa. Code §127.12(a)(5).
5.5 Equipment Leaks
The proposed project includes piping and a large number of connectors and valves, as
well as pumps, compressors and similar components for movement of gas and liquid raw
materials, intermediates and products. Each of these components are potential sources of
fugitive VOC and methane (CH4) emissions due to leakage from rotary shaft seals,
connection interfaces, valve stems and similar points.87
5.5.1 Equipment Leaks of VOC LAER Analysis
Control strategies for VOC emissions from component equipment leaks are based on
comprehensive work practices commonly known as leak detection and repair (LDAR)
programs. The baseline requirements for the LDAR program applicable to the proposed
ethylene cracking and polyethylene manufacturing facilities are set forth in 40 CFR
Part 60 subparts VV88 and VVa, 40 CFR Part 61 subparts J and V, and 40 CFR Part 63
subparts UU, YY, and FFFF. These programs include requirements for monitoring to
87 Control of hazardous air pollutants from equipment leaks is addressed by the appropriate 40 CFR
parts 61 and 63 subparts 88 Subpart VV is referenced by 40 CFR 60 subpart DDD; if desired VVa or 40 CFR 63 Subpart F
can be used as an alternate means of compliance with the LDAR requirements of the remainder of the
facility.
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detect leaks and attempting and completing repairs of leaking components in the
following categories:
Pumps in light liquid service;
Compressors;
Pressure relief devices in gas/vapor service;
Sampling connection systems;
Open-ended valves or lines;
Valves in gas/vapor service and in light liquid service;
Pumps, valves, connectors, and agitators in heavy liquid service;
Instrumentation systems;
Pressure relief devices in liquid service;
Closed-vent systems
5.5.1.1 Steps 1: Identify Equipment Leaks VOC Controls
Potential enhancements to the baseline LDAR program work practice requirements
include the following:
Lowering the monitoring exemption threshold from <10% VOC to <5% VOC.
Lower definition of a “leaking” component threshold concentration, as measured
at the potential leak interface. This has the effect of accelerating or broadening
the repair obligations for leaking components to include components that would
not require repair under the NESHAP/NSPS rules.
Increase leak monitoring frequencies, which has the effect of accelerating the
identification and repair of leaking components.
Disallowing reduced monitoring frequency for valves (skip periods)
As part of an effective LDAR program, equipment specifications and maintenance
practices are designed and implemented to reduce the occurrence of leaks. For certain
service applications, components with inherently leakless design features are available.
These components reduce VOC emissions, regardless of the quality or frequency of
LDAR activities. Some regulations and permits have specified the use of leakless
designs in applications where such use is practicable. These leakless designs include the
following:
Canned, magnetic drive or diaphragm pumps not having external seals;
Pumps with double mechanical seals and a barrier fluid;
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Magnetic-drive centrifugal pumps, with no direct coupling between the drive and
the pump casing, and consequently no rotating shaft seal (the pump is driven by
magnetic coupling of strong permanent magnets attached to the drive motor and
similar permanent magnets incorporated into the impeller of the pump);
Diaphragm valves;
Bellows valves with the bellows welded to both the bonnet and stem; and
Connectors welded around the complete circumference to prevent the joint from
being disassembled by unbolting or unscrewing the components.
Finally, in addition to enhanced work practice requirements, because leakless designs are
not available for all components and across all sizes, some facilities have been subjected
to enforceable limits on the number of leaking components.
5.5.1.2 Step 2: Eliminate Technically Infeasible Controls
All of the identified control options are technically feasible to some degree. However,
components with inherently leakless design features are not available for all services and
all sizes. The most effective of the identified control strategies is a combination of the
identified control options. Specifically, this includes an LDAR program with enhanced
work practices relative to the NESHAP prescribed minimum, combined with enforceable
limits on percent leaking components.
5.5.1.3 Step 3: Establish Equipment Leaks VOC LAER
The proposed LAER for VOC emissions from equipment leaks covers both the cracking
and polyethylene manufacturing facilities. In accordance with its definition, a proposed
LAER may not allow a source to emit a pollutant in excess of the amount allowable
under an applicable new source standard of performance. As a result, any proposal
covering both the cracking and polyethylene manufacturing facilities must include the
requirements of 40 CFR Part 60, subparts VVa, DDD (which refers to VV) and 40 CFR
Part 63 subparts UU, YY, and FFFF (which refers to UU). All of these can be
streamlined by requesting that the proposed equipment be controlled in accordance with
the requirements of NESHAP subpart UU (40 CFR §63.1019). As a result, site wide
compliance with NESHAP subpart UU is proposed except:
For purposes of compliance, all organic compounds (ethane, methane, VOC and
HAP) shall be considered as if they were organic HAP;
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Equipment containing or contacting fluids with < 5% total organic compounds
(including ethane and methane) is exempt from monitoring;
Monthly inspection of non-bellows seal valves shall be required unless
98.0 percent or greater of the non-bellows seal gas/vapor and/or light liquid
valves are found to leak at a rate less than 100 ppmv for two consecutive months,
then the operator may change to a quarterly inspection program. The annual
monitoring frequency for valves (skip periods) is not applicable;
Components with inherently leakless design features will be installed as
practicable;
Leak definitions of 100 ppmv for pump seals, compressor seals, flanges and
valves in gas/vapor and light liquid service, 200 ppmv for atmospheric pressure
relief devices without a rupture disk and 500 ppmv for all other components shall
be used;
Screwed connections; heat exchanger heads; sight glasses; meters; gauges;
sampling connections; bolted manways and hatches shall be included in the
definition of “equipment”;
All sampling systems in total organic compound (VOC, ethane, methane and
HAP) service > 5% shall be closed-purge, closed loop, or closed-vent systems.
In-situ sampling systems shall be exempt; and
A first attempt at repair shall be required for all leaking components within five
(5) days and repair shall be completed within 15 days for all components unless
the repair would require a unit shutdown that would create more emissions than
the repair would eliminate, and if so, the repair may be delayed until the next
scheduled shutdown, except first attempt at repair for:
o Any leak >10,000 ppm & <25,000 ppm - 2 days,
o Atmospheric pressure relief device leak without a rupture disk >200 &
<25,000ppm - 2 days,
o Any leak > 25,000 ppm - 1 day,
o Heavy liquid components > 500 ppm - 1 day, and
o Any leak in HRVOC89 service > 10,000 ppm - 1 day
These proposed work practice emission limits are substantially more stringent than NSPS
standards in 40 CFR 60 subpart VVa, 40 CFR 61 subparts J and V, and NESHAPS
requirements in 40 CFR 63 subparts FFFF, UU and YY. Table 5-30 presents the above
proposed LAER components and references the regulations/permits where these items
were found.
89 HRVOC = 1,3-butadiene, ethylene, propylene and butylene.
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Table 5-30. LAER Components and References
LAER Component Reference
In organic hazardous air pollutant or in organic HAP service means that piece
of equipment either contains or contracts a fluid (liquid or gas) that is at least
five (5) percent by weight of total organic HAP's as determined according to
the provisions of §63.180(d) of subpart H.
40 CFR §63.1020 Definitions (Subpart UU)
If 98.0 percent or greater of the new (non-bellows seal) valves and the new
flange population inspected is found to leak gaseous or liquid volatile organic
compounds at a rate less than 500 ppmv for two consecutive months, then the
operator may change to a quarterly inspection program with the approval of
the District.
Chevron Products Co, El Segundo, CA. Permit to
Operate for Facility ID 800030, Revision #145, July
1, 2012.
Leak definition of 100 ppmv for pump seals, compressor seals, valves and
connectors in gas/vapor and light liquid service.
BAAQMD Best Available Control Technology
Guideline
Leak definition of 500 ppmv for all other components. SCAQMD Rule 1173 & TCEQ Tex. Admin. Code
tit. 30, Chapter 115 Subchapter H
Inclusion of connectors; heat exchanger heads; sight glasses; meters; gauges;
sampling connections; bolted manways; and hatches in the LDAR program;
TCEQ Tex. Admin. Code tit. 30, Chapter 115
Subchapter H
Underground process pipelines will contain no buried valves such that
fugitive emission monitoring is rendered impractical;
TCEQ Tex. Admin. Code tit. 30, Chapter 115
Subchapter D
Requirements for a first attempt at repair of all leaking components within 5
days a and repair in 14 days b for all components unless the repair would
require a unit shutdown, that would create more emissions than the repair
would eliminate, the repair may be delayed until the next scheduled
shutdown, except first attempt at repair for:
Any leak >10,000 ppm & <25,000 ppm - 2 days, c
Atmospheric pressure relief device leak >200 & <25,000 - 2 days, e
Any leak > 25,000 ppm - 1 day, e
Heavy liquid components > 500 ppm - 1 day, e
Light liquid leaks > 3 drops per minute - 1 day, e and
Any leak in HRVOC service > 10,000 - 1day.d
a - TCEQ Tex. Admin. Code tit. 30, Chapter 115
Subchapter D
b - Chevron Products Co, El Segundo, CA. Permit to
Operate for Facility ID 800030, Revision #145,
July 1, 2012
c - SCAQMD Rule 1173
d - TCEQ Tex. Admin. Code tit. 30, Chapter 115
Subchapter H
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The LDAR program that is proposed must meet two criteria to be considered LAER. To
fulfill the first criterion, the fugitive emissions regulations and BACT guidelines were
reviewed for the states most likely to have the most stringent emission limits contained in
the state implementation plan:
South Coast Air Quality Management District (SCAQMD) Rule 1173,
Texas Commission on Environmental Quality (TCEQ) 28LAER90 and Tex.
Admin. Code tit. 30, Chapter 115 Subchapter H (highly reactive VOCs)
programs, and
Bay Area Air Quality Management District (BAAQMD) BACT guidelines.
A summary of the equipment leak rates and repair periods in SCAQMD Rule 1173, the
TCEQ LAER requirements and the TCEQ Chapter 115 Subchapter H requirements are
presented in Table 5-31 and Table 5-32. Table 5-33 presents a summary of the
BAAQMD’s leak rate definitions. Based on a comparison of the program requirements
summarized in these tables, the first criterion is met by the equipment leak LDAR
proposal described above.
The second criterion is addressed above through the identification of the Chevron permit
precedent and the incorporation of its work practices (where more stringent) into the
proposed LDAR program. In accordance with 25 Pa. Code §127.205(7), the proposed
VOC LAER limit is equivalent to and satisfies the PaBAT requirements of 25 Pa. Code
§127.12(a)(5).
5.5.2 Equipment Leaks of GHG BACT Analysis
Two sources of GHG emissions associated with equipment leaks must be considered: 1)
methane contained in the VOC leaks associated with process units (which are addressed
via the LAER analysis provided in the previous section, and 2) potential leaks from the
piping employed to deliver natural gas to the projects furnaces, Cogen Units, flares, and
other combustion sources. This piping includes connectors/flanges, block and control
90 28LAER refers to the Texas Commission on Environmental Quality’s (TCEQ’s) “boilerplate” special
conditions for nonattainment NSR. The most recent version of these conditions is found at
http://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bpc_rev28laer.pdf
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Table 5-31. SCAQMD Rule 1173 Equipment Leak Rates and Repair Periods 1
Equipment/Service 2 Leak Rate Trigger
(ppm)
First Repair
Period 3
Extended
Repair Period 3,4
Light liquid/gas/vapor
components >500 & <10,000 7 days 7 days
Heavy liquid components >100 & <500 7 days 7 days
Any leak >10,000 & <25,000 2 days 3 days
Atmospheric pressure relief
device >200 & <25,000 2 days 3 days
Any leak >25,000 1 day
Heavy liquid components >500 1 day
Light liquid leaks > 3 drops per minute 1 day
1. South Coast Air Quality Management District Rule 1173 Control of Volatile Organic Compound
Leaks and Releases from Components at Petroleum Facilities and Chemical Plants, as amended
February 6, 2009.
2. Components are valves, fittings, pumps, compressors, pressure relief devices, diaphragms, hatches,
sight-glasses, and meters
3. Calendar days
4. For each calendar quarter, the operator may extend the repair period for a total number of components
for a total number of leaking component, not to exceed 0.05 percent of components inspected during
the previous quarter, by type, rounded upward to the nearest integer where required.
Table 5-32. TCEQ LAER Equipment Leak Rates and Repair Periods 1
Equipment Leak
Rate
(ppm) 2
Repair Period Other
Valves
>500
15 days -
If the repair would
require a unit
shutdown, that would
create more emissions
than the repair would
eliminate, the repair
may be delayed until
the next scheduled
shutdown
Each open-ended valve or line shall be
equipped with a cap, blind flange, plug,
or a second valve.
Connectors
Connectors shall be inspected by
visual, audible, and/or olfactory means
at least weekly by operating personnel
walk-through
Agitator seals All new and replacement pumps,
compressors, and agitators shall be
equipped with a shaft sealing system
that prevents or detects emissions of
VOC from the seal. These seal systems
need not be monitored.
Compressor
seals
Pump seals
Any Leaks > 10,000 First attempt – 1 day
Repaired -7 days In HRVOC service
Pressure Relief
Valves with
Rupture Disc
For valves equipped with rupture disc, a pressure-sensing device shall be
installed between the relief valve and rupture disc to monitor disc integrity.
Replace at the earliest opportunity but no later than the next process shutdown
1. Texas Commission on Environmental Quality, Air Permits Division, New Source Review Boilerplate
Special Conditions for 28LAER, August 2011.
2. Quarterly monitoring using approved gas analyzer
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Table 5-33. BAAQMD Best Available Control Technology Guideline
Equipment/Service Leak Rate a (ppm)
Flanges >100
Valves >100
Pumps >100
Compressors >100
Pressure relief valves Not applicable
a - http://hank.baaqmd.gov/pmt/bactworkbook/default.htm
valves, pressure relief valves and miscellaneous devices (pressure and temperature
gauges, flow meters, sample connections, etc.).
No applicable GHG standards have been promulgated for equipment leaks under 40 CFR
parts 60 and 61. In accordance with 25 Pa. Code §127.205(7), the proposed GHG BACT
limit is equivalent to and satisfies the PaBAT requirements of 25 Pa. Code §127.12(a)(5).
5.5.2.1 Steps 1-4: GHG Piping Equipment Leaks
The above discussion pertaining to equipment leaks of VOCs is directly applicable to
equipment leaks of the methane contained in the natural gas and as a result is not
reviewed again. Although LAER requirements are not applicable to methane emissions
(i.e., the definition of VOC’s excludes methane), the same LDAR program is proposed to
control equipment leaks of methane from natural gas lines containing methane.
The equipment leak provisions included in the Texas GHG permits for ethylene
manufacturing are summarized in Table 5-34. The Texas GHG permits for ethylene
manufacturing facilities utilize the following work practices:
LDAR for VOC containing streams but not gaseous fuel containing streams
(BASF FINA) for one furnace,
Auditory, Visual, and Olfactory (AVO) Monitoring (Chevron/Phillips and
ExxonMobil) for eight furnaces each, or
LDAR for methane containing streams for two furnaces.
5.5.2.2 Step 5: Establish Equipment Leaks GHG BACT
The same LDAR program that is proposed for VOCs in Section 5.5.1 is proposed for
GHGs except that methane will be the targeted pollutant. As previously noted, no
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Table 5-34. Summary of Texas Ethylene/Polyethylene Manufacturing GHG BACT Determinations
Company/
Project Control Options Considered Selected Limits
BASF FINA
Petrochemicals
Port Arthur, TX
2012 PSD-TX-
903-GHG SOB
and permit
Leak detection and repair (LDAR) for methane
Use of an LDAR program to control the
negligible amount of GHG emissions
that occur as process fugitives would be
cost prohibitive.
LDAR program to minimize process
fugitive VOC emissions.
No limit
Work practices: TCEQ’s 28LAER
LDAR for VOCs
Chevron/Phillips,
Cedar Bayou, TX
PSD-TX-748-
GHG October
2012 SOB and
permit
Leak detection and repair (LDAR) for methane
Audio and visual observations (AVO) monitoring
AVO for the piping components in the
new ethylene cracker plant in fuel gas
and natural gas service.
No limit
Work practices: AVO for the piping
components in fuel gas and natural
gas service.
Equistar
Channelview, TX
(OP-1 & OP-2)
PSD-TX-1272-
GHG May 2013
SOB and permit
Installation of leakless technology components to
eliminate fugitive emission sources. Instrumented
Leak Detection and Repair (LDAR) program
(Method 21).
Leak Detections and Repair with remote sensing
technology
Auditory, Visual, and Olfactory (AVO) monitoring
program.
Design and construct facilities with high quality
components, with materials of construction
compatible with the process.
Equistar proposes to use TCEQ method
28LAER for LDAR & to use AVO
methods as additional monitoring for
leaks.
Based on adverse environmental
impacts, leakless technologies are
eliminated as BACT.
No limit
Work practices: TCEQ’s 28LAER
LDAR for methane on two furnaces
ExxonMobil,
Baytown, TX
(draft SOB and
permit)
Leakless/Sealless Technology
Instrument LDAR Programs
Remote Sensing
Auditory, Visual, and Olfactory (AVO) Monitoring
AVO for the piping components in fuel
gas and natural gas service
Leakless valve technology for fuel lines
is considered technically impracticable
Instrument LDAR and/or remote sensing
of piping fugitive emissions in fuel gas
and natural gas service considered
economically impracticable
No limit
Work practices: AVO for the piping
components in fuel gas and natural
gas service.
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applicable GHG standards have been promulgated for equipment leaks under 40 CFR
parts 60 and 61.
5.6 Evaluation of the Potential Use of Carbon Capture and Sequestration (CCS) as BACT for CO2
The major GHG emitted by the Project is carbon dioxide (CO2). The significant sources
of CO2 emissions from the Project are the ethylene cracking furnaces and the Cogen
Units. Other minor combustion sources of GHG emissions include the emergency diesel
engines to generate electricity during power outages and diesel engine drivers for
emergency firewater pumps, thermal incinerators, and flares. These additional minor
sources of GHGs, which comprise approximately six percent of the combustion-related
CO2 emissions, are not considered by this analysis because the cost effectiveness
associated with application of CCS to these minor sources is less economic (i.e., less cost
effective) than its application to the significant sources for which CCS is determined
below to be cost infeasible.
CCS is an approach used to capture the CO2 emitted from large industrial facilities and
subsequently store the CO2 instead of releasing it to the atmosphere. The CCS process
involves three main stages:
Capturing and concentrating CO2 at its source by separating it from other
constituents in the exhaust gas stream;
Transporting the captured CO2 to a suitable storage location, typically in
compressed form; and
Storing the CO2 away from the atmosphere for a long period of time, for instance
in underground geological formations or in the deep ocean.
Steps 1 and 2 of the BACT analysis for CCS as presented below are organized by the
CCS process stage (i.e., capture, transport, and sequestration). For each of the process
stages, the results from the BACT Step 1 and 2 analyses are presented. Based on the Step
1 and 2 analyses, it is concluded that CCS is undemonstrated technology for exhaust
gases from natural gas-fired combustion turbines and tailgas-fired cracking furnaces due
to their inherently low CO2 concentration. However, in response to EPA’s request that
all CCS BACT analyses include a Step 4 cost based impact analysis, under Step 3 a best
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possible configuration for a CCS system is hypothesized and the cost impacts associated
with this hypothetical configuration is evaluated under Step 4.
5.6.1 Technical Feasibility of Potential CCS Process Alternatives
5.6.1.1 Step 1 - Identify Potential CO2 Capture Methods
The amount of CO2 produced by the Project’s ethane cracking furnaces and Cogen Units
is already designed to be reduced to a minimum through the use of improved efficiency
(see Sections 5.2.5 and 5.3.5). Thus, this analysis focuses on whether those already
reduced CO2 emissions can be feasibly captured.
In a conventional combustion source, the oxygen required for combustion of fuel is
provided by air. Because air contains 79 percent nitrogen, the CO2 concentration in the
exhaust gas from the source is diluted by the inert nitrogen as well as other products of
combustion. The average CO2 concentration in the exhaust gas from a natural gas-fired
source is on the order of 3 to 10 volume % depending upon the exhaust gas oxygen
concentration (i.e., combustion turbines have exhaust gas oxygen levels on the order of
15% by volume which greatly reduces the CO2 concentration in the exhaust to less than
3 % by volume when firing natural gas).
Capture and/or concentration of CO2 from a combustion source such as the proposed
furnaces and Cogen Units can theoretically be achieved either through pre-combustion
methods or through post-combustion methods.
Pre-Combustion: There are two potential pre-combustion CO2 capture approaches
using oxygen to combust the fuel: direct and indirect. Oxygen instead of air is used to
combust the fuel, eliminating the inert nitrogen from the exhaust, and thereby increasing
the exhaust gas CO2 concentration to approximately 90% (a concentration that can be
transported via pipeline). Notably, in both cases, there are significant capital and energy
costs associated with the construction and operation of an air separation plant required to
produce the oxygen that is needed for either direct or indirect oxygen use.
Direct Approach. The direct approach (i.e., oxy-firing) involves substituting oxygen for
air during the combustion process. This technique results in a more concentrated CO2
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exhaust gas stream, with the exhaust gas containing primarily CO2, H2O, and oxygen.
This stream would still need to be further processed to produce a relatively pure CO2
stream suitable for transportation and storage, but the size of downstream processing
equipment is reduced relative to that required if air is used in the combustion step.
Oxygen firing has not been demonstrated to be technically feasible on a commercial scale
for natural gas fired systems. Most of the oxygen firing research has focused on coal-
fired boilers. The use of oxygen firing for the Project’s ethane cracking furnaces and the
natural gas-fired Cogen unit has not been demonstrated and would require the
development of technology that is not currently commercially available. U.S. EPA has
explicitly acknowledged that, although various oxy-fueled combustion processes are
undergoing laboratory- and pilot-scale testing, this technology has not been
demonstrated.91 Because oxygen-fired cracking furnaces and Cogen Units are not offered
commercially, the use of oxygen firing for the proposed furnaces and Cogen Units is not
considered an “available technology” for purposes of this BACT analysis,92 As a result,
the precombustion direct approach is eliminated from further analysis.
Indirect Approach. The indirect approach, which is otherwise known as gasification,
involves partial combustion of a carbon-containing fuel (e.g., coal, coke or, residual oil)
with oxygen and steam to produce a synthesis gas (“syngas”) composed of CO and H2.
The CO is reacted with steam to yield CO2 and more H2. A physical or chemical
absorption based process is then used to separate the CO2, usually resulting in a
hydrogen-rich fuel that can be combusted. This indirect approach significantly increases
91 See, “Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from the
Petroleum Refining Industry,” U.S. EPA, Office of Air Quality Planning and Standards, October 2010,
at p. 13; see, also, “Available and Emerging Technologies from Coal-Fired Electric Generating Units,”
U.S. EPA, Office of Air Quality Planning and Standards, October 2010, at p. 35. 92 According to U.S. EPA’s top-down BACT guidance, “available control options are those air pollution
control technologies or techniques with a practical potential for application to the emissions unit and the
regulated pollutant under evaluation.” U.S. EPA’s assessment of oxy-combustion as it relates to
petroleum refining is that “this technology is still in the research stage” (see: Available and Emerging
Technologies for Reducing Greenhouse Gas Emissions from the Petroleum Refining Industry, p.25).
Therefore, the use of oxy-combustion does not have a practical potential for application to the planned
process heaters and it should not be considered in this BACT analysis.
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the fuel cost. It has currently only been used to produce hydrogen for use in the
manufacture of high valued chemicals and liquid fuels. In addition, firing a combustion
turbine with pure H2 has not been commercially demonstrated. To do so, the combustor
section of the turbine would need to be specifically designed for hydrogen’s unique
combustion characteristics (i.e., hydrogen has a much higher flame velocity and specific
heat release rate). A combustion turbine designed for hydrogen would not be capable of
combusting natural gas.
The ethane cracking process utilizes steam-ethane cracking to produce a valuable
chemical, ethylene, and byproduct tailgas, consisting of hydrogen and methane. Because
the proposed Project does not have an outlet for the hydrogen that is produced in the
cracking furnace process, the tailgas, containing hydrogen (~85% by volume) and
methane (~15% by volume), is designed to be combusted in the cracking furnaces,
replacing natural gas as a fuel. Thus, the fuel to the cracking furnaces already has a
significantly reduced carbon content, thereby resulting in a significant reduction in CO2
emissions. Approximately 50% of the heat required in the furnaces for ethane cracking is
obtained via the high hydrogen concentration of the tailgas, which means CO2 emissions
are approximately 50% lower for this Project’s cracking furnaces compared to a case
where natural gas is combusted in similar units.
Based on the above discussion, the pre-combustion indirect approach is eliminated from
further consideration.
Post-Combustion: Post-combustion methods are methods potentially applied to
conventional combustion sources (i.e., air is used to combust the carbon-containing fuels)
to capture and concentrate the CO2 in the combustion exhaust gases prior to transport.
The potentially available post-combustion CO2 capture technologies include: 1)
absorption with chemical solvents such as amines; 2) physical absorption using materials
such as Selexol®; 3) calcium cycle separation; 4) cryogenic separation; 5) membrane
separation; and 6) adsorption. These potential methods are addressed in order.
Absorption of the CO2 with chemical solvents such as amines. Use of amines for CO2
absorption is currently the most common method for CO2 capture where such capture is
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feasible. This process is illustrated in Figure 5-1. In such a process, monoethanolamine
(MEA) solvent is utilized, which has a fast reaction with CO2 at the relatively low partial
pressures found in most combustion exhaust gases. Some of the main concerns with
MEA and other amine solvents are: 1) corrosion due to the presence of O2 and other
impurities in the exhaust gas, 2) high solvent degradation rates because of the solvent’s
irreversible reaction with SO2 and NOx, and 3) the large amount of energy required for
solvent regeneration. This technology has not been commercially demonstrated with fuel
gas-fired combustion sources similar to the proposed project’s tailgas-fired furnaces and
natural gas-fired Cogen Units. However, this technology is assumed to be a potentially
Figure 5-1. CO2 Capture and Concentration System
“available technology” for the purposes of this BACT analysis because it can be applied
without materially negatively impacting the design or operation of the furnaces and
Cogen Units; and thus this technology is retained for further feasibility analysis in Step 2.
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One notable aspect of the capture and concentration process illustrated in Figure 5-1 is
that the solvent regeneration step in the process requires significant amounts of steam. If
the units currently included in the project cannot meet the increased steam demand,
construction of a new steam generator (e.g., a new natural gas-fired boiler) is required. In
any event, generation of additional steam will result in additional emissions, including a
considerable quantity of GHGs, as well as lesser amounts of NOx, CO, particulate matter,
and other pollutants.
Absorption with physical solvents such as Selexol®. Physical adsorbents, such as
Selexol, may be used for CO2 absorption at high pressure and low temperature. A form
of this method is commonly used for CO2 rejection from raw natural gas, which has a
composition this is much different than the exhaust gas composition from a combustion
source. This technology has not been commercially demonstrated in any application
related to combustion exhaust gases. As a result, this technology is removed from further
consideration.
Calcium cycle separation. In theory, quicklime (i.e., CaO) can be used to capture CO2
yielding limestone, which is then heated, releasing the captured CO2 in a concentrated
stream and regenerating the quicklime for reuse. Research and development work is still
required to obtain adequate sorbent stability after regeneration. As a result, this
technique is not considered an “available technology” for purposes of this BACT
analysis.
Cryogenic separation. This technique is based on solidifying CO2 by frosting (i.e.,
cooling CO2 to its condensation point) in order to separate the CO2 from other gaseous
components in the exhaust gas stream. The low concentration of CO2 in the exhaust gas
from conventional air-based combustion processes renders this technology impractical.
As a result, this technique is not considered an “available technology” for purposes of
this BACT analysis.
Membrane separation. Membrane separation is commonly used for CO2 removal from
natural gas at high pressure and high CO2 concentrations. Currently membranes are not
available that can effectively address gas streams with the low CO2 concentrations
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produced by the proposed cracking furnaces and Cogen Units. Additional research and
development work is required to develop membranes suitable for such an application,
including the need to optimize the technology for large-scale CO2 recovery and minimize
the energy required for separation. As a result, this technique is not considered an
“available technology” for purposes of this BACT analysis.
Adsorption. With this technique, exhaust gas is fed through a bed of solid material with
high surface area, such as a Zeolite or activated carbon. These materials can
preferentially adsorb CO2 while allowing other gases (e.g., nitrogen) to pass through.
The saturated adsorption bed is regenerated by either pressure swing (low pressure),
temperature swing (high temperature), or electric swing (low voltage) desorption.
Adsorption would require either a high degree of compression or multiple separation
steps to produce a high CO2 concentration from the furnace or Cogen Unit exhaust gas.
This technique has not been used in this type of application. As a result, adsorption is not
considered an “available technology” for purposes of this BACT analysis.
As noted above, amine-based chemical absorption is the only commercially demonstrated
technology that has been applied to the capture of CO2 from post-combustion exhaust gas
streams. The remaining technologies, are not commercially available. There are
additional potential CO2 reduction measures that are in the laboratory or conceptual
stages of development that are not discussed here because they have not been
demonstrated commercially. As a result, only amine-based chemical absorption and is
considered potentially available and considered further by this analysis.
5.6.1.2 Step 2- Technical Feasibility of Potential CO2 Capture Methods
Table 5-35 presents a summary of the commercial amine-based plants where CO2 is
captured from flue gas. As shown, these plants range in size from 200 to 600 metric tons
per day of CO2 captured with CO2 concentrations in the exhaust between 8 and 14%. In
comparison, the proposed Project’s cracking furnaces and Cogen Units will emit
5,270 metric tons per day of CO2 with the concentration of CO2 in the combined exhaust
being less than four (4) percent.
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Table 5-35. Amine Based CO2 Capture Plants ≥ 200 TPD 1
Capture Technology Location Fuel Gas CO2
Concentration
CO2 Capture
(Metric TPD) CO2 Use
Kerr-McGee/ABB Lumus Trona, CA Coal-fired 14% @ 3% O2 600 Soda Ash
Kerr-McGee/ABB Lumus Shady Point, OK Coal-fired 14% @ 3% O2 200 Food
Kerr-McGee/ABB Lumus Botswana, Africa Coal-fired 14% @ 3% O2 300 Soda Ash
Kerr-McGee/ABB Lumus Warrior Run, MD Coal-fired 14% @ 3% O2 200 Food
Fluor Econamine Bellingham, MA Gas-fired 8% @ 3% O2 320 Food
Mitsubishi Heavy Industries Kedah Darul Aman, Malaysia Gas Furnace 8% @ 3% O2 200 Urea
Mitsubishi Heavy Industries Fukoka, Japan Gas Furnace 8% @ 3% O2 330 General
Mitsubishi Heavy Industries Aonla, India Gas Furnace 8% @ 3% O2 450 Urea
Mitsubishi Heavy Industries Phulpur, India Gas Furnace 8% @ 3% O2 450 Urea
Mitsubishi Heavy Industries Kakinada, India Gas Furnace 8% @ 3% O2 450 Urea
Mitsubishi Heavy Industries Abu Dhabi, UAE Gas Furnace 8% @ 3% O2 400 Urea
Mitsubishi Heavy Industries Bahrain Gas Furnace 8% @ 3% O2 450 Urea
Mitsubishi Heavy Industries Ghotoki, Pakistan Gas Furnace 8% @ 3% O2 340 Urea
Mitsubishi Heavy Industries Phu My, Vietnam Gas Furnace 8% @ 3% O2 240 Urea
CERI Shanghai, China Coal-fired 14% @ 3% O2 360 General
1. http://www.globalccsinstitute.com/publications/process-modelling-amine-based-post-combustion-capture-
plant/online/113436.
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The information presented in Table 5-35, indicates that amine-based CO2 capture is
considered technically feasible for capturing CO2 in the combustion flue gases when the
CO2 concentration is eight (8) percent or greater than. However, no application has been
demonstrated in practice of amine-based CO2 capture for exhaust gas from a natural gas-
fired combustion turbine or tailgas-fired furnace where the concentration of CO2 in the
exhaust is less than 4%.
In conclusion, no amine-based or other CO2 capture techniques were identified as having
been demonstrated in practice in an application with a CO2 concentration in the exhaust
that is similar to that of the proposed natural gas-fired Cogen Units or tailgas-fired
cracking furnaces (i.e., less than 4 percent). In addition, if an amine-based technique
were applied, the energy requirements associated with the capture of CO2 from the
proposed project’s cracking furnaces and Cogen Units would result in a significant
energy impact.
5.6.1.3 Step 1 and 2 – Identification of Potential Technologies and Feasibility Analysis of CO2 Transportation
After capturing the CO2, regardless of the capture technique employed, the CO2 must be
transported to a suitable storage/sequestration site. Pipelines are the most common and
theoretically available method for transporting large quantities of CO2 over some
distance.
The oldest long-distance CO2 pipeline in the United States is the 140 mile Canyon Reef
Carriers Pipeline (in Texas), which began service in 1972 for Enhanced Oil Recovery
(EOR) in regional oil fields.93 Other CO2 pipelines, each of which is shorter, have been
constructed since then, mostly in the mid-continent United States, to transport CO2 for
EOR. These other pipelines carry CO2 from naturally-occurring underground reservoirs,
93 Congressional Research Service Report to Congress, Carbon Dioxide Pipelines for Carbon
Sequestration: Emerging Policy Issues; Order Code RL33971, updated January 2008.
http://www.marstonlaw.com/index_files/Emerging%20Policy%20issues%20for%20CO2%20pipelines%
202008%20CORRECTED%20(2008-01-17%20(No%20RL33971).pdf
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natural gas processing facilities, ammonia manufacturing plants, and a large coal
gasification project to oil fields located in the vicinity of the CO2 source. Altogether,
approximately 3,600 miles of CO2 pipeline are in operation in the United States.94
Pipeline transportation of CO2 requires very high pressures with correspondingly high
compressor energy requirements. CO2 is typically transported in its “supercritical” state.
It is very important that water be eliminated from CO2 pipeline systems, as the presence
of water results in formation of carbonic acid, which is extremely corrosive to the carbon
steel pipe. The primary compressor stations are located at the CO2 source. Booster
compressors are located as needed along the pipeline. CO2 pipelines are similar to
natural gas pipelines, requiring the same attention to design, monitoring for leaks and
protection against overpressure, especially in populated areas. All of these technical
issues can be addressed through modern pipeline construction and maintenance practices.
As a result, for the purposes of this BACT analysis, CO2 transportation by pipeline is
considered a technically feasible technology.
However, there are currently no CO2 pipelines at or near the proposed Project. The
closest existing CO2 pipeline, located in south central Mississippi, is over 900 miles
away. To install a pipeline as part of implementing CCS at the proposed Project is
considered impractical, especially in light the following: 1) technical/physical work
required to define and construct a pipeline in the mountainous western region of
Pennsylvania, 2) legal uncertainties associated with obtaining the rights of way required
to construct such a pipeline over a long distance (since the Project does not enjoy public
utility eminent domain powers), and 3) proposed Project’s timeline for construction.
5.6.1.4 Steps 1 and 2 Identification of Potential Technologies and Feasibility Analysis of CO2 Sequestration
There are several potential options for permanent storage of CO2 currently being
evaluated by regional carbon sequestration partnerships and other organizations. These
94 Ibid.
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options include storage in various geological formations (including saline formations,
exhausted oil and gas fields, and unmineable coal seams) and as well as storage in the
ocean. Each of these options is discussed in more detail below.
Geologic Formations:95 The geologic formations considered appropriate for CO2 storage
consist of layers of porous rock deep underground that are “capped” by a layer or
multiple layers of non-porous rock. In geologic storage, a well is drilled down into the
porous rock and pressurized CO2 is injected into it. Under high pressure, CO2 is turned
into a liquid and moves through the formation as a fluid. Once injected, the buoyant
liquid CO2 will flow upward until it encounters a non-porous rock barrier, trapping the
CO2 and preventing further upward migration.
There are other mechanisms for CO2 trapping. CO2 molecules can be dissolved in brine
or reacted with minerals to form solid carbonates or adsorbed in the pores of porous rock.
The degree to which a specific underground formation is amenable to CO2 storage is
difficult to determine. Ongoing research is aimed at developing the ability to characterize
a formation before CO2 injection in order to predict the structure’s CO2 storage capacity.
Research is also being conducted to develop CO2 injection techniques that achieve broad
dispersion of CO2 throughout the formation, to overcome low diffusion rates and to avoid
damaging the cap rock.
Some of the major unresolved issues with respect to CO2 sequestration pertain to the
legal framework for closing and remediating geologic sites, including liability for
accidental releases from these sites. In December 2010, U.S. EPA promulgated a final
rule establishing minimum Federal requirements under the Safe Drinking Water Act for
underground injection of CO2 for the purpose of geologic sequestration.96 This rule set
minimum technical criteria for the permitting, geologic site characterization, area of
review and corrective action, financial responsibility, well construction, operation,
95 2008 Carbon Sequestration Atlas of the United States and Canada, U.S. Department of Energy, National
Energy Technology Laboratory, Page 15. 96 75 Fed. Reg. 77230. December 10, 2010.
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mechanical integrity testing, monitoring, well plugging, post-injection site care, and site
closure of wells for the purposes of protecting underground sources of drinking water. In
September 2011, U.S. EPA promulgated a final rule making, U.S. EPA the permitting
authority for this program nationwide.97
Depending on geologic conditions in various regions, there are several types of geologic
formations in which CO2 can theoretically be stored and each has different opportunities
and challenges, as briefly described below.
Depleted Oil and Gas Reservoirs. Depleted oil and gas reservoirs are formations that
previously held crude oil and natural gas. In general, these formations have a layer of
porous rock with a layer of non-porous rock above, forming a dome. This dome offers
the potential to trap CO2 and makes these formations suitable for GHG sequestration. As
a side benefit of this type of sequestration, CO2 injected into a depleting oil reservoir can
enable recovery of additional oil and gas. When injected into a depleting oil-bearing
formation, the CO2 dissolves in the trapped oil and reduces its viscosity. This process
“frees” more of the oil by improving its ability to move through the pores in the rock and
flow with a pressure differential toward a recovery well. A CO2 flood typically enables
recovery of an additional 10 to 15 percent of the original oil in place.
Use of CO2 for enhanced oil recovery (EOR) and enhanced gas recovery (EGR) are
commercial processes used in some parts of the country, where CO2 can be injected to
increase pressures in partly depleted formations and thereby enhance recovery of oil and
gas from those formations. EOR injection of CO2 has occurred primarily in the Permian
Basin of west Texas.
There are known oil or gas reservoirs within the vicinity of the Project, including oil and
gas fields in western Pennsylvania and eastern Ohio. However, it is unknown whether
these depleted oil and gas fields provide a real sequestration opportunity or would be
97 76 Fed. Reg. 56982. September 15, 2011.
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available for such use. For example, a significant number of depleted gas reservoirs
(particularly those with proven geologic integrity) have been converted to natural gas
storage projects, and dedicated to seasonal injection and withdrawal of natural gas to
meet peak demands of the northeastern U.S., and thus unavailable for CO2 injection.
Regarding other active or depleted oil and gas reservoirs, only limited studies and tests
have been conducted by the Midwest Regional Carbon Sequestration Partnership
(MRCSP) or cooperating entities, including studies in the Michigan Basin-Otsego County
and a test well in Tuscarawas County, Ohio. Studies have noted that characteristics of
any particular formation in western Pennsylvania, eastern Ohio and West Virginia can
change significantly horizontally within the formation, where subtle shifts in lithology or
facies of each formation may be crucial to the capability of such formations to provide
for carbon sequestration. Further such studies would be needed to determine the field
injectability characteristics and migration/capture potential.98 The following steps would
be required to ensure that such a study was implemented safely and complied with all
regulations:
Initial planning and preliminary assessment,
Site characterization including seismic survey and implementation of a test well,
Conversion of the site to injection operations including additional wells if needed,
CO2 injection,
Monitoring prior to, during, and after injection, and
Closing or capping the well after the research is completed.
There are significant legal issues in terms of obtaining access to such oil and gas
reservoirs for CO2 injection. Injection of CO2 into underground horizons requires
acquisition of necessary property rights under relatively large amounts of acreage (with
typical oil and gas reservoirs spanning many square miles each). The mineral, oil and gas
rights associated with these areas are held by a large number of owners and mineral rights
lessees, and further it is unclear whether those interest holders have the right to, or would
98 Midwest Regional Carbon Sequestration Partnership (MRCSP) Geologic Projects,
http://www.mrcsp.org/GeologicProjects.aspx
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be inclined to, allow for injection of CO2.99 No entity currently has eminent domain
rights to acquire the subsurface interests needed to access such areas for purposes of
operating a CO2 injection and carbon sequestration project.
Due to the lack of studies and testing of EOR, EGR and depleted formation storage in the
western Pennsylvania and eastern Ohio fields and unknown legal issues associated with
such a sequestration effort, an assessment of the feasibility of injection CO2 from the
Project for EOR/EGR or storage in depleted oil and gas reservoirs is not currently
available. As a result, it is not possible to commit to the use of an undemonstrated
storage option until assessment, drilling, testing, analysis and injection and performance
monitoring has been conducted at potential EOR/EGR and/or depleted formation sites.
This type of effort would extend well beyond the PSD permitting and construction phases
of the proposed Project.
Unmineable Coal Seams. Unmineable coal seams are those that are too deep or too thin
to be mined economically. Theoretical use of unmineable coal seams involves injection
of CO2 into a coal bed, where it would both occupy pore spaces and would bond, or
adsorb, onto the carbon of the coal itself. Because the adsorption rate for CO2 in coals is
approximately twice that of methane, CO2 injection would displace coal bed methane
(CBM) that is adsorbed onto the pore surfaces of the coal. Thus, a potential has been
posited that wells could be drilled into unmineable coal beds to inject CO2 and recover
this coal bed methane (CBM).
Thus, like depleted oil reservoirs, unmineable coal beds represent a potential opportunity
for CO2 storage. One potential barrier to injecting CO2 into unmineable coal seams,
however, is swelling. When coal adsorbs CO2, it swells in volume. In an underground
formation, swelling can cause a sharp drop in permeability, not only restricting the flow
of CO2 into the formation, but also impeding the recovery of displaced CBM.
99 For example, Pennsylvania courts have held that the grant of oil and gas rights does not imply a right to
inject and store natural gas, but that such an injection/storage right must be explicitly stated in an oil and
gas lease.
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The only coal bed methane production identified in Pennsylvania by Pennsylvania’s
Department of Conservation and Natural Resources (DCNR) is in the anthracite region of
northeastern Pennsylvania.100 Moreover, injection of CO2 into underground coal seams
raises many of the same issues as to obtaining legal rights for injection, given the
complexity of mineral rights and multiplicity of involved mineral rights owners.
Accordingly, this CO2 sequestration technique is less advantageous for the Project than
other geologic sequestration options and is not considered further in this analysis.
Saline Formations. Saline formations are layers of porous rock that are saturated with
brine. They are much more common than coal seams or oil and gas bearing rock and
represent a significant potential for CO2 storage capacity. Much less is known about
saline formations than is known about crude oil reservoirs and coal seams and there is a
greater amount of uncertainty associated with the ability of saline formations to store
CO2. Saline formations contain minerals that could react with injected CO2 to form solid
carbonates. The carbonate reactions have the potential to be both a positive and a
negative. Such reactions can increase permanence but they also may plug up the
formation in the immediate vicinity of an injection well.
Additional research is required to better understand these potential obstacles and whether
and how those may be addressed. For example, a saline formation CO2 injection test was
conducted at the R.E Burger power plant near Shadyside, Ohio,101 approximately 60
miles southwest of the proposed Project site. CO2 injection testing was conducted on
three saline formations (Oriskany, Salina, and Clinton) at depths ranging from 5,900 to
8,300 feet. Even though the well was stimulated using acid and high injection pressures,
low flow rates were observed at each formation, indicating poor opportunities for CO2
sequestration.
100 Second Revisions to Final Draft Report by the Carbon Management Advisory Group (CMAG); April
2008. http://www.dcnr.state.pa.us/info/carbon/conferencecalls.aspx#secondfinal. 101 Appalachian Basin – R.E. Burger Plant Geologic CO2 Sequestration Field Test; DOE-NETL
Cooperative Agreement DE-FC26-05NT42589; Midwest Regional Carbon Sequestration Partnership;
January 2011.
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Use of saline formations for injection and storage involves many of the same legal /
property interest acquisition issues as those discussed above for injection into depleted oil
and gas formations or unminable coal seams.
Accordingly, this CO2 sequestration technique is considered to be technically infeasible
for the Project until assessment, drilling, testing, analysis and injection and performance
monitoring have been conducted at any potential injection site.
Basalt and Organic Rich Shale Formations.102 Two additional geological environments
being investigated for long-term CO2 storage are basalt formations and organic shale
formations. Basalt formations are geological formations of solidified lava. These
formations have a unique chemical makeup that could potentially convert injected CO2
into a solid mineral form, thus isolating it from the atmosphere permanently. Some key
factors affecting the capacity and ability to inject CO2 into basalt formations are effective
porosity and interconnectivity. Current efforts are focused on enhancing and utilizing the
mineralization reactions and increasing CO2 flow within basalt formations.
Organic-rich shales are another potential geological storage option. Shales are formed
from silicate minerals, which are degraded into clay particles that accumulate over
millions of years. The plate-like structure of these clay particles causes them to
accumulate in a flat manner, resulting in rock layers with extremely low permeability in a
vertical direction.
At this time, long-term CO2 storage in basalt formations and organic-rich shale basins has
not been demonstrated, as recently stated by the U.S. Department of Energy:
While the location of some basalt formations and organic-rich shale basins has
been identified, a number of questions relating to the basic geology, the CO2
trapping mechanisms and their kinetics, and monitoring and modeling tools need
to be addressed before they can be considered viable storage targets. As such, no
102 2008 Carbon Sequestration Atlas of the United States and Canada, U.S. Department of Energy, National
Energy Technology Laboratory, page 15.
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CO2 storage resource estimates for basalt formations or organic-rich shale basins
are currently available.103
As a result, this storage option is not considered an “available technology” for purposes
of this BACT analysis.
Terrestrial Ecosystems: 104 Terrestrial sequestration is the enhancement of CO2 uptake
by plants that grow on land and in freshwater and, importantly, the enhancement of
carbon storage in soils where it may remain more permanently stored. Terrestrial
sequestration provides an opportunity for low-cost CO2 emissions offsets. Early efforts
include tree-plantings, no-till farming and forest preservation. To date, there are no
applications of this method that would be large enough to handle the volumes of CO2
produced by this Project. Due to the undemonstrated cost and effectiveness of terrestrial
ecosystem sequestration options for storing 2 million tons per year of CO2 over the life of
the Project, this sequestration option is considered to be technically infeasible and is not
further evaluated as BACT.
5.6.2 Step 3: CCS Control Technology Hierarchy
As concluded above, 1) there are currently no CO2 pipelines at or near the proposed
Project and installation of such a pipeline is considered impractical; 2) permanent CO2
sequestration has not been commercially demonstrated as a GHG control technique; and
3) significant technical and legal uncertainties remain before this control option can be
considered commercially available in the context of a GHG BACT analysis. As a result,
the use of CCS is considered technically infeasible for application to the proposed
Project’s tailgas-fired cracking furnaces and natural gas-fired Cogen Units.
Although Shell does not consider CCS to be technically feasible for the proposed Project,
USEPA has requested that PSD permit applicants conduct a Step 4 BACT impacts
103 “The North American Carbon Storage Atlas,” 1st ed., U.S. Department of Energy et al., 2012, at page 19. 104 Ibid, Page 22.
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analysis, as reflected in the following recent permitting actions where USEPA reviewed
or issued the GHG PSD permits:
Illinois Environmental Protection Agency’s (IEPA) intent to issue a Prevention of
Significant Determination (PSD) construction permit for Universal Cement,
located in Chicago, Illinois.
Wisconsin Department of Natural Resources’ (WDNR) intent to issue a
Prevention of Significant Deterioration (PSD) construction permit for Wisconsin
DOA I UW Madison - Charter St.
USEPA Region 6 Application Completeness Determination for the Chevron
Phillips Chemical Company LP Prevention of Significant Deterioration Permit for
the Cedar Bayou Plant-New Ethylene Production Unit.
For this reason, Shell is proceeding in Step 4 to provide a cost, energy, and environmental
impact analysis of a conceptual CCS system.
5.6.3 Step 4: Evaluate the Most Effective Controls.
For purposes of the following evaluation of the impacts of applying CCS to the cracking
furnaces and Cogen Units, chemical absorption using MEA based solvents is assumed to
represent the most applicable CO2 capture option and the use of sequestration in a
subsurface saline formation is assumed to represent the most applicable option for long-
term storage.105 Under this conceptual CCS system, the combustion flue gases from the
furnaces and Cogen Units would be ducted to an absorption system where the gases
would be quenched and then CO2 would be captured in an MEA solution. The MEA
solution would be regenerated to release the CO2 as a concentrated stream, which would
then be dehydrated, compressed, transported and injected into a subsurface saline
formation.
The potential CO2 reductions that would result from the theoretical application of CCS
are presented in Table 5-36. It should be noted that due to the low CO2 concentrations in
the cracking furnace and combustion turbine exhaust gases, the capture efficiency of
105 Data in terms of potentially available metric tons of capacity, available through the National Carbon
Sequestration Viewer (http://www.natcarbviewer.com/), indicates that there is greater potential
capacities of subsurface saline than the other sequester options discussed above.
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90 percent presented in Table 5-36 is considered to be conservatively high because is has
not been demonstrated in practice on an exhaust gas will CO2 levels of less than four (4)
percent.
As discussed previously, permanent CO2 sequestration has not been commercially
demonstrated as a GHG control technique and significant technical and legal
uncertainties remain. In addition, as shown by the following discussion, the adverse
economic, energy, and environmental impacts of CCS are significant and beyond those
that should be considered acceptable in establishing a BACT limit for GHG emissions
from the proposed Project.
Table 5-36. CO2 BACT Hierarchy and Emissions
Source
Uncontrolled CO2
(tons per year)
CCS %
Control
Controlled CO2
(tons per year)
Ethane Cracking Furnaces (7) 1,059,500 90 106,000
Cogen Units (3) 1,060,500 90 106,000
Emergency Generators (4) 1,150 0 1,150
Firewater Pumps (3) 120 0 120
Thermal Incinerators (2) 71,600 0 71,600
Flares (5) 75,600 0 75,600
Total 2,268,470 84 360,470
5.6.3.1 Economic Impacts Evaluation
To implement CCS, the exhaust streams from the process heaters would be collected and
routed to an MEA absorption unit to concentrate the CO2 in this combined stream from
around 5 percent to approximately 90 percent. This concentrated CO2 stream would then
need to be dehydrated and compressed from ambient pressure to about 2,200 pounds per
square inch before transportation and subsequent deep well injection. The costs of
purification, compression, transportation, well construction and operation are substantial,
as shown in Table 5-37 and as summarized below.
As shown in Table 5-37, the estimated capital cost for the equipment needed for
purification, compression and deepwell injection/storage of CO2 from the furnaces and
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Cogen Units is approximately $360 million. The annualized cost of implementing CCS,
including transportation, operating and maintenance costs, is estimated to be
approximately $132 million per year. The resulting control cost-effectiveness of CCS is
$117 per ton of CO2 sequestered.
5.6.3.2 Energy Impacts Evaluation
The electric power required to capture, compress, and inject the CO2 captured from the
furnaces and Cogen Units is about 30 megawatts, which is a significant, adverse energy
impact associated with the CCS option. This is enough electricity to power more than
22,500 average American homes.106 In addition, over six (6) billion cubic feet of natural
gas would be consumed annually in generating the steam needed to operate the CCS
Table 5-37. Summary of CCS Impacts Analysis for the Cracking Furnaces and
Cogen Units 1
Parameter Value
Economic Impacts
CCS Total Installed Cost 360,315,000 $
Annualized Costs 131,901,000 $/yr
Net GHG Reduced 1,730,800 T/yr
Control Cost-Effectiveness 117 $/T
Environmental Impacts (CCS Steam & Power Related Emissions)
NOx Emissions 392 T/yr
SO2 Emissions 860 T/yr
Energy Impacts
CCS Power Demand 264,500 MWh/yr
CCS Steam Demand (from Natural Gas) 6,033,500 MMscf/yr
1. The basis for the results presented in this table is presented in Table B-30
of Appendix B.
106 Source: http://www.eia.gov/tools/faqs/faq.cfm?id=97&t=3 (last accessed September 24, 2013).
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capture and concentration system. This is enough natural gas to heat more than 120,000
homes during the winter.107
5.6.3.3 Environmental Impacts
The adverse environmental impacts of implementing CCS on the CO2 emissions from the
furnaces and Cogen Units are those associated with construction of the subsurface CO2
injection well system along with the collateral increase in pollutants emitted from steam
and electrical generation required to meet the CCS system’s steam and power demands
described above. These emissions include 392 tons per year of NOx, 860 tons per year of
SO2, and 217,130 tons per year of CO2e. There will also be increases in emissions of
other pollutants such as PM10, PM2.5, CO and HAP.
5.6.4 Step 5: Proposed CO2 BACT
As discussed in Section 5.6, no carbon capture technologies are believed to be technically
feasible as applied to this Project’s low CO2 concentrations, no current infrastructure for
transport of CO2 in the region, and no carbon sequestration methods are available at this
time within a reasonable distance of the Project. Without this necessary transportation
and sequestration infrastructure, it is uncertain (and doubtful) that sufficient storage
capability will be available and/or accessible in the time frame being considered for
construction of the Project.
The estimated control cost for the application of CCS to the furnaces and Cogen Units is
$117 per ton. This cost is well above the range of cost effectiveness values considered to
be reasonable and acceptable in BACT determinations for control of GHG emissions.
For example:
107 Based on August 2013 EIA projections that a home heating with gas will consume 58 Mscf of natural
gas during the winter of 2013/14 (see: http://www.eia.gov/tools/faqs/faq.cfm?id=867&t=8 and
http://www.eia.gov/tools/faqs/faq.cfm?id=5&t=8 - last accessed September 24, 2013).
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In making the GHG BACT determination for Copano Processing, U.S. EPA
determined that control of GHG emissions at a cost of $54/ton is not BACT
because it is “economically prohibitive.”108
In making the GHG BACT determination for the City of Palmdale, U.S. EPA
determined that control of GHG emissions at a cost of $45/ton is not BACT
because it is “economically infeasible.”109
In making the GHG BACT determination for Valero’s McKee Refinery, U.S.
EPA determined that control of GHG emissions at a cost effectiveness of
$134/ton is not BACT.110
In making the GHG BACT determination for Freeport LNG Development,
L.P.’s Freeport LNG Liquefaction Project, U.S. EPA determined that control
of GHG emissions from the amine treatment units was cost prohibitive, were
the cost effectiveness of the control option under consideration was estimated
at approximately at $14/ton of CO2 sequestered.111
As another benchmark, California Carbon Allowances are currently trading on the spot
market for less than $12 per ton.112
As noted in Sections 5.2.5 and 5.3.5, incorporating the highly energy efficient cracking
furnaces and Cogen Units associated with the Project will minimize the emissions of
GHGs (CO2, N2O and methane). A highly efficient operation requires less fuel to
operate, directly impacting the amount of GHGs emitted. Establishing an aggressive
108 Statement of Basis: Draft Greenhouse Gas Prevention of Significant Deterioration Preconstruction
Permit for the Copano Processing, L.P., Houston Central Gas Plant, Permit Number: PSD-TX-104949-
GHG. U.S. EPA Region 6, December 2012. (Cost effectiveness calculated based on listed cost of $10.9
million/yr for annual emission reduction of 202,000 tons per year.) 109 Responses to Public Comments on the Proposed Prevention of Significant Deterioration Permit for the
Palmdale Hybrid Power Project. U.S. EPA Region 9, October 2011. (Cost effectiveness calculated
based on listed cost of $78 million/yr for annual emission reduction of 1.7 million tons per year.) 110 Statement of Basis: Draft Greenhouse Gas Prevention of Significant Deterioration Preconstruction
Permit for the Diamond Shamrock Refining Company, L.P., Valero McKee Refinery Permit Number:
PSD-TX-861-GHG, July 2013, p. 7; and Diamond Shamrock Refining Company, L.P., a Valero
Company Greenhouse Gas Prevention of Significant Deterioration Permit Application for Crude
Expansion Project Valero McKee Refinery Sunray, Texas, Updated December 2012, p. 4-15. 111 Statement of Basis: Draft Greenhouse Gas Prevention of Significant Deterioration Preconstruction
Permit for the Freeport LNG Development, L.P., Freeport LNG Liquefaction Project, Permit Number:
PSD-TX-1302-GHG, December 2013, p. 31; and Greenhouse Gas PSD Application, Freeport LNG
Development, L.P., December 2011, p. 10-21. 112 See: BGC Carbon Market Daily, March 21, 2014.
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basis for energy recovery and facility efficiency will reduce GHG emissions and the costs
to mitigate it.
Further, as noted in Sections 5.2.5, use of low carbon fuels like hydrogen rich tailgas in
the cracking furnaces also reduces CO2 emissions by approximately 50% compared to
natural gas. Use of a low carbon feedstock such as ethane instead of naphtha will also
reduce the emissions of GHGs (CO2, N2O and methane).
Thus, the BACT analysis for GHG concludes that the combination use of hydrogen rich
tail gas in the cracking furnaces and energy efficient technologies discussed in
Sections 5.2.5 and 5.3.5 constitute BACT for this Project.
5.7 Polyethylene Process, Storage, and Handling Vents
The three PE manufacturing units and their associated pellet storage and handling
systems will have vents that exhaust to the VOC control system or to the atmosphere. A
summary of these vents along with the pollutant type emitted is included in Table D-2 of
Appendix D. The two pollutant types emitted from these vents are VOC and/or PM.
5.7.1 Polyethylene Process, Storage and Handling Vent VOC LAER Analysis
The proposed project is located in an area that is classified as nonattainment with regard
to the ozone standard, for which VOC is considered a precursor. As a result, a LAER
analysis is required for all of the project’s VOC sources. This LAER analysis addresses
VOC emissions from the PE manufacturing process, storage, and handling vents and
includes the emissions points identified in Table D-2 of Appendix D.
The VOC containing vents from the PE manufacturing process fall into two categories:
continuous/intermittent process vents that are part of the polyethylene manufacturing
process’ design and operation and emergency vents. Continuous/intermittent vents that
contain VOC and are inherent to the PE manufacturing process will either be directed to
the VOC Control System or restricted by the proposed LAER limit. Emergency vents
that contain VOC will be directed to the VOC Control System or the atmosphere.
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As noted in Section 4.0, VOC emissions from Polymer Manufacturing Facilities are
regulated under 40 CFR Part 60 subpart DDD. This NSPS covers all of the processes
used to manufacture high and low density polyethylene including the high and low
pressure processes used to manufacture low density PE and the gas phase, liquid phase
slurry, and liquid phase solution processes used to manufacture high density PE. The
number of VOC emitting vents that must be controlled in accordance with the NSPS’s
requirements is determined based on which process is used and the total uncontrolled
amount of VOC that is emitted from defined areas of that process.
5.7.1.1 Step 1: Identify PE Process, Storage, and Handling Vent VOC Controls
To identify VOC controls applicable to the class or category consisting of a PE
manufacturing facility’s process, storage, and handling vents, information contained in
the RBLC, recent and ongoing permitting actions and other permits for PE manufacturing
facilities were reviewed. A summary of the information obtained through this review is
presented in Table 5-38. Based on an evaluation of the information presented in Table
5-38, the following observations can be made:
There are three precedents in the form of recently issued permits or pending
applications (i.e., ExxonMobil MBPP, Chevron/Phillips, and Sasol Lake Charles)
that have not yet been constructed and as a result, the limits included/proposed in
those permits/applications have not yet been achieve in practice.
The same approach (i.e., form of the limits) is used for limiting emissions from
each of the identified facilities, regardless of the PE manufacturing process
employed.
The VOC emissions are limited from each of the identified facilities by using the
following combination of limits:
o There is a condition which requires the continuous/intermittent VOC
containing process vents located upstream of a defined point in the
process to be directed to a VOC control system, where either a flare or
incinerator is used to control the VOC emissions.
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Table 5-38. Summary of VOC BACT Precedents for Polyethylene Unit Vents 1
RBLC ID
No./State
Facility
Name
Permit
Date
Process
Description Vent Location Description
Control
Description VOC Limit
TX 103048 2
ExxonMobil
Chemical
Company -
MBPP
10/07/13
PE Unit
(2 Units Total
1,300 MT/yr) 3
Reactor and high capacity feed supply
depressurizations
Multipoint Ground
Flare
40 CFR 60.18 and
99.5% DRE
Unreacted gases removed from the gas/resin
in the purge system located upstream of the
granular resin feed hoppers
Flameless Thermal
Oxidizer (FTO) 99.99 % control
Elevated Flare 40 CFR 60.18 and
99% DRE
Residual emissions between the purger and
the extruder
Regenerative
Thermal Oxidizer
(RTO)
97% DRE or
<10 ppmv 12-mth
roll
Residual VOC after the extruder through
product loadout
Residual VOC
Limit
70 lb/MMlb of PE
pellets 12-mth roll
Dryer Vent Included in
Residual VOC limit
Emissions cap covering resin bins to loadout VOC Cap 13.83 TPY
TX 103832 4
final
Chevron/
Phillips
Chemical
Company LP
08/08/13
2 PE s\Units
(2 Units Total
1,200 MT/yr)
Carbon compound emissions from: process
vents, relief valves, analyzer vents, steam jet
exhausts, upset emissions, start-up &
shutdown-related emissions or purges,
blowdowns, or other system emissions of
waste gas
Flare
Compliance with 40
CFR 60.8, 60.18, and
subpart DDD, 40
CFR Part 63 subparts
A and FFFF
Dryer Vent No control Unit 41 – 6 lb/hr
Unit 40 – 12 lb/hr
Residual VOC after the dryer through
product loadout
Residual VOC
Limit
50 lb VOC/MMlb of
PE pellets 12-mth roll
Emissions cap covering uncontrolled vents
(i.e., extruder feed hopper vents, pellet
dryers, storage silos, & rail loadout)
VOC Cap 39.86 TPY
LA 5
SASOL
Lake Charles
Chemical
Complex
04/30/13
PSD
Permit
App.
Low Density PE
Low Product Purge Bin Vent filter
Centrifugal Dryer Vent Thermal Oxidizer
40 CFR 60 subpart
DDD
(99% control)
Extruder Pellet Hopper, Silo Vents, Bin
Vents, Pellet Elutriation Separator,
Emergency vent
Calc. threshold
emissions to
demonstrate need
for control
40 CFR 60 subpart
DDD
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RBLC ID
No./State
Facility
Name
Permit
Date
Process
Description Vent Location Description
Control
Description VOC Limit
LA 5
SASOL
Lake Charles
Chemical
Complex
04/30/13
PSD
Permit
App.
Linear Low
Density PE
CRV Catalyst Relief Vent, CV Catalyst
Vent, Pellet Dryers, Extruders, & Silos
Maintain TRE > 5.0
but <= to 8.0
40 CFR 60 subpart
DDD
40 CFR 63 subpart
FFFF
TX 8758
Exxon
Beaumont
Chemical
TX Permit
Linear low and
high density PE
800 MT/yr
1. Carbon compound emissions from process
vents, relief valves, analyzer vents, steam
jet exhausts, upset emissions, start-up and
shutdown-related emissions or purges,
blowdowns, or other system emissions of
waste gas
2. Excludes analyzer vents and vents
associated with the formation, handling,
and storage of solidified products.
Flare
Compliance with 40
CFR 60.18
Ground flare:
99% DRE C1-C4
98% >C4+
Air Assisted Flare
99.5% DRE C1-C4
98% DRE >C4+
Ethylene cap in PE granules at surge silos 6 Residual VOC
Limit
50 lb/MMlb PE
product
Emissions cap covering uncontrolled
emissions downstream of the product purge
vessels (dryers, product silos, Flo-Triators,
railcar loadouts, surge silo, loadout surge
vessels, prefill bins, seed silo, feed hoppers,
sample pot, product conveyers, and elutriator
VOC Cap 197.14
TX 40157
PSDTX1222
Formosa
Plastics
2/00 PSD
Permit
HDPE II
275 MT/yr
Vent control system Flare Compliance with 40
CFR 60.18
After the dryer through product loadout Residual VOC
Limit
40 lb VOC/MMlb of
PE pellets
Emissions cap covering pellet dryer,
blending and storage, & loadout VOC Cap 15 TPY
TC 18836
PSDTX1206 Equistar
PSD
Permit
High density PE
4 Lines
930 MT/yr
Vent control system Flare Compliance with 40
CFR 60.18
If hexane concentration of the vent stream
from the tank truck during PE loading
exceeds 2600 ppmv
Powder in silo shall
be purged to flare
until concentration
is below 2600
ppmv
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RBLC ID
No./State
Facility
Name
Permit
Date
Process
Description Vent Location Description
Control
Description VOC Limit
1. VOC emitted to the atmosphere between
the classifier and hopper car loadout
2. As measured using headspace analysis
Residual VOC
Limit
90 lb/MMlb PE
product
Emissions cap covering uncontrolled
emissions from blending silos, product filter
receiver, product silos, railcar silos,
bagging/boxing
VOC Cap 83.7 TPY
1. MT = 1000 metric tons
2. ExxonMobil Chemical Company Permit 103048, Special Conditions.
3. http://www.businessweek.com/news/2012-06-01/exxon-applies-for-permits-to-expand-plastics-production-in-texas
4. Chevron/Phillips Chemical Permit 08/08/13 Condition 9
5. Sasol North America Permit Application for Lake Charles Chemical Complex, 4/30/13, pages 3-85 & 86.
6. Ethylene is in affect a surrogate for residual VOC. The same upstream actions that would be taken to control the ethylene content of the PE granules
would also control VOC.
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o There is a limit on the amount of residual VOC that the polymer can
contain at that same defined point in the process. This limit is used to
restrict the amount of VOC that can be emitted through the uncontrolled
vents located downstream of the defined point in the process.113
o A mass rate emissions cap is placed over all of the uncontrolled VOC
containing vents.
The point in the process where vents are directed to a VOC control system (i.e.,
flare or incinerator) vs. where vents are subject to a residual VOC content limit
varies between the various permit precedents reviewed.
o The Chevron/Phillips permit requires flaring of the VOC containing vents
prior to the extruder while the residual VOC limit begins following the
dryer. As a result, an additional mass rate limit is used to control
emissions from the dryer.
o The ExxonMobil Beaumont permit requires flaring of all process vents up
to the extruder (i.e., formation) and the residual VOC is measures in the
PE granules at surge silos. Thus, all VOC vents are covered under the
two limits.
The VOC control system must achieve a reduction between 98114 and
99.99 percent.
The VOC controls identified include the following
o Flameless Thermal Oxidizer (FTO) (see ExxonMobil MBPP)
o Regenerative Thermal Oxidizer (RTO) (see ExxonMobil MBPP)
o Thermal Oxidizer (see Sasol)
o Flares (see ExxonMobil MBPP, Chevron/Phillips, Exxon Beaumont,
Formosa, and Equistar)
In summary, the review of recent PE manufacturing facility permitting precedents
indicates that the continuous and intermittent VOC containing vents fall into two
categories of controls/limits: 1) vents that are directed to a VOC control device that must
achieve a certain required destruction efficiency and 2) vents that are permitted under one
of two forms of an emissions cap (i.e., residual VOC content or group emissions cap).
113 The residual VOC limit is, in effect, a performance specification on the upstream equipment that ensures
that equipment is operated in such a manner that the residual VOC remains below the limit. 114 Compliance with the flaring design and operational requirements at 40 CFR 60.18 is assumed to achieve
a minimum 98 % VOC destruction efficiency. In Texas, compliance with compliance with the design
and operational requirements at 40 CFR 60.18 is assumed achieve a 99% destruction efficiency on C1-
C3 compounds and a 98% destruction efficiency on C3+ compounds.
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5.7.1.2 Step 2: Eliminate Technically Infeasibility Controls
Three of the precedents presented are for facilities that have not yet been constructed. As
a result, the following precedents have not been achieved in practice at a polyethylene
manufacturing facility:
99.5% DRE using a flare to control the VOC from reactor and high capacity feed
supply depressurizations (ExxonMobil MBPP);
99.99% control using a flameless thermal oxidizer to control the VOC contained
in the unreacted gases removed from the gas/resin in the purge system located
upstream of the granular resin feed hoppers (ExxonMobil MBPP);
97% DRE or <10 ppmv VOC on a 12-month rolling average basis using a
regenerative thermal oxidizer to control the residual VOC emissions in the vents
located between the purge system and the extruder (ExxonMobil MBPP);; and
99% control using a thermal oxidizer to control the VOC in the vents located on
the low product purge bin and centrifugal dryer (Sasol).
In accordance with the LAER criterion that requires that limits be achieved in practice on
that class or category of source, these control levels (i.e., destruction efficiencies or
residual VOC concentrations) on the specified vents are eliminated from consideration in
determining the LAER limit for the proposed polyethylene manufacturing process vents.
5.7.1.3 Step 3: Establish PE Manufacturing Process, Storage, and Handling Vent VOC LAER
Based on the applicable LAER precedents for the operating PE facilities (i.e.,
ExxonMobil Beaumont, Formosa, and Equistar), the most comprehensive use of a VOC
control system from a process perspective is the ExxonMobil Beaumont precedent that
requires control of all carbon compound emissions from process vents, relief valves,
analyzer vents, steam jet exhausts, upset emissions, start-up and shutdown-related
emissions or purges, blowdowns, or other system emissions of waste gas. The
ExxonMobil control scheme excludes analyzer vents and process vents associated with
the formation, handling, and storage of solidified products. The vents that are not
directed to the flare for control are located in the part of the process where the solidified
products are formed, handled, and stored. VOC emissions from this section of the PE
manufacturing process are restricted by the residual VOC limit.
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Many of the identified precedents summarized in Table 5-38 reference to the flare design
and operational requirements at 40 CFR §60.18. In accordance with several of the NSPS
and NESHAP regulations (e.g., NSPS Part 60 subpart DDD or NESHAP Part 63 subpart
CC), it is assumed that greater than 98% destruction efficiency is achieved when a flare is
operated in compliance with the requirements of 40 CFR §60.18 or 40 CFR §63.11. The
ExxonMobil Beaumont permit requires that destruction efficiencies of 99.5% and 99% be
achieved on C1-C4 compounds when using the air assisted and ground flares,
respectively. However, the Beaumont permit does not include any testing requirement to
verify that these higher levels of destruction are achieved. As a result, because the flare
design and operating requirements at 40 CFR §60.18 are what is specified by the
Beaumont permit, it is concluded that only a 98% destruction of VOC from polyethylene
manufacturing vents has been achieved in practice at that facility.
The residual VOC limits (i.e., lb/MMlb limits) included in the identified permits vary
with respect to location(s) and sampling objective. The breakdown is as follows:
In some permits, the limit applies to residual VOC measured at one of three
possible sample locations with a presumption that all of the VOC in the sampled
material is emitted prior to the PE pellets being shipped from the facility:
o Granules or resin upstream of the extruder;
o Pellets exiting the extruder; or
o Pellets exiting the dryer.
In some permits, the limit applies to residual VOC based on measurements at two
sample locations with a presumption that only the change in measured VOC
content is emitted:
o Pellets exiting the dryer and pellets being loaded out.
The most stringent residual VOC limits are those where the sample is taken at the first
point in the process where the vents are not controlled
Mass emissions rate caps are also used to limit the emissions from uncontrolled vents.
The caps are set up in one of two ways. In the first, the cap quantifies the maximum
amount of VOC that can be emitted from that point forward in the process by limiting the
residual VOC content in the polymer at that point in the process. In the second, the cap is
used to limit emissions from uncontrolled vents that are not included in the residual VOC
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limit. An example of this would be the Chevron/Phillips permit, where the residual VOC
in the pellets is measured in the pellets exiting the dryer and then again prior to loadout.
The emissions cap covers all uncontrolled vents from the extruder feed hoppers and pellet
dryer to pellet loadout. If the residual VOC measurement is taken at the first point in the
process where the vent is uncontrolled, the need for a mass based emissions cap is
unnecessary as long as the mass production rate of polymer/pellets is measured.
Based on the above review of PE plant permits to determine the most stringent emissions
limits that have been achieved in practice, the following is proposed as VOC LAER for
the PE manufacturing process, storage, and handling vents:
At PE Units 1 & 2 all continuous and intermittent VOC containing gases vented
from the PE process vents (A listing of the controlled vents is presented in
Table D-4 of Appendix D) located upstream of the Product Purge Bin and
including the Product Purge Bin will be directed to a VOC control system
designed and operated to achieve a 99.5% DRE during normal operation;
At PE Unit 3 all continuous and intermittent VOC containing gases vented from
the PE process vents (A listing of the controlled vents is presented in Table D-4 of
Appendix D) located upstream of the degasser will be directed to a VOC control
system designed and operated to achieve a 99.5% DRE during normal operation;
At PE Units 1 & 2 the residual VOC content in the resin exiting the Product Purge
Bins shall be less than 50 ppmw.
At PE Unit 3 the residual VOC content in the resin exiting the Degasser shall be
less than 50 ppmw.
The proposed emission limits for the PE unit process vents meet the two criteria to be
considered LAER. Applying the first criterion, a review was performed of state
regulations and guidelines in states where PE manufacturing facilities are known to
operate. That review identified a BACT guideline for polyethylene manufacturing
facilities located in Texas as the most stringent guidance (not a SIP “limit”) provided by a
state. The Texas guideline requires the following:
Uncontrolled VOC < 80 lb/MMlb of polymer for low pressure HDPE and case-
by-case for high pressure LDPE
NSPS Part 60 subpart DDD, which is part of most if not all state SIPs, requires that the
controlled vents be directed to a control device capable of achieving 98% destruction
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efficiency. It does not include a residual VOC limit covering uncontrolled vents.
Because the proposed residual VOC limit of 50 lb/MMlb of polymer is more stringent
than the Texas BACT guideline and the NSPS, the first criterion is met. The second
criterion is addressed by proposing the most stringent emission limit achieved in practice,
identified from the survey discussed above of PE manufacturing facilities. The proposed
VOC LAER is more stringent than the applicable standard promulgated under 40 CFR
part 60 and 61. In accordance with 25 Pa. Code §127.205(7), the proposed VOC LAER
limit is equivalent to and satisfies the PaBAT requirements of 25 Pa. Code §127.12(a)(5).
5.7.2 Polyethylene Process, Storage, and Handling Vent PM/PM10/PM2.5 LAER/BACT Analysis
The proposed project is located in an area that is classified as nonattainment with the
annual PM2.5 standard. As a result, a LAER analysis is required for all of the project’s
PM2.5 sources. Because the PM2.5 that will be emitted from the PE process, storage, and
handling system vents will be filterable PM, the control technologies applicable to the
control of PM2.5 are the same as the controls applicable to PM and PM10. As a result, for
purposes of this analysis all forms of PM (i.e., PM, PM10, PM2.5) are referred to as “PM”
unless otherwise noted. It should be noted that no applicable PM standards have been
promulgated for PE storage and handling vents under 40 CFR parts 60 and 61.
5.7.2.1 Step 1: Identify PE Process, Storage, and Handling Vent PM Controls
A summary of the results from a survey of the recent permit precedents related to
process, storage, and handling vents at PE manufacturing facilities is presented in Table
5-39. As shown, all of the permits that were reviewed relied upon the use particulate
filters (i.e., fabric, sintered metal, or HEPA) to control PM emissions from these points of
emissions. In addition, all of the permit limits are written in terms of PM (i.e., not PM10
and/or PM2.5). The most stringent limits identified required the fabric filters (FF) to
achieve a grain loading of 0.01 gr/dscf.
If technology transfer from other types of PM emitting sources (i.e., controls applied to
different classes or categories of sources) is considered, the following additional PM
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controls would be potentially applicable: mechanical separation (i.e., cyclonic
separators), wet scrubbing, and electrostatic precipitators (ESP).
5.7.2.2 Step 2 – Eliminate Technically Infeasibility Controls
Emissions of PM from the PE manufacturing process fall into two categories: emergency
vents and continuous/intermittent process vents used as part of the polyethylene
manufacturing process. Emergency vents cannot be routed to filter type controls and will
instead vent through knockout/seal pots. Emergency events are infrequent and
unplanned, so these emergency pressure relieving vents are expected to be used rarely.
Because these vents are designed to rapidly release pressure from within a process unit,
controls such as particulate filters, ESPs, and wet scrubbers are not technically feasible
due to the backpressure imposed on the vent. As a result, the use of particulate filters,
ESPs, and wet scrubbers to control PM emissions associated with the control of
emergency events is not considered further by this analysis. The remainder of this
section discusses the feasibility of applying the identified controls to the continuous/
intermittent process vents used as part of the polyethylene manufacturing process,
including storage and handling operations.
As shown by the review of recent permits, particulate filters are used to control PM
emissions from polyethylene manufacturing process vents. As a result, the use of
particulate filters is considered technically feasible for application to these process vents
associated with the project’s PE manufacturing processes. Particulate filters have several
advantages when used for PM control including:
High particulate matter control efficiencies.
Relatively constant outlet grain loading over the entire boiler operating range.
Simple operation and maintenance.
The remaining control technologies identified via technology transfer from other sources
of PM such as coal and oil-fired boilers are discussed below.
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Table 5-39. Summary of Recent Determinations for Polyethylene Process Vents
RBLC ID
NO /State Facility Name Permit Date
Process
Description
Emissions Unit
Description
Control
Description
PM Limit a
(gr/dscf)
TX
103048
ExxonMobil
Chemical Company -
MBPP
10/07/13 Polyethylene Unit Process Vents Filter 0.01 b
TX
0631 draft
103832
final
Chevron Phillips
Chemical Company
LP
08/06/13
08/08/13
Polyethylene
Manufacturing Unit
Process Vents & Pellet
Handling & Product
Loadout
High Efficiency
Filters 0.01
LA
SASOL North
America
Lake Charles
Chemical Complex
04/30/13
PSD Permit
Application c
Low Density
Polyethylene
B207 & B208 vents
Pellet Elutriation Separator
Vents (2)
Fabric Filter 0.02
LA
SASOL North
America
Lake Charles
Chemical Complex
04/30/13
PSD Permit
Application
Linear Low
Density
Polyethylene
Catalyst Relief Vent
Continuous Catalyst Vent
Powder/Pellets Drop Points
Feeder Vent
Extruder Feed Vent
Pellet Transfer System
Pellet Blending System
Polymer Relief Drum
Pellet Dryer
Fabric Filter 0.02
a – gr/dscf = grains per dry standard cubic feet as PM. Vent specific limits for PM10 and PM2.5 were not required by these precedents.
b – Exxon Mont Belvieu PE Plant Permit 103048 Special Conditions, page 8, condition 14 (D)
c – Latest amendment to permit application dated 10/09/2013
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Electrostatic Precipitators (ESPs)
Electrostatic precipitators (ESP) are a common PM control system for heavy oil and solid
fuel-fired boilers, and for systems where the exhaust gases are too hot for fabric filter
materials (kilns). An ESP uses a large enclosure to slow the exhaust gas stream, allowing
more time to electrostatically charge particulates and collect them in the ESP. An ESP is
arranged in a series of fields that consist of negatively charged discharge electrodes and
positively charged collection plates. The discharge electrodes impart a negative charge to
particles in the gas stream. The negatively charged particles then migrate to the larger
positively charged plates. PM collected on the plates is periodically removed by rapping
the plate. Most of the PM knocked off the plates falls into collection hoppers for
removal. A portion of the collected PM is re-entrained in the gas stream during rapping.
This re-entrained PM is normally collected in subsequent sections of the ESP. ESP’s
may be located either upstream of the air heater (hot-side ESP) or downstream of the air
heater (cold-side ESP). The location is selected to achieve the best PM resistivity
conditions. Gas composition and temperature and particle composition all influence
resistivity, which is a measure of the ability of a particle to retain an electrostatic charge.
The ability to collect particles using electrostatic attraction is directly related to particle
resistivity. If the particle resistivity is outside the design range, particle collection
efficiency is reduced. Unlike particulate emissions from coal and oil fired sources, PE
particulate has a very high resistivity. This very high resistivity would result in a poor
ESP collection efficiency. In addition, the control of particulate from the multiple PE
manufacturing related vents requires a control technology that can be implemented at
several different locations. As a result, as is seen from the review of recent precedents,
the use of FF technology is favored because of both its ease in implementation and the
higher collection efficiency achieved. As a result the use of an ESP is not considered
further by this analysis.
Wet Scrubbers
Wet scrubbers are used in many industrial processes to control PM emissions,
particularly when the PM is sticky or when the exhaust gas is saturated with moisture.
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Wet scrubbers reduce PM emissions through several mechanisms, including
condensation, inertial impaction of PM with water droplets, and reactions of PM and PM
precursors with the scrubber reagent.
There are many types of wet scrubbers, namely, spray towers, packed towers, and venturi
scrubbers. All of these scrubbers have one principal in common, to contact the particles
in the flue gas with a liquid droplet. Once wetted or trapped inside a liquid droplet, the
particle can be separated from the flue gas and washed away with the liquid stream.
Spray tower scrubbers contact the flue gas with a liquid spray. The liquid spray is
generated either using spray nozzles or high speed rotating disks. Spray tower scrubbers
typically have high removal efficiencies for large particles and are less effective as the
particle size decreases. Spray tower scrubbers have relatively low energy costs
associated with liquid pumping and flue gas compression (fan energy).
Packed tower scrubbers counter currently contact the flue gas with a liquid cascading
down through packing. The packing is wetted with the liquid and the particles in the flue
gas are impacted on the wet packing as the flue gas flows through the packing. Packed
tower scrubbers typically have higher removal efficiencies for small particles than do
spray towers. However, packed towers are more easily plugged if the particle loading is
high and the particles are sticky in nature. Packed tower scrubbers have relatively low
energy costs associated with liquid pumping and moderate energy costs for flue gas
compression (fan energy). Packed tower scrubbers can have high costs for labor and lost
production associated with cleaning of the packing.
Venturi scrubbers contact the flue gas with a liquid by forcing the liquid and gas through
a small diameter pipe called a venturi throat. The compressed flue gas and liquid rapidly
mix in the throat causing the production of fine liquid droplets. After passing through the
venturi throat, the flue gas and liquid droplets are well mixed as they are rapidly
expanded in the expansion section of the venturi. Venturi scrubbers have a range of
removal efficiencies depending on the particle size and the amount of energy used to
compress the liquid and flue gas through the venturi throat. To effectively remove fine
particles and to achieve low particulate outlet concentrations, a high-energy venturi is
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required. High-energy venturi scrubbers have high energy costs associated with liquid
pumping and flue gas compression.
Wet scrubbers are typically only used when the exhaust gas is at the water saturation
temperature, the particulate matter is sticky or the flue gas temperature is too hot for
fabric filters. In the proposed plant, the pellet dryer vent is the only PM-containing vent
that is high in moisture content, where the use of wet scrubbing should be considered.
Mechanical Collectors
Mechanical collectors (cyclones) are not as effective as FFs for particulate matter control.
Mechanical collectors are typically used upstream of more effective control devices such
as FFs and ESPs when the PM loading is very high. This is not the case with the
proposed PE manufacturing vents. As a result, while mechanical collectors are a
technically feasible alternative, the performance of mechanical collectors is inferior to
FFs for the proposed service. Thus, FFs are favored for control of the PE manufacturing
vents due to the higher control efficiencies that can be achieved using FF versus
mechanical collectors. The use of mechanical collectors is not considered further by this
analysis.
5.7.2.3 Step 3 – Establish PE Manufacturing Process, Storage, and Handling Vent PM BACT/LAER Limits
A summary of the project’s proposed controls for the PE manufacturing process, storage,
and handling vents is presented in Table D-5 of Appendix D. A review of the limits
associated with PE manufacturing facilities indicates that 0.01 gr/dscf has been achieved
in practice. However, based on recent permit precedents in the State of Pennsylvania for
fabric filters, a grain loading of 0.005 gr/dscf is proposed for all particulate containing
vents.115 Particulate filter technology will be used where feasible.
115 PA Bulletin, Doc. No. 07-643c, April 14, 2007; PA Bulletin, Doc. No. 08-353a, March 1, 2008; and PA
Bulletin, Doc. No. 12-1311a, July 14, 2012.
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The proposed emission limits for the PE unit process vents must meet two criteria to be
considered LAER. With respect to the first criterion, a review was conducted of the
BACT guidelines for California agencies (BAAQMD, SJVAPCD, SCAQMD, and
CARB) and the Texas guidelines. The results from this review identified the two BACT
guidelines presented in Table 5-40. The proposed emission limit of 0.005 gr/dscf is more
stringent than the identified guideline limit of 0.01 gr/dscf. As a result, the first LAER
criterion is met. The second criterion has already been addressed by proposing a limit
that is more stringent than the most stringent emission limit achieved in practice,
identified from the survey of recent permit actions for PE manufacturing facilities.
Table 5-40. Summary of BACT Guidelines for Bay Area Air Quality Management
District and Texas Pertaining to Manufacturing Process Particulate Emissions
Agency Description Emission
Limit
Technology Reference
Bay Area Air
Quality
Management
District
Solid Material
Handling
(Conveying, Size
Reduction,
Classification) - Dry
<0.01 grains
per dry
standard cubic
feet
Baghouse Best Available
Control Technology
Guideline
(10/18/91)
Texas
Commission on
Environmental
Quality
Polyethylene
Facilities
<0.01 grains
per dry
standard cubic
feet
Baghouse
BACT Guidelines
for Chemical
Sources
The criteria for determining a BACT limit are somewhat different than the criteria for
determining a LAER limit. However, in the case of PM emissions from the PE process
vents, there is no difference in the limit. The proposed LAER limit of 0.005 gr/dscf is
based on the use of the most-effective, feasible PM control technology option and the
limit is the lowest that has been achieved in practice using that technology on this type of
source. In other words, the proposed LAER limit is consistent with the top-performing
control option in a top-down ranking of the feasible control options, which is the
appropriate basis for establishing a BACT limit.
As previously noted, no applicable PM standards have been promulgated for PE storage
and handling vents under 40 CFR parts 60 and 61. In accordance with 25 Pa. Code
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§127.205(7), the proposed PM LAER limit is equivalent to and satisfies the PaBAT
requirements of 25 Pa. Code §127.12(a)(5).
5.8 VOC Emissions from Storage Tanks and Vessels
As described in Section 3.5.2, the proposed Project will include the following VOC –
containing storage tanks and vessels, as shown in Table 5-41. The pressurized storage
vessels (i.e., spheres or bullets) are not sources of VOC emissions and do not require any
LAER analysis. The LAER analysis for emissions that may occur as a result of
component leaks, including leaks in piping and equipment associated with these tanks, is
presented in Section 5.5. This section presents the LAER analysis for the outside
boundary limit (OSBL) tanks for pyrolysis tar, light gasoline, hexene, recovered oil, spent
caustic, diesel, and wastewater flow equalization. The LAER analysis for VOC-
containing tanks included as part of the wastewater treatment system is presented in
Section 5.10.
Emissions from tanks occur as a result of displacement of headspace vapor during filling
operations in the case of fixed roof or internal floating roof (IFR) tanks, or from tank rim
seals in the case of external floating roof (EFR) tanks (i.e., “working losses”). To a lesser
degree, diurnal temperature variations and solar heating cycles also result in emissions
from storage tanks (i.e., “breathing losses”).
5.8.1 Tank Emissions Control Technology Baseline
5.8.2 Step 1: Identify Tank VOC Control Options
Available VOC control options for organic liquid storage tanks include inherently less-
polluting processes, control equipment designed to minimize vapor leakage from the
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Table 5-41. Summary of Storage Tanks and Vessels in VOC Service
Service Tank/Vessel Description No. Equipment ID Capacity(m3)
Ethylene Spherical Pressure Vessel 2 V-64201,V-
64202
7,238
Ethylene Atmospheric Refrigerated Tank 1 T-64201 30,000
C3+ (propane/heavier hydrocarbons) Spherical Pressure Vessel 2 V-64205,V-
64206
2,300
Butene Spherical Pressure Vessel 2 V-64301,V-
64302
1,288
Isopentane Horizontal Pressure Vessel 2 V-64401,V-
64402
600
Isobutane Horizontal Pressure Vessel 2 V-64501,V-
64502
200
C3+ Refrigerant Horizontal Pressure Vessel 1 V-64203 300
Pyrolysis Tar Heated Fixed Roof Tank 1 T-64201 130
Light Gasoline Internal Floating Roof 2 T-64207,T-
64208
325
Hexene Internal Floating Roof 1 2 T-64301,T-
64302
2,300
Recovered Oil Storage Internal Floating Roof 1 T-59708 90
Equalization (Wastewater) 4 Internal Floating Roof 2 T-59707A,T-
59707B
2,810
Biotreater Aeration Tank 1 T-59709 5,210
Secondary Clarifier 4 Tank 2 T-59710A,T-
59710B 1,466
Biosludge (WAS) Holding 4 Tank 1 T-59711 43
Sand Filter Backwash Receiver 4 Tank 1 T-59713 143
Spent Caustic Internal Floating Roof 1 T-53501,T-
53502
900/8,630 2
Generator Diesel 3 Fixed Roof 4 T-58901A,T-
58901B,T-
38
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Service Tank/Vessel Description No. Equipment ID Capacity(m3)
58901C,T-
58901D
Fire Pump Diesel 3 Fixed Roof 3 T-59101A,T-
59101B,T-
59101C
7
Locomotive Diesel Fixed Roof 1 T-4000 38
Dimethyl disulfide (DMDS) Drum 1 V-18831 25
1. Includes nitrogen blanketing.
2. Two spent caustic scenarios.
3. Emergency use internal combustion engines.
4. VOC LAER analysis included in WWTP (see Section 5.10)
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tanks, end-of-pipe air pollution control equipment and combinations thereof. Specific,
identified options are as follows:
Route tank vapors to a process via hard piping, such that the vessel (i.e., tank)
operates with no emissions;
Fixed roof in combination with an internal floating roof including vapor
collection in a closed vent system routed to a control device (e.g., thermal
incinerator);
Fixed roof with vapor collection by a closed vent system routed to a control
device (e.g., thermal incinerator or carbon adsorber).
Fixed roof in combination with an internal floating roof; and
External floating roof.
It should be noted that many of the Project’s tanks use a fixed roof in combination with
an internal floating roof and an inert gas blanket that is inherent to the process and would
be applied even in the absence of air pollution control requirements.
The above identified tank control options are typically used for tanks larger than 75 cubic
meters (20,000 gallons). For smaller tanks, such as the diesel fuel tanks, carbon
adsorption and other absorption media can be used to capture VOCs. These systems are
effective for remote, low flow and low VOC emitting vents.
As noted in Section 4.0, there are several regulations potentially applicable to the
Project’s tanks, including, for tanks in organic compound service:
NSPS 40 CFR Part 60, subpart Kb,
NESHAP 40 CFR Part 63 subpart FFFF,
NESHAP 40 CFR Part 63 subpart WW,
25 Pa. Code § 129.56, and
25 Pa. Code §129.57.
These regulations serve as a baseline for the proposed LAER and will be met or exceeded
via compliance with the proposed LAER controls.
5.8.3 Step 2: Eliminate Technically Infeasible Tank VOC Controls
The most effective control option is to operate the tank with the vent directed to a
process, a fuel gas system, or a VOC control system (i.e, incinerator or flare). Routing a
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tank’s vent gases to a process is feasible only for tanks that store liquids compatible with
the process.
For the pyrolysis tar storage tank, the use of an internal or external floating roof design is
considered to be technically infeasible due to: 1) the asphalt-like nature of the material
being stored; and 2) the storage temperature of approximately 300 °F.
All other identified control options are technically feasible for the other storage tanks.
5.8.4 Step 3: Establish Tank VOC LAER
The most stringent storage tank control options, in order of decreasing overall control
effectiveness, are presented below:
Control strategies that achieve nearly 100 percent VOC control.
o Route vapors to a process via hard piping, such that the vessel operates
with no emissions.
o Fixed roof in combination with internal floating roof and vapor collection
in a closed vent system routed to a thermal incinerator.
Control strategies that achieve nearly 98 to 99 percent VOC control.
o Fixed roof tank with vapor collection by a closed vent system routed to a
control device
o Fixed roof tank with internal floating roof and nitrogen blanketing.
Neither the pressurized storage vessels nor the ethylene atmospheric refrigerated tank
presented in Table 3-1 will vent to the atmosphere. If over pressured, these vessels and
tank will vent to one of the facility’s VOC control systems. The only emissions of VOC
from these vessels/tank will be from equipment leaks. The remaining tanks listed in
Table 3-1 will be controlled as follows:
The Light Gasoline and two Hexene tanks will be internal floating roof tanks and
vent to a vapor recovery system with a thermal incinerator as their primary form
of control. During upset events when the loading on the LP Flare Header is
greater than the incinerator’s capacity, the excess load will be directed to a LP
Ground Flare.
The flow equalization and oil removal (FEOR) and recovered oil storage tanks,
and spent caustic/unoxidized spent caustic tanks will vent to the Spent Caustic
Vent Incinerator.
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The pyrolysis tar, diesel locomotive, emergency generator and firewater pump
diesel engine fuel tanks (each <20,000 gallons) will vented to carbon canisters.
The proposed emission limits or operating standards for the above tanks meet the two
criteria to be considered LAER. A survey was conducted to determine the most stringent
emission limit contained in a permit and achieved in practice or included in approved
implementation plan. The results of the survey are presented in Table 5-42. As shown,
the proposed emission standards are consistent with the most stringent limitations
associated with the Arizona Clean Fuels Project (AZ-0046),116 St. Charles Refinery (LA-
0213), and the BAAQMD BACT Guidelines. The most stringent limitation found in the
implementation plan for a state/agency is the BAAQMD BACT Guidelines. As a result,
the proposed emissions controls/limitations meet both of the LAER criteria. The
proposed VOC LAER for the Project’s are as stringent as the applicable standards under
40 CFR parts 60 and 61.
In accordance with 25 Pa. Code §127.205(7), the proposed VOC LAER limit is
equivalent to and satisfies the PaBAT requirements of 25 Pa. Code §127.12(a)(5). The
proposed LAER is also more stringent than the applicable NSPS and NESHAP
requirements for these tanks.
116 The Arizona Clean Fuels project was never constructed/operated, and as such the limitations associated
with this permit are not demonstrated.
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Table 5-42. Summary of VOC BACT/LAER Precedents for Tanks
RBLC ID
No. Facility Name
Permit
Date
Process
Description Capacity Control Description Emission Limitation
AZ-0046 Arizona Clean
Fuels Yuma 04/14/05
Petroleum Refinery
Group A Storage
Tanks
1.51 to 3.78
million
gallons
Emissions must be collected by
vapor compression system &
routed to the refinery fuel gas.
None specified
AZ-0046 Arizona Clean
Fuels Yuma 04/14/05
Petroleum Refinery
Group D Storage
Tanks
850,000
gallons
The tanks are required to be
under pressure so that no
emissions are emitted to the
atmosphere
None specified
AZ-0046 Arizona Clean
Fuels Yuma 04/14/05
Petroleum Refinery
Group B Storage
Tanks
378,000 to
7,560,000
gallons
Internal Floating Roofs with
headspace routed to the tank
farm thermal oxidizer
99.9% design destruction
efficiency & 20 ppmv limit when
inlet conc.to thermal oxidizer
<20,000 ppmv
IA-0096 Verasun Charles
City, LLC
11/18/08
Hexane Storage Tanks
30,000
gallons
Internal Floating Roof
NSPS Kb & NESHAP EEEE
LA-0213
Valero Refining
St. Charles
Refinery
11/17/09
Tanks - For Benzene,
Xylene, Sulfolane,
Parex, Intermediate
Not
specified
Equipped with internal floating
roofs followed by thermal
oxidizers
Not specified
TX -0631
ChevronPhillips
Chemical Cedar
Bayou Plant
08/06/13
Internal floating roof
tanks with VOC
partial pressure >0.5
psia 1
> 25,000
gallons 1
Tank VOC emissions will be
controlled by internal floating
roof tanks.
Internal floating roof: (1) a liquid-
mounted seal, (2) two continuous
seals mounted one above the other,
or (3) a mechanical shoe seal. 1
BAAQMD BACT
Guidelines 03/03/95
Storage Tank - Fixed
Roof, Organic Liquids
> 20,000
gallons
Vapor recovery system: Thermal
Incinerator; or Carbon Adsorber;
or Refrigerated Condenser
Overall system efficiency >98%
BAAQMD BACT
Guidelines 03/03/95
Storage Tank - Fixed
Roof, Organic Liquids
< 20,000
gallons
Vapor recovery system: Vapor
Balance; or Carbon Adsorber; or
Refrigerated Condenser; or
Incinerator
Overall system efficiency >95%
Special Conditions Permit Number 103832, N166; August 8, 2013. Note, this project subject to non-attainment review for VOC per Polyethylene Production
Units Initial Permit Application; June 21, 2012.
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5.9 PM and VOC Emissions from Cooling Towers
Two counter-flow mechanical draft cooling water towers (CWT) will be constructed at
the site to provide cooling water. A twenty-six (26) cell recirculating water tower will be
used to provide cooling water for the process units and another four (4) cell recirculating
water tower will support the Cogeneration Plant.
Evaporative cooling towers are designed to cool water by contacting the water with air
and evaporating some of the water. Thus, these units use the latent heat of water
vaporization to exchange heat between the process and the air passing through the tower.
This type of cooling tower typically contains a wetted medium to promote evaporation,
by providing a large surface area and/or by creating many water drops with a large
cumulative surface area.
Measurement of the PM and VOC emissions from a cooling tower is impractical, because
of difficulties in obtaining a representative sample. There is currently no EPA Reference
Method for sampling the exhaust from forced draft cooling towers. As a result,
equipment specifications and operating practices are used to control PM and VOC
emissions. No applicable PM or VOC standards have been promulgated for cooling
towers under 40 CFR parts 60 and 61.
5.9.1 Cooling Tower PM/PM10/PM2.5 BACT/LAER Analysis
As part of a cooling tower’s operation, some of the liquid water is entrained in the air
stream and is carried out of the tower. PM, PM10, and PM2.5 (PM) emissions from a
cooling tower can be generated by the dissolved solids within the water droplets (drift)
that escape the tower. The PM is generated when escaped droplets evaporate and the
dissolved solids are left behind. The concentration of total dissolved solids (TDS) in
cooling water varies widely and is site dependent. For a given solids concentration
(defined by the cooling water source, tower design and operating specifications), PM
emissions from cooling towers depend on the amount of water that drifts from the tower.
Drift eliminators of various types are used to control the amount of total liquid drift.
Directional changes through a structured media result in the inertial separation of water
droplets (mist) from the air stream.
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This section addresses the control of PM, PM10, and PM2.5 emissions from the project’s
two cooling towers. The proposed project is located in an area that is classified as
nonattainment with regard to the annual PM2.5 standard. As a result, a LAER analysis is
required for all of the project’s sources of PM2.5. The PM2.5 that will be emitted from
operation of the cooling towers will be filterable PM. As a result, the control
technologies applicable to the control of PM2.5 are the same as the technologies for PM
and PM10. Thus, there is no need to distinguish between the various PM species and
throughout this LAER analysis all forms of PM are referred to as “PM”. It is assumed
that the LAER analysis will meet the requirements of BACT for PM10 and PM.
5.9.1.1 Step 1: Identify Potential Cooling Tower PM Controls
A summary of the cooling tower PM permitting precedents in the USEPA’s RBLC
database for the last ten years is presented in Table 5-43. As shown, two PM control
options were identified for cooling towers: use of mist/drift eliminators and limits on the
level of total dissolved solids (TDS) in the circulating water. Another potential cooling
water approach not identified in the RBLC is the use of dry cooling.
5.9.1.2 Step 2: Eliminate Technically Infeasible Controls
Drift eliminators and the use of TDS limits are both controls that have been demonstrated
in the past and as a result are considered to be technically feasible for purposes of this
analysis.
Dry cooling uses an air cooled heat exchanger or a dry cooling tower that operates by
transferring the heat in the process cooling water through a surface such as in a tube to air
heat exchanger, utilizing convective heat transfer. Although air cooling and dry cooling
towers inherently generate less PM compared to a wet cooling tower, air coolers and dry
cooling towers are not technically feasible cooling options for the proposed Project. At
the ethylene manufacturing unit and PE units, there are process streams that must be
cooled to 130°F or less. At times during the summer, ambient air temperatures are high
enough that these streams cannot be cooled by using air alone.
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Table 5-43. RBLC Summary of Cooling Tower Emission Limits for PM
RBLC ID
No. FACILITY NAME
Permit
Date
Capacity
(gpm) Control
Limit
(wt% of total
circulating rate)
Other Emission
Limit
FL-0299 Crystal River Power Plant 10/12/2007 342,306 Not specified 0.0005 None
IA-0088 ADM Corn Processing -
Cedar Rapids 06/29/2007 150,000 Drift Eliminators 0.0005 None
IA-0089 Homeland Energy Solutions,
LLC, PN 06-672 08/08/2007 50,000 Drift Eliminator / Demister 0.0005 None
IA-0095 Tate & Lyle Ingredients
Americas 09/19/2008
Not
specified Drift Eliminators 0.0005 None
ID-0017 Power County Advanced
Energy Center 02/10/2009 121,000 Drift/Mist Eliminators 0.0005 1.5 lb/hr
WI-0252 Specialty Minerals Inc. -
Superior 07/22/2011 200
High Efficiency Mist / Drift
Eliminators (W/ Additional
Layer); Dissolved Solids
Limit
0.0005 None
IA-0067 Walter Scott Jr. Energy
Center 06/17/2003 349,400 Mist Eliminators 0.001 None
ID-0017 Power County Advanced
Energy Center 02/10/2009 985 Drift/Mist Eliminators 0.001 0.3 lb/hr
MD-0032 Dickerson 11/05/2004 10 cells Mist Eliminators 0.001 None
IL-0102 Aventine Renewable Energy,
Inc. 11/01/2005
Not
specified Drift Eliminator 0.005 6.85 tpy
MN-0070 Minnesota Steel Industries,
LLC 09/07/2007
Not
specified Designed to Minimize Drift 0.005 None
NE-0029 Abengoa Bioenergy
Corporation - York 01/21/2004
Not
specified Not Specified 0.005
3600 ppm per
sample
2400 ppm per 12
consecutive months
AR-0100 Lion Oil Company 10/01/2007 19,977 Drift Eliminators 0.005 3000 mg/l
PA1 River Hill Power Company, 7/21/2005 140,000 Drift Eliminators 0.0005 5000 ppm
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RBLC ID
No. FACILITY NAME
Permit
Date
Capacity
(gpm) Control
Limit
(wt% of total
circulating rate)
Other Emission
Limit
LLC
PA2 Robinson Power Co., LLC 6/30/2011 Not
specified Designed to Minimize Drift 0.0005 None
PA3 Hickory Run Energy, LLC 4/23/2013 175,000 Not Specified 0.0005 5000 ppm
1. PA Bulletin, Doc. No. 05-946b
2. PA Bulletin, Doc. No. 11-973
3. Plan Approval Number 37-337A issued April 23, 2013
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At the Cogen Units, a water-cooled condensing steam turbine generator will be used.
The use of an air-cooled condensing steam turbine generator would result in significantly
lower power generation and increased air emissions. Air-cooled steam condensers are
installed in only 1% of U.S. steam electric generating plants. While they utilize less
water, the use of dry cooling systems can result in up to a 10% power production penalty
on hot days, and up to five times higher capital costs compared to a recirculating cooling
tower and water-cooled surface condenser systems. Large fans are used to circulate air
past the finned-condenser tubes. Besides the cost and the power production penalty,
other drawbacks of air-cooled condensers are the large footprint of the condenser and the
typical dimensions, including the fan size.117
The use of dry/air cooling for all process cooling and for power generation would result
in redefining the project.
5.9.1.3 Steps 3: Establish Cooling Tower PM BACT/LAER
As shown in Table 5-43, mist/drift eliminators combined with TDS limits are used to
control/limit PM emissions from cooling towers. The limits for drift losses range from
0.005 to 0.0005 weight percent of the total circulating water rate and the TDS limits
range from 2400 to 3600 ppm based on averaging time. Based on these prior precedents,
the following PM BACT/LAER limit for the cooling towers is proposed:
Use of mist/drift eliminators designed to achieve a drift rate of 0.0005%
TDS limits of 2400 ppm averaged over 12 consecutive months
The proposed emission limits or operating standards for the cooling towers must meet
two criteria to be considered LAER. To fulfill the first criterion, a survey of emissions
limits contained in state implementation plans for those states most likely to have the
most stringent emission limits was performed. The results of this survey found only two
117 NSF/EPRI Collaboration on "Water for Energy"- Advanced Dry Cooling for Power Plants.
http://www.nsf.gov/pubs/2013/nsf13564/nsf13564.htm
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agencies that included specific cooling tower PM control requirements in their
implementation plans:
The Texas Commission on Environmental Quality (TCEQ) has a BACT guideline
requiring:118
o drift eliminators, and
o drift < 0.001%.
The Maricopa County Arizona Air Quality Department Regulations require:119
o Drift eliminators not made out of wood,
o Concentration of Total Dissolved Solids multiplied by the percentage of drift not
to exceed 20.
The search included other agencies for which guidelines or rules could not be found:
South Coast Air Quality Management District (SCAQMD),
Bay Area Air Quality Management District (BAAQMD);
San Joaquin Valley Air Pollution Control District,
California Air Resource Board (CARB) permit determinations;
New Jersey State of the Art Manuals; and
Clark County Nevada Department of Air Quality.
The survey of emissions limits contained in state implementation plans for those states
most likely to have the most stringent emission limits demonstrated that the proposed
cooling tower PM limits are more stringent than Texas and Maricopa County
limits/regulation. Note that when the proposed drift rate of 0.0005% is multiplied by the
proposed TDS limit of 3600, the value obtained is 1.8, which is significantly below the
Maricopa County rule value of 20. As a result, the proposed cooling tower limits meet
the first criterion for LAER.
118 TCEQ Chemical Sources, Current Best Available Control Technology (BACT) Requirements, Cooling
Towers; last revision 08/01/2011.
http://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bact/bact_cooltow.
pdf 119 Maricopa County Air Pollution Control Regulations, September 2013, Section 300-Standards, 301
Limitations-Particulate Matter, Rule 301.4 Cooling Towers.
http://www.maricopa.gov/aq/divisions/planning_analysis/rules/docs/MCAQD%20Rules.pdf
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The second criterion is addressed by the proposal of the most stringent drift loss and TDS
concentration requirements identified via the survey of past precedents. As previously
noted, no PM standards have been promulgated for cooling towers under 40 CFR parts 60
and 61. In accordance with 25 Pa. Code §127.205(7), the proposed PM BACT/LAER
limit is equivalent to and satisfies the PaBAT requirements of 25 Pa. Code §127.12(a)(5).
5.9.2 Cooling Tower VOC LAER
When water from a cooling tower is used to cool streams containing VOCs, leaks can
occur in the heat exchanger tubes allowing VOCs to leak into the cooling water stream if
the stream containing the VOC is at higher pressure than the cooling water. The VOCs
that leak into the cooling water get stripped out of the cooling water when it returns to the
cooling tower and is contacted with air. The cooling water at the Cogen Units will be
separate from the process cooling water, so there is no potential for VOC emissions from
the Cogen cooling tower.
5.9.2.1 Step 1: Identify Cooling Tower VOC Limits
A summary of the cooling tower PM permitting precedents in the USEPA’s RBLC
database for the last ten years is presented in Table 5-44. As shown, one control option
was identified for the control of VOC emissions from cooling towers: monitoring of
VOC content in the cooling water with repair of leaking heat exchangers. Another
cooling water approach not identified in the RBLC is the potential use of dry cooling.
5.9.2.2 Step 2: Eliminate Technically Infeasible Controls
As noted above, only one of the cooling water towers will be used to cool water that has
the potential to come in contact with hydrocarbon. The Cogen cooling tower will have
no source of hydrocarbon contamination. As result, only the Process Unit cooling tower
is considered further as part of this VOC analysis.
To minimize leaks of VOC containing process fluids into cooling water, a heat exchanger
leak detection and repair program is technically feasible and effective. This program
involves monitoring cooling water for the presence of hydrocarbons, finding and
repairing leaks. In some instances, suitable control may include installation of
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Table 5-44. RBLC Summary of Cooling Tower Emission Limits for VOC
RBLC
ID No. Facility Name Facility Type
Permit
Date
Capacity
(gpm) Control
Emission Limit
(lb/MMgal)
WI-
0204
United
Wisconsin
Grain
Producers
Fuel Grade Ethanol
Plant
(cooling tower P80)
08/14/2003 22,000
124 ppm VOCs
(synthetic minor permit for
VOCs)
0.076
Calculated from 0.1
lb/hr emission rate 1
WI-
0207
Ace Ethanol -
Stanley Ethanol Plant 01/21/2004 20,000 300 ppm VOCs
0.125
Calculated 2
OH-
0256
Lima
Chemicals
Complex
Manufacture of
butanediol &
tetrahydrofuran,
butyrolactone,
butanol, &
maleic anhydride
07/10/2003 20,000 LDAR Program 0.175
from permit
LA-
0211
Garyville
Refinery Petroleum Refinery 12/27/2006
30,000
96,250
2,500
"Monitoring Process Side of the
Heat Exchangers for Leaks
2008-35: VOC Monitoring
Program Meets 40 CFR 63
Subpart F"
0.5
Calculated from
4.14 lb/hr
OH-
0308
Sun Company
Toledo
Refinery
Petroleum Refinery 02/23/2009 2,000 Not Specified 0.7
from permit
TX-
0575
Sabina
Petrochemicals
LLC
C4 Olefins Complex
(Manufacture of 1,
3-butadiene &
mixed iso-octanes) 3
08/20/2010 73,000
Cooling Tower has non-contact
design, utilizes weekly
monitoring of VOC in water per
Appendix P or approved
equivalent & identified leaks
repaired as soon as possible, but
before next scheduled shutdown
0.7
Calculated 5
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RBLC
ID No. Facility Name Facility Type
Permit
Date
Capacity
(gpm) Control
Emission Limit
(lb/MMgal) 4
LA-
0246
St. Charles
Refinery Petroleum Refinery 12/31/2010
61,250
45,000
50,000
40,000
Monitoring VOC concentration
in cooling water
20.7
Calculated 6
1. This permit limit found in RBLC could not be confirmed. Construction permits only have the following permit condition for P80: (2) The cooling water
additives may not contain significant VOCs. As such, this listing is not considered further.
2. From permit 03-DCF-184 Source F06, 0.15 pounds per hour of VOC for 20,000 gpm cooling tower (0.125 = 0.15 lb/hr / 60 min/hr / 20,000 gpm* 10^6
gal/MMgal).
3. A leak is detected if the exit mean concentration is found to be greater than the entrance mean using a one-sided statistical procedure at the 0.05 level of
significance and the amount by which it is greater is at least 1 part per million or 10 percent of the entrance mean, whichever is greater. 40 CFR 63.104
(b)(6).
4. From Texas permits 41945, PSD-TX-950, and N-018; July 7, 2011. Weekly monitoring of the cooling water is required, not monthly as listed in RBLC.
5. Calculated by using 13.43 tpy VOC limit and 73,000 gpm flow rate as follows: 13.43 tpy * 2000 lb/ton / 8760 hrs/yr / 60 min/hr / 73,000 gpm * 10^6
gal/MMgal.
6. Calculated using gpm and the following cooling tower lb/hr limits: 76, 55.84, 62.04, and 49.63, respectively.
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hydrocarbon detectors or sampling points in the exit water downstream of the exchanger
to identify leaks. This control measure also includes a systematic inspection, preventive
maintenance, and repair programs to avoid leakage. This latter function can include
routine replacement of seals, exchanger cleaning, and pressure testing of exchanger
vessels. This control technique is technically feasible for the Project’s Process Unit
cooling tower.
The use of dry cooling is eliminated based on the same technical logic stated in
Section 5.9.1 above for the PM BACT/LAER analysis.
5.9.2.3 Steps 3: Establish Cooling Tower VOC LAER
Some operations within the proposed project’s process units will need cooling water to
achieve the required process temperatures. Wherever possible, the proposed process
units will be designed/operated to maximize the recovery of heat for process use (e.g.,
steam generation) to maximize the project’s thermal efficiency, and minimize the
project’s demand for cooling water. In addition, based on the precedents listed in Table
5-44, a cooling water heat exchanger leak detection and repair program consistent with
40 CFR §63.104, except that weekly monitoring will be conducted instead of
monthly/quarterly as required by 40 CFR §63.104, consistent with Texas permit PSD-
TX-950 (RBLC ID TX-0575) is proposed. Based on the prior precedents, a VOC
emission limit of 0.5 pounds per million gallons of cooling water circulation is proposed
as VOC LAER for the cooling towers. The lower determinations found in RBLC (WI-
0207 and OH-0256) are rejected as LAER because these determinations are not for large
systems similar to that being proposed for the Project.
The proposed emission limits or operating standards for the cooling towers must meet
two criteria to be considered LAER. To fulfill the first criterion, a survey of emissions
limits contained in state implementation plans for those states most likely to have the
most stringent emission limits was performed. The results of this survey found only one
agency with a specific cooling tower VOC control requirement in its implementation plan
as follows.
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The Texas Commission on Environmental Quality (TCEQ) has a BACT guideline
requirement of:120
o Non-contact design, and
o Monthly monitoring of VOC in water per Appendix P or approved equivalent
– assume all VOC stripped out.
o Repair identified leaks as soon as possible, but before next scheduled
shutdown, or shutdown triggered by 0.08 ppmw cooling water VOC
concentration.
Conversion of TCEQ’s 0.08 ppmw cooling water VOC content limit gives a VOC pound
per million gallons of water of 0.7.121 This rate is higher than that proposed for the
Project.
Other agencies searched for which guidelines or rules could not be found include:
South Coast Air Quality Management District (SCAQMD),
Bay Area Air Quality Management District (BAAQMD);
San Joaquin Valley Air Pollution Control District,
California Air Resource Board (CARB) permit determinations;
New Jersey State of the Art Manuals;
Louisiana Department of Environmental Quality;
The Maricopa County Arizona Air Quality Department; and
Clark County Nevada Department of Air Quality.
The survey of emissions limits contained in state implementation plans for those states
most likely to have the most stringent emission limits demonstrate that the proposed
cooling tower VOC limits are more stringent than the Texas limits/regulations.
The second criterion is addressed above through the proposal of the most stringent limits
identified via the survey of past precedents. As previously noted, no VOC standards have
120 TCEQ Chemical Sources, Current Best Available Control Technology (BACT) Requirements, Cooling
Towers; last revision 08/01/2011.
http://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bact/bact_cooltow.
pdf 121 0.08 ppmw /1,000,000 parts/million * 1,000,000 gallons *8.32 pounds/gallon of water = 0.665 lb
VOC/million gallons.
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been promulgated for cooling towers under 40 CFR parts 60 and 61. In accordance with
25 Pa. Code §127.205(7), the proposed VOC LAER limit is equivalent to and satisfies
the PaBAT requirements of 25 Pa. Code §127.12(a)(5).
5.10 VOC Emissions from Wastewater Treatment Plant
5.10.1 VOC LAER Analysis
The Wastewater Treatment Plant (WWTP) will consist of primary flow equalization and
oil removal, followed by a secondary activated sludge bioreactor (including clarifiers)
and a tertiary sand filter to treat the wastewater streams from process units and potentially
contaminated storm water runoff from process paved areas. A more detailed description
of the WWTP is presented in Section 3.5.6. The NSPS Subpart Kb standards are
applicable to the WWTP’s recovered oil storage and flow equalization tanks.
5.10.1.1 Step 1: Identify WWTP VOC Controls
Table 5-45 presents a summary of the recent precedents/permit determinations for
wastewater treatment plants VOC emissions and controls. The review included an
examination of the following information sources:
EPA’s RACT/BACT/LAER Clearinghouse
SCAQMD BACT Guidelines
BAAQMD BACT/TBACT WORKBOOK
CA and TX RACT
Based on this review, WWTP tanks and equipment located upstream of activated sludge
biological treatment that are designed to store or treat influent wastewater containing
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Table 5-45. RBLC Summary of VOC RACT/BACT/LAER Precedent for Wastewater Treatment
RBLC ID
No. Facility Name
Permit
Date
Process
Description Capacity Control Description VOC Limit
VOC Limit
Units
IA-0088 ADM
Cedar Rapids, IA 6/29/07
WWTP Aeration
Tank 1.5 MGD None 20
ppmvd avg. of 3
test runs
IA-0088 ADM
Cedar Rapids, IA 6/29/07
WWTP Anaerobic
Digester
1500 SCFM of
Biogas Enclosed Flare
98 % reduction avg. of
3 test runs
0.36 lb/hr avg. of 3 test
runs
TX-0354
ATOFINA
Chemicals
Jefferson County,
TX
12/19/02 WWTP Not specified
Emissions from any VOC Water Separation
Equipment Shall Be Vented to a Permitted
Control Device or Recycled to the Process.
0.12 lb/h
0.5 TPY
SCAQMD Sunoco Chemicals
Philadelphia, PA 7/27/99
WWT system at
chemical plant.
VOC-contaminated
water air stripped of
VOC.
Approx. 6000
scfm (510 gpm
water to
stripper)
Wastewater is required to be air-stripped with
stripper vented to thermal oxidizer with
minimum 95% destruction efficiency.
95 % destruction
efficiency
BAAQMD
Best Available
Control
Technology
(BACT) Guideline
6/2/95
Sewage Treatment
Plant - Headworks
and Primary
Treatment
N/A
Process modifications (e.g., turbulence
reduction), and covers with vapor phase
controls (process air recycle, odor control
equipment, activated carbon or alumina
systems, biofilters). None
[Technologically
Feasible/ Cost
Effective]
Industrial source control, packed scrubber for
odor control at headworks, and fixed covers
for primary clarifiers.
[Achieved in
Practice]
BAAQMD
Best Available
Control
Technology
(BACT) Guideline
6/2/95
Sewage Treatment
Plant - High Purity
Oxygen Activated
Sludge
N/A
Vapor phase controls (odor control equipment,
activated carbon or alumina systems, or
combustion abatement
device) None
[Technologically
Feasible/ Cost
Effective]
Industrial source control. [Achieved in
Practice]
BAAQMD
Best Available
Control
Technology
(BACT) Guideline
10/4/91 Water Treating -
Oil/Water Separator >250 Gal/min
Vapor-tight fixed cover and vented to vapor
recovery system
w/ combined collection and
destruction/recovery efficiency of >95%
None [Achieved in
Practice]
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RBLC ID
No. Facility Name
Permit
Date
Process
Description Capacity Control Description VOC Limit
VOC Limit
Units
TN-0039 OSCO Treatment
Systems, INC. 6/12/90
Wastewater
Treatment Plant 0.325 MGD
Thermal Incinerator - 99% Efficient, Caustic.
Scrub.-95% Efficient 4.3 lb/hr
OH-0153 Hilton Davis Co. 7/22/87 Wastewater
Treatment System 4.5 MGD
Thermal Incinerator, Covers (Est. Efficiency
95%) 17.8 TPY
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significant concentrations of VOC are equipped with a closed vent system, where the
vapors are routed to one of the following types of control devices:
Combustion device with VOC destruction efficiency up to 99%
Activated carbon system
Alumina system
Biofilter
Packed scrubber
The VOC removal efficiencies of activated carbon and alumina systems, biofilters and
packed scrubbers vary considerably depending on the organic compound being removed.
According to Section 7.1 of EPA’s AP-42, activated carbon systems typically remove up
to 98% of the VOC from a petroleum tank vent.
5.10.1.2 Step 2: Eliminate Technically Infeasible WWTP VOC Control Options
Each of the precedents identified in Table 5-45 were reviewed to determine their
applicability to the proposed WWTP. This review is summarized below.
ADM. This precedent is for an Anaerobic Digester with vapors routed to an enclosed
flare. The proposed Shell WWTP will not be equipped with an anaerobic digester. As
such, this precedent is not applicable.
ATOFINA. This permit states: “Emissions from any VOC Water Separation Equipment
shall be vented to a permitted control device or recycled to the process.” The ATOFINA
emission controls are applicable only to the VOC/wastewater separation system. At the
proposed Shell WWTP, the flow equalization and oil removal (FEOR) tanks comprise the
VOC/wastewater separation system. As such, this precedent is partially applicable, and
applies only to those tanks.
SUNOCO. According to the SCAQMD summary, “Wastewater is required to be air-
stripped with stripper vented to thermal oxidizer with minimum 95% destruction
efficiency.” The proposed Shell WWTP will treat both stormwater and oily wastewater.
Oils and other hydrocarbons will be removed in FEOR tanks designed for flow
equalization and oil removal, and these tanks will be equipped with both IFRs and with a
system designed to collect VOCs and route them to a combustion device with a minimum
99% destruction removal efficiency. For the proposed project, it does not make process
sense to use an air stripper rather than the proposed system to remove VOCs from either
oily wastewater, or from stormwater, which has a widely varying flow rate. As such, this
precedent is not applicable.
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BAAQMD. BACT for Sewage Treatment Plant: Headworks and Primary Treatment.
This precedent is partially applicable to the proposed WWTP, in which process
wastewater will be hard-piped from certain process units to the FEOR Tanks. These two
tanks can be classified as Primary Treatment (there will be no headworks at the proposed
facility).
BAAQMD. BACT for Sewage Treatment Plant: High Purity Oxygen Activated Sludge.
The Shell WWTP will not be equipped with High Purity Oxygen Activated Sludge. As
such, this precedent is not applicable.
BAAQMD. BACT for Water Treating: Oil/Water Separator. BAAQMD specifies as
BACT that the oil-water separator be covered with a vapor control system and vapors
routed to an emission control device. This precedent is partially applicable to the
proposed WWTP, in which process wastewater will be hard-piped from certain process
units to the FEOR Tanks which will be equipped with IFRs and a vapor control system
routed to emission control device. These tanks can be classified as Oil/Water Separators.
OSCO. The RBLC entry states: ”All incoming storage and treatment tanks are covered
and vented to a control system consisting of a thermal incinerator followed by a caustic
scrubber. The emission limit shown above does not include other fugitive emissions
from the facility.” At the proposed Shell WWTP, the flow equalization and oil removal
(FEOR) tanks comprise the incoming storage and treatment tanks. As such, this
precedent is partially applicable, and applies only to those tanks.
Hilton Davis. WWTP with thermal incinerator and covers with an estimated efficiency
of 95%. The RBLC data indicate that the process to which these controls apply are the
water system and wastewater tank. The proposed Shell project’s wastewater tanks are the
FEOR tanks, equipped with IFRs and a vapor control system routed to an emission
control device. As such, this precedent is partially applicable, and applies only to those
tanks.
Based on these precedents, add-on controls are considered to be technically feasible for
the proposed Flow Equalization and Oil Removal Tanks. No add-on controls were
identified as being feasible and applicable to the WWTP equipment located downstream
of the FEOR Tanks (i.e., Biotreater Aeration Tank, two Secondary Clarifiers, Biosludge
Holding Tank, Biosludge Dewatering Tank, Centrate Sump, Sand Filter, Sand Filter
Backwash Receiver and Outfall).
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5.10.1.3 Step 3: Establish WWTP VOC LAER
For the Flow Equalization and Oil Removal (FEOR) Tanks,122 the most stringent level of
VOC control identified equipping the tanks with a closed vent system and routing the
collected vapors to a combustion device with a VOC destruction efficiency of 99% or
greater. This is the control identified for the proposed FEOR tanks.
As LAER for the proposed wastewater treatment plant units, the following limit is
proposed for VOC:
The two (2) Flow Equalization and Oil Removal Tanks (T-5307A/B) shall be
equipped with a closed vent system that routes collected vapors to a combustion
device with a design VOC destruction efficiency of 99% or greater.
Compliance with this limit shall be determined by testing the combustion device
during normal operation in accordance with a test protocol approved by PADEP.
It should be noted that the site will also operate in compliance with the applicable HAP
control requirements in the Miscellaneous Organic NESHAP or MON (40 CFR 63
Subpart FFFF) and Ethylene MACT (40 CFR 63 Subpart XX). The MON provides
multiple control options for various types of emission points, including process
wastewater and maintenance wastewater streams that contain listed HAPs, when those
streams exit the last recovery device or chemical manufacturing process unit equipment.
The proposed emission limits or operating standards for the above WWTP meet the two
criteria to be considered LAER.
The precedents presented in Table 5-45 represent a composite of the most stringent
emission limitation contained in the implementation plan and the most stringent emission
limitation achieved in practice, for the class or category of source. As a result, both
criteria have been met. The proposed controls are as stringent as the NSPS Part 60
subpart Kb standard. In accordance with 25 Pa. Code §127.205(7), the proposed VOC
122 Oil skimmed from these tanks is directed to the Recovered Oil Tank. VOC controls for this tank are
discussed in Section 5.8.
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LAER limit is equivalent to and satisfies the PaBAT requirements of 25 Pa. Code
§127.12(a)(5).
5.11 Loading Operations
The proposed project includes facilities that will be used to offload of materials used to
support the operation of the facility and loading of products generated by the facility.
Emissions associated with offloading will result from the displacement of gases in the
tanks used to store those materials and from leaks in fugitive components associated with
the offloading facilities. A VOC LAER analysis for each of these emissions points in
included in Sections 5.8 and 5.5, respectively. Particulate emissions will result from the
loading of PE pellets into railcars and truck. VOC emissions will result from the loading
of low vapor pressure organic liquids (i.e., pyrolysis tar, recovered oil, and spent caustic)
and C3+ materials. A PM BACT/LAER analysis for the PE pellet loading operation and
VOC LAER analysis for the low vapor pressure organic liquids and C3+ liquids is
presented below.
5.11.1 Polyethylene Loading PM/PM10/PM2.5 BACT/LAER Analysis
The primary end product of the proposed Project is polyethylene (PE) pellets. PE pellets
will be shipped from the facility via both truck and rail. Loading will be accomplished
by gravimetric feed through a chute that delivers the material into the truck or railcar.
Loading of PE pellets into transport vehicles could result in emissions of particulate
matter as the pellets flow by gravity from the storage loading silos into the trucks or rail
cars. Displaced air in the empty transport vehicles can entrain some of the dust present in
the pellets, creating the potential for particulate matter emissions from the loading
operations. The displaced air resulting from the loading operations will be vented
through a filter to prevent emissions of any particulate matter that may be entrained in the
air.
This section addresses the control of PM, PM10, and PM2.5 emissions from the PE loading
operations. The proposed project is located in an area that is classified as nonattainment
with regards to the annual PM2.5 standard. As a result, a LAER analysis is required for
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all of the project’s sources of PM2.5. No applicable PM standards have been promulgated
for PE Loading operations under 40 CFR parts 60 and 61.
The PM2.5 that will be emitted from the PE loading operation will be filterable PM. As a
result, the control technologies applicable to the control of PM2.5 are the same as the
technologies available for controlling emissions of PM and PM10. For purposes of this
analysis, it is assumed that the PM2.5 LAER analysis will meet the requirements of BACT
for PM10 and PM. 123 Application of LAER is estimated to limit annual loadout
particulate emissions to less than 0.1 tons/yr.
5.11.1.1 Step 1: Identify PE Loading PM Controls
The only PM control option identified for application to the PE truck and rail car loading
operations is routing of the displaced air through a filter that would remove entrained
particulate matter from the air stream. The only similar emissions source identified
through a search of U.S. EPA’s RBLC database is the PE loading operation at the
Chevron Phillips polyethylene plant that will be located in Sweeny, Texas (RBLC ID
TX-0631). The BACT emissions limit applicable to the Chevron Phillips railcar loading
operation is 0.01 gr/scf.
5.11.1.2 Step 2: Eliminate Technically Infeasible Controls
Venting of the PE pellet loading operations through a filter is a feasible control option.
For PE loading, this control is typically accomplished by installing a filter on an open
hatch on the vehicle being loaded such that the displaced air vents through the filter. This
control method provides a high level of capture and control of any entrained particulate
matter generated by the loading operation and is technically feasible for application to the
PE loading operations at the proposed Project.
123 This assumption is appropriate given the low level of emissions that result from application of a LAER
limit to this source.
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5.11.1.3 Step 3: Establish PE Loading PM BACT/LAER
The proposed emission limits or operating standards for the PE pellet loading operation
meet the two criteria to be considered LAER. To address the first criterion, a survey was
conducted of particulate matter emissions limits contained in state implementation plans
for those jurisdictions most likely to have the most stringent emission limits was
performed (i.e., air rules applicable to serious PM10 nonattainment areas).124 The results
of this review, summarized in Table 5-46, indicate that the applicable rules found at 25
Pa. Code §§ 123.13 and 123.41 are as restrictive as those in any of the other jurisdictions
reviewed. The applicable PA rules limit PM emissions from this process to 0.04 gr/dscf
and visible emissions to 20% opacity.
Table 5-46. Summary of the State Implementation Plan Review for Loading
Operations PM Requirements
Jurisdiction Rule Citation Pollutant Applicable Emissions
Limit
Clark County, NV
CCAQR Sec. 26 Visible
Emissions
20% opacity
CCAQR Sec. 27 PM Process Weight Rate
East Kern County,
CA
EKCAPCD Rule
401
Visible
Emissions
20% opacity
EKCAPCD Rule
404.1
PM 0.1 gr/scf
EKCAPCD Rule
405
PM Process Weight Rate
Maricopa County,
AZ
MCAQD Rule
310.303
Visible
Emissions
20% Opacity
MCAQD Rule
311.301
PM Process Weight Rate
Pennsylvania
25 Pa. Code
§123.13
PM 0.04 gr/scf
25 Pa. Code
§123.41
Visible
Emissions
20% Opacity
124 As of 12/5/2013 U.S. EPA’s Green Book listed the following serious PM10 nonattainment areas: Clark
County, Nevada; Coachella Valley, CA; East Kern Co, CA; Imperial Valley, CA; Owens Valley, CA;
Phoenix, AZ; and Washoe Co, NV. In general, PM2.5 regulations applicable to specific source
categories have not been developed. Thus, source-specific regulations limiting PM or PM10 were
surveyed as well.
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To address the second criterion, BACT precedents were evaluated. A review of U.S.
EPA’s RBLC database identified a limit of 0.01 gr/dscf as the lowest limit achieved in
practice for this class or category of source. In addition, Texas’ BACT guidance for
polyethylene facilities identifies a particulate mass loading limit of 0.01 gr/scf as BACT
for particulate emitting sources in polyethylene plants. Similarly, potentially applicable
BACT guidance from the BAAQMD in California limits emissions to 0.01 gr/dscf.
Based on these reviews, a LAER limit equal to 0.01 gr/dscf fulfills the requirement to
address the second criterion used in determining LAER. Thus, LAER for the PE pellet
loading operations is appropriately based on the application of a loadout system that
vents the displaced air through a filter and the LAER PM2.5 emissions limit for this filter
is 0.01 gr/dscf.
Given the low rate of particulate emissions from the PE loadout operations (i.e., less than
0.1 tons per year), the PM/PM10 BACT limit would be 0.01 gr/dscf. In other words, there
are no more effective controls that could be considered that would not have adverse
economic impacts relative to the control provided by complying with the identified
LAER limit.
Because it is not feasible to test emissions from the PE loading operations, Shell proposes
that a design and work practice be established as BACT/LAER. Specifically, Shell
proposes a design standard requiring the use of filter material specified to limit
PM/PM10/PM2.5 emissions to no more than 0.01 gr/dscf for the PE loading application,
that PE pellets only be loaded into vehicles when the displaced air is vented through such
a filter, and that loading be terminated at any time visible emissions from the loading
operation are observed.
As previously noted no applicable PM standards have been promulgated for PE Loading
operations under 40 CFR parts 60 and 61. In accordance with 25 Pa. Code §127.205(7),
the proposed PM BACT/LAER limits are equivalent to and satisfies the PaBAT
requirements of 25 Pa. Code §127.12(a)(5).
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5.11.2 VOC LAER Analysis For Liquids Loading Operations
A small amount of VOC may be emitted as liquid products/byproducts from the proposed
project are loaded into transport vehicles. This LAER analysis addresses emissions from
loading of the following liquids into transport vehicles:
Pyrolysis tar (i.e., pitch or ethylene cracker residue);
Recovered oil;
Spent caustic; and
C3+ byproduct (i.e., a mixture of propane, butane, etc.).
Note that any VOC emissions that may be emitted from PE pellet loading are addressed
in Section 5.8 of this control technology review. No applicable VOC standards have
been promulgated for liquid loading operations under 40 CFR parts 60 and 61.
5.11.2.1 Source Descriptions
Pyrolysis tar or pitch is a low vapor pressure organic liquid that is produced during the
manufacture of ethylene in a steam cracking process.125 An estimated 50 to 60 thousand
barrels per year of pyrolysis tar will be produced at the proposed plant. This organic
liquid will be stored in an insulated and heated fixed roof tank and from storage, loaded
into trucks and/or railcars for shipment offsite. Based on an annual production rate of
60,000 barrels and the proposed LAER limits in this analysis, potential VOC emissions
from this operation are estimated to be 1.4 tons per year.
Recovered oil is also a low vapor pressure organic liquid produced during the cracking
process. It is recovered from the process wastewater in the wastewater treatment plant.
An estimated 5,000 barrels per year of recovered oil will be produced by the proposed
Project. This organic liquid will be stored in an internal floating roof tank that vents to a
control device, and from the storage tank, loaded into trucks and/or railcars for shipment
offsite. Based on an annual production rate of 5,000 barrels and the proposed LAER
125 The term “low vapor pressure organic” is used in this LAER analysis to denote a liquid with a maximum
true vapor pressure of less than 0.5 psia. The term “high vapor pressure” is used to denote a liquid with
a maximum true vapor pressure in excess of 14.7 psia.
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limits in this analysis, potential VOC emissions from this operation are estimated to be
0.1 tons per year.
An estimated 12,000 barrels per year of spent caustic solution will be produced by the
proposed Project. Spent caustic solution is a byproduct of the ethylene manufacturing
process. A caustic (i.e., sodium hydroxide) solution is used to scrub product gases to
remove H2S from those gases. Some organic compounds are also scrubbed in the process
giving the resulting aqueous spent caustic solution a vapor pressure, somewhat higher
than that of fresh caustic, due to entrained organic compounds.
The project is currently considering two options related to spent caustic: 1) on-site
regeneration where the stripped VOC will be directed to a Spent Caustic Vent Incinerator
(see Section 5.12) or 2) shipment off-site.
If the option to ship the spent caustic off-site is chosen, the aqueous spent caustic stream
containing entrained hydrocarbon will be loaded via hoses into trucks or railcars for
shipment offsite. The presence of organic compounds in the spent caustic makes the
loading of spent caustic a potential source of VOC emissions and this material will be
controlled as if it was a low vapor pressure organic liquid. Based on an annual spent
caustic production rate of 12,000 barrels and the proposed LAER limits in this analysis,
potential VOC emissions from this operation are estimated to be less than 0.3 tons per
year.
C3+ is a high vapor pressure organic liquid produced during the ethylene cracking
process. An estimated 1.3 million barrels per year of C3+ liquids will be produced at the
proposed plant. This organic liquid will be stored in pressure spheres with no vents to
atmosphere. From storage, C3+ will be loaded into pressurized transport vehicles (i.e.,
trucks and/or railcars) for shipment offsite. All VOC emissions from the vehicle loading
operations are fugitive. These VOC emissions are estimated to total 13 tons per year.
The low vapor pressure organic liquids produced at the proposed plant are distinctly
different from the C3+ (i.e., high vapor pressure) liquids in physical and chemical
characteristics and in the equipment and techniques used to store, transfer, and transport
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these materials. These materials are also subject to distinctly different regulatory
requirements. Thus, the LAER analysis for these loading operations evaluates the
loading activities for low vapor pressure organic liquids and the C3+ liquid as two
distinct categories.
5.11.2.2 VOC LAER Analysis for Low Vapor Pressure Organic Liquids
This LAER analysis applies to the pyrolysis tar, recovered oil, and spent caustic loading
operations. The proposed emission limits or operating standards for the low vapor
pressure organic liquid loading operations meet the two criteria to be considered LAER.
To address the first criterion, a survey was made of relevant VOC emissions limits and
work practices applied to loading of low vapor pressure organic liquids contained in state
implementation plans and recent PSD permits. The results of this survey are summarized
in Table 5-47 below. In general, loading of low vapor pressure organic liquids is not
specifically regulated under any SIP provisions.
Low vapor pressure organic liquid loadout operations have not been required to be
controlled using add-on control devices in recently issued PSD permits (second LAER
criterion).
Exceptions to this general conclusion include petroleum refineries where the truck
loading operations also include the loading of liquids such as gasoline and/or in cases
where the limit has not been achieved in practice because the permitted facilities have not
yet been constructed. These facilities do not belong to the same class or category as the
low vapor pressure organic liquids loading operations planned for the Project. Based on
this review, the control option that has been applied to the same class or category of
source and that has been achieved in practice is the use of submerged filling coupled with
dedicated service transport vehicles.
Consistent with the appropriate LAER precedents, Shell proposes the following LAER
limits for the low vapor pressure organic liquid loading operations (including spent
caustic, if the option to ship spent caustic off-site is chosen) at the Franklin plant:
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Table 5-47. Summary of the State Implementation Plan Review for Loading
Operations VOC Requirements for Loading of Low Organic Vapor Pressure Liquid
Jurisdiction Rule Citation /
RBLC ID Pollutant Applicable Limit
South Coast, CA SCAQMD Rule 462 VOC None for liquids with Vp <1.5 psia.
Bay Area, CA BAAQMD Reg. 8,
Rule 6 VOC None for liquids with Vp < 0.5 psia.
Texas (TCEQ) Subchapter C,
§115.211 VOC None for liquids with Vp < 0.5 psia.
Arizona (ADEQ) AZ-0046 VOC
Thermal oxidizer w/ no specific
limit.
Limit not achieved in practice
because this facility has not been
constructed.
Louisiana (LDEQ) LA-0212 VOC None for liquids with Vp < 1.5 psia.
Louisiana (LDEQ) LA-0213 VOC None for liquids with Vp < 1.5 psia.
Louisiana (LDEQ) LA-0232 VOC Submerged loading and dedicated
service.
New Mexico
(NDEQ) NM-0050 VOC
10 mg VOC/L of liquid loaded.
Unclear if this applies to low-Vp
liquids.
Ohio (OEPA) OH-0317 VOC
0.06 lb VOC/Mgal naptha loaded.
0.01 lb VOC/Mgal diesel loaded.
Limit not achieved in practice
because this facility has not been
constructed.
Virginia (VDEQ) VA-0313 VOC
10 mg VOC/L of gasoline loaded.
No limit on distillate, residual or
lube oil (i.e., low-vapor pressure
liquids) loading.
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The maximum true vapor pressure of the low vapor pressure organic liquids
loaded shall not exceed 0.5 psia;
Submerged filling or bottom loading shall be used for loading of all low vapor
pressure organic liquids into transport vehicles; and
All transport vehicles loaded shall either be in dedicated service or shall be
cleaned prior to loading.
As previously note, no applicable VOC standards have been promulgated for liquid
loading operations under 40 CFR parts 60 and 61. In accordance with 25 Pa. Code
§127.205(7), the proposed VOC LAER limit is equivalent to and satisfies the PaBAT
requirements of 25 Pa. Code §127.12(a)(5).
5.11.2.3 VOC LAER Analysis for C3+ Liquids
For purposes of the C3+ liquid LAER analysis, Shell conducted a review of SIP rules and
permits applicable to loading of LPG, since the C3+ liquid and LPG loading operations
have similar characteristics. The results of this review are summarized in Table 5-48.
Shell did not identify any recent PSD permits that establish emissions limits for C3+ or
LPG loading operations.
Based on the above review, it appears that the most restrictive “limits” applicable to the
same class or category of source are the use of pressurized loading (Texas) and the use of
low-leak fittings with no visible leaks (Louisiana). The use of vapor balance/recovery is
less effective than pressurized loading due to the potential for additional leakage from the
vapor balance system. In addition, it is unclear whether vapor balanced loading is even
feasible with pressurized liquids. Because any emissions from the C3+ loading are
considered fugitive, it is appropriate to establish design/work practices in lieu of a
specific emissions limit. Thus, based on the most stringent achievable limits, this
analysis concludes that LAER for the C3+ liquid loading is a design standard requiring
low-leak couplings and pressurized loading of the C3+ liquids. In terms of the low-leak
couplings, this analysis proposes to use OPW’s Drylok™ Dry Disconnect Coupling or
equivalent. These couplings minimize leakage associated with disconnecting pressurized
hoses after loading of transport vehicles. In accordance with 25 Pa. Code §127.205(7),
the proposed VOC LAER limit is equivalent to and satisfies the PaBAT requirements of
25 Pa. Code §127.12(a)(5).
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Table 5-48. Summary of the State Implementation Plan Review for Loading
Operations VOC Requirements for Loading of C3+ or LPG
Jurisdiction Rule Citation /
RBLC ID Pollutant Applicable Limit
South Coast, CA
SCAQMD Rule 462 VOC Not applicable to LPG loading.
SCAQMD Rule 1177 VOC Not applicable to facilities that produce
LPG.
SCAQMD Rule 1173 VOC
Applicable to leaks and releases. No
specific requirement applicable to
loading operations.
Bay Area, CA BAAQMD Reg. 8,
Rule 6 VOC Not applicable to LPG loading.
Texas (TCEQ) Subchapter C,
§115.212 VOC
Requires vapor control, vapor balance
or pressurized loading.
Louisiana
(LDEQ) LAC 33:III.2107 VOC
Requires vapor recovery to storage
tank or control device plus low-leak
fittings and no visible leaks.
5.12 VOC Control Systems
The proposed project includes four systems that will be used to gather and control VOC
emissions during normal operation, startup, shutdown, and unforeseeable events at the
facility as follows:
High Pressure (HP) Header System (HP System),
Low Pressure (LP) Header System (LP System,
Ethylene Refrigerated Storage Relief System, and
Spent Caustic Vent Incinerator.
The HP System will be used to control VOC emissions resulting from startup, shutdown,
maintenance, and unforeseeable (i.e., upsets and malfunctions) events at the ethane
cracking unit and the polyethylene units. The HP System comprises two enclosed ground
flares, one elevated flare and ancillary equipment such as knockout pots. The elevated
flare (HP Elevated Flare) will be a secondary system used only when the combined
capacity of the two ground flares (HP Ground Flares) is exceeded due to a major facility
upset or malfunction (e.g., power failure).
The following VOC containing streams will be directed to the LP System, which includes
the LP Thermal Incinerator and LP Ground Flare:
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Continuous and intermittent VOC containing gases vented from the PE process
vents in accordance with the VOC LAER proposal in Section 5.7.1.3 and
specifically defined in Table D-4 of Appendix D;
Tank emission control systems as defined by the VOC LAER proposal in
Section 5.8.4;
VOC containing streams generated during product grade changes;
VOC containing streams generated during startup and shutdown of the three PE
manufacturing units;
VOC containing streams resulting from maintenance activities at the three PE
manufacturing unit; and
VOC containing streams generated during an upset or malfunction.
The gases in the LP System will be directed to the LP Thermal Incinerator whenever
there is capacity available in the incinerator. When the incinerator’s capacity is exceeded
due to an upset or malfunction, the excess gases will be directed to the LP Ground Flare.
The Ethylene Refrigerated Atmospheric Storage Relief system will be dedicated to
controlling emissions from ethylene refrigerated atmospheric storage tank startup,
shutdown, and emergency release. The Spent Caustic Vent Incinerator will be used to
control VOC and reduced sulfur compound emissions in the spent caustic oxidation unit
offgas and from the WWTP flow equalization and oil removal (FEOR) tank vents. The
Spent Caustic Vent Incinerator will be in a very different service than the LP Thermal
Incinerator. While the LP Thermal Incinerator will see high concentration VOC
containing streams that are easily combusted without the need of significant quantities of
supplemental fuel, the VOC containing offgas from the Spent Caustic oxidation unit and
the WWTP FEOR tank vents will have a much lower VOC concentration and require
significant amounts of supplemental fuel on a relative basis.126 In addition, there is the
chance for caustic carryover from the spent caustic oxidation unit, which restricts the
incinerator type to a flame-based system. As a result, the LP Thermal Incinerator is a
different category of emissions source than the Spent Caustic Vent Incinerator.
126 The vent stream composition is predominately moisture and air (i.e., 99.7 percent) with trace quantities
of VOC and H2S.
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The HP and LP systems will be designed such that the foreseeable events are combusted
in the most efficient control device. In the HP System the ground flares, which are the
more efficient control device, will be used to control VOC containing streams associated
with foreseeable events. In the LP system, the LP Thermal Incinerator, which is the more
efficient control device, will be used to control foreseeable VOC containing streams
associated with operation of the PE units. In general, the two elevated flares in the HP
and LP systems will be used during unforeseeable events.
The primary purpose of each of the VOC control systems reviewed in this section of the
LAER analysis will be efficient combustion of VOC-containing gases generated at the
facility due to routine operation as well as planned and unplanned infrequent events. As
a result, the control technology analysis focuses on: (1) minimizing the production of
those gases; and (2) ensuring efficient combustion of the gases that are generated. As
discussed in Section 5.12.2, control of the secondary pollutants (i.e., NOx/ NO2,
PM/PM10/PM2.5, CO, and GHGs that are formed as byproducts of thermal
incinerator/flare operation) will be achieved by minimizing the amount of gas that is
combusted.
5.12.1 VOC Control Systems LAER Analyses
Incomplete combustion of the gases directed to the VOC control systems results in VOC
emissions. The proposed project is located in an area that is classified as nonattainment
for ozone, for which VOC is a defined precursor. As a result, the VOC control systems
are subject to LAER.
For VOC emissions, there are several potentially applicable NSPS and NESHAP rules
that would require any continuously or periodically generated vent gas streams to be
controlled, including subparts VV, VVa, DDD, NNN and RRR of 40 CFR 60 and
subparts YY, SS, UU, and FFFF of 40 CFR 63. Each of the NSPS and NESHAP rules
require a defined control efficiency of 95 to 98% or compliance with design/work
practice requirements at 40 CFR §60.18 (NSPS) or 40 CFR §63.11 (NESHAP) if a flare
is used. The specifications at 40 CFR §60.18 and 40 CFR §63.11 establish a floor with
respect to the LAER analysis.
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5.12.1.1 Step 1: Identify VOC Control System Precedents
Summary results from a review of precedents and requirements identified for flares in the
RBLC database, permits, EPA/DOJ consent decrees, and State Implementation Plan
(SIP) requirements and regulations are presented in Table 5-49. As shown, the identified
flaring related control options used to minimizing VOC emissions are work practices and
equipment design elements that will: (1) minimize the quantity (i.e., mass) of the gases
directed to the combustion devices within these systems and (2) maximize the VOC
destruction efficiency of the flare. The following specific measures are included:
Compliance with the design and operating requirements of 40 CFR §60.18
maximum exit velocity and net heat content of the vent gas;
Using flare gas recovery systems;
Instrumentation and control required for automated control of the net heating
value of the gases in the combustion zone
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Table 5-49. Summary of RBLC and Other Flare Related Permitting Precedents and Regulatory Requirements
Facility
Instrumentation &
Monitoring Waste Gas Minimization Combustion Efficiency
Flaring
Limits
NHVcz 2
(Btu/scf)
Ethylene Manufacturing
ExxonMobil Baytown
Olefins Plant
Elevated flare (EF) &
Multi-point ground
flare (MPGF)
pilot thermocouple
or an infrared
monitor
continuous flow
monitor and
composition
analyzer
gas net heating value
and actual exit
velocity determined
Not specified 40 CFR §60.18
No visible emissions
The flare shall be
operated with a flame
present at all times
and/or have a constant
pilot flame
lb/hr &
tpy for:
NOx, SO2,
CO,
&VOC
Chevron/Phillips Cedar
Bayou Plant Flares
pilot thermocouple
or an infrared
monitor
continuous flow
monitor and
composition
analyzer
gas net heating value
and actual exit
velocity determined
Not specified 40 CFR §60.18
No visible emissions
The flare shall be
operated with a flame
present at all times
and/or have a constant
pilot flame
lb/hr &
tpy for:
NOx, SO2,
CO, VOC
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Facility
Instrumentation &
Monitoring Waste Gas Minimization Combustion Efficiency
Flaring
Limits
NHVcz 2
(Btu/scf)
Equistar Channelview
Plant OP-1 furnace
addition
Flares
pilot thermocouple
or an infrared
monitor
Not specified 40 CFR §60.18
No visible emissions
The flare shall be
operated with a flame
present at all times
and/or have a
constant pilot flame
99.5% control
lb/hr &
tpy for:
NOx, SO2,
CO, VOC
Equistar Channelview
Plant OP-2 furnace
addition
Flares
pilot thermocouple
or an infrared
monitor
gas net heating value
and actual exit
velocity determined
None specified 40 CFR §60.18
No visible emissions
The flare shall be
operated with a flame
present at all times
and/or have a constant
pilot flame
lb/hr &
tpy for:
NOx, SO2,
CO, VOC
PE Manufacturing
ExxonMobil Beaumont
Polyethylene Plant
Air Assisted (AA) and
Ground (G) Flares
pilot thermocouple
or an infrared
monitor
continuous flow
monitor and British
thermal unit (Btu)
analyzer
Maintenance venting from
each Low Pressure Reactor
are limited to 20 ventings
per year.
40 CFR §60.18
No visible emissions
The flare shall be
operated with a flame
present and have a
constant pilot flame.
The Air-Assisted Flare
destruction efficiency
AA & G
Flares:
lb/hr &
tpy for:
NOx, SO2,
CO, VOC
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-220
Facility
Instrumentation &
Monitoring Waste Gas Minimization Combustion Efficiency
Flaring
Limits
NHVcz 2
(Btu/scf)
gas net heating value
and actual exit
velocity determined
of 99.5 percent for
carbon compounds with
a carbon number of one
through four and 98
percent for carbon
compounds with a
carbon number of five
or greater.
The Ground Flare
destruction efficiency
of 99 percent for carbon
compounds with a
carbon number of one
through three and 98
percent for carbon
compounds with a
carbon number of four
or greater.
ExxonMobil Mont
Belvieu Plastics Plant
Elevated flare (EF) &
Multi-point ground
flare (MPGF)
pilot thermocouple
or an infrared
monitor
continuous flow
monitor and
composition
analyzer
None specified EF & MPGF:
40 CFR §60.18
No visible emissions
The flare shall be
operated with a flame
present at all times
and/or have a constant
pilot flame
MPGF:
>99.5% DRE
EF &
MPGF:
lb/hr &
tpy for:
NOx, SO2,
CO, VOC
MPGF:
lb/hr &
tpy for:
PM/PM10
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-221
Facility
Instrumentation &
Monitoring Waste Gas Minimization Combustion Efficiency
Flaring
Limits
NHVcz 2
(Btu/scf)
gas net heating value
and actual exit
velocity determined
>800 Btu/scf /PM2.5
Chevron/Phillips Sweeny
Complex pilot thermocouple
or an infrared
monitor
continuous flow
monitor and
composition
analyzer
gas net heating value
and actual exit
velocity determined
None specified 40 CFR §60.18
No visible emissions
The flare shall be
operated with a flame
present at all times
and/or have a constant
pilot flame
lb/hr &
tpy for:
NOx, SO2,
CO, VOC
Consent Decrees
Shell Deer Park Refining
Consent Decree
Vent gas flow
monitoring
Vent gas MW 1
Steam flow rate
Steam control
equipment
Gas chromatograph
(regular use flares)
Net heating value
(temporary-use
flares)
Video camera
Pilot gas rate
Initial WGMP submittal
Characterize waste gas
Baseload waste gas rate
Identify constituents
Waste gas mapping
Planned reductions
Prevention measures
First Update WGMP
Updated mapping
Reductions based on root
cause
Subsequent Updates -
Root cause anal. & corrective
No visible emissions
Pilot monitoring
40 CFR §60.18
monitoring
Automated control of
steam and supplemental
gas
Operate in accordance
with design
Net heating value of
vent gas (NHVvg)
Momentum Flux Ratio
(MFR)
Yes
refinery
wide
w/FGR 4
355
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-222
Facility
Instrumentation &
Monitoring Waste Gas Minimization Combustion Efficiency
Flaring
Limits
NHVcz 2
(Btu/scf)
(optional) action implementation
Shell Deer Park Olefins
Consent Decree
Vent gas flow
monitoring
Vent gas MW 1
Steam flow rate
Steam control
equipment
Gas chromatograph
(regular use flares)
Net heating value
(temporary-use
flares)
Video camera
Pilot gas rate
(optional)
Initial WGMP submittal
Characterize waste gas
Baseload waste gas rate
Identify constituents
Waste gas mapping
Planned reductions
Prevention measures
First Update WGMP
Updated mapping
Reductions based on root
cause
Subsequent Updates -
Root cause anal. & corrective
action implementation
No visible emissions
Pilot monitoring
40 CFR §60.18
monitoring
Automated control of
steam and supplemental
gas
Operate in accordance
with design
Net heating value of
vent gas (NHVvg)
Momentum Flux Ratio
(MFR)
No 500 3
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-223
Facility
Instrumentation &
Monitoring Waste Gas Minimization Combustion Efficiency
Flaring
Limits
NHVcz 2
(Btu/scf)
Marathon Petroleum
Consent Decree
Vent gas flow
monitoring
Vent gas MW 1
Steam control
equipment
Steam flow rate
Gas chromatograph
Video camera
Pilot gas rate
(optional)
Initial WGMP submittal
Characterize waste gas
Baseload waste gas rate
Identify constituents
Waste gas mapping
Planned reductions
Prevention measures
First Update WGMP
Updated mapping
Reductions based on root
cause
Subsequent Updates -
Root cause anal. & corrective
action implementation
No visible emissions
Pilot monitoring
40 CFR §60.18
monitoring
Automated control of
steam and supplemental
gas
Operate in accordance
with design
Net heating value of
vent gas (NHVvg)
Momentum Flux Ratio
(MFR)
Yes by
flare
w/FGR 4
Based on
vent gas
VOC
content 3
BP Whiting Refinery
Consent Decree
Vent gas flow
monitoring
Vent gas MW 1
Steam flow rate
Gas chromatograph
(regular use flares)
Video camera
Pilot gas rate
(optional)
Initial WGMP submittal
Characterize waste gas
Baseload waste gas rate
Identify constituents
Waste gas mapping
Planned reductions
Prevention measures
First Update WGMP
Updated mapping
Reductions based on root
cause
Subsequent Updates -
Root cause anal. & corrective
No visible emissions
Pilot monitoring
40 CFR §60.18
monitoring
Automated control of
steam and supplemental
gas
Operate in accordance
with design
Net heating value of
vent gas (NHVvg)
Momentum Flux Ratio
(MFR)
Yes
refinery
wide
w/FGR 4
Based on
vent gas
VOC
content 3
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-224
Facility
Instrumentation &
Monitoring Waste Gas Minimization Combustion Efficiency
Flaring
Limits
NHVcz 2
(Btu/scf)
action implementation
Country Mark Refining
Consent Decree
Vent gas flow
monitoring
Vent gas MW 1
Steam flow rate
Gas chromatograph
(regular use flares)
Video camera
Pilot gas rate
(optional)
Initial WGMP submittal
Characterize waste gas
Baseload waste gas rate
Identify constituents
Waste gas mapping
Planned reductions
Prevention measures
First Update WGMP
Updated mapping
Reductions based on root
cause
Subsequent Updates -
Root cause anal. & corrective
action implementation
No visible emissions
Pilot monitoring
40 CFR §60.18
monitoring
Automated control of
steam and supplemental
gas
Operate in accordance
with design
Net heating value of
vent gas (NHVvg)
Yes
refinery
wide
Based on
vent gas
VOC
content 3
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-225
Facility
Instrumentation &
Monitoring Waste Gas Minimization Combustion Efficiency
Flaring
Limits
NHVcz 2
(Btu/scf)
State SIP Requirements and Regulations
BAAQMD Rule 12 Flares
at Petroleum Refineries The owner or
operator of a flare
subject to this rule
with a water seal
shall continuously
monitor and record
the water level and
pressure of the water
seal that services
each flare.
Continuously
monitor volumetric
flow
Flare gas
composition
monitoring
Pilot monitoring
Video monitoring
Flaring is prohibited unless it
is consistent with an approved
FMP and all commitments
due under that plan have been
met.
Evaluate flaring that has
occurred during planned
major maintenance
activities, including startup
and shutdown, and the
feasibility of performing
these activities without
flaring.
Evaluate flaring caused by
the recurrent failure of air
pollution control equipment,
process equipment, or a
process to operate in a
normal or usual manner,
and consider the adequacy
of existing maintenance
schedules and protocols.
SCAQMD Rule 1118
Control of Emissions
from Refinery Flares
Gas flow
Gas higher heating
value
Conduct a Specific Cause
Analysis for any flare event,
Operate all flares in such a
manner that minimizes all
Maintain a pilot flame
present at all times a
flare is operational.
Operate all flares in a
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-226
Facility
Instrumentation &
Monitoring Waste Gas Minimization Combustion Efficiency
Flaring
Limits
NHVcz 2
(Btu/scf)
flaring and that no vent gas
is combusted except during
emergencies, shutdowns,
startups, turnarounds or
essential operational needs.
Develop Flare Minimization
Plan if cannot meet specific
SO2 emission requirements.
smokeless manner with
no visible emissions
TCEQ Title 30, Part 1,
Chapter 115, Subchapter
B, Division2 Vent Gas
Controls, rule 115.121
Flares 40 CFR
60.18
None specified Control efficiency of at
least 98% or to a
volatile organic
compound (VOC)
concentration of no
more than 20 ppmv
TCEQ Chemical Sources
Current Best Available
Control Technology
(BACT) Requirements
Flares and Vapor
Combustors
Flares:
flow
Btu
None specified Flares
40 CFR 60.18
99% for certain
compounds up to three
carbons, 98% otherwise
1. MW = molecular weight
2. NHVcz = Net heating value of the combustion zone
3. Net Heating Value for hydrogen shall be equal to 1212 BTU/scf when determining the NHVcz.
4. FGR = Flare gas recovery
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
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The use of waste gas minimization plans (WGMPs) to minimize emissions during
startup and shutdown;
Operate the flare system in accordance with a required net heating value in the
combustion zone.
Summary results from a review of the precedents identified for thermal incinerators in the
RBLC database, a recent Texas permit, and State Implementation Plan (SIP)
requirements and regulations are presented in Table 5-50. As shown, the incinerator
requirements are directed at defining a design that will achieve the required destruction
efficiency and operating conditions (e.g., operating temperatures) that ensure the desired
destruction efficiency.
5.12.1.2 Step 2: Achieved VOC Control System Work Practices and Limits
Each of the identified control options, except use of a flare gas recovery system, is
technically feasible and is inherent in the design of the proposed Project’s VOC control
systems. Flare gas recovery systems are only feasible at large integrated petrochemical
facilities where the recovered gas can be combined with other gases and used as fuel. As
discussed below, this is not technically feasible for the proposed Project.
Ethylene Manufacturing: As part of the ethylene manufacturing process, tailgas will be
recovered and used as fuel in the cracking furnaces. During normal operation of the
cracking unit, no routine vent gases other than analyzer vents and pressure relief valve
leakage will be directed to the HP System. As a result, during normal operations there
will be little or no VOC gas to recover using a flare gas recovery system. The start-up
and shutdown release of VOC gases to the HP System will be infrequent and primarily
composed of ethylene. The use of a flare gas recovery system to recover routine vent
gases beyond what is recovered as tailgas and routing of these gases to a process or to a
fuel gas system is not technically feasible for the proposed facility.
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
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Table 5-50. Summary of RBLC Incinerator Related Permitting Precedents
Facility Instrumentation &
Monitoring Waste Gas
Minimization Combustion Efficiency Incinerator Limits 1
ExxonMobil Mont Belvieu
Plastics Plant RTO & Flameless
Thermal Oxidizer (FTO)
RTO:
exit temperature shall
be continuously
monitored
FTO:
exit temperature shall
be continuously
monitored
None specified RTO:
99% VOC control or
outlet VOC
concentration of less
than 10 ppmv
FTO:
99.99%
RTO:
Maintain a minimum of 1400°F
lb/hr & tpy limits for: VOC,
NOx, CO, SO2,
PM/PM10/PM2.5
FTO:
Maintain a minimum of 1400°F
lb/hr & tpy limits for: VOC,
NOx, CO, SO2,
PM/PM10/PM2.5
Owens Corning Medina
Asphalt Roofing Plant
(OH-0288)
Thermal Incinerator
continuous temperature
monitor
None specified 95% For any 3-hour block of time
when the emissions unit is in
operation, shall not be less than
1450 oF
lb/hr & tpy limits for: VOC,
NOx, CO, SO2, PM Formosa Specialty PVC
Plant
(TX-0508)
Incinerators/Scrubbers
continuous temperature
monitor
O2 monitor
None specified 99.95% Minimum firebox temperature
set by testing
Minimum standby firebox
temperature of 800 oF
lb/hr & tpy limits for: VOC,
NOx, CO, SO2
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-229
Facility Instrumentation &
Monitoring Waste Gas
Minimization Combustion Efficiency Incinerator Limits 1
State SIP Requirements and Regulations
TCEQ Title 30, Part 1,
Chapter 115, Subchapter
B, Division2 Vent Gas
Controls, rule 115.121
Incinerator exhaust gas
temperature
None specified Control efficiency of
at least 98% or to a
volatile organic
compound (VOC)
concentration of no
more than 20 ppmv
TCEQ Chemical Sources
Current Best Available
Control Technology
(BACT) Requirements
Flares & Vapor
Combustors
Temperature None specified 99%
1. Sufficient information was not found in RBLC and the permits to put the lb/hr and tpy emission limits on a standard unit basis (e.g.,
lb/MMBtu).
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
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Capture and recovery of ethylene for use as a fuel gas at the Cogen Units is not
technically feasible because ethylene has very different combustion characteristics (e.g.,
adiabatic flame temperature, flame velocity and heat release rate) 127 than tailgas
(primarily hydrogen and methane), and natural gas (primarily methane with lesser
amounts of ethane and propane). The cracking furnaces will be designed to efficiently
and cleanly combust tailgas and natural gas. The Cogen Units will be designed to burn
natural gas. As a result, use of either the furnaces or Cogen Units to combust ethylene
would result in 1) damage to the burners due to ethylene’s high heat release and 2) burner
fouling due to the formation of polymerization residue.128 Furthermore, the combustion
turbines will use dry low NOx combustors, which must be designed for a particular fuel
type. It is not possible to design a dry low NOx combustor to burn both natural gas and
ethylene due to the dissimilarity in the combustion characteristics.
During startup and shutdown, the capture and recovery of cracking furnace product gas
for use as a feedstock is not technically feasible because the low purity of the captured
gases. The recovered furnace product gases would contain ethane, ethylene, propylene
and acetylene. The furnaces require high purity ethane to produce desirable product (i.e.,
ethylene). Using these startup/shutdown gases as a cracking furnace feedstock would
result in rapid coking of the cracking furnace process tubes.
PE Manufacturing: The PE units will have continuous and intermittent process vents
that will be directed to the LP system. These vents contain significant amounts of
diluents (i.e., air and nitrogen) that make their capture and recovery for use as fuel
infeasible. If a vent gas containing a significant amount of nitrogen is mixed with
another fuel, the heat content of that stream is reduced. This in turn results in a fuel that
has different combustion characteristics. Unlike the cracking furnaces and Cogen Units,
127 The heat content of ethylene is 1,631 Btu/scf and the adiabatic flame temperature is ~2010 oC. The heat
content of methane is 1,011 Btu/scf and the adiabatic flame temperature is 1950 oC. 128 Polymerization residues form when ethylene is combusted in a combustion device not designed to
combust ethylene. The products of incomplete combustion are sticky and polymerize at or near the point
of combustion (i.e., the burner).
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-231
the LP System’s incinerator will be designed to combust vent gases with significant
amounts of diluents with highly variable combustion characteristics.
Releases of hydrocarbons to the LP System during startup, shutdown, maintenance, and
unforeseeable events will be intermittent and infrequent. Additionally, as noted above,
the captured gases, mostly ethylene, are not suitable for use as fuel at the proposed
facility, where the combustion units (i.e., cracking furnaces and Cogen Units) will be
designed to combust clean burning tailgas and natural gas. As such, a flare gas recovery
system is not technically feasible for the LP System.
Recovered ethylene from the PE units during startup, shutdown, or malfunction would
contain catalyst, other reaction chemicals and polyethylene. Introducing these
contaminants into the PE unit feed would result in off specification polyethylene.
As noted above, the gases in the LP System will be routed to the LP Thermal Incinerator
whenever there is capacity available in tis incinerator. When the incinerator’s capacity is
exceeded due to an upset or malfunction, the excess gases will be directed to the LP
ground flare. The LP Thermal Incinerator will be sized and designed to ensure a
residence time in the incinerator and operating temperature that results in a high
destruction efficiency (i.e., >99.5%) when combusting the routinely generated vent gases
from the PE unit. To accept additional upset and malfunction gases would require an
incinerator with a larger firebox. This larger firebox would result in a loss of efficiency
during the treatment of the routinely generated gases, due to mixing constraints. As a
result, it is not technically feasible to design an incinerator that can both reliably ensure a
high VOC destruction efficiency of the routinely generated gases while having an
adequate size to achieve similar combustion efficiency for the possible gas rates
associated with upsets and malfunctions.
Refrigerated Atmospheric Storage System: This flare will be dedicated to controlling
emissions from ethylene refrigerated atmospheric storage tank startup, shutdown, and
emergency. These events will occur infrequently. As such, a vapor recovery system
would not have anything to recover on a routine basis. Additionally, any recovered
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
5-232
ethylene could not be put in the fuel gas system or as feed to the cracking furnaces for
reasons discussed previously in this subsection.
Spent Caustic Incinerator: This incinerator will be used to control VOC and reduced
sulfur compounds in the spent caustic oxidation unit offgas and from the WWTP FEOR
tank vents. This incinerator will operate continuously. The vent stream composition is
predominately moisture and air (i.e., 99.7 percent) with trace quantities of VOC and H2S.
5.12.1.3 Step 3: Establish VOC Control System Work Practices and Limits
The proposed LAER for VOC emissions from the VOC control systems includes a
combination of emissions limitations, work practice requirements, and equipment design
standards as follows:
The LP Thermal Incinerator and Spent Caustic Vent Incinerator shall be designed
and operated to achieve VOC control efficiencies of 99.5 and 99%, respectively.
The facility will minimize flaring resulting from startups, shutdowns, and
unforeseeable events by operating at all times in accordance with an approved
flare minimization plan. The plan shall include the following elements:
o Procedures for operating and maintaining the HP and LP Systems during
periods of process unit startup, shutdown and unforeseeable events.
o A program of corrective action for malfunctioning process equipment.
o Procedures to minimize discharges either directly to the atmosphere or to
the HP and LP Systems during the planned and unplanned startup or
shutdown of process unit and air pollution control equipment.
o Procedures for conducting root cause analyses.
o Procedures for taking identified corrective actions.
The facility shall conduct a root cause analysis within 45 days after any startup,
shutdown and unforeseeable flaring event. Flaring event shall be defined as an
event that exceeds the baseline by 500,000 scf within a 24 hour period.129 The
analysis shall address the following elements:
o The date and time that the flaring event started and ended.
o The total quantity of gas flared during each event.
o An estimate of the quantity of VOC that was emitted and the calculations
used to determine the quantities.
129 See Shell Deer Park Consent Decree, July 10, 2013, No. 4:13-cv-2009, page 18.
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
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o The steps taken to limit the duration of the flaring event or the quantity of
emissions associated with the event.
o A detailed analysis that sets forth the root cause and all significant
contributing causes of the flaring event to the extent determinable.
o An analyses of the measures that are available to reduce the likelihood of a
recurrence of a flaring event resulting from the same root cause or
significant contributing causes in the future.
o A demonstration that the actions taken during the flaring event are
consistent with the procedures specified in the flare minimization plan.
o In response to a flaring event, the facility shall implement, as
expeditiously as practicable, such interim and/or long-term corrective
actions as are consistent with good engineering practice to minimize the
likelihood of a recurrence of the root cause and all significant contributing
causes of that flaring event.
The flares shall be designed to meet limitations on maximum exit velocity, as set
forth in the general provisions at 40 CFR § 60.18 and § 63.11.
The flares shall be operated to meet minimum net heating value requirements for
gas streams combusted in the flares, as set forth at 40 CFR § 60.18 and § 60.18.
o HP and LP Ground Flares shall be equipped with the following automated
controls:Control of the supplemental gas flow rate to the flare
o Control of the total steam mass flow rate (if applicable) to the flare.
Net Heating Value of Combustion Zone Gas (NHVcz)130
o The HP Flare Header shall be operated such that the NHVcz, on a
three-hour rolling average basis, rolled every fifteen minutes, is equal to or
greater than 500 Btu/scf, using a Net Heating Value for hydrogen of 1212
BTU/scf.
Establishment of equipment design and work practice requirements as LAER is
appropriate in this instance because it is infeasible to apply a measurement methodology
for demonstration of compliance with numeric limits on emissions rates. The
configuration of flare systems renders both manual stack testing and continuous
emissions monitoring systems technically infeasible.
130 Net Heating Value of Combustion Zone Gas” or “NHVcz” shall mean the Lower Heating Value, in
Btu/scf, of the combustion zone gas in a flare and shall be determined in accordance with Appendix 1.3
of the Shell Deer Park Consent Decree, July 10, 2013, No. 4:13-cv-2009.
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
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The proposed emission limits for the VOC control systems must meet two criteria to be
considered LAER. The first criterion is met because the proposed LAER limits and work
practices identified in Table 5-49 and Table 5-50 are equivalent to or go beyond what is
currently required for flares and incinerators in any State implementation plans and
regulations. The second criterion is met because the proposal represents a compilation of
the most stringent limits and work practices in permits and recent consent decrees. Note
the consent decrees were relied on primarily because they provided more detailed
requirements than the permits and State implementation plans and regulations. The
proposed VOC LAER for the VOC Control System is more stringent than the standards
promulgated under 40 CFR Parts 60 and 61. In accordance with 25 Pa. Code
§127.205(7), the proposed VOC LAER limit is equivalent to and satisfies the PaBAT
requirements of 25 Pa. Code §127.12(a)(5).
5.12.2 VOC Control System CO, NOx, PM, and GHG BACT/LAER Analyses
The proposed VOC control systems will be used to safely control routine and non-routine
hydrocarbon venting. The combustion of the hydrocarbons will produce emissions of
CO, NOx, PM, PM10, PM2.5, and GHGs. There are no applicable NSPS or NESHAP
rules that would establish a baseline emission rate for CO, NOx, PM, PM10, PM2.5, or
GHG emissions from the flares and incinerators, although the regulations at 40 CFR parts
60.18 and 63.11 do require smokeless operation of flares, which would affect the amount
of CO and PM emitted.
5.12.2.1 Step 1 – Identify All Control Options
A review of the RBLC database identified the following types of design and work
practices for flares and incinerators:
Work practice/good combustion practices,
Proper equipment design,
Maintain the net heating value of the gas being combusted (e.g., 300 Btu/scf or
greater if the flare is steam-assisted or 200 Btu/scf or greater if the flare is not
assisted),
Shell Chemical Appalachia LLC Plan Approval Application
Beaver County, Pennsylvania Petrochemicals Complex
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Burner design, premix and combustion temperature control,
Proper plant operations,
Comply with 40 CFR parts 60.18 and 63.11, and
Proper maintenance practices.
5.12.2.2 Step 2 – Eliminate Technically Infeasible Control Options
For flares, there are no technically feasible add-on control technologies demonstrated for
the control of CO, NOx, PM, PM10, PM2.5, and GHG emissions. This is because gas flow
rates to flares are highly variable, and the high temperatures required to obtain high
efficiency destruction of the hydrocarbons would damage add-on control technologies
such as oxidation catalyst for CO control, selective catalytic reduction for NOx control or
filters for PM control.
Another control option for condensable PM is through the combustion of low sulfur flare
gases and pilot fuel. The proposed facility will used natural gas for the pilot fuel, and the
vent streams from the cracking facility and PE units will have no sulfur compounds, as
this is a requirement of the manufacturing processes. Trace amounts of sulfur
compounds coming in with the ethane feed stock will be scrubbed out of the ethylene
stream using a caustic wash.
For incinerators, there are no identified add-on control technologies demonstrated for the
control of CO, NOx, PM, PM10, PM2.5, and GHG emissions. One entry in the RBLC
database identified the use of low NOx burners and good combustion practices for
control of NOx.131 Using the available information, NOx emissions were estimated to be
0.2 lb/MMBtu when firing natural gas and 0.3 lb/MMBtu when firing waste gas. As is
the case for flares, the high temperatures required to obtain high efficiency destruction of
the hydrocarbons would damage add-on control technologies.
131 RBLC ID LA-0235 Westlake Vinyls Company Geismar site VCM-E plant.
Shell Chemical Appalachia LLC Plan Approval Application
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5.12.2.3 Steps 3-5: Establish VOC Control System BACT/LAER for CO, NOx, PM/PM10/PM2.5, and GHG
The most effective control options for CO, NOx, PM, PM10, PM2.5, and GHG emissions
from the VOC control systems are the work practices and equipment design elements
identified in Section 5.12.1.3. Each of these control options is technically feasible and is
inherent in the design of the proposed facility. The proposed work practices and
equipment design standards for these pollutants are those proposed for VOC LAER.
For flares, establishment of equipment design and work practice requirements as
BACT/LAER is appropriate in this instance because it is infeasible to apply a
measurement methodology for demonstration of compliance with numeric limits or
emissions rates. The configuration of elevated flare systems renders both manual stack
testing and continuous emissions monitoring systems technically infeasible. Although
stack testing of ground flares is potentially more feasible than testing of an elevated flare,
“infield” testing is generally difficult or impossible for several reasons. Operating
conditions are not easily modified or controlled and taking the plant off-line to test the
flare is impractical. In addition, flares are nearly impossible to test under critical design
conditions once installed and operating.”132 Testing of an operating ground flare is
unsafe to the stack testers because an unforeseeable event creates safety concerns and
would destroy the test equipment.
For incinerators, manual testing and continuous emission monitoring are feasible
although manual testing at or near maximum design loads may not be feasible without
disrupting the process. LAER and BACT emission rates (e.g., lb/MMBtu) for CO, NOx,
PM, PM10, PM2.5, and GHG emissions based on the RBLC database review and other
permits could not be determined for the thee permits found in Table 5-50 because the
design heat input to the incinerators was not found in the permits. Only pound per hour
and ton per year limits were identified in these permits.
132 Industrial-Scale Flare Testing, Jianhui Hong, et. al. John Zink Company. www.johnzink.com/wp-
content/uploads/industrial-flare-testing.pdf
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With the exception of the ExxonMobil Mont Belvieu PE plant RTO and FTO, the other
incinerators precedents presented in Table 5-50 are not of the same class or category as
the proposed Project’s incinerators. For LAER, the control technology must be verified
to perform effectively over the range of operation expected for that class or category of
source. The verification must be based on a performance test or tests, when possible, or
other performance data. The Mont Belvieu plant has not yet begun operation, so the
limits in these permits have not been achieved in practice.
Due to the lack of achieved in practice emission rates from the same class or category of
emissions units, Shell proposes the following emission rates for the LP Thermal
Incinerator and the Spent Caustic Vent Incinerator:
0.068 lb/MMBtu for NO2/NOx,
0.0075 lb/MMBtu for PM/PM10/PM2.5,
0.37 lb/MMBtu for CO, and
132.0 lb/MMBtu for CO2e.
The proposed emission limits for NOx and PM2.5 must meet two criteria to be considered
LAER. To evaluate the first criterion as noted above, a review of the requirements
included in State implementation plans, regulations and BACT guidelines for Texas, and
California agencies (CARB, BAAQMD, SJVAPCD and SCAQMD) was performed. No
State implementation plans, regulations, and BACT guidelines specific to incinerators for
CO, NOx, PM, PM10, PM2.5, and GHG emissions were identified. The second criterion is
met because no CO, NOx, PM, PM10, PM2.5, and GHG emissions rate limits achieved in
practice were identified, except for NOx at the Owens Corning Medina Asphalt Roofing
Plant (OH-0288). This NOx limit was “estimated” to be 0.2 lb/MMBtu when firing
natural gas and 0.3 lb/MMBtu when firing waste gas. Shell has proposed a much lower
limit as being reasonable for the class and category of incinerators proposed.
In accordance with 25 Pa. Code §127.205(7), the proposed CO, NOx, PM/PM10/PM2.5,
and GHG BACT/LAER limits are equivalent to and satisfies the PaBAT requirements of
25 Pa. Code §127.12(a)(5).
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5.13 Plant Roads
Although much of the material that moves in and out of the the proposed project will be
transported by rail, certain materials will also transported by truck. Truck traffic on plant
roadways is a potential source of fugitive particulate matter emissions. Most of these
emissions are estimated to be PM with only a small fraction of the total emissions being
PM10 (about 20%) and even smaller fraction being PM2.5 (about 5%).
Particulate emissions occur as vehicles travel over a paved surface such as a road.
Particulate emissions from paved roads are primarily associated with re-suspension of
loose material on the road surface. According to U.S. EPA’s model of road-related
fugitive emissions, in the absence of continuous addition of fresh material (through
localized trackout or application of antiskid material), paved road surface silt loading
reaches an equilibrium value in which the amount of material re-suspended matches the
amount replenished.133
Dust emissions from paved roads have been correlated with what is termed the “silt
loading” present on the road surface as well as the average weight of vehicles traveling
the road. The term “silt loading” refers to the mass of silt-size material (i.e., loose
surface dust equal to or less than 75 µm in physical diameter) per unit area of the travel
surface. The total road surface dust loading consists of loose material that can be
collected by vacuuming of the traveled portion of the paved road. The silt fraction is
determined by measuring the proportion of the loose dry surface dust that passes through
a 200-mesh screen, using the ASTM-C-136 method. Silt loading is the product of the silt
fraction and the total loading.
Based on the expected level of truck traffic, the characteristics of the production
processes and the length of the plant roads, estimated fugitive PM emissions from the
133 See AP-42, Chapter 13, Section 2.1 (paved roads)
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plant roads total approximately 0.3 tons per year. PM2.5 emissions are estimated to be
less than 0.1 tons per year.
5.13.1 Plant Road Fugitive PM LAER/BACT Analysis
Two criteria must be evaluated to determine LAER for a particular class or category of
source. The first criterion considered is the most stringent achievable limit in a SIP that
is applicable to the class or category of source being evaluated – in this case an industrial
paved road. A review of SIP limits applicable to fugitive particulate emissions from
industrial plant roads shows that there are no specific emissions limits applicable to this
class or category of source. Instead, SIP regulations contain design and/or work practices
applicable to this source category. A sampling of applicable SIP “limits” is shown in
Table 5-51.
Table 5-51. Summary of SIP Regulations for Plant Road Particulate
Jurisdiction Rule
Citation Summary of Requirements
Louisiana LAC §1301 Paving roadways and maintaining the roadways in a
clean condition.
Clark County,
NV §93.2.1.1
Paved roads shall be constructed with a paved travel
section, and four (4) feet of paved or stabilized
shoulder on each side of the paved travel section.
Texas §111.147
Requires industrial roads to be paved unless the
owner of the roadway demonstrates that the cost of
paving is economically unreasonable compared to
other specified methods of dust control.
The second criterion in determining a LAER limit is that it must be at least as stringent as
the most stringent limit achieved in practice by the class or category of source. U.S.
EPA’s RBLC database was queried to determine limits established for industrial paved
roads in recent permit actions. Selected results of this review are summarized in Table
5-52. As shown, in most of the recent BACT determinations, fugitive particulate
emissions are limited by work practices that include paving and dust removal/suppression
as deemed necessary.
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Based on the information provided in Table 5-51 and Table 5-52, it is concluded that
PM2.5 LAER for plant roads is not an emissions limit, but rather a design/work practice.
This conclusion is consistent with U.S. EPA’s guidance in the 1990 DRAFT NSR
Workshop Manual that states:
In some cases where enforcement of a numerical limitation is judged to be
technically infeasible, the permit may specify a design, operational, or equipment
standard; however, such standards must be clearly enforceable, and the
reviewing agency must still make an estimate of the resulting emissions for offset
purposes.134
Based on available BACT precedents, a LAER design/work practice which requires that
all plant roads be paved and that Shell develop and implement a road dust control plan to
minimize fugitive emissions from the roadways is proposed. Given the low level of
estimated emissions from the proposed Project’s roads, the proposed design/work
practice also represents BACT for PM and PM10 emissions. In other words, there are no
more effective controls that could be considered that would not have adverse economic
impacts relative to the control provided by implementing the identified LAER
design/work practices. In accordance with 25 Pa. Code §127.205(7), the proposed PM
BACT/LAER limit is equivalent to and satisfies the PaBAT requirements of 25 Pa. Code
§127.12(a)(5).
134 See “1990 New Source Review Workshop Manual, DRAFT”, 1990, page G.4.
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Table 5-52. Summary of RBLC Survey Results for Plant Road Particulate
Facility RBLC
ID
Emission
Limit Discussion
Indiana Gasification,
LLC IN-0166 90% control
There is no practical way to measure control
efficiency of a road dust control plan so this “limit” is
not achievable. Further, this facility has not been
constructed and therefore, this “limit” has not been
achieved in practice and is appropriately not
considered in establishing a LAER limit.
Aventine Renewable
Energy Aurora West NE-0046
Silt Loading
< 3 g/m2
Note that this is not an emissions limit, but rather a
limit on a variable that is correlated with fugitive
road dust emissions. This facility is not operational
and Shell has been unable to determine if compliance
with this limit has been demonstrated or achieved in
practice. However, Shell believes this “limit” is
achievable.
Flopam, Inc. LA-0240 PM10 < 0.2 T/yr
This is the lowest paved road BACT limit identified.
Compliance with this limit is not monitored in any
way, nor is it even possible to monitor compliance
with such a limit. In this case, BACT is implemented
via a design/work practice that requires the facility’s
main roadways to be paved “where practical” and
that precautions be taken to prevent dust from
becoming airborne.
5.14 PaBAT Analyses for Pollutants Not Subject to BACT or LAER
This section presents Pennsylvania best available technology (PaBAT) analysis for those
pollutants which are not subject to BACT and LAER.
Sulfur dioxide (SO2) will be emitted from the proposed Project’s combustion sources
including the ethane cracking furnaces, catalyst activation process heaters, Cogen Units,
emergency generators, firewater pumps, and the VOC control system. The Project’s
potential to emit for SO2 was determined by assuming that all of the sulfur in the fuel will
be released as SO2 when combusted. Based on this approach the combined SO2
emissions for the Project were determined to be below the major source threshold.135
135 The location of the proposed Project in Beaver County is in an area that is classified as nonattainment
with the 1-hr SO2 standard. As a result, NSR applicability was determined in accordance with the major
source threshold for listed sources.
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Selective catalytic reduction (SCR) technologies will be used to control NOx emissions
from the cracking furnaces and the Cogen Units using ammonia (NH3) as the selective
reducing agent. Ammonia emissions, known as NH3 slip, will result from the NH3 that is
not adsorbed on the SCR catalyst. The NH3 injection rate is controlled to ensure
compliance with the required NOx emissions limits while minimizing NH3 slip.
Finally, certain sources will potentially emit some quantity of hazardous air pollutants
(HAP) which are not subject to BACT or LAER.
For projects and modifications not subject to the major source or major modification
requirements of 25 Pa. Code §127.12(a)(5) requires that a new or modified source “show
that the emissions from a new source will be the minimum attainable using best available
technology.” The following sections address the BAT requirement associated with
emissions of SO2 and NH3.
5.14.1 SO2
In accordance with the §127.12(a)(5) requirement, the SO2 PaBAT limits presented in
Table 5-53 are proposed. Accepted approaches for controlling SO2 emissions include
add-on control technologies such as sorbent injection and flue gas desulfurization and use
of lower sulfur fuels. All of the proposed projects combustion sources will be fired with
either fuels that have very low concentrations of sulfur or no sulfur. The fuels that are
not a byproduct of the processes will be either pipeline quality natural gas or Tier II ultra
low sulfur diesel (i.e., <15 ppmw sulfur).
Control of SO2 via add-on control technology is widely applied to coal-fired and high
sulfur oil-fired combustion sources. Emissions of sulfur dioxide from the proposed
Project’s sources,136 which will fire either natural gas (i.e., ~2 ppmv S) or low-sulfur
136 There will be no sulfur in the tailgas that is fired in the cracking furnaces and the process vent gases that
result from manufacturing PE. The only process gas that will be combusted by the Project that will
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Table 5-53. Proposed Limitations to Meet SO2 BAT
Emission Unit Fuel Proposed Limit 1 Compliance
Demonstration
Cracking Furnaces Tailgas & NG 2 0.5 gr/100 dscf Pipeline NG 2
Cogen Units NG 2 0.5 gr/100 dscf Pipeline NG 2
Emergency Generators Diesel 15 ppmw S in fuel Fuel purchase
records
Firewater Pumps Diesel 15 ppmw S in fuel Fuel purchase
records
VOC Control System
& Spent Caustic Vent
Incinerator
NG 2 0.5 gr/100 dscf
Pipeline NG 2
1. The definition of pipeline natural gas at 40 CFR Part 72 includes the following: “Pipeline
natural gas contains 0.5 grains or less of total sulfur per 100 standard cubic feet.”
2. NG = natural gas
diesel (i.e., 15 ppmw), are significantly less than in coal-fired add-on control applications
where the coal sulfur content is measured in percentages of greater than one percent (i.e.,
1% = 10,000 ppmw). As a result, SO2 emissions from natural gas and low sulfur diesel
fuel are too low to make the use of either sorbent injection or flue gas desulfurization cost
effective on the basis of $/ton of SO2 removed.
Further removal of sulfur contained in the pipeline natural gas or Tier II ultra low sulfur
diesel is also cost prohibitive. To avoid corrosion in the pipeline, any appreciable amount
of sulfur present in natural gas produced at the wellhead is removed prior to placing the
gas into the pipeline. Ultra low sulfur diesel is produced at refineries via desulfurization
processes that operate under high pressure and use catalytic reactions to react hydrogen
with the fuel bound sulfur and remove it from the oil as H2S. In accordance with the fuel
sulfur requirements at 40 CFR §80.510(1), the proposed diesel engines will burn Tier II
mobile source diesel containing less than 15 ppmw sulfur. Treatment to remove
additional sulfur would require more severe hydrotreating by a refinery or at the proposed
contain sulfur is the spent caustic stripper off gas, which will contain less than 50 ppmv H2S and be
combusted in the Spent Caustic Vent Thermal Incinerator.
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new source. The cost to install and operate this additional treatment equipment and its
operation would not be justified by the level of SO2 emissions reductions.
Further, the RBLC database does not identify any add-on control technology
requirements for the projects with combustion sources fired by natural gas or low sulfur
diesel. Due to these findings, coupled with the economic infeasibility of add-on controls,
the PaBAT for SO2 emissions is considered the use of natural gas, as proposed.
5.14.1.1 Cracking Furnaces SO2 PaBAT
As described in Section 3.1, ethane cracking furnaces are large combustion sources used
to thermally crack ethane into ethylene. During normal operation, over 95% of the
furnaces’ heat input will come from firing tailgas (consisting of up to 85% hydrogen and
15% methane by volume) with the remainder of the fuel being natural gas. There will be
no sulfur present in the tailgas. During start up, pipeline quality natural gas will be used
until the tailgas production has begun. During operations, pipeline natural gas will be
used as a supplement.
The permit precedents summarized in the RBLC 137 for sources similar to the ethane
cracking furnaces (i.e., refinery fuel gas combustion devices, pyrolysis furnaces,
reformers, and recent cracking furnace precedents) indicate that the most stringent sulfur
content requirement on a lb/MMBtu basis is 0.0015 lb/MMBtu.138 The proposed
0.5 gr/100 limit is equivalent to 0.0007 lb/MMBtu. Compliance with this proposed limit
would be based on the use of pipeline natural gas.
5.14.1.2 Cogen Unit SO2 PaBAT
The proposed Project includes three natural gas-fired Cogen Units. A review of
combustion turbine based cogen precedents in the RBLC database (see Table F.1-3 in
Appendix F) indicated that the use of pipeline natural gas is consistent with the proposed
137 A complete summary of the identified precedents is included in Appendix F. 138 For purposes of comparison the permitted hourly mass rate limits were converted to a lb/MMBtu value
based on the rated heat input capacity provided in the RBLC.
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BAT. For purposes of the proposed Project’s Cogen Units, a sulfur content of 0.5
grains/100 scf (0.0007 lb/MMBtu) in the natural gas is proposed. Compliance with this
proposed limit would be based on the use of pipeline natural gas.
5.14.1.3 Emergency Generators and Firewater Pumps SO2 PaBAT
The project includes four diesel-fired emergency generator engines and three firewater
pump engines. Each of the engines will combust low sulfur diesel fuel containing
15 ppmw sulfur; the total annual SO2 emissions are estimated at 2.8 tons/yr. The SO2
emissions from these engines are low enough to exempt these engines from the PaDEP
Plan Approval Process. Nonetheless, the use of 15 ppmw sulfur diesel is proposed as
PaBAT. This sulfur level meets the lowest levels identified in the RBLC database for
similar sources (see Appendix E.1-4 and E.1-5). Though not required, this will meet
Condition 7 of the General Plan Approval for Diesel or No. 2 Fuel-fired Internal
Combustion Engines (BAQ-GPA/GP-9). This will also comply with 40 CFR §80.510(1)
requirement referenced in 40 CFR Part 60 subpart IIII, NSPS for Stationary Compression
Ignition Internal Combustion Engines, which requires the fuel sulfur content be no
greater than 15 ppmw.
5.14.1.4 VOC Control System SO2 PaBAT
As discussed in Section 3.5.5, the proposed Project will include three header systems and
a Spent Caustic Vent Thermal Incinerator that will be used to gather and control VOC
emissions during normal operation, startup, shutdown, and unforeseeable events at the
facility. No sulfur will be present in the vent streams controlled by the header systems.
Sulfur dioxide emissions from these systems may result from pipeline natural gas
combustion in the flare pilots and to support operation of the proposed thermal
incinerator at its operating temperature. For the proposed flares and incinerators, a sulfur
content of 0.5 grains/100 scf (0.0007 lb/MMBtu) in the natural gas is proposed.
Compliance with this proposed limit would be based on the use of pipeline natural gas.
Emissions of SO2 from the Spent Caustic Vent Thermal incinerator will result from the
combustion of any H2S that is stripped from the spent caustic and the supplemental
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natural gas fuel that is used to ensure that the incinerator operates above a specified
operating temperature. The level of H2S in the stripped gas is expected to be less than
40 ppmv, which is well below the level where removal would be considered cost
effective. As a result, only a PaBAT sulfur content for the natural gas which is used to
ensure the specified operating temperature is proposed. For purposes of the proposed
Spent Caustic Vent Incinerator, a sulfur content of 0.5 grains/100 scf (0.0007 lb/MMBtu)
in the natural gas is proposed. Compliance with this proposed limit would be based on
the use of pipeline natural gas.
5.14.2 Ammonia (NH3)
The following limits are proposed as BAT for the ammonia emissions:
Cracking Furnaces: 10 ppmv at 3% O2, and
Cogen Units: 5 ppmv at 15% O2.
5.14.2.1 Cracking Furnace NH3 PaBAT
As discussed in Section 5.2, ethane cracking furnaces are different from boilers and
process heaters in both their design and operation. Due to fuel differences (i.e., high
hydrogen content) and the firebox temperatures required by cracking furnaces and
resulting burner issues, LNBs do not achieve the same NOx levels as when implemented
in boilers and process heaters. Though a review of the RBLC database of boilers and
process heaters was performed for completeness (and is presented in Table 1), the sources
are dissimilar enough to warrant an examination that focuses on recent permits for similar
cracking furnaces. Five (5) recently permitted ethylene plant expansions or new plants
located in Texas include:
BASF Fina Port Arthur, TX Cracking Furnace (10 ppmvd at 15% O2),139
Equistar Channelview, TX Op-2 Furnace (10 ppmvd at 3% O2 hourly),
Equistar Channelview, TX Op -1Furnace (10 ppmv at 3% O2),
139 Equivalent to 30.3 ppmvd @ 3% O2.
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ExxonMobil Baytown, TX Furnace (15 ppmvd at 3% O2), and
Chevron Phillips Cedar Bayou, TX Furnace (10 ppmvd at 3% O2).
These facilities are also presented in Table E.2-1 of Appendix E.2. The range of NH2 slip
limits is from 10 ppmvd at 3% O2 hourly to 15ppmvd at 3% O2 hourly. These findings
support the proposed NH3 PaBAT limit of 10 ppmvd at 3% O2 (dry) for the cracking
furnaces.
5.14.2.2 Combustion Turbine NH3 PaBAT
The RBLC findings for NH3 slip limits for combined cycle turbines are presented in
Table E.2-2 of Appendix E.2. As shown, the NH3 limits range from 2 ppm at 15%
(steady state operations) to 10 ppmv at 15% O2 3 hr rolling average. The 2 ppm limit is
for the Kleen Energy Systems power plant in Middletown, CT for times of steady-state
operation firing natural gas. This site has experienced operating issues since its original
start-up. As a result, the facility has not yet demonstrated that the 2 ppmvd @ 15% O2
NH3 slip has been achieved at the catalyst end of run condition. It is therefore eliminated
from consideration. Three PaBAT determinations for NH3 in Pennsylvania at SCR-
controlled combined-cycle combustion turbines were identified. For these precedents
PaDEP determined a BAT level of 5 ppmvd at 15% O2. The facilities permitted at this
level include:
Moxie Liberty LLC – 10/10/2012,
Sunbury Generation – 04/01/2013, and
Hickory Run Energy Station – 04/23/2013.
Pursuant to BAT, these facilities must monitor the pre-control and post-control NOx
emissions by the feed-forward process control loop to ensure maximum control
efficiency and minimize NH3 slip. To be consistent with the recently approved BAT
determinations by the Pennsylvania DEP, the project proposes the same 5 ppmvd at 15%
O2 limit as BAT for the Cogen Units.
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5.14.3 Hazardous Air Pollutants (HAPs)
Each of the following sources that comprise the Project will potentially emit some
quantity of HAP: cracking furnaces, Cogen Units, emergency engines, incinerators and
flares, cooling towers, WWTP, fugitive emitting components. As a result, per 25 Pa.
Code 127.12(a)(5), each of these sources must have their emissions limited to the
minimum attainable through use of the best available technology (PaBAT). Organic
HAP is emitted from the Project’s combustion sources and has the potential to be emitted
from the Project’s process fugitive emitting components, water cooling tower, and
WWTP. The potential for metal HAP emissions is from the Project’s combustion
sources. The level of organic HAP that is emitted will be directly related to the amount
of VOC emitted while the amount of metal HAP emitted will be related to the amount of
fuel combusted. As a result, the VOC LAER limits will minimize the amount of organic
HAP emitted and the GHG BACT fuel efficiency limits will minimize the amount of
metal HAP emitted. A summary of the proposed HAP PaBAT is presented in Table
5-54. As shown, the proposed VOC LAER and GHG BACT efficiency requirements are
used as the basis for the proposal.
Table 5-54. Summary of Proposed PaBAT for HAP from the Proposed Project
Sources
Source PaBAT Proposal
Cracking Furnaces Sections 5.2.2 & 5.2.5 VOC & GHG LAER
Cogen Units Sections 5.3.2 & 5.3.5 VOC & GHG LAER
Emergency Engines Sections 5.4.1 and 5.4.4 VOC & GHG LAER
PE Process Vents Section 5.7.1 VOC LAER and Section 5.7.2
PM LAER
Equipment Leaks Section 5.5.1 VOC LAER
Spent Caustic Tanks Section 5.8 VOC LAER
Cooling Towers Section 5.9 VOC LAER
WWTP Section 5.10 VOC LAER
VOC Control System
Incinerators & Flares
Section 5.12 VOC LAER
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6.0 Air Quality Modeling Analysis
An air quality dispersion modeling analysis was conducted for the proposed Project to be
located in Beaver County Pennsylvania. Details of the air dispersion modeling analysis
performed in support of the Project are presented in Appendix C. The analysis evaluated
emissions of the criteria pollutants regulated under the Prevention of Significant
Deterioration ("PSD") regulations of 40 CFR 52.21 as implemented under 25 Pa. Code
Chapter 127, Subchapter D. The criteria pollutant analysis was conducted to insure that
the proposed project will not cause or contribute to air pollution in violation of a National
Ambient Air Quality Standard ("NAAQS") or PSD increments.
The analyses quantify only the impacts of the pollutants that are emitted in amounts in
excess of the significant emission rates ("SERs"). For the proposed project, emissions of
nitrogen dioxides ("NO2"), carbon monoxide ("CO"), and particulate matter with an
aerodynamic diameter of less than 10 µm ("PM10") will be emitted in significant
quantities.
To determine if the Project would significantly impact local air quality, only the
emissions from the proposed Project were initially evaluated. The resultant modeled
concentrations from this effort were compared to the ambient Significant Impact Levels
("SILs") for Class I and Class II areas. The results of this significant impacts analysis
demonstrate that the proposed Project will result in ambient impacts in excess of the
Class II SIL only for the 1-hour NO2 standard. Impacts for all other pollutants were
determined to be less than the Class I and Class II SILs. Therefore, a refined air quality
analysis to determine concentrations for comparison to the NAAQS was required for the
1-hr NO2 standard.
The results from the NAAQS analysis for the 1-hour NO2 standard indicate modeled NO2
violations in the vicinity of the proposed Shell site. These modeled violations are
attributable to existing sources in the vicinity of the proposed Project’s site. However,
the proposed Project is shown not to cause or contribute to any of the existing modeled
exceedances of the 1-hour NO2 NAAQS.
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Class II visibility impacts were also evaluated at the Raccoon Creek State Park and
determined to be acceptable.
The analysis conforms to the modeling procedures outlined in the Environmental
Protection Agency’s Guideline on Air Quality Models 140 ("Guideline") and associated
EPA modeling policy and guidance as well as the modeling protocol submitted to and
approved by the PaDEP on February 18, 2014.
For purposes of the modeling demonstration the following additional mass based
emission limits covering foreseeable operation are required:
Cracking Furnaces PM10:
o 2.480 lbs/hr on a 24-hr rolling average basis
o 2.264 lbs/hr on an annual basis
Cogen Units PM10:
o 11.385 lbs/hr on a 24-hr rolling average basis (all units combined)
HP Ground Flares PM10:
o 7.507 lbs/hr on a 24-hr rolling average basis
o 0.230 lbs/hr on an annual basis
HP Elevated Flare PM10:
o 0.289 lb/hr on a 24-hr rolling and annual average basis
Refrigerated Storage Flare PM10:
o 0.404 lb/hr on a 24-hr rolling average basis
Cooling Towers PM10:
o 0.125 lb/hr on a 24-hr rolling and annual basis
140 Guidelines on Air Quality Models, (Revised). EPA-450/2-78-027R, Appendix W of 40 CFR Part 51,
U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research
Triangle Park, North Carolina. November 2005.
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7.0 Additional Impacts Analysis
In accordance with 40 CFR §52.21(o)(1) and (2), this section provides: 1) an analysis of
the potential for impairment to visibility, soils, and vegetation that could occur as a result
of the proposed Project, and 2) an analysis of air quality impacts projected for the area as
a result of general commercial, residential, industrial and other growth associated with
the proposed source. For purposes of presentation, the potential for impacts due to
growth are discussed first, followed by a discussion of the potential impacts to visibility,
soils and vegetation.
7.1 Analysis of Impacts Due to Growth
7.1.1 Overview
The proposed Project is a major stationary source (major source) subject to PSD program
requirements, including the requirement to analyze air quality impacts projected for the
area resulting from general commercial, residential, industrial, and other growth
associated with the Project. The growth analysis is used in conjunction with the air
quality impacts analysis to assess the impacts of activities that are not a part of the Project
but can reasonably be expected to occur as a result of the Project.
The growth analysis focuses on the permanent impacts during the operational phase of a
project. Aggregate air quality impacts during the construction phase of the project are
small in relation to the impacts during the operational phase, and permit applicants are
not required to consider these emissions in the growth analysis.141
For the proposed Project, quantifiable growth includes commercial and residential growth
related to the project workforce. Shell expects no industrial growth in the immediate
area, because existing markets for the Project’s product (i.e., polyethylene) already exist
141 U.S. EPA interpretive policy expressly calls for consideration of only “permanent residential,
commercial, and industrial growth,” excluding “temporary sources,” in the growth analysis under 40
CFR § 52.21(o). See, e.g., Prevention of Significant Deterioration Workshop Manual (EPA-450/2-80-
081), Oct. 1980, at page I-D-5.
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within the area and region. No further chemical processing of the proposed Project’s
major product (i.e., PE) is required. Moreover, the Project will not produce the primary
raw material (ethane), but instead will receive ethane by pipeline.
7.1.2 Growth in Population
The proposed Project is located in Beaver County, Pennsylvania, approximately 35 miles
northwest of Pittsburgh. Beaver County is bordered on five sides by Allegheny, Butler,
Lawrence, and Washington Counties in Pennsylvania; Hancock county in West Virginia;
and, Columbiana County in Ohio. A 45-mile radius from the site also includes Brooke
County in West Virginia, and Mahoning County in Ohio.
Upon completion of construction, the Project will employ approximately 400 workers.
Shell expects to fill most of these permanent jobs from the local population. As the plant
converts from zinc smelting to cracker operations, Shell anticipates no significant change
in the permanent workforce, because Horsehead Corporation formerly employed
approximately 600 workers at the site. Thus, no residential growth is expected due to
direct job growth. However, when considering indirect and induced job growth arising
from increased economic activity, the Project may increase local employment by as much
as 2000-8000 permanent jobs.142 For purposes of this growth analysis, this higher growth
rate is assumed to result from the Project. As shown in the following analysis, the
emissions associated with this growth will not be substantial when compared to the
existing emissions inventory.
The U.S. Census Bureau tracks commuter flow patterns from one county to another.
According to data from 2006-2010, of the people who reside in the 10 county area but
work in Beaver County, 77 percent of the commuters also live in Beaver County.
Residents working in Beaver County and residing in one of the other nine counties
represent the remaining 13%. Less than one (1) percent of commuters reside in Jefferson
142 “Economic Impact Analysis of Proposed Petrochemical facility in Beaver County,” Pennsylvania
Economy League of Greater Pittsburgh, Sept. 18, 2012.
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County, WV. As a result, this county was removed from further consideration in this
growth analysis.143
As shown in Table 7-1, the nine-county region encompasses over 4,282 square miles and
has a current population of individuals over the age of 18 of approximately 1.8 million
persons.
Table 7-1. Nine Counties Considered in Population Growth Impact Area144
County Land Area
(square
miles)
Population
Over 18
(2012)
Population
Density
(persons/mi2)
Project
Induced
Growth (# of
individuals)
Percent of
Beaver County
Workers living
in County
Allegheny, PA 730 995,764 1,676 574 7
Beaver, PA 435 135,661 392 6176 77
Butler, PA 788 142,596 233 218 3
Lawrence, PA 358 71,756 254 362 5
Washington, PA 857 165,136 243 87 1
Columbiana, OH 531 83,075 203 361 5
Mahoning, OH 411 185,765 580 62 1
Brooke, WV 89 19,559 269 62 1
Hancock, WV 83 24,244 371 96 1
Total 4282 1,823,556 8000
7.1.3 Growth in Air Pollutant Emissions
Based on population growth of 8000 individuals, the Project’s operations are expected to
cause indirect pollution growth in the nine county region of 0.44 percent, with the largest
growth likely occurring in Beaver County. The associated residential and commercial
growth will result in increased air pollutant emissions throughout this region.
7.1.3.1 Stationary Source Emissions
For the reasons described above, Shell expects no quantifiable industrial growth in the
area to occur as a direct result of the proposed Project.
143 See Table 2 Residence County to Workplace County Flows for the United States and Puerto Rico Sorted
by Workplace Geography: 2006-2010. Available at:
https://www.census.gov/newsroom/releases/archives/news_conferences/commuting.html#ccc_flows . 144 Population data from http://quickfacts.census.gov/qfd/states/16000.html. (Last accessed Feb. 26, 2013.)
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7.1.3.2 Other Area Source Emissions
It is anticipated that residential and commercial growth in the affected area will lead to
increased emissions from various categories of area source emissions. These categories
include residential and commercial fuel combustion, solvent usage, and waste disposal,
commercial cooking, commercial marine vessels, and gas stations. The emissions
increases associated with these categories were estimated by applying the highest
population growth rate (0.44%), to the existing inventory for the nine counties in
proportion to each county’s expected contribution to growth (as represented by the
commuter patterns). The area source emissions within the affected area are summarized
in Table 7-2. Also shown is a summary of the anticipated increases in emissions within
the affected area due to residential and commercial growth associated with the Project,
and provides a comparison with the existing emissions inventory in the nine county area.
Table 7-2. Other Area Source Emissions Increases Compared to Current Inventory
Pollutant
2011 Emissions
Other Area
Sources
(tons/yr)
Emissions
Increases
Other Area
Sources
(tons/yr)
2011 Total
Emissions
Inventory
(tons/yr)
Relative
Increase in
Affected
Area
(%)
CO 30,046 133 406,974 0.033
NOX 8,535 46 98,532 0.047
PM10 5,802 28 42,259 0.007
PM2.5 4365 23 17,063 0.001 VOC 19000 80 106,462 0.008
7.1.4 Air Quality Impacts
As shown in Table 7-2, residential and commercial growth associated with the proposed
Project will result in slight increases in air pollutant emissions in the surrounding area.
Because the anticipated emissions increases are very small in relation to the existing
emissions inventory, the impact on ambient air pollutant concentrations will not be
significant. Thus, no adverse impacts are anticipated.
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7.2 Analysis of Impacts to Visibility
The CAA Amendments of 1977 require evaluation of new and modified emission sources
to determine potential impacts on visibility. The maximum increase in hourly particulate
matter and NOX emissions from the proposed Shell facility were used as input parameters
in the visibility analysis. Emissions were evaluated as described in the EPA Workbook
for Plume Visual Impact Screening and Analysis 145 to determine potential contribution to
atmospheric discoloration and visual range reduction. The results from this analysis are
presented in Section 7.0 of the Modeling Report included as Appendix C to this
document. Class II visibility impacts were evaluated at the Pittsburgh International
Airport and Raccoon Creek State Park and determined to be acceptable.
7.3 Analysis of Impacts to Soils and Vegetation
7.3.1 Overview
The pollutants included in this analysis of the potential for impairment to soils and
vegetation are PM, PM10, PM2.5, NOX, CO, and VOC. Consistent with EPA policy, we
did not include GHG in this analysis. The results of the soils and vegetation impact
analyses show that no significant impairment will occur as a result of the construction or
operation of the facility. Specific findings are documented in the following subsections.
7.3.2 Effects on Soil
For purposes of the soil analysis, information related to soils in the Beaver County area
was reviewed. The Natural Resources Conservation Service (“NRCS”) has published
soil survey data collectively covering Beaver and Lawrence counties. 146 The total land
area in Beaver County covered by this analysis is approximately 447 square miles. This
145 Workbook for Plume Visual Impact Screening and Analysis. US EPA, EPA Pub. No. 450/4-88-015.
RTP, NC. September 1988. 146 “Soil Survey of Beaver and Lawrence Counties, Pennsylvania,” U.S. Dept. of Agric. Soil Conservation
Service in cooperation with Penn. State Univ., Issued April 192. NRCS Soil Data Mart at
http://www.nrcs.usda.gov/Internet/FSE_MANUSCRIPTS/pennsylvania/PA603/0/gsm.pdf (last accessed
March 14, 2013).
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exceeds the scope suggested by U.S. EPA guidance, which is limited to the area within
approximately 10 kilometers (i.e., ~120 square miles) of the proposed facility.147
The assessment of potential impacts on soils shows no likelihood of impairment from the
proposed project. The basis for this conclusion is summarized below. This conclusion is
likely representative of the lack of impairment throughout the larger 10-county area. This
is because greater levels of deposition to soil and a higher potential for impairment occur
closer to the project. Having found no likelihood of impairment within the Beaver
County, there is no likelihood of impairment further from the project.
7.3.2.1 Pollutant Impacts on Soils
At least 10 different soil types exist in the Beaver county area.148 Some of these soils are
moderate to well-drained, while others exhibit poor drainage characteristics. Most of the
soils in the NRCS maps units are classified as various varieties of silt loam, with the
surface soil pH ranging from 4.6 to 7.0. A readily accessible table of Beaver county soils
with key soil properties is available through the Pennystone Project.149
Current literature contains little information on impairment or other direct effects on soils
due to air pollution, and as part of this analysis no studies were identified in which
potential pollutant effects on the soils specific to the project area were evaluated. This is
consistent with U.S. EPA’s findings on this topic:
In contrast to the amount of published information on the effects of atmospheric
pollutants on plants and animals, very little has been reported on their effects on
soils. Research on trace elements in soils, often the same elements as
atmospheric pollutants, has been directed to notable deficiencies or excesses that
limit agricultural crop production. When the amount of an atmospheric pollutant
entering a soil system is sufficiently small, the natural ecosystem can adapt to
these small changes in much the same way as the ecosystem adapts to the natural
147 See, e.g., Prevention of Significant Deterioration Workshop Manual (EPA-450/2-80-081), Oct. 1980, at
page I-D-6, expressly limiting the soils and vegetation impairment analysis to the “impact area.” See,
also, the same document at page I-C-12, defining the impact area as “a circular area whose radius is
equal to the greatest distance from the source to which approved dispersion modeling shows the
proposed emissions will have a significant impact.” 148 Beaver River Conservation and Management Plan, Penn. Environmental Council, August 2008. 149 See http://www.pennystone.com/soils/beaver.php.
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weathering processes that occur in all soils. Cultural practices (e.g., liming,
fertilization, use of insecticides and herbicides) add elements and modify a soil
system more than a small amount of deposited atmospheric pollutant can The
secondary effects of the pollutant appear to impact the soil system more
adversely than the addition of the pollutant itself to the soil. For instance,
damaging or killing vegetative cover could lead to increased solar radiation,
increased soil temperatures, and moisture stress. Increased runoff and erosion
add to the problem. The indirect action of the pollutant, through changes to the
stability of the system, thus may be more significant than the direct effects on
soil invertebrates and soil microorganisms. However the lack of long-term
historical data on both the type and amount of atmospheric pollutants as well as
the lack of baseline data on soils has made difficult the task of determining the
effect of pollutants on soils by monitoring changes associated with exposure to
pollutants. A limited number of studies have been carried out on trace element
contamination in soils. Plant and animal communities appear to be affected
before noticeable accumulations occur in the soils. Thus, the approach used here
in which the soil acts as an intermediary in the transfer of deposited trace
elements to plants appears reasonable as a first attempt at identifying the air
quality related values associated with soils.150
Because deposition of NOX and other nitrogen compounds into soils in the survey area
could occur as a result of emissions from the facility, it is reasonable to consider whether
some marginal acidification of the soils might occur as a result of this project. Changes in
soil acidity caused by nitrogen deposition can affect tree growth, and affect lake and
stream acidification through nitrate (NO3-) leaching.
In 2007, the USDA Forest service undertook an assessment to estimate critical acid loads
(CAL) and exceedances for forest soils in the United States.151 A critical load is an
estimate of ecosystem exposure to a pollutant below which harmful ecosystem effects do
not occur, and above which there is an increased risk of adverse effects. A soil’s acid
neutralizing capacity (ANC) will affect an area’s critical load. The ANC is the ability of
the soil to buffer acids. Critical loads are typically expressed in terms of kilograms per
hectare per year (kg/ha/yr) of wet or total (wet + dry) deposition, and consider the soil’s
acid neutralizing capacity (ANC). For acidification, CAL is a function of both nitrogen
150 Smith, A.E., and J.B. Levenson. A Screening Procedure for the Impacts of Air Pollution Sources on
Plants, Soils, and Animals (EPA-450/2-81-078). U.S. EPA, Office of Air Quality Planning and
Standards. Research Triangle Park, NC. December 1980. Pp. 17-19. 151 “Estimates of critical acid loads and exceedances for forest soils across the conterminous United States,”
Steven G. McNulty, et. al., Environmental Pollution 149 (2007) 281-292.
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and sulfur deposition. Based on 1994-2000 data, the 2007 assessment reported areas in
Western Pennsylvania as having a CAL between 1000-2000 eq/ha/yr, with exceedances
of the CAL in this area of between 0 and 250 eq/ha/yr.
Importantly, however, the study concluded that these findings were preliminary, and that
additional research was needed before a CAL exceedance should be used as a tool for
identifying areas of potential concern. Moreover, the CAL estimates are based on 1994-
2000 data which occurred before a significant amount of the NOx and SO2 emissions
reductions occurred due to the Acid Rain Program, the Clean Air Interstate Rule (CAIR),
the NOx SIP call and other 1990 Clean Air Act Amendment emissions reductions
programs. In fact, the U.S. EPA reports a 31% decline in NO2 ambient air concentrations
(based on annual 98th percentile of daily max 1-hour average values) and a 67% decline
in SO2 ambient air concentrations (based on the annual 99th percentile of daily max 1-
hour averages) in the Northeast between the years 2000-2012.152 Thus, to the extent that
the estimated CAL levels have planning value, the reported exceedances may no longer
exist in the Northeast area due to the rapid decline in acidic deposition in the area.
The critical loads (CLs) for nitrogen deposition were considered. The National
Atmospheric Deposition Program (NADP) collects pollutant deposition data from a
number of national monitoring networks. There are four monitoring sites located in the
Western Pennsylvania area that are in relatively close proximity to the proposed Project’s
location. These include Goddard State Park (62 miles north), Laurel Hill State Park
(87 miles, southeast), Crooked Creek Lake (55 miles east), and Allegheny Portage
Railroad (115 miles east). The 2012 monitoring data from these sites indicted annual
NO3 deposition rates of 12.49 kg/ha, 15.57 kg/ha, 10.67 kg/ha, and 15.67, respectively.
Published CL values for NO3 deposition specific to the Beaver county area were not
identified. In general, however, it is recognized that broad areas of the entire eastern US
are likely exceeding empirical (CL) estimates for nitrogen. Studies for the broad
Northeastern US region have shown that nitrogen leaching begins to increase in some
152 See U.S. EPA emissions trends reports available at http://www.epa.gov/airtrends/.
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forests soils at atmospheric nitrogen deposition greater than 8-12 kg N/ha/yr,153
Leaching, however, does not directly equate to an adverse effect, as the effect is related to
the CAL/ANC, and can be both positive or negative, depending on the species effected
(e.g. stunted growth of an invasive species would be a positive effect.)
As critical load information is unavailable for the Beaver county area, empirical values
developed for an application in the United Kingdom for habitats, which may be at least
remotely comparable to the Beaver County area, were considered.154 In 1982, NRCS
found that roughly 44% of the county was covered by woodlands, with 28% oak-hickory
cover, 23% elm-ash-red maple cover; 23% aspen-birch cover; 19% maple-beech-birch
cover; chestnut-oak 2 and white pine cover 4%. Roughly 5% of the area is used as
outdoor recreation land including state game lands, camps and golf courses, and large
parts of land support agricultural crops such as hay.155 This is largely consistent with a
study of the Beaver Creek Watershed that reported 43% of the study area comprised of
deciduous and coniferous forest, and 28% hay pastures.156 The U.K. recommended
critical load level for broadleaved, deciduous woodlands is 10-20 kg N/ha/yr; for
coniferous woodland is 5-15 kg N/ha/yr; and for mountain hay, and low and medium hay
meadows are 10-20 kg N/ha/yr and 20-30 kg N/ha/yr, respectively.
Notably, the monitored values from the 2012 NADP monitoring data represent a single
year of data. Data from earlier years are generally unavailable, and no useful annual
trends for the monitored sites are available. In a recent presentation, Penn State
Associate Professor Dr. Elizabeth Boyner indicated that there was a significant
downward trend in nitrate concentration in stream and lakes in near the Western
Pennsylvania area.157 This is indicative of an overall decrease in the nitrogen deposition
153 “Setting Limits: Using Air Pollution Thresholds to Protect and Restore U.S. Ecosystems,” Issues in
Ecology, Report No. 14, Fall 2011. Available at: http://www.esa.org/esa/wp-
content/uploads/2013/03/issuesinecology14.pdf. 154 See data available through the Air Pollution Information System, http://www.apis.ac.uk/. 155 See NRCS Soil Data Mart and Section 2.3 of this Report - Effects on Vegetation. 156 PA. Envir. Council at 64. 157 “Atmospheric Deposition in Pennsylvania & Impacts on Watersheds,” Penn State Water Resources
Extension Webinar Series, Sept. 4, 2013.
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rate. Given this, it is reasonable to assume that monitored values from the NADP
similarly represent one point on a declining curve.
After reviewing all of this information, and recognizing that “[t]here is no single
‘definitive’ critical load for a natural resource,” it is concluded that the Project will not
cause additional impairment of soils in this area.158 This finding is based on the
decreasing levels of acid deposition and nitrogen deposition in the area. In addition, to
the extent that any of the identified acid and nitrogen CL values have meaning for the
Beaver county area, it should be noted that the NADP values are near values at which
leaching (but not necessary adverse effects) only begins to occur, and they are close to or
well below levels recommended CLs for potentially comparable ecosystems in the U.K.
Finally, this project will result in a net decrease of approximately 500 tpy of NOx in the
area from offsets, further contributing to the likelihood that the proposed Project will not
cause further impairment to soils.
7.3.2.2 Effects on Vegetation
Pursuant to 40 CFR § 52.21(o), our initial analysis is limited to vegetation having
significant commercial or recreational value. The assessment of potential impacts on
vegetation shows no likelihood of impairment from the proposed project. The basis for
this conclusion is presented below.
7.3.2.3 Identification of Vegetation with Significant Commercial Value
This analysis of impacts to commercial vegetation covers both the entire ten-county area.
This exceeds the scope suggested by U.S. EPA guidance, which is limited to the area
within the impact area of the proposed facility (10 km).159
158 “Integrated Science Assessment” at p 250. 159 See, e.g., Prevention of Significant Deterioration Workshop Manual (EPA-450/2-80-081), Oct.
1980, at page I-D-6, expressly limiting the soils and vegetation impairment analysis to the “impact area.”
See, also, the same document at page I-C-12, defining the impact area as “a circular area whose radius is
equal to the greatest distance from the source to which approved dispersion modeling shows the
proposed emissions will have a significant impact.”
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Table 7-3 lists the commercially significant vegetation in the ten-county study area. As
shown, approximately 14 percent of the land area in the ten-county study area is used for
harvested crops; of this total, approximately 92 percent is used for corn as grain, corn as
silage, other forage (e.g. hay), and soybeans. Based on the results of the vegetation
survey, the following were identified as the principal crops for study in this analysis:
Corn for grain (Zea mays)
Corn for silage or greencrop
Oats for grain ((Avena sativa)
Vegetables for harvest
Other forage (other hay, etc.)
Soybean for beans
7.3.2.4 Identification of Vegetation with Potential Recreational Value
To identify vegetation with potential recreational value, the Beaver County Natural
Heritage Inventory (NHI) was reviewed. The NHI, identifies areas within the county that
are of importance for biological diversity and ecological integrity of the County. Within
Beaver County, the NHI identified two areas as Dedicated Areas (DA). A DA is an area
that is specifically dedicated for protection for ecological and biological diversity. DAs
within Beaver County include the Raccoon Creek State Park and Wildflower Reserve,
(located approximately 17 miles northwest of the proposed Project site); and the Ohio
River Islands National Wildlife Refuge, Georgetown Island (approximately 11 miles west
of the proposed Project site), and Phillis Island (approximately 9 miles west of the
proposed Project site). Of these two, only Raccoon Creek State Park is listed as habitat
for several plant species of concern.
Beaver County also includes five Biological Diversity Areas (BDAs) within Potter
Township. A BDA identifies areas supporting a special species or a large number and
kinds of species. The BDA’s within Potter Township include the Lower Raccoon Creek
[which includes a northern hardwood forest community; a Mesic central forest
community; dry-mesic acidic central forest community; a robust emergent Marsh
community; and habitat for a plant species of special concern (SP001)]; Monaca Bluffs
[which includes habitat for two plant species of concern (SP002 and SP003); and two
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Table 7-3. Commercially Significant Vegetation in Ten-County Study Area (Acres)
Beaver Allegheny Butler Lawrence Washington Total
Total Land Area 278,214 467,251 504,704 229,235 548,473 2,027,877
Harvested Cropland 24,426 8,689 63,341 52,580 75,163 224,199
Corn for Grain 3,508 538 14,920 18,328 4,205 41,499
Corn for Silage/Greenchop 848 141 3,320 3,876 -- 8,185
Wheat for Grain (all) 849 -- -- -- -- 849
Oats for Grain 206 895 3,163 2,549 1,080 7,893
Barley for Grain 155 44 435 148 782
Vegetables Harvested for Sale 787 803 1,225 211 664 3,690
Sweet Corn -- 398 -- -- 398
Cut Christmas Trees 392 281 562 88 332 1,655
Other Forage (hay, haylage, grass,
silage, & greenchop)
15,568 6,188 31,597 18,011 63,795 135,159
Soybeans for Beans 1,386 6,112 8,428 1,319 17,245
Blueberries, Raspberries, Strawberries 20 41 51 200 15 327
Land in Orchards 174 126 183 90 239 812
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Table 1-3. Commercially Significant Vegetation in Ten-County Study Area (Acres) – cont’d
Columbiana Mahoning Brook Jefferson Hancock Total
Total Land Area 339,840 263,040 56,960 53,120 134,400 847,360
Harvested Cropland 79,340 41,656 4,594 38,351 2,190 166,131
Corn for Grain 20,932 12,839 9,164 7,198 212 50,345
Corn for Silage/Greenchop 5,216 3,558 84 4,186 13,044
Wheat for Grain (all) 5,963 2,835 3,985 130 12,913
Oats for Grain 2,560 1,255 69 50 100 4,034
Barley for Grain 29 175 1 391 596
Vegetables Harvested for Sale 274 908 -- 118 30 1,330
Sweet Corn -- -- -- -- -- 0
Cut Christmas Trees 256 258 -- 227 v 741
Other Forage (hay, haylage, grass,
silage, & greenchop)
28,328 10,477 4,199 15,696 1,789 60,489
Soybeans for Beans 17,036 10,051 -- 7,930 -- 35.017
Blueberries, Raspberries, Strawberries 49 31 -- -- -- 80
Land in Orchards 395 189 -- 828 -- 1,412
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natural communities (NC005 and NC006)]; Ohio River [habitat for several fish species of
concern]; Ohioview [which includes a rivertine forest community (NC008) and habitat
for species of concern (SA004, SA005, SA007, SA008 and SA010).]
A search of the Pennsylvania Natural Diversity Inventory Index to identify potential
impacts to threatened and endangered, and/or special concern plant species within the
project area was as conducted. The PNDI is a database run by the Pennsylvania Natural
Heritage Program that provides information on the location and status of important
ecological resources. A search of the PNDI Database (Search #20140318443038)
indicated that further development of the proposed Project site should have no known
impacts on plant species federally protected under the Endangered Species Act, and no
known impact on Pennsylvania plant species of special concern if conservation measures
are implemented within the riparian buffer.
To evaluate whether any vegetation outside of the Beaver County area, but within the ten
county region might contain vegetation of special concern, the 2009 Environmental
Report, produced by the Nuclear Regulatory Commission (NRC) to support approval of
the license renewal for the Beaver Valley Nuclear Plant (BVNP) was reviewed. BVNP is
located 7 miles west of the proposed Project site. As shown in Table 7-4, the NRC
identified 11 Pennsylvania-listed plant species that have the potential to occur within the
vicinity (50 mile radius) of BVNP.160,161,162 The NRC noted that none of these plants
were identified in a 2002 survey of the area, and the NRC concluded that tall larkspur
(Delphinium exaltatum) was the only species of plant that had the potential to occur in
the impact area in the future. No records exist that document its historical occurrence in
160 The Beaver Valley Nuclear Plant is located approximately 7 miles west of the Franklin Ethane Cracker
facility. The application for permit renewal and final environmental report considered impacts within a
50 miles radius of the facility. 161 No federally-listed, vegetation species were identified with the potential to occur in the vicinity. 162 “Generic Environmental Impact Statement for License Renewal of Nuclear Plants,” NUREG-1437,
Supplement 36, Nuclear Regulatory Commission, p 81, May 2009.
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Table 7-4. Pennsylvania-Listed Plant Species with Potential to Occur in Vicinity of
Beaver Valley Nuclear (BVN) Plant (7 miles from the Proposed Project Site)
Species Common Name State Listing Status
Carex typhina Cattail sedge Endangered Clematis viorna Vasevine Endangered
Delphinium exaltatum tall larkspur Endangered*
Helianthemum bicknellii Hoary frostweed Endangered
Juncus torreyi Torrey’s rush Threatened
Lithospermum latifolium American stoneseed Endangered
Matelea obliqua Climbing milkvine Endangered
Myriophyllum sibiricum Northern water-milfoil Endangered
Potamogeton tennesseensis Tennessee pondweed Endangered
Cypripedium calceolus var.
parviflorum
Lesser yellow lady’s slipper Endangered
*Only species determined by NRC for potential to occur within vicinity of BVN plant.
the Beaver County area, however, there is a record of occurrence before 1980 in
Allegheny and Butler Counties, and after 1980 in Washington County.163 164
7.3.2.5 Identification of Pollutants of Concern
There are substantial scientific data characterizing the effects of air pollutant emissions
on certain crops (e.g., common wheat), whereas there are limited data available for other
crops. This subsection discusses the methodology utilized to identify air pollutants, and
constituents thereof, to which the identified crops and recreational vegetation may be
sensitive. Air pollutants can affect crops through two principal means:
Direct phytotoxic effects from air concentrations of pollutants; and
Indirect phytotoxic effects due to deposition of pollutants in soils in which the
crops are growing.
Direct Phytotoxic Effects of Air Pollutants: Of the gaseous air pollutants covered by
this analysis, only NOX (i.e., NO and NO2) is known to be toxic to some plants at
moderate to high concentrations in the ambient air. Carbon monoxide and volatile
163 Id. 164 Tall Larkspur (Delphinium exaltatum) Fact Sheet, Pennsylvania Natural Heritage Program.
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organic compounds are generally not phytotoxic.165,166,167,168 Thus, these pollutants were
not considered further by this analysis. Studies linking gaseous species of nitrogen (N) to
plant foliar damage have been conducted well above concentration levels occurring in the
United States. Thus, there is little evidence to show that current U.S. concentrations of
gaseous phase N cause phytotoxic effects.169 In the 2008 review of the secondary NO2
NAAQS, EPA concluded that agricultural ecosystems are not sensitive to N
concentrations found in the U.S.170
7.3.2.6 Determination of Effects Concentrations
This section discusses the methodology used to determine the air pollutant concentrations
that may be expected to result in adverse effects to the vegetation species.
Direct Phytotoxic Effects: As is customary for this type of analysis, the assessment
relied heavily on the screening criteria in the U.S. EPA report, A Screening Procedure for
the Impacts of Air Pollution Sources on Plants, Soils, and Animals.171 This document
establishes the air pollutant concentrations that are generally viewed by U.S. EPA to be
protective of soils and vegetation having significant commercial or recreational value,
including agricultural crops, based on a broad review of pertinent scientific literature.
165 Smith, A.E., and J.B. Levenson. A Screening Procedure for the Impacts of Air Pollution Sources on
Plants, Soils, and Animals (EPA-450/2-81-078). U.S. EPA, Office of Air Quality Planning and
Standards. Research Triangle Park, NC. December 1980. p. 11. 166 Air Quality Criteria for Carbon Monoxide. U.S. Department of Health, Education, and Welfare, Public
Health Service, National Air Pollution Control Administration. Washington, DC. March 1970. pp. 7-1
through 7-3. 167 Air Quality Criteria for Hydrocarbons. U.S. Department of Health, Education, and Welfare, Public
Health Service, National Air Pollution Control Administration. Washington, DC. March 1970. pp. 6-1
through 6-9. 168 E.M. Hulzebos et al. “Phytotoxicity Studies with Lactuca Sativa in Soil and Nutrient Solutions.”
Environmental Toxicology and Chemistry. Volume 12. 1993. pp. 1079-1094. 169 “Executive Summary Integrated Science Assessment Oxides of Nitrogen and Sulfur Ecological
Criteria.” EPA/600/R-08/082F, Dec. 2008. 170 ISA at 713. 171 Smith, A.E., and J.B. Levenson. A Screening Procedure for the Impacts of Air Pollution Sources on
Plants, Soils, and Animals (EPA-450/2-81-078). U.S. EPA, Office of Air Quality Planning and
Standards. Research Triangle Park, NC. December 1980.
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The secondary National Ambient Air Quality Standards (NAAQS),172 which are
established by U.S. EPA at levels that are protective of the public welfare, including
agriculture, are also relied on.
Indirect Deposition Effects: Two general approaches have been used in establishing
deposition rate limits and soil concentration limits: a) preventing accumulation of
pollutants in soils; and b) maximizing the capacity of soils to assimilate, attenuate, and
detoxify pollutants. The first approach is based on the premise that soil can be used
without any undue restriction if it is maintained free of contamination; if pollutants are
artificially introduced and are allowed to accumulate in the soil, then, over the long term,
the potential uses of the soil may become limited. The second approach is based on the
premise that soils have a capacity to detoxify pollutants. This approach has been applied
by the U.S. EPA and by the World Health Organization.173
7.3.2.7 Results
This section presents the results of dispersion modeling for each air pollutant, and
assesses these results with respect to effects levels.
NOX Effects: NOX includes both nitric oxide (NO) and nitrogen dioxide (NO2), and
much of the scientific literature treats these two gases separately.
Based on the results of the air quality impacts analysis, the maximum predicted ambient
NOX concentrations due to emissions from the facility are 44.2 μg/m3 (1-hour average)
and 0.79 μg/m3 (annual average). These values represent total NOX, including both NO
and NO2. These impacts are one to two orders of magnitude below the secondary
NAAQS of 100 μg/ m3 (annual average)174 and the minimum U.S. EPA screening values
172 See, 40 CFR part 50. 173 A.C. Chang, et al. Developing Human Health-related Chemical Guidelines for Reclaimed Water and
Sewage Sludge Applications in Agriculture. World Health Organization. Copenhagen, Denmark. May
2002. pp. 19-41. 174 40 CFR § 50.11(c).
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of 3,760 μg/ m3 (4-hr average) and 94 μg/ m3 (annual average).175 Both the secondary
NAAQS and the screening value are expressed in terms of NO2; there are no NAAQS or
screening values for NO.176
The agricultural crops for which the minimum U.S. EPA screening value is listed as
being protective include barley, corn, oats, vegetables (carrot, lettuce, leek, broccoli,
radish, peas). The principal crops identified in the 10-county area (Table 7-4 above) that
are not specifically listed in the Screening Procedures report are soybean and forage (e.g.
hay).177
The literature was reviewed to ascertain whether there exists, in the scientific literature,
any basis for concluding that: a) the secondary NAAQS and the minimum U.S. EPA
screening value are not protective of any of the crops identified herein; or b) the facility’s
NOX emissions will have an unacceptable, adverse impact on agricultural crops in the
five-county study area. A summary of the findings follows.
In April 2012, U.S. EPA issued a final rule retaining and affirming the secondary NO2
NAAQS of 100 μg/ m3 (annual average).178 This action reflected both the U.S. EPA
Administrator’s finding that this standard is “adequate to protect against direct phytotoxic
effects on vegetation”179 and the judgment that an alternative standard to protect against
deposition-related effects is not supported by currently available data.180 The data relied
upon by U.S. EPA with respect to direct phytotoxic effects are summarized in the
Integrated Science Assessment,181 including the following observations:
175 Smith, A.E., and J.B. Levenson. A Screening Procedure for the Impacts of Air Pollution Sources on
Plants, Soils, and Animals (EPA-450/2-81-078). U.S. EPA, Office of Air Quality Planning and
Standards. Research Triangle Park, NC. December 1980. p. 11. 176 Ibid. 177 Ibid at p. 68. 178 See, generally, 77 Fed. Reg. 20218. April 3, 2012. 179 Ibid at p. 20241. 180 Ibid at pp. 20262-63. 181 Integrated Science Assessment for Oxides of Nitrogen and Sulfur – Ecological Criteria (EPA-600/R-08-
082F). U.S. EPA, Office of Research and Development. Research Triangle Park, NC. December 2008.
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An analysis of over 50 peer-reviewed reports on the effects of NO2 on foliar
injury indicated that plants are relatively resistant to NO2. With few exceptions,
visible injury was not reported at concentrations below 377 μg/ m3, and these
occurred when the cumulative duration of exposures extended to 100 hours or
longer.
Soybean, peas (Pisum sativum L.) radish (Raphanus sativus L.) are among
numerous plant species for which no phytotoxic effects were documented based
on exposure to NO2 at 189 μg/ m3.182
In 2000, the WHO instituted a NOX guideline concentration value of 30 μg/m3 on an
annual average (including both NO and NO2, expressed as NO2). The WHO declined to
institute a short-term value, saying “[t]here are insufficient data to provide these levels
with confidence at present,” but indicated that current evidence would suggest a guideline
NOX concentration value of about 75 μg/m3 on a daily average. The guideline
concentration value is intended to be protective of all classes of vegetation under all
environmental conditions.183
In summary, the scientific literature affirms that the secondary NAAQS and the minimum
annual U.S. EPA screening value are protective of the crops identified herein. The
maximum predicted NOX concentration resulting from the Project and other emission
sources in the area is well below the secondary NAAQS, the minimum U.S. EPA
screening value, guideline concentration values established by foreign governmental
agencies, and concentrations that are identified in the literature as being harmful to
commercially significant vegetation in the ten-county study area.
A search was conducted to determine whether any information identifies a unique
sensitivity of tall larkspur, the only endangered plant species NRC identified with
potential to occur within the vicinity of the Beaver Valley Nuclear plant (and hence the
vicinity of the Project). Tall larkspur grows in meadows at high elevations and is
poisonous to cattle. Efforts to develop an effective herbicide program have led to
182 Ibid at pp. 3-200 through 3-201. 183 Air Quality Guidelines for Europe, 2nd Ed. World Health Organization, Regional Office for Europe.
Copenhagen, Denmark. 2000. pp. 230-233.
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experiments with a high rate of N application on the plant. A variety of these studies
demonstrate that tall larkspur is generally resistant to high concentration N application,
and that herbicide mortality is linked to salt concentrations, not N concentrations.184
7.3.2.8 Conclusion
Based on the effects analysis described herein, the facility’s emissions are not expected to
result in adverse effects to soils, crops, or plant species of concern, within the vicinity of
the Project site. For each pollutant of concern, the predicted ambient concentration or the
predicted deposition rate is well below the secondary NAAQS and the minimum
screening values established by U.S. EPA. Nothing in the scientific literature identified
during this review indicates that the secondary NAAQS and the minimum U.S. EPA
screening values are not protective of any identified crops and, the predicted ambient
concentration or the predicted deposition rate is less than the screening values established
by other governmental authorities. Moreover, the only identified plant species of
concern, tall larkspur, is resistant to N application in experimental studies.
184 “Mechanism by which ammonium fertilizer kill tall larkspur,” Woolsey, et.al., Journal of Range
Management, 56, 524-528, Sept 2003. (citing results of various historical studies).
Appendix A Plan Approval Application Forms
Section B - Processes Information (Ethylene Manufacturing) 1. Source Information
Source Description (give type, use, raw materials, product, etc). Attach additional sheets as necessary. Ethylene manufacturing process is described in detail in Section 3.1 of the Plan Approval Application.
Manufacturer To be determined
Model No. Number of Sources
Source Designation Maximum Capacity Rated Capacity Ethylene: 1,500,000 metric tons/yr
Type of Material Processed
Maximum Operating Schedule Hours/Day 24
Days/Week 7
Days/Year 7
Hours/Year 365
Operational restrictions existing or requested, if any (e.g., bottlenecks or voluntary restrictions to limit PTE)
Capacity (specify units) Per Hour Per Day Per Week Per Year
1,500,000 metric tons/yr Operating Schedule Hours/Day 24
Days/Week 7
Days/Year 7
Hours/Year 365
Seasonal variations (Months) From to If variations exist, describe them
N/A
2. Fuel
Type Quantity Hourly Annually Sulfur
% Ash (Weight) BTU Content
Oil Number GPH @ 60°F X 103
Gal % by wt
Btu/Gal. & Lbs./Gal. @ 60 °F
Oil Number GPH @ 60°F X 103
Gal % by wt
Btu/Gal. & Lbs./Gal. @ 60 °F
Natural Gas SCFH X 106
SCF grain/100
SCF Btu/SCF
Gas (other) SCFH X 106
SCF grain/100
SCF Btu/SCF
Coal TPH Tons % by wt Btu/lb
Other *
*Note: Describe and furnish information separately for other fuels in Addendum B.
Section B - Processes Information (Ethylene Manufacturing) (Continued) 6. Miscellaneous Information Attach flow diagram of process giving all (gaseous, liquid and solid) flow rates. Also, list all raw materials charged to process equipment, and the amounts charged (tons/hour, etc.) at rated capacity (give maximum, minimum and average charges describing fully expected variations in production rates). Indicate (on diagram) all points where contaminants are controlled (location of water sprays, collection hoods, or other pickup points, etc.). Describe collection hoods location, design, airflow and capture efficiency. Describe any restriction requested and how it will be monitored. See the Plan Approval Application as follows: A detailed project description containing flow diagrams is included as Section 3.1. Raw materials and capacity information are provided in Appendices B and D. No restrictions on the production capacity are requested.
Describe fully the facilities provided to monitor and to record process operating conditions, which may affect the emission of air contaminants. Show that they are reasonable and adequate. N/A
Describe each proposed modification to an existing source. N/A
Identify and describe all fugitive emission points, all relief and emergency valves and any by-pass stacks. Fugitive emissions will result from equipment leaks, tanks, paved roads and parking areas, cooling towers, and pressure safety valves (psvs). Additional information related to the control and monitoring of the fugitive emissions points is presented in Section 5.0 of the Plan Approval Application Describe how emissions will be minimized especially during start up, shut down, process upsets and/or disruptions. The facility will install BACT and LAER controls as proposed in Section 5.0 of the Plan Approval Application. Where appropriate startup and shutdown BACT/LAER limits are proposed. A VOC control system will be used to minimize emissions during startup, shutdown, and upsets. The VOC Control System LAER proposal (see Section 5.12) includes submittal of a waste gas minimization plan (WGMP) along with the performance of a root cause and corrective action analysis in response to events greater than a defined trigger level. The proposed WGMP will include procedures to minimize emissions during startup, shutdown, and upset. Anticipated Milestones:
i. Expected commencement date of construction/reconstruction/installation: Late 2015 ii. Expected completion date of construction/reconstruction/installation: 2018 iii. Anticipated date of start-up: 2018
Section B – Combustion Unit Information (Ethane Cracking Furnaces (7x)) 1. Combustion Units: Coal Oil Natural Gas Other:
Tailgas (85% hydrogen & 15% methane by volume) Description: ETHANE CRACKING FURNACES: Furnaces will be fired with a fuel comprised of
tail gas and a makeup portion of natural gas defined by the systems fuel balance. In the presence of steam, ethane will be thermally cracked to form ethylene. As part of the cracking
process, other cracking side products will be formed. Tail gas is a side product of the cracking process.
Manufacturer TBD
Model No.
Number of units Seven (7)
Maximum heat input (Btu/hr) 620 MM (each)
Rated heat input (Btu/hr)
Typical heat input (Btu/hr)
Furnace Volume
Grate Area (if applicable) N/A
Method of firing
Indicate how combustion air is supplied to boiler N/A Indicate the Steam Usage:
Mark and describe soot Cleaning Method: i. Air Blown ii. Steam Blown iii. Brushed and Vacuumed
iv. Other v. Frequency of Cleaning
As part of the cracking process, coke is formed on the process side of the furnace tubes. As a result, the tubes in each cracking furnace are decoked once every 30 to 60 days. To ensure complete combustion the exhaust gases generated by the decoking process are directed back into the cracking furnace.
Maximum Operating schedule (per Furnace) Hours/Day 24
Days/Week 7
Days/Year 365
Hours/Year 8760
Operational restrictions taken or requested, if any (e.g., bottlenecks or voluntary restrictions to limit potential to emit)
Capacity (specify units) Per hour
Per day
Per week
Per year
Typical Operating schedule Hours/Day 24
Days/Week 7
Days/Year 365
Hours/Year 8760
Seasonal variations (Months): If variations exist, describe them. Operating using primary fuel: From to Operating using secondary fuel: Form to Non-operating: From to 2. Specify the primary, secondary and startup fuel. Furnish the details in item 3.
During start-up, furnaces are fired on natural gas until ethane cracking begins and self-produced tail-gas becomes available. At that point the furnace is primarily tailgas-fired with some natural gas being used to meet the process’ heat balance requirements.
Section B - Combustion Unit Information (Ethane Cracking Furnaces (7x)) (Continued) 3. Fuel
Type Quantity Hourly Annually Sulfur
% Ash (Weight) BTU Content
Oil Number
GPH @ 60°F
X 103 Gal
% by wt
Btu/Gal. & Lbs./Gal. @ 60 °F
Oil Number
GPH @ 60°F
X 103 Gal
% by wt
Btu/Gal. & Lbs./Gal. @ 60 °F
Oil Number
GPH @ 60°F
X 103 Gal
% by wt
Btu/Gal. & Lbs./Gal. @ 60 °F
Natural Gas
77,200 SCFH
X 106
Gal
0.5 gr/100 SCF
1020 Btu/SCF
Gas (other)
SCFH
X 106
Gal
gr/100
SCF
Btu/SCF
Coal Other* Tailgas 1,174,000 0% 461 Btu/SCF * Note: Describe and furnish information separately for other fuels in Addendum B. 4. Burner Manufacturer TBD
Model Number
Type of Atomization (Steam, air, press, mech., rotary cup)
Number of Burners TBD
Maximum fuel firing rate (all burners)
Normal fuel firing rate
If oil, temperature and viscosity. Maximum theoretical air requirement Percent excess air 100% rating Turndown ratio Combustion modulation control (on/off, low-high fire, full automatic, manual). Describe. Main burner flame ignition method (electric spark, auto gas pilot, hand-held torch, other). Describe. 5. Nitrogen Oxides (NOx) control Options
Mark and describe the NOx control options adopted Low excess air (LEA) Over fire air (OFA) x Low-NOx burner Low NOx burners with over fire
air
Flue gas recirculation Burner out of service Reburning x Flue gas treatment (SCR /
SNCR)
Other:.
Section B - Combustion Unit Information (Ethane Cracking Furnaces (7x)) (Continued)
6. Miscellaneous Information
Describe fly ash reinjection operation N/A
Describe, in detail, the equipment provided to monitor and to record the source(s) operating conditions, which may affect emissions of air contaminants. Show that they are reasonable and adequate.
NOx monitoring will meet 40 CFR Part 75 requirements as referenced by 25 Pa. Code Ch. 145.
Describe each proposed modification to an existing source.
N/A
Describe how emissions will be minimized especially during start up, shut down, combustion upsets and/or disruptions. Provide emission estimates for start up, shut down and upset conditions. Provide duration of start up and shut down.
Emissions will be minimized through operation in accordance with the proposed BACT/LAER limits cracking furnace limits and the waste gas minimization plan. Emissions estimates associated with startup and shutdown of the cracking furnaces are provided in Appendix B of the Plan Approval Application.
Describe in detail with a schematic diagram of the control options adopted for SO2 (if applicable). N/A
Anticipated milestones:
Expected commencement date of construction/reconstruction: Late 2015 Expected completion date of construction/reconstruction: 2018 Anticipated date(s) of start-up: 2018
Section C - Air Cleaning Device (Ethane Cracking Furnaces (7x))
1. Precontrol Emissions* Please refer to Appendix B in the Plan Approval Application for this emissionsdataEmission Rate
Pollutant
Maximum Emission Rate Calculation/ Estimation
Method Specify Units Pounds/Hour Hours/Year Tons/Year PM
PM10
SOx
CO
NOx
VOC
Others: (e.g., HAPs) ----- ----- ----- -----
* These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operatingschedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emissionvalues were determined. Attach calculations.
2. Gas Conditioning – N/A
Water quenching YES NO Water injection rate GPM
Radiation and convection cooling YES NO Air dilution YES NO
If YES, CFM
Forced draft YES NO Water cooled duct work YES NO
Other
Inlet volume
ACFM@ °F
Outlet volume
ACFM@ °F % Moisture
Describe the system in detail.
* Please refer to the Plan Approval Application for a detailed process description.
Section C - Air Cleaning Device (Ethane Cracking Furnaces (7x)) (Continued)
8. SELECTIVE CATALYTIC REDUCTION (SCR)
SELECTIVE NON-CATALYTIC REDUCTION (SNCR)
NON-SELECTIVE CATALYTIC REDUCTION (NSCR)
Equipment specifications Manufacturer
To be determined
Type Model No
Design inlet volume (SCFM) Design operating temperature (°F)
Is the system equipped with process controls for proper mixing/control of the reducing agent in gas stream? If yes, give details.
Attach efficiency and other pertinent information (e.g., Ammonia, urea slip). SCR will be designed to meet the proposed NOx LAER/BACT limits (See Section 5.2.1 of the Plan Approval Application). Operating parameters
Volume of gases handled (ACFM) @ (°F) Operating temperature range for the SCR/SNCR/NSCR system (°F) From To
Reducing agent used, if any. Ammonia
Oxidation catalyst used, if any.
State expected range of usage rate and concentration.
Service life of catalyst Ammonia slip (ppm) 10 ppmvd @ 3% O2
Describe fully with a sketch giving locations of equipment, controls system, important parameters and method of operation.
Describe the warning/alarm system that protects against operation when unit is not meeting design requirements.
Emissions data: Please refer to Section 5.2 and Appendix B of the Plan Approval Application for this emissions data.
Pollutant Inlet Outlet Removal Efficiency (%) NOx 0.01 lb/MMBtu Annual
Avg. 85 – 90%
NOx 0.015 lb/MMBtu 24-hr rolling avg.
85 – 90%
Section C - Air Cleaning Device (VOC Control System- HP System Ground Flares (2x)) (Ethylene Manufacturing)
1. Precontrol Emissions* See Appendix B of the Plan Approval Application
Pollutant
Maximum Emission Rate Calculation/ Estimation
Method Specify Units Pounds/Hour Hours/Year Tons/Year PM PM10 SOx CO NOx VOC Others: (e.g., HAPs) ----- ----- ----- ----- -----
* These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operatingschedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emissionvalues were determined. Attach calculations.
2. Gas Cooling
Water quenching Yes No Water injection rate GPM
Radiation and convection cooling Yes No
Air dilution Yes No If yes, CFM
Forced Draft Yes No Water cooled duct work Yes No
Other
Inlet Volume ACFM
@ °F % Moisture
Outlet Volume ACFM
@ °F % Moisture
Describe the system in detail.
VOC emissions resulting from startup, shutdown, maintenance and upset at the ethane cracking unit and PE manufacturing units will be routed to the HP Flare System. The HP system consists of one elevated flare with a relieving capacity of 1,200 tons/hr and two totally enclosed ground flares, each rated for 150 tons/hr. The HP elevated flare will only be used to control emissions during upsets. The two HP Ground Flares will be used to control VOC emission associated with startup, shutdown, and maintenance of the ethylene manufacturing plant. Emissions associated with the two HP Ground and Elevated Flares are included in Appendix B of the Plan Approval Application. NOTE: This is the same HP Flare System presented in the forms for PE Plants.
Section C - Air Cleaning Device (VOC Control System -HP System Ground Flares (2x)) (Ethylene Manufacturing) (Continued)
12. Flares Equipment Specifications
Manufacturer To be determined
Type Elevated flare Ground flare Other Describe
Model No.
Design Volume (SCFM)
Dimensions of stack (ft.) Diameter 55 Height 110
Residence time (sec.) and outlet temperature (°F) 1832
Turn down ratio
Burner details
Describe the flare design (air/steam-assisted or nonassisted), essential auxiliaries including pilot flame monitor of proposed flare with a sketch. Non-assisted, pilot flame monitoring
Describe the operation of the flare’s ignition system.
Describe the provisions to introduce auxiliary fuel to the flare.
Operation Parameters
Detailed composition of the waste gas
Heat content
Exit velocity
Maximum and average gas flow burned (ACFM)
Operating temperature (°F)
Describe the warning/alarm system that protects against operation when unit is not meeting design requirements.
Emissions Data See Appendix B of the Plan Approval Application
Pollutant Inlet Outlet Removal Efficiency (%)
Section C - Air Cleaning Device (VOC CONTROL SYSTEM -HP System Elevated Flare)
(Ethylene Manufacturing)
1. Precontrol Emissions* See Appendix B of the Plan Approval Application
Pollutant
Maximum Emission Rate Calculation/ Estimation
Method Specify Units Pounds/Hour Hours/Year Tons/Year PM PM10 SOx CO NOx VOC Others: (e.g., HAPs) ----- ----- ----- ----- ----- * These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating
schedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emission values were determined. Attach calculations.
2. Gas Cooling
Water quenching Yes No Water injection rate GPM
Radiation and convection cooling Yes No
Air dilution Yes No If yes, CFM
Forced Draft Yes No Water cooled duct work Yes No
Other
Inlet Volume ACFM
@ °F % Moisture
Outlet Volume ACFM
@ °F % Moisture
Describe the system in detail.
VOC emissions resulting from startup, shutdown, maintenance and upset at the ethane cracking unit and PE manufacturing units will be routed to the HP Flare System. The HP system consists of one elevated flare with a relieving capacity of 1,200 tons/hr and two totally enclosed ground flares, each rated for 150 tons/hr. The HP elevated flare will only be used to control emissions during upsets. The two HP Ground Flares will be used to control VOC emission associated with startup, shutdown, and maintenance of the ethylene manufacturing plant and PE Units. Emissions associated with the two HP Ground and Elevated Flares are included in Appendix B of the Plan Approval Application. NOTE: This is the same HP Flare System presented in the forms for the PE Plants..
Section C - Air Cleaning Device (VOC CONTROL SYSTEM -HP System Elevated Flare) (Ethylene Manufacturing) (Continued)
12. FLARES Equipment Specifications
Manufacturer
Type Elevated flare Ground flare Other Describe
Model No.
Design Volume (SCFM)
Dimensions of stack (ft.) Diameter Height
Residence time (sec.) and outlet temperature (°F) 1832
Turn down ratio
Burner details
Describe the flare design (air/steam-assisted or non-assisted), essential auxiliaries including pilot flame monitor of proposed flare with a sketch. Steam assisted. Refer to Section 3.5.5 and Section 5.12 of the Plan Approval Application for full flare description. Pilot flame monitoring. Describe the operation of the flare’s ignition system.
Describe the provisions to introduce auxiliary fuel to the flare.
Operation Parameters See Appendix B of the Plan Approval Application Detailed composition of the waste gas
Heat content
Exit velocity
Maximum and average gas flow burned (ACFM)
Operating temperature (°F)
Describe the warning/alarm system that protects against operation when unit is not meeting design requirements.
Emissions Data See Appendix B of the Plan Approval Application
Pollutant Inlet Outlet Removal Efficiency (%)
Section C - Air Cleaning Device (Ethylene Manufacturing) (Continued)
10. Costs – Refer to Section 5.0 of the Plan Approval Application
Indicate cost associated with air cleaning device and its operating cost (attach documentation if necessary)
Device Direct Cost Indirect Cost Total Cost Operating Cost
11 MISCELLANEOUS Describe in detail the removal, handling and disposal of dust, effluent, etc. from the air cleaning device including proposed methods of controlling fugitive emissions.
N/A
Attach manufacturer's performance guarantees and/or warranties for each of the major components of the control system (or complete system).
Expected guarantees of control system performance consistent with levels determined as BACT/LAER/BAT.
ch the maintenance schedule for the control equipment and any part of the process equipment that, if in disrepair, would increase air contaminant emissions.
Maintenance will be performed per manufacturer’s recommendations, as needed during operations, and during planned or forced outages as necessary.
Section E - Compliance Demonstration (Ethylene Manufacturing)
Note: Complete this section if the facility is not a-Title V facility. Title V facilities must complete Addendum A. Method of Compliance Type: Check all that apply and complete all appropriate sections below.
Monitoring Testing Reporting
Recordkeeping Work Practice Standard
Monitoring: Refer to Table 5-1 of the Plan Approval Application for more information a. Monitoring device type (stack test, CEM etc.): NOx and CO: CEMs;
VOC and PM/PM10/PM2.5:Stack test; CO2e/GHG; In-line gas chromatograph or 40 CFR 98.34(b)(3)
b. Monitoring device location: NOx (upstream of SCR and stack); CO (stack); Fuel Supply
c. Describe all parameters being monitored along with the frequency and duration of monitoring each parameter: Continuous measurement of NOx and CO concentration, and volumetric flow rate, 5 year performance test for PM and VOC, and hourly monitoring of total fuel flow, HHV, carbon content and MW.
Testing: a. Reference Test Method Citation: PM: EPA Method 5, and 202.
VOC: EPA Method 18, 25,
CO2e/GHG: 40 CFR 98.34(b)(3)
b. Reference Test Method Description: Method 18-Measurement of Gaseous Organic Compound Emissions by Gas Chromatography; Method 25-Determination of Total Gaseous Nonmethane Organic Emissions as Carbon; Method 5 – Determination of Particulate Matter Emissions from Stationary Sources; Method 202 – Dry Impinger Method for Determining Condensable Particulate Matter from Stationary Sources. 40CFR 98.34(b)(3) – Contains procedure for determining carbon content and molecular weight of fuels.
Recordkeeping: Describe the parameters that will be recorded and the recording frequency:
Records kept for continuous measurement of NOx and CO concentration and volumetric flow rate (15-minute value), 5 year performance test for PM and VOC, and hourly monitoring of total fuel flow, HHV, carbon content and MW (daily).
Reporting: a. Describe the type of information to be reported and the reporting frequency:
Reporting of required monitoring in compliance with regulations listed in Appendix G of the Plan Approval Application. Submittal of reports of required monitoring semi-annually per 25 Pa. Code § 127.511(c)
b. Reporting start date: To be determined
Work Practice Standard: Describe each: Good combustion design of the furnaces and operation for control of VOC, PM/PM10/PM2.5, and CO. Highly energy efficient design and operation for control of CO2e (GHG). VOC Control System – Waste gas minimization and operation to achieve good destruction removal efficiency. Flares will be designed to meet limitations on maximum exit velocity, as set forth in the general provisions at 40 CFR 60.18 and 63.11. Flares will be operated to meet minimum net heating value requirements for gas streams combusted in flares as set forth in 40 CFR 60.18/63.11 Further details on the VOC Control System compliance methods are presented in Section 5.0 of the Plan Approval Application
Refer to the Plan Approval Application for further details.
Section F - Flue and Air Contaminant Emission
1. Estimated Maximum Emissions* Refer to Appendix B for emissions calculations
Pollutant
Maximum emission rate Calculation/
Estimation Method specify units lbs/hr tons/yr. PM
PM10
SOx
CO
NOx
VOC
Others: ( e.g., HAPs) ----- ----- ----- -----
* These emissions must be calculated based on the requested operating schedule and/or process rate e.g., operating schedule for maximum limits or restricted hours of operation and /or restricted throughput. Describe how the emission values were determined. Attach calculations. Refer to Appendix B of the Plan Approval Application for emissions calculations.
2. Stack and Exhauster Refer to Appendix C of the Plan Approval Application
Stack Designation/Number: Seven (7) Identical Stacks –
List Source(s) or source ID exhausted to this stack: F-11101, F12101, F-13101, F-14101, F-15101, F-16101, F-17101
% of flow exhausted to stack: 100
Stack height above grade (ft.) Grade elevation (ft.)
Stack diameter (ft) or Outlet duct area (sq. ft.)
Weather Cap YES NO
Distance of discharge to nearest property line (ft.). Locate on topographic map.
If modeling (estimating) of ambient air quality impacts is needed, attach a site plan with buildings and their dimensions and other obstructions. Refer to Appendix C of the Plan Approval Application
Location of Stack** Latitude/Longitude Point of Origin
Latitude Longitude
Degrees Minutes Seconds Degrees Minutes Seconds
Stack Exhaust
Volume ACFM Temperature °F Moisture %
Exhauster (attach fan curves) in. of water HP @ RPM.
** If the datum and collection method information and codes differ from those provided on the General Information Form - Authorization Application, provide the additional required by that form on a separate sheet.
Section B - Processes Information (Polyethylene Plants 1 & 2) 1. Source Information:
Source Description (give type, use, raw materials, product, etc). Attach additional sheets as necessary. Polyethylene (PE) Plants 1 and 2 are described in detail in Section 3.2 of the Plan Approval Application.
Manufacturer(s) To be determined
Model No.
Number of Sources See Appendix D of the Plan Approval Application
Source Designation See Table D-2 of the Plan Approval Application
Maximum Capacity:
Rated Capacity (Design capacities) Polyethylene: 1200 metric tons/yr
Type of Material Processed: Ethylene polymerized with comonomer to produce various grades of polyethylene (PE). Maximum Operating Schedule Hours/Day 24
Days/Week 7
Days/Year 365
Hours/Year 8760
Operational restrictions existing or requested, if any (e.g., bottlenecks or voluntary restrictions to limit PTE) Capacity (specify units) Per Hour
Per Day
Per Week
Per Year 1200 metric tons/yr PE, total
Operating Schedule Hours/Day 24
Days/Week 7
Days/Year 365
Hours/Year 8760
Seasonal variations (Months) From to If variations exist, describe them N/A
2. Fuel:
Type Quantity Hourly Annually Sulfur
% Ash (Weight) BTU Content
Oil Number
GPH @ 60°F
X 103
Gal
% by wt
Btu/Gal. & Lbs./Gal. @ 60 °F
Oil Number
GPH @ 60°F
X 103
Gal
% by wt
Btu/Gal. & Lbs./Gal. @ 60 °F
Natural Gas SCFH
X 106
SCF
grain/100
SCF
Btu/SCF
Gas (other)
SCFH
X 106
SCF
grain/100
SCF
Btu/SCF
Coal
TPH Tons % by wt Btu/lb
Other *
*Note: Describe and furnish information separately for other fuels in Addendum B.
Section B – Processes Information (Polyethylene Plants 1 & 2) (Continued) 6. Miscellaneous Information Attach flow diagram of process giving all (gaseous, liquid and solid) flow rates. Also, list all raw materials charged to process equipment, and the amounts charged (tons/hour, etc.) at rated capacity (give maximum, minimum and average charges describing fully expected variations in production rates). Indicate (on diagram) all points where contaminants are controlled (location of water sprays, collection hoods, or other pickup points, etc.). Describe collection hoods location, design, airflow and capture efficiency. Describe any restriction requested and how it will be monitored. See the Plan Approval Application as follows: A detailed project description containing flow diagrams is included as Section 3.2. Raw materials and capacity information are provided in Appendices B and D. No restrictions on the production capacity are requested. Describe fully the facilities provided to monitor and to record process operating conditions, which may affect the emission of air contaminants. Show that they are reasonable and adequate. N/A
Describe each proposed modification to an existing source. N/A
Identify and describe all fugitive emission points, all relief and emergency valves, and any by-pass stacks. Fugitive emissions will result from equipment leaks, tanks, paved roads and parking areas, cooling towers, and pressure safety valves (psvs). Additional information related to the control and monitoring of the fugitive emissions points is presented in Section 5.0 of the attached Plan Approval Application.
Describe how emissions will be minimized especially during start up, shut down, process upsets and/or disruptions. The facility will install BACT and LAER controls as proposed in Section 5.0 of the Plan Approval Application. Where appropriate, startup and shutdown BACT/LAER limits are proposed. A VOC control system will be used to minimize emissions during startup, shutdown, and upsets. The VOC Control System LAER proposal (see Section 5.12) includes submittal of a waste gas minimization plan (WGMP) along with the performance of a root cause and corrective action analysis in response to events greater than a defined trigger level. The proposed WGMP will include procedures to minimize emissions during startup, shutdown, and upset. Anticipated Milestones:
i. Expected commencement date of construction/reconstruction/installation: Late 2015 ii. Expected completion date of construction/reconstruction/installation: 2018 iii. Anticipated date of start-up: 2018
Section C - Air Cleaning Device (Particulate Control - PE 1 & 2 Manufacturing and Pellet Handling)
1. Precontrol Emissions* (Refer to Appendix B for emissions calculations)
Pollutant
Maximum Emission Rate Calculation/ Estimation
Method Specify Units Pounds/Hour Hours/Year Tons/Year PM PM10 SOx CO NOx VOC Others: (e.g., HAPs) ----- ----- ----- ----- ----- * These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating
schedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emission values were determined. Attach calculations.
Describe the system in detail.
Appendix D of the Plan Approval Application provides a full listing of the PE manufacturing PM sources and proposed particulate filter control. A grain loading of 0.005 gr/dscf is proposed for all particulate containing vents, except truck and rail loading. A grain loading of 0.01 gr/dscf is proposed for truck and rail loading. Particulate filter technology will be used where feasible.
Section C - Air Cleaning Device (PE 1& 2 Manufacturing and Pellet Handling) (Continued) 5. Fabric Collector: Particulate filters be designed to achieve PM limits as presented in Section 5.0 of the Plan
Approval Application. Equipment Specifications Refer to Appendix D for PM Sources. Specifications TBD Manufacturer To be determined
Model No.
Pressurized Design Suction Design
Number of Compartments
Number of Filters Per Compartment
Is Baghouse Insulated? Yes No
Can each compartment be isolated for repairs and/or filter replacement?
Yes No
Are temperature controls provided? (Describe in detail)
Yes No
Dew point at maximum moisture °F Design inlet volume SCFM Type of Fabric
Material Felted Membrane Weight oz/sq.yd Woven Others: List: Thickness in Felted-Woven
Fabric permeability (clean) @ ½” water-∆ P CFM/sq.ft.
Filter dimensions Length Diameter/Width
Effective area per filter Maximum operating temperature (°F)
Effective air to cloth ratio Minimum Maximum
Drawing of Fabric Filter A sketch of the fabric filter showing all access doors, catwalks, ladders and exhaust ductwork, location of each pressure and temperature indicator should be attached.
Operation and Cleaning Volume of gases handled
ACFM @ °F
Pressure drop across collector (in. of water). Describe the equipment to be used to monitor the pressure drop.
Type of filter cleaning Manual Cleaning Bag Collapse Reverse Air Jets Mechanical Shakers Sonic Cleaning Other: Pneumatic Shakers Reverse Air Flow
Describe the equipment provided if dry oil free air is required for collector operation
Cleaning Initiated By Timer Frequency if timer actuated Expected pressure drop range in. of water Other Specify
Does air cleaning device employ hopper heaters, hopper vibrators or hopper level detectors? If yes, describe.
Describe the warning/alarm system that protects against operation when the unit is not meeting design requirements.
Emissions Data: Refer to Appendix B of the Plan Approval Application for Emissions Estimates Pollutant Inlet Outlet Removal Efficiency (%)
Section C - Air Cleaning Device (VOC Control System – LP System Thermal Incinerator) (Polyethylene Plants 1 & 2)
1. Precontrol Emissions See Appendix B of the Plan Approval Application
Pollutant
Maximum Emission Rate Calculation/ Estimation
Method Specify Units Pounds/Hour Hours/Year Tons/Year PM PM10 SOx CO NOx VOC Others: (e.g., HAPs) ----- ----- ----- ----- ----- * These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating
schedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emission values were determined. Attach calculations.
2. Gas Cooling
Water quenching Yes No Water injection rate GPM
Radiation and convection cooling Yes No
Air dilution Yes No If yes, CFM
Forced Draft Yes No Water cooled duct work Yes No
Other
Inlet Volume ACFM
@ °F % Moisture
Outlet Volume ACFM
@ °F % Moisture
Describe the system in detail.
VOC containing vents upstream of the Product Purge Bins will be routed to the VOC Control System’s LP header (LP System). The LP System consists of an LP Thermal Incinerator and an LP Ground Flare. The rated capacity of the Thermal Incinerator will be 12 tons/hr. The LP Ground Flare will only be used during process upsets. Emissions associated with the VOC Control System are included in Appendix B of the Plan Approval Application. Section 3 of the Plan Approval Application provides additional information on LP System. (NOTE: This is the same VOC Control System presented in the forms for Ethylene Manufacturing and PE Plant 3).
Section C - Air Cleaning Device (VOC Control System – LP System Thermal Incinerator) (Polyethylene Plants 1 & 2)
11. Oxidizer/Afterburners Equipment Specifications
Manufacturer To be determined
Type Thermal Catalytic Model No.
Design Inlet Volume (SCFM)
Combustion chamber dimensions (length, cross-sectional area, effective chamber volume, etc.)
Describe design features, which will ensure mixing in combustion chamber.
Describe method of preheating incoming gases (if applicable).
Describe heat exchanger system used for heat recovery (if applicable).
Catalyst used
Life of catalyst
Expected temperature rise across catalyst (°F)
Dimensions of bed (in inches). Height: Diameter or Width: Depth:
Are temperature sensing devices being provided to measure the temperature rise across the catalyst? Yes No If yes, describe.
Describe any temperature sensing and/or recording devices (including specific location of temperature probe in a drawing or sketch.
Burner Information
Burner Manufacturer
Model No.
Fuel Used
Number and capacity of burners
Rated capacity (each)
Maximum capacity (each)
Describe the operation of the burner
Attach dimensioned diagram of afterburner
Operating Parameters
Inlet flow rate (ACFM) @ °F Outlet flow rate (ACFM) @ °F
State pressure drop range across catalytic bed (in. of water).
Describe the method adopted for regeneration or disposal of the used catalyst.
Describe the warning/alarm system that protects against operation when unit is not meeting design requirements.
Emissions Data See Appendix B of the Plan Approval Application
Pollutant Inlet Outlet Removal Efficiency (%)
Section C - Air Cleaning Device (VOC Control System – LP System Ground Flare) (Polyethylene Plants 1 & 2)
1. Precontrol Emissions* See Appendix B of the Plan Approval Application
Pollutant
Maximum Emission Rate Calculation/ Estimation
Method Specify Units Pounds/Hour Hours/Year Tons/Year PM PM10 SOx CO NOx VOC Others: (e.g., HAPs) ----- ----- ----- ----- ----- * These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating
schedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emission values were determined. Attach calculations.
2. Gas Cooling
Water quenching Yes No Water injection rate GPM
Radiation and convection cooling Yes No
Air dilution Yes No If yes, CFM
Forced Draft Yes No Water cooled duct work Yes No
Other
Inlet Volume ACFM
@ °F % Moisture
Outlet Volume ACFM
@ °F % Moisture
Describe the system in detail.
Continuous and intermittent VOC containing vents prior to the upstream of the Product Purge Bins will be routed to the VOC Control System’s LP header (LP System). The LP Ground Flare will only be used during process upsets. Emissions associated with the VOC Control System are included in Appendix B of the Plan Approval Application. The capacity of the totally enclosed LP Ground Flare will be 45 ton/hr. Section 3 of the Plan Approval Application provides additional information on LP system. (NOTE: This is the same VOC Control System presented in the forms for Ethylene Manufacturing and PE Plant 3).
Section C - Air Cleaning Device (VOC Control System – LP System Ground Flare) (Polyethylene Plants 1 & 2) (Continued)
12. Flares Equipment Specifications
Manufacturer To be determined
Type Elevated flare Ground flare Other Describe
Model No.
Design Volume (SCFM)
Dimensions of stack (ft.) Diameter 34 Height 75
Residence time (sec.) and outlet temperature (°F) 1832
Turn down ratio
Burner details
Describe the flare design (air/steam-assisted or nonassisted), essential auxiliaries including pilot flame monitor of proposed flare with a sketch. Non-assisted, pilot flame monitoring.
Describe the operation of the flare’s ignition system.
Describe the provisions to introduce auxiliary fuel to the flare.
Operation Parameters
Detailed composition of the waste gas
Heat content
1 MMBtu/hr (Pilot) Exit velocity
Maximum and average gas flow burned (ACFM)
Operating temperature (°F)
Describe the warning/alarm system that protects against operation when unit is not meeting design requirements.
Emissions Data See Appendix B of the Plan Approval Application
Pollutant Inlet Outlet Removal Efficiency (%)
Section C - Air Cleaning Device (VOC Control System- HP System Ground Flares (2x)) (Polyethylene Plants 1 & 2)
1. Precontrol Emissions* See Appendix B of the Plan Approval Application
Pollutant
Maximum Emission Rate Calculation/ Estimation
Method Specify Units Pounds/Hour Hours/Year Tons/Year PM PM10 SOx CO NOx VOC Others: (e.g., HAPs) ----- ----- ----- ----- ----- * These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating
schedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emission values were determined. Attach calculations.
2. Gas Cooling
Water quenching Yes No Water injection rate GPM
Radiation and convection cooling Yes No
Air dilution Yes No If yes, CFM
Forced Draft Yes No Water cooled duct work Yes No
Other
Inlet Volume ACFM
@ °F % Moisture
Outlet Volume ACFM
@ °F % Moisture
Describe the system in detail.
VOC emissions resulting from startup, shutdown, maintenance and upset at the ethane cracking unit and PE manufacturing units will be routed to the HP Flare System. The HP system consists of one elevated flare with a relieving capacity of 1,200 tons/hr and two totally enclosed ground flares, each rated for 150 tons/hr. The HP elevated flare will only be used to control emissions during upsets. The two HP Ground Flares will be used to control VOC emission associated with startup, shutdown, and maintenance of the ethylene manufacturing plant and PE Units. Emissions associated with the two HP Ground and Elevated Flares are included in Appendix B of the Plan Approval Application. (NOTE: This is the same HP Flare System presented in the forms for PE Plant 3).
Section C - Air Cleaning Device (VOC Control System -HP System Ground Flares (2x))
(Polyethylene Plants 1 & 2) (Continued)
12. Flares Equipment Specifications
Manufacturer To be determined
Type Elevated flare Ground flare Other Describe
Model No.
Design Volume (SCFM)
Dimensions of stack (ft.) Diameter 55 Height 110
Residence time (sec.) and outlet temperature (°F) 1832
Turn down ratio
Burner details
Describe the flare design (air/steam-assisted or nonassisted), essential auxiliaries including pilot flame monitor of proposed flare with a sketch. Non-assisted, pilot flame monitoring
Describe the operation of the flare’s ignition system.
Describe the provisions to introduce auxiliary fuel to the flare.
Operation Parameters
Detailed composition of the waste gas
Heat content
Exit velocity
Maximum and average gas flow burned (ACFM)
Operating temperature (°F)
Describe the warning/alarm system that protects against operation when unit is not meeting design requirements.
Emissions Data See Appendix B of the Plan Approval Application
Pollutant Inlet Outlet Removal Efficiency (%)
Section C - Air Cleaning Device (VOC CONTROL SYSTEM -HP System Elevated Flare)
(Polyethylene Plants 1 & 2)
1. Precontrol Emissions* See Appendix B of the Plan Approval Application
Pollutant
Maximum Emission Rate Calculation/ Estimation
Method Specify Units Pounds/Hour Hours/Year Tons/Year PM PM10 SOx CO NOx VOC Others: (e.g., HAPs) ----- ----- ----- ----- ----- * These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating
schedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emission values were determined. Attach calculations.
2. Gas Cooling
Water quenching Yes No Water injection rate GPM
Radiation and convection cooling Yes No
Air dilution Yes No If yes, CFM
Forced Draft Yes No Water cooled duct work Yes No
Other
Inlet Volume ACFM
@ °F % Moisture
Outlet Volume ACFM
@ °F % Moisture
Describe the system in detail.
VOC emissions resulting from startup, shutdown, maintenance and upset at the ethane cracking unit and PE manufacturing units will be routed to the HP Flare System. The HP system consists of one elevated flare with a relieving capacity of 1,200 tons/hr and two totally enclosed ground flares, each rated for 150 tons/hr. The HP elevated flare will only be used to control emissions during upsets. The two HP Ground Flares will be used to control VOC emission associated with startup, shutdown, and maintenance of the ethylene manufacturing plant and PE Units. Emissions associated with the two HP Ground and Elevated Flares are included in Appendix B of the Plan Approval Application. (NOTE: This is the same HP Flare System presented in the forms for PE Plant 3).
Section C - Air Cleaning Device (VOC CONTROL SYSTEM -HP System Elevated Flare)
(Polyethylene Plants 1 & 2) (Continued)
12. FLARES Equipment Specifications
Manufacturer
Type Elevated flare Ground flare Other Describe
Model No.
Design Volume (SCFM)
Dimensions of stack (ft.) Diameter 5 Height
Residence time (sec.) and outlet temperature (°F) 1832
Turn down ratio
Burner details
Describe the flare design (air/steam-assisted or nonassisted), essential auxiliaries including pilot flame monitor of proposed flare with a sketch. Steam assisted, pilot flame monitoring. Refer to Section 3.5.5 and 5.12 of the Plan Approval Application for full flare description. Describe the operation of the flare’s ignition system.
Describe the provisions to introduce auxiliary fuel to the flare.
Operation Parameters See Appendix B of the Plan Approval Application Detailed composition of the waste gas
Heat content
Exit velocity
Maximum and average gas flow burned (ACFM)
Operating temperature (°F)
Describe the warning/alarm system that protects against operation when unit is not meeting design requirements.
Emissions Data See Appendix B of the Plan Approval Application
Pollutant Inlet Outlet Removal Efficiency (%)
Section C - Air Cleaning Device (PE 1& 2 Residual VOC Content in Pellets)
13. Other Control Equipment Equipment Specifications
Manufacturer
Type
Model No.
Design Volume (SCFM)
Capacity
Describe pH monitoring and pH adjustment, if any.
Indicate the liquid flow rate and describe equipment provided to measure pressure drop and flow rate, if any.
Attach efficiency curve and/or other efficiency information.
Attach any additional date including auxiliary equipment and operation details to thoroughly evaluate the control equipment.
Operation Parameters
Volume of gas handled
ACFM @ °F % Moisture
Describe fully giving important parameters and method of operation.
The residual VOC content in the resin exiting the Product Purge Bins shall be less than 50 ppmw.
Describe the warning/alarm system that protects against operation when unit is not meeting design requirements.
Emissions Data
Pollutant Inlet Outlet Removal Efficiency (%)
Section E - Compliance Demonstration (Polyethylene Plants 1 & 2) Note: Complete this section if source is not a Title V facility. Title V facilities must complete Addendum A.
Method of Compliance Type: Check all that apply and complete all appropriate sections below
Monitoring Testing Reporting
Recordkeeping Work Practice Standard
Monitoring: a. Monitoring device type (Parameter, CEM, etc): PM: Once every five years EPA reference method stack
tests Residual VOC: weekly measurement
b. Monitoring device location: Particulate containing vents as denoted in Appendix D
VOC content in resin exiting the product purge bin c. Describe all parameters being monitored along with the frequency and duration of monitoring each parameter:
Testing:
a. Reference Test Method: Citation PM: EPA Method 5, 202 VOC: EPA Method 3810
b. Reference Test Method: Description Method 5 – Determination of Particulate Matter Emissions from
Stationary Sources; Method 202 – Dry Impinger Method for Determining Condensable Particulate Matter from Stationary Sources; Method 3810-Headspace
Recordkeeping:
Describe what parameters will be recorded and the recording frequency:
VOC content of the resin exiting the Product Purge Bins will be recorded weekly.
Reporting:
a. Describe what is to be reported and frequency of reporting:
Reporting of required monitoring in compliance with regulations listed in Appendix G of the Plan Approval Application. Submittal of reports of required monitoring semi-annually per 25 Pa. Code § 127.511(c)
b. Reporting start date:
Work Practice Standard:
Describe each:
VOC Control System – Waste gas minimization and operation to achieve good destruction removal
efficiency. Flare will be designed to meet limitations on maximum exit velocity, as set forth in the general
provisions at 40 CFR 60.18 and 63.11. Flare will be operated to meet minimum net heating value
requirements for gas streams combusted in flares as set forth in 40 CFR 60.18. Further details on the
VOC Control System compliance methods are presented in Section 5.0 of the Plan Approval Application.
Section F - Flue and Air Contaminant Emission (Polyethylene Plants 1 & 2)
1. Estimated Atmospheric Emissions* See Appendix B of the Plan Approval Application for the detailed emissions calculations
Pollutant
Maximum emission rate Calculation/
Estimation Method specify units lbs/hr tons/yr. PM
PM10
SOx
CO
NOx
VOC
Others: ( e.g., HAPs) ----- ----- ----- -----
* These emissions must be calculated based on the requested operating schedule and/or process rate e.g., operating schedule for maximum limits or restricted hours of operation and /or restricted throughput. Describe how the emission values were determined. Attach calculations.
2. Stack and Exhauster See Appendix D for specific stack identification and Appendix C for stack parameter information
Stack Designation/Number: Refer to Section 6.0 of the Plan Approval Application
List Source(s) or source ID exhausted to this stack: % of flow exhausted to stack:
Stack height above grade (ft.) Grade elevation (ft.)
Stack diameter (ft) or Outlet duct area (sq. ft.)
f. Weather Cap YES NO
Distance of discharge to nearest property line (ft.). Locate on topographic map. Does stack height meet Good Engineering Practice (GEP)? If modeling (estimating) of ambient air quality impacts is needed, attach a site plan with buildings and their dimensions and other obstructions. Refer to Appendix C of the Plan Approval Application
Location of stack** Latitude/Longitude
Latitude Longitude
Point of Origin Degrees Minutes Seconds Degrees Minutes Seconds LP Ground Flare HP Ground Flare HP Elevated Flare PE vents –
See Appendix C for Detailed Information on location and exhaust characteristics.
Stack exhaust Volume ACFM Temperature °F Moisture %
Indicate on an attached sheet the location of sampling ports with respect to exhaust fan, breeching, etc. Give all necessary dimensions. Exhauster (attach fan curves) in. of water HP @ RPM.
** If the data and collection method codes differ from those provided on the General Information Form-Authorization Application, provide the additional detail required by that form on a separate form.
Section B - Processes Information (Polyethylene Plant 3) 1. Source Information
Source Description (give type, use, raw materials, product, etc). Attach additional sheets as necessary.
Polyethylene Plant 3 is described in detail in Section 3.3 of the Plan Approval Application. Manufacturer(s) Various
Model No.
Number of Sources
Source Designation
Maximum Capacity
Rated Capacity Polyethylene: 500 metric tons/yr
Type of Material Processed Ethylene polymerized with comonomer to produce various grades of polyethylene (PE) Maximum Operating Schedule Hours/Day 24
Days/Week 7
Days/Year 365
Hours/Year 8760
Operational restrictions existing or requested, if any (e.g., bottlenecks or voluntary restrictions to limit PTE) Capacity (specify units) Per Hour
Per Day
Per Week
Per Year 500 metric tons/yr
Operating Schedule Hours/Day 24
Days/Week 7
Days/Year 365
Hours/Year 8760
Seasonal variations (Months) From to If variations exist, describe them
2. Fuel
Type Quantity Hourly Annually Sulfur
% Ash (Weight) BTU Content
Oil Number
GPH @ 60°F
X 103
Gal
% by wt
Btu/Gal. & Lbs./Gal. @ 60 °F
Oil Number
GPH @ 60°F
X 103
Gal
% by wt
Btu/Gal. & Lbs./Gal. @ 60 °F
Natural Gas SCFH
X 106
SCF
grain/100
SCF
Btu/SCF
Gas (other)
SCFH
X 106
SCF
grain/100
SCF
Btu/SCF
Coal
TPH Tons % by wt Btu/lb
Other *
*Note: Describe and furnish information separately for other fuels in Addendum B.
Section B - Processes Information (Polyethylene Plant 3) (Continued) 6. Miscellaneous Information Attach flow diagram of process giving all (gaseous, liquid and solid) flow rates. Also, list all raw materials charged to process equipment, and the amounts charged (tons/hour, etc.) at rated capacity (give maximum, minimum and average charges describing fully expected variations in production rates). Indicate (on diagram) all points where contaminants are controlled (location of water sprays, collection hoods, or other pickup points, etc.). Describe collection hoods location, design, airflow and capture efficiency. Describe any restriction requested and how it will be monitored. See the Plan Approval Application as follows: A detailed project description containing flow diagrams is included as Section 3.3. Raw materials and capacity information are provided in Appendices B and D. No restrictions on the production capacity are requested.
Describe fully the facilities provided to monitor and to record process operating conditions, which may affect the emission of air contaminants. Show that they are reasonable and adequate. N/A
Describe each proposed modification to an existing source. N/A
Identify and describe all fugitive emission points, all relief and emergency valves and any by-pass stacks. Fugitive emissions will result from equipment leaks, tanks, paved roads and parking areas, cooling towers, and pressure safety valves (psvs). Additional information related to the control and monitoring of the fugitive emissions points is presented in Section 5.0 of the attached Plan Approval Application
Describe how emissions will be minimized especially during start up, shut down, process upsets and/or disruptions. The facility will install BACT and LAER controls as proposed in Section 5.0 of the Plan Approval Application. Where appropriate startup and shutdown BACT/LAER limits are proposed. A VOC control system will be used to minimize emissions during startup, shutdown, and upsets. The VOC Control System LAER proposal (see Section 5.12) includes submittal of a waste gas minimization plan (WGMP) along with the performance of a root cause and corrective action analysis in response to events greater than a defined trigger level. The proposed WGMP will include procedures to minimize emissions during startup, shutdown, and upset. Anticipated Milestones:
i. Expected commencement date of construction/reconstruction/installation: Late 2015 ii. Expected completion date of construction/reconstruction/installation: 2018 iii. Anticipated date of start-up: 2018
Section C - Air Cleaning Device (Particulate Control - PE 3 Manufacturing and Pellet Handling)
1. Precontrol Emissions* (Refer to Appendix B for emissions calculations)
Pollutant
Maximum Emission Rate Calculation/ Estimation
Method Specify Units Pounds/Hour Hours/Year Tons/Year PM PM10 SOx CO NOx VOC Others: (e.g., HAPs) ----- ----- ----- ----- ----- * These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating
schedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emission values were determined. Attach calculations.
Describe the system in detail.
Appendix D of the Plan Approval Application provides a full listing of the PE manufacturing PM sources and proposed particulate filter control. A grain loading of 0.005 gr/dscf is proposed for all particulate containing vents, except truck and rail loading. A grain loading of 0.01 gr/dscf is proposed for truck and rail loading. Particulate filter technology will be used where feasible.
Section C - Air Cleaning Device (PE 3 Manufacturing and Pellet Handling) (Continued) 5. Fabric Collector: Particulate filters be designed to achieve total PM of less than 0.005 gr/DSCF outlet Equipment Specifications Refer to Appendix D for Filter Specifications Manufacturer
Model No.
Pressurized Design Suction Design
Number of Compartments
Number of Filters Per Compartment
Is Baghouse Insulated? Yes No
Can each compartment be isolated for repairs and/or filter replacement?
Yes No
Are temperature controls provided? (Describe in detail)
Yes No
Dew point at maximum moisture °F Design inlet volume SCFM Type of Fabric
Material Felted Membrane Weight oz/sq.yd Woven Others: List: Thickness in Felted-Woven
Fabric permeability (clean) @ ½” water-∆ P CFM/sq.ft.
Filter dimensions Length Diameter/Width
Effective area per filter Maximum operating temperature (°F)
Effective air to cloth ratio Minimum Maximum
Drawing of Fabric Filter A sketch of the fabric filter showing all access doors, catwalks, ladders and exhaust ductwork, location of each pressure and temperature indicator should be attached.
Operation and Cleaning Volume of gases handled
ACFM @ °F
Pressure drop across collector (in. of water). Describe the equipment to be used to monitor the pressure drop.
Type of filter cleaning Manual Cleaning Bag Collapse Reverse Air Jets Mechanical Shakers Sonic Cleaning Other: Pneumatic Shakers Reverse Air Flow
Describe the equipment provided if dry oil free air is required for collector operation
Cleaning Initiated By Timer Frequency if timer actuated Expected pressure drop range in. of water Other Specify
Does air cleaning device employ hopper heaters, hopper vibrators or hopper level detectors? If yes, describe.
Describe the warning/alarm system that protects against operation when the unit is not meeting design requirements.
Emissions Data: Refer to Appendix B of the Plan Approval Application for Emissions Estimates Pollutant Inlet Outlet Removal Efficiency (%)
Section C - Air Cleaning Device (VOC Control System – LP System Thermal Incinerator)
(Polyethylene Plant 3)
1. Precontrol Emissions See Appendix B of the Plan Approval Application
Pollutant
Maximum Emission Rate Calculation/ Estimation
Method Specify Units Pounds/Hour Hours/Year Tons/Year PM PM10 SOx CO NOx VOC Others: (e.g., HAPs) ----- ----- ----- ----- ----- * These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating
schedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emission values were determined. Attach calculations.
2. Gas Cooling
Water quenching Yes No Water injection rate GPM
Radiation and convection cooling Yes No
Air dilution Yes No If yes, CFM
Forced Draft Yes No Water cooled duct work Yes No
Other
Inlet Volume ACFM
@ °F % Moisture
Outlet Volume ACFM
@ °F % Moisture
Describe the system in detail.
Continuous and intermittent VOC containing vents prior to the upstream of the Degasser will be routed to the VOC Control System’s LP header (LP System). The LP System consists of a Thermal Incinerator and a LP Ground Flare. The rated capacity of the Thermal Incinerator will be 12 tons/hr. The LP Ground Flare will only be used during process upsets. Emissions associated with the VOC Control System are included in Appendix B of the Plan Approval Application. Section 3 of the Plan Approval Application provides additional information on LP system. (NOTE: This is the same VOC Control System presented in the forms for Ethylene Manufacturing and PE Plants 1&2).
Section C - Air Cleaning Device (VOC Control System – LP System Thermal Incinerator) (Polyethylene Plant 3) (Continued)
11. Oxidizer/Afterburners Equipment Specifications
Manufacturer To be determined
Type Thermal Catalytic Model No.
Design Inlet Volume (SCFM)
Combustion chamber dimensions (length, cross-sectional area, effective chamber volume, etc.)
Describe design features, which will ensure mixing in combustion chamber.
Describe method of preheating incoming gases (if applicable).
Describe heat exchanger system used for heat recovery (if applicable).
Catalyst used
Life of catalyst
Expected temperature rise across catalyst (°F)
Dimensions of bed (in inches). Height: Diameter or Width: Depth:
Are temperature sensing devices being provided to measure the temperature rise across the catalyst? Yes No If yes, describe.
Describe any temperature sensing and/or recording devices (including specific location of temperature probe in a drawing or sketch.
Burner Information
Burner Manufacturer
Model No.
Fuel Used
Number and capacity of burners
Rated capacity (each)
Maximum capacity (each)
Describe the operation of the burner
Attach dimensioned diagram of afterburner
Operating Parameters
Inlet flow rate (ACFM) @ °F Outlet flow rate (ACFM) @ °F
State pressure drop range across catalytic bed (in. of water).
Describe the method adopted for regeneration or disposal of the used catalyst.
Describe the warning/alarm system that protects against operation when unit is not meeting design requirements.
Emissions Data See Appendix B of the Plan Approval Application
Pollutant Inlet Outlet Removal Efficiency (%)
Section C - Air Cleaning Device (VOC Control System - LP System Ground Flare) (Polyethylene Plant 3)
1. Precontrol Emissions* See Appendix B of the Plan Approval Application
Pollutant
Maximum Emission Rate Calculation/ Estimation
Method Specify Units Pounds/Hour Hours/Year Tons/Year PM PM10 SOx CO NOx VOC Others: (e.g., HAPs) ----- ----- ----- ----- ----- * These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating
schedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emission values were determined. Attach calculations.
2. Gas Cooling
Water quenching Yes No Water injection rate GPM
Radiation and convection cooling Yes No
Air dilution Yes No If yes, CFM
Forced Draft Yes No Water cooled duct work Yes No
Other
Inlet Volume ACFM
@ °F % Moisture
Outlet Volume ACFM
@ °F % Moisture
Describe the system in detail.
Continuous and intermittent VOC containing vents prior to the upstream of the Degasser will be routed to the VOC Control System’s LP header (LP System). The LP Ground Flare will only be used during process upsets. Emissions associated with the VOC Control System are included in Appendix B of the Plan Approval Application. The capacity of the totally enclosed LP Ground Flare will be 45 ton/hr. Section 3 of the Plan Approval Application provides additional information on LP system. (NOTE: This is the same VOC Control System presented in the forms for Ethylene Manufacturing and PE Plants 1&2).
Section C - Air Cleaning Device (VOC Control System - LP System Ground Flare) (Polyethylene Plant 3) (Continued)
12. Flares Equipment Specifications
Manufacturer To be determined
Type Elevated flare Ground flare Other Describe
Model No.
Design Volume (SCFM)
Dimensions of stack (ft.) Diameter Height
Residence time (sec.) and outlet temperature (°F) 1832
Turn down ratio
Burner details
Describe the flare design (air/steam-assisted or nonassisted), essential auxiliaries including pilot flame monitor of proposed flare with a sketch. Refer to Section 3.5.5 and Section 5.0 for a full flare system description
Describe the operation of the flare’s ignition system.
Describe the provisions to introduce auxiliary fuel to the flare.
Operation Parameters
Detailed composition of the waste gas
Heat content
1 MMBtu/hr (Pilot)
Exit velocity
Maximum and average gas flow burned (ACFM)
Operating temperature (°F)
Describe the warning/alarm system that protects against operation when unit is not meeting design requirements.
Emissions Data See Appendix B of the Plan Approval Application
Pollutant Inlet Outlet Removal Efficiency (%)
Section C - Air Cleaning Device (VOC Control System - HP System Ground Flares (2x))
(Polyethylene Plant 3)
1. Precontrol Emissions* See Appendix B of the Plan Approval Application
Pollutant
Maximum Emission Rate Calculation/ Estimation
Method Specify Units Pounds/Hour Hours/Year Tons/Year PM PM10 SOx CO NOx VOC Others: (e.g., HAPs) ----- ----- ----- ----- ----- * These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating
schedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emission values were determined. Attach calculations.
2. Gas Cooling
Water quenching Yes No Water injection rate GPM
Radiation and convection cooling Yes No
Air dilution Yes No If yes, CFM
Forced Draft Yes No Water cooled duct work Yes No
Other
Inlet Volume ACFM
@ °F % Moisture
Outlet Volume ACFM
@ °F % Moisture
Describe the system in detail.
VOC emissions resulting from startup, shutdown, maintenance and upset at the ethane cracking unit and PE manufacturing units will be routed to the HP Flare System. The HP system consists of one elevated flare with a relieving capacity of 1,200 tons/hr and two totally enclosed ground flares, each rated for 150 tons/hr. The HP elevated flare will only be used to control emissions during upsets. The two HP Ground Flares will be used to control VOC emission associated with startup, shutdown, and maintenance of the ethylene manufacturing plant and PE Units. Emissions associated with the two HP Ground and Elevated Flares are included in Appendix B of the Plan Approval Application. (NOTE: This is the same HP Flare System presented in the forms for PE Plants 1 & 2)..
Section C - Air Cleaning Device (VOC Control System -HP System Ground Flares (2x)) (Polyethylene Plant 3) (Continued)
12. Flares Equipment Specifications
Manufacturer To be determined
Type Elevated flare Ground flare Other Describe
Model No.
Design Volume (SCFM)
Dimensions of stack (ft.) Diameter Height
Residence time (sec.) and outlet temperature (°F)
Turn down ratio
Burner details
Describe the flare design (air/steam-assisted or nonassisted), essential auxiliaries including pilot flame monitor of proposed flare with a sketch. Non-assisted, pilot flame monitoring. Refer to Section 3.5.5 and Section 5.12 for a full flare system description.
Describe the operation of the flare’s ignition system.
Describe the provisions to introduce auxiliary fuel to the flare.
Operation Parameters
Detailed composition of the waste gas
Heat content
.
Exit velocity
Maximum and average gas flow burned (ACFM)
Operating temperature (°F)
Describe the warning/alarm system that protects against operation when unit is not meeting design requirements.
Emissions Data See Appendix B of the Plan Approval Application
Pollutant Inlet Outlet Removal Efficiency (%)
Section C - Air Cleaning Device (VOC CONTROL SYSTEM -HP System Elevated Flare)
(Polyethylene Plant 3)
1. Precontrol Emissions* See Appendix B of the Plan Approval Application
Pollutant
Maximum Emission Rate Calculation/ Estimation
Method Specify Units Pounds/Hour Hours/Year Tons/Year PM PM10 SOx CO NOx VOC Others: (e.g., HAPs) ----- ----- ----- ----- ----- * These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating
schedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emission values were determined. Attach calculations.
2. Gas Cooling
Water quenching Yes No Water injection rate GPM
Radiation and convection cooling Yes No
Air dilution Yes No If yes, CFM
Forced Draft Yes No Water cooled duct work Yes No
Other
Inlet Volume ACFM
@ °F % Moisture
Outlet Volume ACFM
@ °F % Moisture
Describe the system in detail.
VOC emissions resulting from startup, shutdown, maintenance and upset at the ethane cracking unit and PE manufacturing units will be routed to the HP Flare System. The HP system consists of one elevated flare with a relieving capacity of 1,200 tons/hr and two totally enclosed ground flares, each rated for 150 tons/hr. The HP elevated flare will only be used to control emissions during upsets. The two HP Ground Flares will be used to control VOC emission associated with startup, shutdown, and maintenance of the ethylene manufacturing plant and PE Units. Emissions associated with the two HP Ground and Elevated Flares are included in Appendix B of the Plan Approval Application. (NOTE: This is the same HP Flare System presented in the forms for PE Plants 1 & 2).
Section C - Air Cleaning Device (VOC CONTROL SYSTEM -HP System Elevated Flare) (Polyethylene Plant 3) (Continued)
12. FLARES Equipment Specifications
Manufacturer
Type Elevated flare Ground flare Other Describe
Model No.
Design Volume (SCFM)
Dimensions of stack (ft.) Diameter 5 Height
Residence time (sec.) and outlet temperature (°F) 1832
Turn down ratio
Burner details
Describe the flare design (air/steam-assisted or nonassisted), essential auxiliaries including pilot flame monitor of proposed flare with a sketch. Steam assisted, pilot flame monitoring. Refer to Section 3.5.5 and Section 5.12 for a full flare system description.
Describe the operation of the flare’s ignition system.
Describe the provisions to introduce auxiliary fuel to the flare.
Operation Parameters
Detailed composition of the waste gas
Heat content
1 MMBtu/hr (Pilot)
Exit velocity
Maximum and average gas flow burned (ACFM)
Operating temperature (°F)
Describe the warning/alarm system that protects against operation when unit is not meeting design requirements.
Emissions Data See Appendix B of the Plan Approval Application
Pollutant Inlet Outlet Removal Efficiency (%)
Section C - Air Cleaning Device (PE 3 Residual VOC Content in Pellets)
13. Other Control Equipment Equipment Specifications Manufacturer
Type
Model No.
Design Volume (SCFM)
Capacity
Describe pH monitoring and pH adjustment, if any.
Indicate the liquid flow rate and describe equipment provided to measure pressure drop and flow rate, if any.
Attach efficiency curve and/or other efficiency information.
Attach any additional date including auxiliary equipment and operation details to thoroughly evaluate the control equipment.
Operation Parameters
Volume of gas handled
ACFM @ °F % Moisture
Describe fully giving important parameters and method of operation.
Based on the LAER determination presented in Section 5.8 of the Plan Approval Application, VOC from the PE units will be controlled as follows: The residual VOC content in the resin exiting the Degasser shall be less than 50 ppmw.
Describe the warning/alarm system that protects against operation when unit is not meeting design requirements.
Emissions Data
Pollutant Inlet Outlet Removal Efficiency (%)
[Section E - Compliance Demonstration (Polyethylene Plant 3)
Note: Complete this section if source is not a Title V facility. Title V facilities must complete Addendum A.
Method of Compliance Type: Check all that apply and complete all appropriate sections below
Monitoring Testing Reporting
Recordkeeping Work Practice Standard
Monitoring: a. Monitoring device type (Parameter, CEM, etc): PM: Stack test once every 5 years for PM/PM10/PM2.5
Residual VOC: weekly measurement b. Monitoring device location: Particulate containing vents as denoted in Appendix D
VOC content in resin exiting the Degasser c. Describe all parameters being monitored along with the frequency and duration of monitoring each parameter:
Testing:
a. Reference Test Method: Citation PM: EPA Method 5, 202 VOC: EPA Method 3810
b. Reference Test Method: Description Method 5 – Determination of Particulate Matter Emissions from
Stationary Sources; Method 202 – Dry Impinger Method for Determining Condensable Particulate Matter from Stationary Sources; Method 3810-Headspace
Recordkeeping:
Describe what parameters will be recorded and the recording frequency:
VOC content of the resin exiting the Degasser will be recorded weekly.
Reporting:
a. Describe what is to be reported and frequency of reporting:
Reporting of required monitoring in compliance with regulations listed in Appendix G of the Plan Approval Application. Submittal of reports of required monitoring semi-annually per 25 Pa. Code § 127.511(c)
b. Reporting start date:
Work Practice Standard:
Describe each:
VOC Control System – Waste gas minimization and operation to achieve good destruction removal
efficiency. Flare will be designed to meet limitations on maximum exit velocity, as set forth in the general
provisions at 40 CFR 60.18 and 63.11. Flare will be operated to meet minimum net heating value
requirements for gas streams combusted in flares as set forth in 40 CFR 60.18. Further details on the VOC
Control System compliance methods are presented in Section 5.0 of the Plan Approval Application.
Section F - Flue and Air Contaminant Emission (PE3)
1. Estimated Atmospheric Emissions* See Appendix B of the Plan Approval Application for the detailed emissions calculations
Pollutant Maximum emission rate Calculation/
Estimation Method specify units lbs/hr tons/yr. PM
PM10
SOx
CO
NOx
VOC
Others: ( e.g., HAPs) ----- ----- ----- -----
* These emissions must be calculated based on the requested operating schedule and/or process rate e.g., operating schedule for maximum limits or restricted hours of operation and /or restricted throughput. Describe how the emission values were determined. Attach calculations.
2. Stack and Exhauster
Stack Designation/Number See Appendix D for specific stack identification and Appendix C for stack parameter information. List Source(s) or source ID exhausted to this stack:
% of flow exhausted to stack:
Stack height above grade (ft.) Grade elevation (ft.)
Stack diameter (ft) or Outlet duct area (sq. ft.)
f. Weather Cap YES NO
Distance of discharge to nearest property line (ft.). Locate on topographic map.
Does stack height meet Good Engineering Practice (GEP)? If modeling (estimating) of ambient air quality impacts is needed, attach a site plan with buildings and their dimensions and other obstructions. . . Refer to Appendix C of the Plan Approval Application
Location of stack** Latitude/Longitude
Latitude Longitude
Point of Origin Degrees Minutes Seconds Degrees Minutes Seconds LP Ground Flare HP Ground Flare HP Elevated Flare PE vents
See Appendix C for Detailed Information on location and exhaust characteristics.
Stack exhaust Volume ACFM Temperature °F Moisture %
Indicate on an attached sheet the location of sampling ports with respect to exhaust fan, breeching, etc. Give all necessary dimensions.
Exhauster (attach fan curves) in. of water HP @ RPM.
** If the data and collection method codes differ from those provided on the General Information Form-Authorization Application, provide the additional detail required by that form on a separate form.
Section B - Combustion Unit Information (Combustion Turbines/Duct Burners (3x)) 2. Combustion Units: Coal Oil Natural Gas Other:
Description: Combustion turbines with duct burners (3 Combined Cycle Units)
Manufacturer Siemens or GE
Model No. SGT-800 or GE Frame 6B
Number of units 3
Maximum heat input (Btu/hr)
Rated heat input (Btu/hr) GE – 475 MMBtu/hr Siemens – 490 MMBtu/hr
Typical heat input (Btu/hr)
Furnace Volume
Grate Area (if applicable)
Method of firing Direct
Indicate how combustion air is supplied to boiler Indicate the Steam Usage:
Mark and describe soot Cleaning Method: i. Air Blown ii. Steam Blown iii. Brushed and Vacuumed
iv. Other v. Frequency of Cleaning
Maximum Operating schedule Hours/Day 24
Days/Week 7
Days/Year 365
Hours/Year 8760
Operational restrictions taken or requested, if any (e.g., bottlenecks or voluntary restrictions to limit potential to emit)
Capacity (specify units) Per hour
Per day
Per week
Per year
Typical Operating schedule Hours/Day 24
Days/Week 7
Days/Year 365
Hours/Year 8760
Seasonal variations (Months): If variations exist, describe them. Operating using primary fuel: From to Operating using secondary fuel: Form to Non-operating: From to 3. Specify the primary, secondary and startup fuel. Furnish the details in item 3.
Single fuel, 40 CFR Part 72 pipeline natural gas.
Section B - Combustion Unit Information (Combustion Turbines/Duct Burners (3x)) (Continued)
5. Fuel
Type Quantity Hourly Annually Sulfur
% Ash (Weight) BTU Content
Oil Number
GPH @ 60°F
X 103 Gal
% by wt
Btu/Gal. & Lbs./Gal. @ 60 °F
Oil Number
GPH @ 60°F
X 103 Gal
% by wt
Btu/Gal. & Lbs./Gal. @ 60 °F
Oil Number
GPH @ 60°F
X 103 Gal
% by wt
Btu/Gal. & Lbs./Gal. @ 60 °F
Natural Gas
GE 465 MSCFH Siemen 482.4 MSCF
X 106
Gal
0.5 gr/100 SCF
1020 Btu/SCF
Gas (other)
SCFH
X 106
Gal
gr/100
SCF
Btu/SCF
Coal Other* * Note: Describe and furnish information separately for other fuels in Addendum B. 6. Burner Manufacturer
Model Number
Type of Atomization (Steam, air, press, mech., rotary cup)
Number of Burners
Maximum fuel firing rate (all burners)
Normal fuel firing rate
If oil, temperature and viscosity. Maximum theoretical air requirement Percent excess air 100% rating Turndown ratio Combustion modulation control (on/off, low-high fire, full automatic, manual). Describe. Main burner flame ignition method (electric spark, auto gas pilot, hand-held torch, other). Describe. 5. Nitrogen Oxides (NOx) control Options
Mark and describe the NOx control options adopted Low excess air (LEA) Over fire air (OFA) x Low-NOx burner Low NOx burners with over fire
air
Flue gas recirculation Burner out of service Reburning x Flue gas treatment (SCR)
Other. : Lean Premix Dry Low NOx Combustor
Section B - Combustion Unit Information (Combustion Turbines/Duct Burners (3x)) (Continued)
6. Miscellaneous Information
Describe fly ash reinjection operation
Describe, in detail, the equipment provided to monitor and to record the source(s) operating conditions, which may affect emissions of air contaminants. Show that they are reasonable and adequate.
Describe each proposed modification to an existing source.
Describe how emissions will be minimized especially during start up, shut down, combustion upsets and/or disruptions. Provide emission estimates for start up, shut down and upset conditions. Provide duration of start up and shut down.
Limits covering startup and shutdown are proposed in Section 5.3 of the Plan Approval Application. Estimates of emissions are provided in Appendix B.
Describe in detail with a schematic diagram of the control options adopted for SO2 (if applicable).
Anticipated milestones:
Expected commencement date of construction/reconstruction: Late 2015 Expected completion date of construction/reconstruction: 2018 Anticipated date(s) of start-up: 2018
Section C - Air Cleaning Device (Combustion Turbines/Duct Burners (3x))
1. Precontrol Emissions* Please refer to Appendix B of the Plan Approval Application for this emissions data
Emission Rate
Pollutant
Maximum Emission Rate Calculation/ Estimation
Method Specify Units Pounds/Hour Hours/Year Tons/Year PM
PM10
SOx
CO
NOx
VOC
Others: (e.g., HAPs) ----- ----- ----- -----
* These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating schedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emission values were determined. Attach calculations.
2. Gas Conditioning NA
Water quenching YES NO Water injection rate GPM
Radiation and convection cooling YES NO Air dilution YES NO
If YES, CFM
Forced draft YES NO Water cooled duct work YES NO
Other
Inlet volume
ACFM@ °F
Outlet volume
ACFM@ °F % Moisture
Describe the system in detail.
Three gas turbines with direct-fired duct burners and heat recovery steam generation capable of producing steam. The baseload ratings are 40.6 MW for the GE unit and 48.7 MW for the Siemens. Both gas turbine models will be equipped with lean premix combustors to minimize NOx. NOx LAER/BACT limits and BACT CO limits will be achieved by using selective catalytic reduction and CO oxidation catalyst, respectively. Two steam turbines each rated at 64.3 MW will be used to generate electricity using the steam produced by the HRSGs and any excess steam from the ethane cracking unit. When tailgas is in excess at the cracking furnaces, a small quantity of the tailgas may be combusted in the duct burners in combination with natural gas.
Section C - Air Cleaning Device (Combustion Turbines/Duct Burners (3x)) (Continued)
8. SELECTIVE CATALYTIC REDUCTION (SCR)
SELECTIVE NON-CATALYTIC REDUCTION (SNCR)
NON-SELECTIVE CATALYTIC REDUCTION (NSCR)
Equipment specifications Manufacturer
To be determined (TBD)
Type
Model No
Design inlet volume (SCFM)
Design operating temperature (°F)
Is the system equipped with process controls for proper mixing/control of the reducing agent in gas stream? If yes, give details. Attach efficiency and other pertinent information (e.g., Ammonia, urea slip). Operating parameters
Volume of gases handled (ACFM) @ (°F) Operating temperature range for the SCR/SNCR/NSCR system (°F)
From
To
Reducing agent used, if any. Ammonia
Oxidation catalyst used, if any.
State expected range of usage rate and concentration. Service life of catalyst
Ammonia slip (ppm) 5 ppmvd @ 15% O2
Describe fully with a sketch giving locations of equipment, controls system, important parameters and method of operation. SCR and CO oxidation will be designed to reduce NOx and CO emissions to the proposed BACT/LAER limits of 2 ppmvd @15% O2. (See Sections 5.3.1 and 5.3.4 of the Plan Approval Application for technology reviews). Emissions calculations for each of the proposed turbine units are included in Appendix B of the Plan Approval Application. Describe the warning/alarm system that protects against operation when unit is not meeting design requirements.
Emissions data Refer to Appendix B of the Plan Approval Application for emissions data Pollutant Inlet Outlet Removal Efficiency (%)
Section C - Air Cleaning Device (Combustion Turbines/Duct Burners (3x)) (Continued)
9. Other Control Equipment: CO Oxidation
Equipment specifications Manufacturer
To be Determined (TBD)
Type
Model No
Design inlet volume (SCFM)
Capacity
Describe pH monitoring and pH adjustment, if any. Indicate the liquid flow rate and describe equipment provided to measure pressure drop and flow rate, if any. Attach efficiency curve and/ or other efficiency information. Attach any additional data including auxiliary equipment and operation details to thoroughly evaluate the control equipment. Operating parameters Volume of gas handled
@ °F % Moisture
Describe, in detail, important parameters and method of operation.
Describe the warning/alarm system that protects against operation when unit is not meeting design requirements.
Emissions data Pollutant Inlet Outlet Removal Efficiency (%)
Section C - Air Cleaning Device (Combustion Turbines/Duct Burners (3x)) (Continued)
10. Costs Refer to the BACT/LAER Analysis contained in Section 5.0 of the Plan Approval Application
Indicate cost associated with air cleaning device and its operating cost (attach documentation if necessary)
Device Direct Cost Indirect Cost Total Cost Operating Cost
11 MISCELLANEOUS Describe in detail the removal, handling and disposal of dust, effluent, etc. from the air cleaning device including proposed methods of controlling fugitive emissions.
Attach manufacturer's performance guarantees and/or warranties for each of the major components of the control system (or complete system).
ch the maintenance schedule for the control equipment and any part of the process equipment that, if in disrepair, would increase air contaminant emissions.
Section E - Compliance Demonstration (Combustion Turbines/Duct Burners (3x)) Note: Complete this section if the facility is not a-Title V facility. Title V facilities must complete Addendum A. Method of Compliance Type: Check all that apply and complete all appropriate sections below.
Monitoring Testing Reporting
Recordkeeping Work Practice Standard
Monitoring: a. Monitoring device type (stack test, CEM etc.): NOx & CO CEMs; Stack test VOC and PM/PM10/PM2.5 b. Monitoring device location: Stack c. Describe all parameters being monitored along with the frequency and duration of monitoring each parameter:
Continuous measurement of NOx and CO concentration and volumetric flow rate, 5 year performance test for PM and VOC.
Testing:
a. Reference Test Method Citation: : EPA Method 18, 25, 5, and 202
b. Reference Test Method Description: Method 18-Measurement of Gaseous Organic Compound Emissions by Gas Chromatography; Method 25-Determination of Total Gaseous Nonmethane Organic Emissions as Carbon; Method 5 – Determination of Particulate Matter Emissions from Stationary Sources; Method 202 – Dry Impinger Method for Determining Condensable Particulate Matter from Stationary Sources.
Recordkeeping:
Describe the parameters that will be recorded and the recording frequency:
Records kept for continuous measurement of NOx and CO concentration and volumetric flow rate, 5 year performance test for PM and VOC. Calculations kept for SO2 and CO2.
Reporting:
a. Describe the type of information to be reported and the reporting frequency:
Reporting of required monitoring in compliance with regulations listed in Appendix G of the Plan Approval Application. Submittal of reports of required monitoring semi-annually per 25 Pa. Code § 127.511(c)
b. Reporting start date:
Work Practice Standard: Describe each
Good combustion design and operation for PM/PM10/PM2.5 control. Use of natural gas and energy efficient design for CO2e/GHG control.
Section F - Flue and Air Contaminant Emission (Combustion Turbines/Duct Burners (3x)) 1. Estimated Maximum Emissions*Presented here for one of three identical SCR/CO Ox units
Pollutant
Maximum emission rate Calculation/
Estimation Method specify units lbs/hr tons/yr. PM
PM10
SOx
CO
NOx
VOC
Others: ( e.g., HAPs) ----- ----- ----- -----
* These emissions must be calculated based on the requested operating schedule and/or process rate e.g., operating schedule for maximum limits or restricted hours of operation and /or restricted throughput. Describe how the emission values were determined. Attach calculations. Refer to Appendix B of the Plan Approval Application for emissions calculations
2. Stack and Exhauster Refer to Appendix C of the Plan Approval Application
Stack Designation/Number Three (3) Identical SCR/CO Ox List Source(s) or source ID exhausted to this stack: CT1/2/3
% of flow exhausted to stack:
Stack height above grade (ft.) Grade elevation (ft.)
Stack diameter (ft) or Outlet duct area (sq. ft.)
Weather Cap YES NO
Distance of discharge to nearest property line (ft.). Locate on topographic map.
Does stack height meet Good Engineering Practice (GEP)? Yes
If modeling (estimating) of ambient air quality impacts is needed, attach a site plan with buildings and their dimensions and other obstructions. Refer to Appendix C of the Plan Approval Application
Location of Stack** Latitude/Longitude Point of Origin
Latitude Longitude
Degrees Minutes Seconds Degrees Minutes Seconds Stack Exhaust
Volume ACFM Temperature °F Moisture %
Exhauster (attach fan curves) in. of water HP @ RPM.
** If the datum and collection method information and codes differ from those provided on the General Information Form - Authorization Application, provide the additional required by that form on a separate sheet.
Section B - Combustion Unit Information (Emergency Generators (4x)) 3. Combustion Units: Coal Oil Natural Gas Other: Diesel fuel Description: Four diesel-fired reciprocating internal combustion engines, each rated at ~5028 BHP/3MWe, will be used to drive emergency electrical generators.
Manufacturer
Model No.
Number of units 4
Maximum heat input (Btu/hr)
Rated heat input (Btu/hr)
Typical heat input (Btu/hr)
Furnace Volume
Grate Area (if applicable)
Method of firing Direct
Indicate how combustion air is supplied to boiler Indicate the Steam Usage:
Mark and describe soot Cleaning Method: i. Air Blown ii. Steam Blown iii. Brushed and Vacuumed
iv. Other v. Frequency of Cleaning
Maximum Operating schedule Hours/Day
Days/Week
Days/Year
Hours/Year 100 (each)
Operational restrictions taken or requested, if any (e.g., bottlenecks or voluntary restrictions to limit potential to emit)
Capacity (specify units) Per hour
Per day
Per week
Per year
Typical Operating schedule Hours/Day
Days/Week
Days/Year
Hours/Year
Seasonal variations (Months): If variations exist, describe them. Operating using primary fuel: From to Operating using secondary fuel: Form to Non-operating: From to 4. Specify the primary, secondary and startup fuel. Furnish the details in item 3.
Low sulfur diesel fuel
Section B - Combustion Unit Information (Emergency Generators (4x)) (Continued) 7. Fuel
Type Quantity Hourly Annually Sulfur
% Ash (Weight) BTU Content
Oil Number
GPH @ 60°F
X 103 Gal
% by wt
Btu/Gal. & Lbs./Gal. @ 60 °F
Oil Number
GPH @ 60°F
X 103 Gal
% by wt
Btu/Gal. & Lbs./Gal. @ 60 °F
Oil Number
GPH @ 60°F
X 103 Gal
% by wt
Btu/Gal. & Lbs./Gal. @ 60 °F
Natural Gas
SCFH
X 106
Gal
gr/100
SCF
Btu/SCF
Gas (other)
SCFH
X 106
Gal
gr/100
SCF
Btu/SCF
Coal Other* * Note: Describe and furnish information separately for other fuels in Addendum B. 8. Burner Manufacturer
Model Number
Type of Atomization (Steam, air, press, mech., rotary cup)
Number of Burners
Maximum fuel firing rate (all burners)
Normal fuel firing rate
If oil, temperature and viscosity. Maximum theoretical air requirement Percent excess air 100% rating Turndown ratio Combustion modulation control (on/off, low-high fire, full automatic, manual). Describe. Main burner flame ignition method (electric spark, auto gas pilot, hand-held torch, other). Describe. 5. Nitrogen Oxides (NOx) control Options
Mark and describe the NOx control options adopted Low excess air (LEA) Over fire air (OFA) Low-NOx burner Low NOx burners with over fire
air
Flue gas recirculation Burner out of service Reburning Flue gas treatment (SCR /
SNCR)
Other.
Section B - Combustion Unit Information (Emergency Generators (4x)) (Continued)
6. Miscellaneous Information
Describe fly ash reinjection operation
Describe, in detail, the equipment provided to monitor and to record the source(s) operating conditions, which may affect emissions of air contaminants. Show that they are reasonable and adequate.
Describe each proposed modification to an existing source.
Describe how emissions will be minimized especially during start up, shut down, combustion upsets and/or disruptions. Provide emission estimates for start up, shut down and upset conditions. Provide duration of start up and shut down.
Describe in detail with a schematic diagram of the control options adopted for SO2 (if applicable).
Anticipated milestones:
Expected commencement date of construction/reconstruction: Late 2015 Expected completion date of construction/reconstruction: 2018 Anticipated date(s) of start-up: 2018
Section C - Air Cleaning Device(Emergency Generators (4x))
1. Precontrol Emissions*Work Practice (Engine Design)
Emission Rate
Pollutant
Maximum Emission Rate Calculation/ Estimation
Method Specify Units Pounds/Hour Hours/Year Tons/Year PM
PM10
SOx
CO
NOx
VOC
Others: (e.g., HAPs) ----- ----- ----- -----
* These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating schedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emission values were determined. Attach calculations. Refer to Appendix B of the Plan Approval Application for emission calculations.
2. Gas Conditioning N/A
Water quenching YES NO Water injection rate GPM
Radiation and convection cooling YES NO Air dilution YES NO
If YES, CFM
Forced draft YES NO Water cooled duct work YES NO
Other
Inlet volume
ACFM@ °F
Outlet volume
ACFM@ °F % Moisture
Describe the system in detail.
Combustion control techniques and use of low sulfur fuel.
Attach efficiency curve and/ or other efficiency information. Attach any additional data including auxiliary equipment and operation details to thoroughly evaluate the control equipment.
Section C - Air Cleaning Device (Emergency Generators (4x)) (Continued)
10. Costs Refer to Section 5.0 of the Plan Approval Application
Indicate cost associated with air cleaning device and its operating cost (attach documentation if necessary)
Device Direct Cost Indirect Cost Total Cost Operating Cost
11 MISCELLANEOUS Describe in detail the removal, handling and disposal of dust, effluent, etc. from the air cleaning device including proposed methods of controlling fugitive emissions.
Attach manufacturer's performance guarantees and/or warranties for each of the major components of the control system (or complete system).
ch the maintenance schedule for the control equipment and any part of the process equipment that, if in disrepair, would increase air contaminant emissions.
Section E - Compliance Demonstration(Emergency Generators (4x)) Note: Complete this section if the facility is not a-Title V facility. Title V facilities must complete Addendum A. Refer to Table 5-1 of the Plan Approval Application for more details. Method of Compliance Type: Check all that apply and complete all appropriate sections below.
Monitoring Testing Reporting
Recordkeeping Work Practice Standard
Monitoring: a. Monitoring device type (stack test, CEM etc.): Fuel usage b. Monitoring device location: Fuel Supply c. Describe all parameters being monitored along with the frequency and duration of monitoring each parameter: Fuel
usage and operating hours when emergency generator is in use Testing:
a. Reference Test Method Citation:
b. Reference Test Method Description:
Recordkeeping:
Describe the parameters that will be recorded and the recording frequency:
Record fuel usage and operating hours when emergency generator is in use
Reporting:
a. Describe the type of information to be reported and the reporting frequency:
Reporting of required monitoring in compliance with regulations listed in Appendix G of the Plan Approval Application. Submittal of reports of required monitoring semi-annually per 25 Pa. Code § 127.511(c)
b. Reporting start date:
Work Practice Standard: Describe each
Compliance with proposed limits for NOx, VOC, PM/PM10/PM2.5 and CO met with purchase of certified engine.
Section F - Flue and Air Contaminant Emission (Emergency Generators (4x)) 1. Estimated Maximum Emissions*
Pollutant Maximum emission rate Calculation/
Estimation Method specify units lbs/hr tons/yr. PM
PM10
SOx
CO
NOx
VOC
Others: ( e.g., HAPs) ----- ----- ----- -----
* These emissions must be calculated based on the requested operating schedule and/or process rate e.g., operating schedule for maximum limits or restricted hours of operation and /or restricted throughput. Describe how the emission values were determined. Attach calculations Refer to Appendix B of the Plan Approval Application for emissions calculations.
2. Stack and Exhauster Refer to Appendix C of the Plan Approval Application
Stack Designation/Number
List Source(s) or source ID exhausted to this stack: EGEN1/2/3/4
% of flow exhausted to stack: 100
Stack height above grade (ft.) Grade elevation (ft.)
Stack diameter (ft) or Outlet duct area (sq. ft.)
Weather Cap YES NO
Distance of discharge to nearest property line (ft.). Locate on topographic map.
Does stack height meet Good Engineering Practice (GEP)? Yes
If modeling (estimating) of ambient air quality impacts is needed, attach a site plan with buildings and their dimensions and other obstructions. Refer to Appendix C of the Plan Approval Application
Location of Stack** Latitude/Longitude Point of Origin
Latitude Longitude
Degrees Minutes Seconds Degrees Minutes Seconds Generator 1 Generator 2 Generator 3 Generator 4
Stack Exhaust
Volume ACFM Temperature °F Moisture %
Exhauster (attach fan curves) in. of water HP @ RPM.
** If the datum and collection method information and codes differ from those provided on the General Information Form - Authorization Application, provide the additional required by that form on a separate sheet.
Section B - Combustion Unit Information (Firewater Pump Engines (3x)) 4. Combustion Units: Coal Oil Natural Gas Other: Diesel fuel Description: Three diesel-fired reciprocating internal combustion engines, each rated at ~700BHP/0.52 MW, will be used to drive emergency firewater pumps. Manufacturer
Model No.
Number of units 3
Maximum heat input (Btu/hr)
Rated heat input (Btu/hr)
Typical heat input (Btu/hr)
Furnace Volume
Grate Area (if applicable)
Method of firing Direct
Indicate how combustion air is supplied to boiler Indicate the Steam Usage:
Mark and describe soot Cleaning Method: i. Air Blown ii. Steam Blown iii. Brushed and Vacuumed
iv. Other v. Frequency of Cleaning
Maximum Operating schedule Hours/Day
Days/Week
Days/Year
Hours/Year 100 (each)
Operational restrictions taken or requested, if any (e.g., bottlenecks or voluntary restrictions to limit potential to emit)
Capacity (specify units) Per hour
Per day
Per week
Per year
Typical Operating schedule Hours/Day
Days/Week
Days/Year
Hours/Year
Seasonal variations (Months): If variations exist, describe them. Operating using primary fuel: From to Operating using secondary fuel: Form to Non-operating: From to 5. Specify the primary, secondary and startup fuel. Furnish the details in item 3.
Low sulfur diesel fuel
Section B - Combustion Unit Information (Firewater Pump Engines (3x)) 9. Fuel
Type Quantity Hourly Annually Sulfur
% Ash (Weight) BTU Content
Oil Number
GPH @ 60°F
X 103 Gal
% by wt
Btu/Gal. & Lbs./Gal. @ 60 °F
Oil Number
GPH @ 60°F
X 103 Gal
% by wt
Btu/Gal. & Lbs./Gal. @ 60 °F
Oil Number
GPH @ 60°F
X 103 Gal
% by wt
Btu/Gal. & Lbs./Gal. @ 60 °F
Natural Gas
SCFH
X 106
Gal
gr/100
SCF
Btu/SCF
Gas (other)
SCFH
X 106
Gal
gr/100
SCF
Btu/SCF
Coal Other* * Note: Describe and furnish information separately for other fuels in Addendum B. 10. Burner Manufacturer
Model Number
Type of Atomization (Steam, air, press, mech., rotary cup)
Number of Burners
Maximum fuel firing rate (all burners)
Normal fuel firing rate
If oil, temperature and viscosity. Maximum theoretical air requirement Percent excess air 100% rating Turndown ratio Combustion modulation control (on/off, low-high fire, full automatic, manual). Describe. Main burner flame ignition method (electric spark, auto gas pilot, hand-held torch, other). Describe. 5. Nitrogen Oxides (NOx) control Options
Mark and describe the NOx control options adopted Low excess air (LEA) Over fire air (OFA) Low-NOx burner Low NOx burners with over fire
air
Flue gas recirculation Burner out of service Reburning Flue gas treatment (SCR /
SNCR)
Other.
Section B - Combustion Unit Information (Firewater Pump Engines (3x))
6. Miscellaneous Information
Describe fly ash reinjection operation
Describe, in detail, the equipment provided to monitor and to record the source(s) operating conditions, which may affect emissions of air contaminants. Show that they are reasonable and adequate.
Describe each proposed modification to an existing source.
Describe how emissions will be minimized especially during start up, shut down, combustion upsets and/or disruptions. Provide emission estimates for start up, shut down and upset conditions. Provide duration of start up and shut down.
Describe in detail with a schematic diagram of the control options adopted for SO2 (if applicable).
Anticipated milestones:
Expected commencement date of construction/reconstruction: Late 2015 Expected completion date of construction/reconstruction: 2018 Anticipated date(s) of start-up: 2018
Section C - Air Cleaning Device(Firewater Pump Engines (3x))
1. Precontrol Emissions*Work Practice
Emission Rate
Pollutant
Maximum Emission Rate Calculation/ Estimation
Method Specify Units Pounds/Hour Hours/Year Tons/Year PM
PM10
SOx
CO
NOx
VOC
Others: (e.g., HAPs) ----- ----- ----- -----
* These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating schedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emission values were determined. Attach calculations. Refer to Appendix B of the Plan Approval Application for emission calculations.
2. Gas Conditioning N/A
Water quenching YES NO Water injection rate GPM
Radiation and convection cooling YES NO Air dilution YES NO
If YES, CFM
Forced draft YES NO Water cooled duct work YES NO
Other
Inlet volume
ACFM@ °F
Outlet volume
ACFM@ °F % Moisture
Describe the system in detail.
Combustion control techniques and use of low sulfur fuel.
Attach efficiency curve and/ or other efficiency information. Attach any additional data including auxiliary equipment and operation details to thoroughly evaluate the control equipment.
Section C - Air Cleaning Device (Firewater Pump Engines (3x)) (Continued)
10. Costs Refer to Section 5.0 of the Plan Approval Application
Indicate cost associated with air cleaning device and its operating cost (attach documentation if necessary)
Device Direct Cost Indirect Cost Total Cost Operating Cost
11 MISCELLANEOUS Describe in detail the removal, handling and disposal of dust, effluent, etc. from the air cleaning device including proposed methods of controlling fugitive emissions.
Attach manufacturer's performance guarantees and/or warranties for each of the major components of the control system (or complete system).
ch the maintenance schedule for the control equipment and any part of the process equipment that, if in disrepair, would increase air contaminant emissions.
Section E - Compliance Demonstration (Firewater Pump Engines (3x)) Note: Complete this section if the facility is not a-Title V facility. Title V facilities must complete Addendum A. Refer to Table 5-1 of the Plan Approval Application for more details. Method of Compliance Type: Check all that apply and complete all appropriate sections below.
Monitoring Testing Reporting
Recordkeeping Work Practice Standard
Monitoring: a. Monitoring device type (stack test, CEM etc.): Fuel usage b. Monitoring device location: Fuel Supply c. Describe all parameters being monitored along with the frequency and duration of monitoring each parameter: Fuel
usage and operating hours when firewater pump is in use. Testing:
a. Reference Test Method Citation:
b. Reference Test Method Description:
Recordkeeping:
Describe the parameters that will be recorded and the recording frequency:
Record fuel usage and operating hours when firewater pump is in use.
Reporting:
a. Describe the type of information to be reported and the reporting frequency:
Reporting of required monitoring in compliance with regulations listed in Appendix G of the Plan Approval Application. Submittal of reports of required monitoring semi-annually per 25 Pa. Code § 127.511(c)
b. Reporting start date:
Work Practice Standard: Describe each
Compliance with proposed limits for NOx, VOC, PM/PM10/PM2.5 and CO met with purchase of certified engine.
Section F - Flue and Air Contaminant Emission (Firewater Pump Engines (3x)) 1. Estimated Maximum Emissions*
Pollutant
Maximum emission rate Calculation/
Estimation Method specify units lbs/hr tons/yr. PM
PM10
SOx
CO
NOx
VOC
Others: ( e.g., HAPs) ----- ----- ----- -----
* These emissions must be calculated based on the requested operating schedule and/or process rate e.g., operating schedule for maximum limits or restricted hours of operation and /or restricted throughput. Describe how the emission values were determined. Attach calculations. Refer to Appendix B of the Plan Approval Application for emissions calculations.
2. Stack and Exhauster Refer to Appendix C of the Plan Approval Application
Stack Designation/Number
List Source(s) or source ID exhausted to this stack: FWP1/2/3
% of flow exhausted to stack: 100
Stack height above grade (ft.) Grade elevation (ft.)
Stack diameter (ft) or Outlet duct area (sq. ft.)
Weather Cap YES NO
Distance of discharge to nearest property line (ft.). Locate on topographic map.
Does stack height meet Good Engineering Practice (GEP)? Yes
If modeling (estimating) of ambient air quality impacts is needed, attach a site plan with buildings and their dimensions and other obstructions. Refer to Appendix C of the Plan Approval Application
Location of Stack** Latitude/Longitude Point of Origin
Latitude Longitude
Degrees Minutes Seconds Degrees Minutes Seconds Firewater Pump 1 Firewater Pump 2 Firewater Pump 3
Stack Exhaust
Volume ACFM Temperature °F Moisture %
Exhauster (attach fan curves) in. of water HP @ RPM.
** If the datum and collection method information and codes differ from those provided on the General Information Form - Authorization Application, provide the additional required by that form on a separate sheet.
Section B - Processes Information (Process Cooling Tower) 1. Source Information
Source Description (give type, use, raw materials, product, etc). Attach additional sheets as necessary. Process Cooling Tower- 26 cell counter-flow mechanical draft cooling tower to supply cooling water to process units. Manufacturer To be Determined
Model No.
Number of Sources 1
Source Designation
Maximum Capacity 57,000 metric tons/hr
Rated Capacity
Type of Material Processed Maximum Operating Schedule Hours/Day 24
Days/Week 7
Days/Year 365
Hours/Year 8760
Operational restrictions existing or requested, if any (e.g., bottlenecks or voluntary restrictions to limit PTE) Capacity (specify units) Per Hour 66,992 tons
Per Day
Per Week
Per Year
Operating Schedule Hours/Day 24
Days/Week 7
Days/Year 365
Hours/Year 8760
Seasonal variations (Months) From to If variations exist, describe them
2. Fuel
Type Quantity Hourly Annually Sulfur
% Ash (Weight) BTU Content
Oil Number
GPH @ 60°F
X 103
Gal
% by wt
Btu/Gal. & Lbs./Gal. @ 60 °F
Oil Number
GPH @ 60°F
X 103
Gal
% by wt
Btu/Gal. & Lbs./Gal. @ 60 °F
Natural Gas SCFH
X 106
SCF
grain/100
SCF
Btu/SCF
Gas (other)
SCFH
X 106
SCF
grain/100
SCF
Btu/SCF
Coal
TPH Tons % by wt Btu/lb
Other *
*Note: Describe and furnish information separately for other fuels in Addendum B.
Section B - Processes Information (Process Cooling Tower) (Continued) 6. Miscellaneous Information Attach flow diagram of process giving all (gaseous, liquid and solid) flow rates. Also, list all raw materials charged to process equipment, and the amounts charged (tons/hour, etc.) at rated capacity (give maximum, minimum and average charges describing fully expected variations in production rates). Indicate (on diagram) all points where contaminants are controlled (location of water sprays, collection hoods, or other pickup points, etc.). Describe collection hoods location, design, airflow and capture efficiency. Describe any restriction requested and how it will be monitored.
Describe fully the facilities provided to monitor and to record process operating conditions, which may affect the emission of air contaminants. Show that they are reasonable and adequate. TDS, Total VOC in circulating water.
Describe each proposed modification to an existing source. N/A
Identify and describe all fugitive emission points, all relief and emergency valves and any by-pass stacks. N/A
Describe how emissions will be minimized especially during start up, shut down, process upsets and/or disruptions. N/A
Anticipated Milestones: i. Expected commencement date of construction/reconstruction/installation: Late 2015 ii. Expected completion date of construction/reconstruction/installation: 2018 iii. Anticipated date of start-up: 2018
Section E Compliance Demonstration (Process Cooling Tower)
Note: Complete this section if source is not a Title V facility. Title V facilities must complete Addendum A.
Method of Compliance Type: Check all that apply and complete all appropriate sections below
Monitoring Testing Reporting
Recordkeeping Work Practice Standard
Monitoring: a. Monitoring device type (Parameter, CEM, etc): b. Monitoring device location: c. Describe all parameters being monitored along with the frequency and duration of monitoring each parameter:
TDS, Total VOC in circulating water
Testing:
a. Reference Test Method: Citation b. Reference Test Method: Description
Recordkeeping:
Describe what parameters will be recorded and the recording frequency:
Reporting:
a. Describe what is to be reported and frequency of reporting:
Reporting of required monitoring in compliance with regulations listed in Appendix G of the Plan Approval Application. Submittal of reports of required monitoring semi-annually per 25 Pa. Code § 127.511(c)
b. Reporting start date:
Work Practice Standard:
Describe each: High efficiency drift eliminators with a manufacturer’s specification of no more than 0.0005%
drift loss will be installed.
Section F - Flue and Air Contaminant Emission(Process Cooling Tower)
1. Estimated Atmospheric Emissions*
Pollutant
Maximum emission rate Calculation/
Estimation Method specify units lbs/hr tons/yr. PM
PM10
SOx
CO
NOx
VOC
Others: ( e.g., HAPs) ----- ----- ----- -----
* These emissions must be calculated based on the requested operating schedule and/or process rate e.g., operating schedule for maximum limits or restricted hours of operation and /or restricted throughput. Describe how the emission values were determined. Attach calculations.
2. Stack and Exhauster Refer to Appendix C of the Plan Approval Application
Stack Designation/Number
List Source(s) or source ID exhausted to this stack: PCT
% of flow exhausted to stack:
Stack height above grade (ft.) Grade elevation (ft.)
Stack diameter (ft) or Outlet duct area (sq. ft.)
f. Weather Cap YES NO
Distance of discharge to nearest property line (ft.). Locate on topographic map.
Does stack height meet Good Engineering Practice (GEP)? Yes
If modeling (estimating) of ambient air quality impacts is needed, attach a site plan with buildings and their dimensions and other obstructions. Refer to Appendix C of the Plan Approval Application
Location of stack** Latitude/Longitude
Latitude Longitude
Point of Origin Degrees Minutes Seconds Degrees Minutes Seconds Stack exhaust
Volume ACFM Temperature °F Moisture %
Indicate on an attached sheet the location of sampling ports with respect to exhaust fan, breeching, etc. Give all necessary dimensions.
Exhauster (attach fan curves) in. of water HP @ RPM.
** If the data and collection method codes differ from those provided on the General Information Form-Authorization Application, provide the additional detail required by that form on a separate form.
Section B - Processes Information (Cogen Cooling Tower) 1. Source Information
Source Description (give type, use, raw materials, product, etc). Attach additional sheets as necessary. Cogen Cooling Tower- 4 cell counter-flow mechanical draft cooling tower to supply cooling water to cogeneration units Manufacturer To be Determined
Model No.
Number of Sources 1
Source Designation
Maximum Capacity 10,000 metric tons/hr
Rated Capacity
Type of Material Processed Maximum Operating Schedule Hours/Day 24
Days/Week 7
Days/Year 365
Hours/Year 8760
Operational restrictions existing or requested, if any (e.g., bottlenecks or voluntary restrictions to limit PTE) Capacity (specify units) Per Hour 10,455 cubic meters
Per Day
Per Week
Per Year
Operating Schedule Hours/Day 24
Days/Week 7
Days/Year 365
Hours/Year 8760
Seasonal variations (Months) From to If variations exist, describe them
2. Fuel
Type Quantity Hourly Annually Sulfur
% Ash (Weight) BTU Content
Oil Number
GPH @ 60°F
X 103
Gal
% by wt
Btu/Gal. & Lbs./Gal. @ 60 °F
Oil Number
GPH @ 60°F
X 103
Gal
% by wt
Btu/Gal. & Lbs./Gal. @ 60 °F
Natural Gas SCFH
X 106
SCF
grain/100
SCF
Btu/SCF
Gas (other)
SCFH
X 106
SCF
grain/100
SCF
Btu/SCF
Coal
TPH Tons % by wt Btu/lb
Other *
*Note: Describe and furnish information separately for other fuels in Addendum B.
Section B - Processes Information (Cogen Cooling Tower) (Continued) 6. Miscellaneous Information Attach flow diagram of process giving all (gaseous, liquid and solid) flow rates. Also, list all raw materials charged to process equipment, and the amounts charged (tons/hour, etc.) at rated capacity (give maximum, minimum and average charges describing fully expected variations in production rates). Indicate (on diagram) all points where contaminants are controlled (location of water sprays, collection hoods, or other pickup points, etc.). Describe collection hoods location, design, airflow and capture efficiency. Describe any restriction requested and how it will be monitored.
Describe fully the facilities provided to monitor and to record process operating conditions, which may affect the emission of air contaminants. Show that they are reasonable and adequate.
Describe each proposed modification to an existing source. N/A
Identify and describe all fugitive emission points, all relief and emergency valves and any by-pass stacks. N/A
Describe how emissions will be minimized especially during start up, shut down, process upsets and/or disruptions. N/A
Anticipated Milestones: i. Expected commencement date of construction/reconstruction/installation: Late 2015 ii. Expected completion date of construction/reconstruction/installation: 2018 iii. Anticipated date of start-up: 2018
Section E Compliance Demonstration (Cogen Cooling Tower)
Note: Complete this section if source is not a Title V facility. Title V facilities must complete Addendum A.
Method of Compliance Type: Check all that apply and complete all appropriate sections below
Monitoring Testing Reporting
Recordkeeping Work Practice Standard
Monitoring: a. Monitoring device type (Parameter, CEM, etc): b. Monitoring device location: c. Describe all parameters being monitored along with the frequency and duration of monitoring each parameter:
TDS
Testing:
a. Reference Test Method: Citation b. Reference Test Method: Description
Recordkeeping:
Describe what parameters will be recorded and the recording frequency:
Reporting:
a. Describe what is to be reported and frequency of reporting:
Reporting of required monitoring in compliance with regulations listed in Appendix G of the Plan Approval Application. Submittal of reports of required monitoring semi-annually per 25 Pa. Code § 127.511(c)
b. Reporting start date:
Work Practice Standard:
Describe each: High efficiency drift eliminators with a manufacturer’s specification of no more than 0.0005%
drift loss will be installed.
Section F - Flue and Air Contaminant Emission(Cogen Cooling Tower)
1. Estimated Atmospheric Emissions*
Pollutant
Maximum emission rate Calculation/
Estimation Method specify units lbs/hr tons/yr. PM
PM10
SOx
CO
NOx
VOC
Others: ( e.g., HAPs) ----- ----- ----- -----
* These emissions must be calculated based on the requested operating schedule and/or process rate e.g., operating schedule for maximum limits or restricted hours of operation and /or restricted throughput. Describe how the emission values were determined. Attach calculations.
2. Stack and Exhauster Refer to Appendix C of the Plan Approval Application
Stack Designation/Number CogenCWT
List Source(s) or source ID exhausted to this stack: CogenCWT
% of flow exhausted to stack:
Stack height above grade (ft.) Grade elevation (ft.)
Stack diameter (ft) or Outlet duct area (sq. ft.)
f. Weather Cap YES NO
Distance of discharge to nearest property line (ft.). Locate on topographic map.
Does stack height meet Good Engineering Practice (GEP)?
If modeling (estimating) of ambient air quality impacts is needed, attach a site plan with buildings and their dimensions and other obstructions. Refer to Appendix C of the Plan Approval Application
Location of stack** Latitude/Longitude
Latitude Longitude
Point of Origin Degrees Minutes Seconds Degrees Minutes Seconds Stack exhaust
Volume ACFM Temperature °F Moisture %
Indicate on an attached sheet the location of sampling ports with respect to exhaust fan, breeching, etc. Give all necessary dimensions.
Exhauster (attach fan curves) in. of water HP @ RPM.
** If the data and collection method codes differ from those provided on the General Information Form-Authorization Application, provide the additional detail required by that form on a separate form.
Section B - Processes Information (Utilities and General Facility) 1. Source Information
Source Description (give type, use, raw materials, product, etc). Attach additional sheets as necessary. This section covers units outside the battery limits (OSBL) of the ethylene and polyethylene manufacturing lines. Included are tanks, cogeneration units, auxiliary engines, cooling tower, and wastewater treatment. . Manufacturer(s) Various
Model No.
Number of Sources
Source Designation
Maximum Capacity
Rated Capacity
Type of Material Processed Maximum Operating Schedule Hours/Day 24
Days/Week 7
Days/Year 365
Hours/Year 8760
Operational restrictions existing or requested, if any (e.g., bottlenecks or voluntary restrictions to limit PTE) Capacity (specify units) Per Hour
Per Day
Per Week
Per Year
Operating Schedule Hours/Day 24
Days/Week 7
Days/Year 365
Hours/Year 8760
Seasonal variations (Months) From to If variations exist, describe them
2. Fuel
Type Quantity Hourly Annually Sulfur
% Ash (Weight) BTU Content
Oil Number
GPH @ 60°F
X 103
Gal
% by wt
Btu/Gal. & Lbs./Gal. @ 60 °F
Oil Number
GPH @ 60°F
X 103
Gal
% by wt
Btu/Gal. & Lbs./Gal. @ 60 °F
Natural Gas SCFH
X 106
SCF
grain/100
SCF
Btu/SCF
Gas (other)
SCFH
X 106
SCF
grain/100
SCF
Btu/SCF
Coal
TPH Tons % by wt Btu/lb
Other *
*Note: Describe and furnish information separately for other fuels in Addendum B.
Section B - Processes Information (Utilities and General Facility) (Continued) 3. Burner Manufacturer
Type and Model No.
Number of Burners
Description:
Rated Capacity
Maximum Capacity
4. Process Storage Vessels A. For Liquids: Refer to Table D-6 of Appendix D of the Plan Approval Application Name of material stored
Tank I.D. No.
Manufacturer
Date Installed
Maximum Pressure
Capacity (gallons/Meter3)
Type of relief device (pressure set vent/conservation vent/emergency vent/open vent) Relief valve/vent set pressure (psig)
Vapor press. of liquid at storage temp. (psia/kPa)
Type of Roof: Describe:
Total Throughput Per Year
Number of fills per day (fill/day): Filling Rate (gal./min.): Duration of fill hr./fill):
B. For Solids Refer to Table D-7 of Appendix D of the Plan Approval Application Type: Silo Storage Bin Other, Describe
Name of Material Stored
Silo/Storage Bin I.D. No.
Manufacturer
Date Installed
State whether the material will be stored in loose or bags in silos
Capacity (Tons)
Turn over per year in tons
Turn over per day in tons
Describe fugitive dust control system for loading and handling operations
Describe material handling system
5. Request for Confidentiality Do you request any information on this application to be treated as “Confidential”? Yes No If yes, include justification for confidentiality. Place such information on separate pages marked “confidential”.
Section B - Processes Information (Utilities and General Facility) (Continued) 6. Miscellaneous Information Attach flow diagram of process giving all (gaseous, liquid and solid) flow rates. Also, list all raw materials charged to process equipment, and the amounts charged (tons/hour, etc.) at rated capacity (give maximum, minimum and average charges describing fully expected variations in production rates). Indicate (on diagram) all points where contaminants are controlled (location of water sprays, collection hoods, or other pickup points, etc.). Describe collection hoods location, design, airflow and capture efficiency. Describe any restriction requested and how it will be monitored. Please refer to the Plan Approval Application. The detailed process descriptions and flow diagrams are included in Section 3.0. The Project’s emissions estimates are included as Appendix B to the Plan Approval Application. Proposed limits for each of the proposed projects emissions points are included in Section 5 of the Plan Approval Application. .
Describe fully the facilities provided to monitor and to record process operating conditions, which may affect the emission of air contaminants. Show that they are reasonable and adequate. Compliance monitoring equipment and recordkeeping procedures will be implemented to ensure that all of the proposed projects sources are operated in compliance with the proposed permit limits. Compliance monitoring and testing requirements are included as part of each of the proposed limits in Section 5.0. Continuous NOx and CO emissions monitors will be used to monitor compliance at the cracking furnaces and combustion turbines. Flares and incinerators will have enhanced monitoring to ensure combustion efficiency. Describe each proposed modification to an existing source. N/A
Identify and describe all fugitive emission points, all relief and emergency valves and any by-pass stacks. Fugitive emissions will result from equipment leaks, tanks, paved roads and parking areas, cooling towers, and pressure safety valves (psvs). Additional information related to the control and monitoring of emissions from each of these sources is presented in Section 5.0 of the attached Plan Approval Application
Describe how emissions will be minimized especially during start up, shut down, process upsets and/or disruptions. The facility will install BACT and LAER controls as proposed in Section 5.0 of the Plan Approval Application. Where appropriate startup and shutdown limits are proposed as part of these analyses. As part of the VOC Control System LAER proposal covering the operation of the incinerators and flares submittal of a waste gas minimization plan (WGMP) is proposed along with the performance of a root cause and corrective action analysis in response to events greater than a defined size. This WGMP will include procedures to minimize emissions due to flaring and incineration during startup and shutdown of the proposed project’s emissions sources. Anticipated Milestones:
i. Expected commencement date of construction/reconstruction/installation: Late 2015 ii. Expected completion date of construction/reconstruction/installation: 2018 iii. Anticipated date of start-up: 2018
Section C - Air Cleaning Device (Carbon Canisters) (Utilities and General Facility)
1. Precontrol Emissions* See Appendix B of the Plan Approval Application
Pollutant
Maximum Emission Rate Calculation/ Estimation
Method Specify Units Pounds/Hour Hours/Year Tons/Year PM PM10 SOx CO NOx VOC Others: (e.g., HAPs) ----- ----- ----- ----- ----- * These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating
schedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emission values were determined. Attach calculations.
2. Gas Cooling
Water quenching Yes No Water injection rate GPM
Radiation and convection cooling Yes No
Air dilution Yes No If yes, CFM
Forced Draft Yes No Water cooled duct work Yes No
Other
Inlet Volume ACFM
@ °F % Moisture
Outlet Volume ACFM
@ °F % Moisture
Describe the system in detail.
Carbon canisters will be used to control tank emissions associated with the pyrolysis tar, emergency diesel generator (4x), emergency firewater pump diesel (3x), and locomotive diesel tanks. Emissions associated with these carbon canister controlled tanks are included in Appendix B of the Plan Approval Application.
Section C - Air Cleaning Device (Carbon Canisters) (Utilities and General Facility)
8. Adsorption Equipment Equipment Specifications
Manufacturer
Type
Model No.
Design Inlet Volume (SCFM)
Adsorbent charge per adsorber vessel and number of adsorber vessels
Length of Mass Transfer Zone (MTZ), supplied by the manufacturer based upon laboratory data.
Adsorber diameter (ft.) and area ft2.)
Adsorption bed depth (ft.)
Adsorbent information
Adsorbent type and physical properties.
Working capacity of adsorbent (%)
Heel percent or unrecoverable solvent weight % in the adsorbent after regeneration.
Operating Parameters
Inlet volume of gases handled (ACFM) @ °F
Adsorption time per adsorption bed
Breakthrough capacity: Lbs. of solvent / 100 lbs. of adsorbent =
Vapor pressure of solvents at the inlet temperature
Available steam in pounds to regenerate carbon adsorber (if applicable)
Percent relative saturation of each solvent at the inlet temperature
Attach any additional data including auxiliary equipment and operation details to thoroughly evaluate the control equipment.
Describe the warning/alarm system that protects against operation when unit is not meeting design requirements.
Emissions Data: See Appendix B of the Plan Approval Application
Pollutant Inlet Outlet Removal Efficiency (%)
Section C - Air Cleaning Device (VOC Control System – LP System Thermal Incinerator)
(Utilities and General Facility)
1. Precontrol Emissions See Appendix B of the Plan Approval Application
Pollutant
Maximum Emission Rate Calculation/ Estimation
Method Specify Units Pounds/Hour Hours/Year Tons/Year PM PM10 SOx CO NOx VOC Others: (e.g., HAPs) ----- ----- ----- ----- ----- * These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating
schedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emission values were determined. Attach calculations.
2. Gas Cooling
Water quenching Yes No Water injection rate GPM
Radiation and convection cooling Yes No
Air dilution Yes No If yes, CFM
Forced Draft Yes No Water cooled duct work Yes No
Other
Inlet Volume ACFM
@ °F % Moisture
Outlet Volume ACFM
@ °F % Moisture
Describe the system in detail.
Continuous and intermittent VOC containing vents from the light gasoline and hexene tanks will be routed to the VOC Control System’s LP header (LP System). The LP System consists of an LP Thermal Incinerator and an LP Ground Flare. The rated capacity of the Thermal Incinerator will be 12 tons/hr. The LP Ground Flare will only be used during process upsets. Emissions associated with the VOC Control System are included in Appendix B of the Plan Approval Application. Section 3 of the Plan Approval Application provides additional information on LP System. (NOTE: This is the same VOC Control System presented in the forms for Ethylene Manufacturing and PE Plants).
Section C - Air Cleaning Device (VOC Control System – LP System Thermal Incinerator) (Utilities and General Facility)
11. Oxidizer/Afterburners Equipment Specifications
Manufacturer To be determined
Type Thermal Catalytic Model No.
Design Inlet Volume (SCFM)
Combustion chamber dimensions (length, cross-sectional area, effective chamber volume, etc.)
Describe design features, which will ensure mixing in combustion chamber.
Describe method of preheating incoming gases (if applicable).
Describe heat exchanger system used for heat recovery (if applicable).
Catalyst used
Life of catalyst
Expected temperature rise across catalyst (°F)
Dimensions of bed (in inches). Height: Diameter or Width: Depth:
Are temperature sensing devices being provided to measure the temperature rise across the catalyst? Yes No If yes, describe.
Describe any temperature sensing and/or recording devices (including specific location of temperature probe in a drawing or sketch.
Burner Information
Burner Manufacturer
Model No.
Fuel Used
Number and capacity of burners
Rated capacity (each)
Maximum capacity (each)
Describe the operation of the burner
Attach dimensioned diagram of afterburner
Operating Parameters
Inlet flow rate (ACFM) @ °F Outlet flow rate (ACFM) @ °F
State pressure drop range across catalytic bed (in. of water).
Describe the method adopted for regeneration or disposal of the used catalyst.
Describe the warning/alarm system that protects against operation when unit is not meeting design requirements.
Emissions Data See Appendix B of the Plan Approval Application
Pollutant Inlet Outlet Removal Efficiency (%)
Section C - Air Cleaning Device (LP Flare System – LP Ground Flare) (Utilities and General Facility)
1. Precontrol Emissions* See Appendix B of the Plan Approval Application
Pollutant
Maximum Emission Rate Calculation/ Estimation
Method Specify Units Pounds/Hour Hours/Year Tons/Year PM PM10 SOx CO NOx VOC Others: (e.g., HAPs) ----- ----- ----- ----- ----- * These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating
schedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emission values were determined. Attach calculations.
2. Gas Cooling
Water quenching Yes No Water injection rate GPM
Radiation and convection cooling Yes No
Air dilution Yes No If yes, CFM
Forced Draft Yes No Water cooled duct work Yes No
Other
Inlet Volume ACFM
@ °F % Moisture
Outlet Volume ACFM
@ °F % Moisture
Describe the system in detail.
Continuous and intermittent VOC containing vents from the light gasoline and hexene tanks will be routed to the VOC Control System’s LP header (LP System). The LP Ground Flare will only be used during process upsets. Emissions associated with the VOC Control System are included in Appendix B of the Plan Approval Application. The capacity of the totally enclosed LP Ground Flare will be 45 ton/hr. Section 3 of the Plan Approval Application provides additional information on LP system.
Section C - Air Cleaning Device (LP Flare System – LP Ground Flare) (Utilities and General Facility) (Continued)
12. Flares Equipment Specifications
Manufacturer To be determined
Type Elevated flare Ground flare Other Describe
Model No.
Design Volume (SCFM)
Dimensions of stack (ft.) Diameter 34 Height 75
Residence time (sec.) and outlet temperature (°F) 1832
Turn down ratio
Burner details
Describe the flare design (air/steam-assisted or nonassisted), essential auxiliaries including pilot flame monitor of proposed flare with a sketch. Non-assisted, pilot flame monitoring.
Describe the operation of the flare’s ignition system.
Describe the provisions to introduce auxiliary fuel to the flare.
Operation Parameters
Detailed composition of the waste gas
Heat content
1 MMBtu/hr (Pilot)
Exit velocity
Maximum and average gas flow burned (ACFM)
Operating temperature (°F)
Describe the warning/alarm system that protects against operation when unit is not meeting design requirements.
Emissions Data See Appendix B of the Plan Approval Application
Pollutant Inlet Outlet Removal Efficiency (%)
Section C - Air Cleaning Device (HP Flare System – Ground Flares (2x)) (Utilities and General Facility)
1. Precontrol Emissions* See Appendix B of the Plan Approval Application
Pollutant
Maximum Emission Rate Calculation/ Estimation
Method Specify Units Pounds/Hour Hours/Year Tons/Year PM PM10 SOx CO NOx VOC Others: (e.g., HAPs) ----- ----- ----- ----- ----- * These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating
schedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emission values were determined. Attach calculations.
2. Gas Cooling
Water quenching Yes No Water injection rate GPM
Radiation and convection cooling Yes No
Air dilution Yes No If yes, CFM
Forced Draft Yes No Water cooled duct work Yes No
Other
Inlet Volume ACFM
@ °F % Moisture
Outlet Volume ACFM
@ °F % Moisture
Describe the system in detail.
The HP Header System consists of one elevated flare with a relieving capacity of 1,200 tons/hr and two totally enclosed ground flares, each rated for 150 tons/hr. The HP Elevated Flare will only be used to control emissions during upsets. The two HP Ground Flares will be used to control VOC emission associated with startup, shutdown, and maintenance of the ethylene manufacturing plant and PE Units. Emissions associated with the two HP Ground and Elevated Flares are included in Appendix B of the Plan Approval Application
Section C - Air Cleaning Device (HP Flare System – Ground Flares (2x)) (Utilities and General Facility) (Continued)
12. Flares Equipment Specifications
Manufacturer To be determined
Type Elevated flare Ground flare Other Describe
Model No.
Design Volume (SCFM)
Dimensions of stack (ft.) Diameter 55 Height 110
Residence time (sec.) and outlet temperature (°F) 1832
Turn down ratio
Burner details
Describe the flare design (air/steam-assisted or nonassisted), essential auxiliaries including pilot flame monitor of proposed flare with a sketch. Non-assisted, pilot flame monitoring.
Describe the operation of the flare’s ignition system.
Describe the provisions to introduce auxiliary fuel to the flare.
Operation Parameters Refer to Appendix B of the Plan Approval Application
Detailed composition of the waste gas
Heat content
Exit velocity
Maximum and average gas flow burned (ACFM)
Operating temperature (°F)
Describe the warning/alarm system that protects against operation when unit is not meeting design requirements.
Emissions Data See Appendix B of the Plan Approval Application
Pollutant Inlet Outlet Removal Efficiency (%)
Section C - Air Cleaning Device (HP Flare System – Elevated Flare
(Utilities and General Facility)
1. Precontrol Emissions* See Appendix B of the Plan Approval Application
Pollutant
Maximum Emission Rate Calculation/ Estimation
Method Specify Units Pounds/Hour Hours/Year Tons/Year PM PM10 SOx CO NOx VOC Others: (e.g., HAPs) ----- ----- ----- ----- ----- * These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating
schedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emission values were determined. Attach calculations.
2. Gas Cooling
Water quenching Yes No Water injection rate GPM
Radiation and convection cooling Yes No
Air dilution Yes No If yes, CFM
Forced Draft Yes No Water cooled duct work Yes No
Other
Inlet Volume ACFM
@ °F % Moisture
Outlet Volume ACFM
@ °F % Moisture
Describe the system in detail.
The HP Header System consists of one elevated flare with a relieving capacity of 1,200 tons/hr and two totally enclosed ground flares, each rated for 150 tons/hr. The HP Elevated Flare will only be used to control emissions during upsets. The two HP Ground Flares will be used to control VOC emission associated with startup, shutdown, and maintenance of the ethylene manufacturing plant and PE Units. Emissions associated with the two HP Ground and Elevated Flares are included in Appendix B of the Plan Approval Application.
Section C - Air Cleaning Device (HP Flare System – Elevated Flare) (Utilities and General Facility) (Continued)
12. FLARES Equipment Specifications
Manufacturer
Type Elevated flare Ground flare Other Describe
Model No.
Design Volume (SCFM)
Dimensions of stack (ft.) Diameter Height
Residence time (sec.) and outlet temperature (°F)
Turn down ratio
Burner details
Describe the flare design (air/steam-assisted or non-assisted), essential auxiliaries including pilot flame monitor of proposed flare with a sketch. Steam assisted, pilot flame monitoring. Refer to Section 3.5.5 and Section 5.12 of the Plan Approval Application for full flare description.
Describe the operation of the flare’s ignition system.
Describe the provisions to introduce auxiliary fuel to the flare.
Operation Parameters Refer to Appendix B of the Plan Approval Application Detailed composition of the waste gas
Heat content Exit velocity
Maximum and average gas flow burned (ACFM)
Operating temperature (°F)
Describe the warning/alarm system that protects against operation when unit is not meeting design requirements.
Emissions Data See Appendix B of the Plan Approval Application
Pollutant Inlet Outlet Removal Efficiency (%)
Section C - Air Cleaning Device (Refrigerated Atmospheric Storage Flare) (Utilities and General Facility)
1. Precontrol Emissions* See Appendix B of the Plan Approval Application
Pollutant
Maximum Emission Rate Calculation/ Estimation
Method Specify Units Pounds/Hour Hours/Year Tons/Year PM PM10 SOx CO NOx VOC Others: (e.g., HAPs) ----- ----- ----- ----- ----- * These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating
schedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emission values were determined. Attach calculations.
2. Gas Cooling
Water quenching Yes No Water injection rate GPM
Radiation and convection cooling Yes No
Air dilution Yes No If yes, CFM
Forced Draft Yes No Water cooled duct work Yes No
Other
Inlet Volume ACFM
@ °F % Moisture
Outlet Volume ACFM
@ °F % Moisture
Describe the system in detail.
The refrigerated atmospheric storage flare will be a ground flare sized for 22 tons/hr of relieving capacity. This flare will be used during the initial startup, following inspections, and for emergency relief of the refrigerated atmospheric storage tank. Inspections will occur once every five to ten years. Emissions associated with refrigerated atmospheric storage flare are included in Appendix B of the Plan Approval Application.
Section C - Air Cleaning Device (Refrigerated Atmospheric Storage Flare) (Utilities and General Facility) (Continued)
12. Flares Equipment Specifications Manufacturer To be determined
Type Elevated flare Ground flare Other Describe
Model No.
Design Volume (SCFM)
Dimensions of stack (ft.) Diameter 15 Height
Residence time (sec.) and outlet temperature (°F) 1832
Turn down ratio
Burner details
Describe the flare design (air/steam-assisted or nonassisted), essential auxiliaries including pilot flame monitor of proposed flare with a sketch.
Describe the operation of the flare’s ignition system.
Describe the provisions to introduce auxiliary fuel to the flare.
Operation Parameters Refer to Appendix B of the Plan Approval Application
Detailed composition of the waste gas
Heat content
Exit velocity
Maximum and average gas flow burned (ACFM)
Operating temperature (°F)
Describe the warning/alarm system that protects against operation when unit is not meeting design requirements.
Emissions Data See Appendix B of the Plan Approval Application
Pollutant Inlet Outlet Removal Efficiency (%)
Section C - Air Cleaning Device (Spent Caustic Vent Thermal Incinerator) (Utilities and General Facility)
1. Precontrol Emissions* See Appendix B or the Plan Approval Application
Pollutant
Maximum Emission Rate Calculation/ Estimation
Method Specify Units Pounds/Hour Hours/Year Tons/Year PM PM10 SOx CO NOx VOC Others: (e.g., HAPs) ----- ----- ----- ----- ----- * These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating
schedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emission values were determined. Attach calculations.
2. Gas Cooling
Water quenching Yes No Water injection rate GPM
Radiation and convection cooling Yes No
Air dilution Yes No If yes, CFM
Forced Draft Yes No Water cooled duct work Yes No
Other
Inlet Volume ACFM
@ °F % Moisture
Outlet Volume ACFM
@ °F % Moisture
Describe the system in detail.
The Spent Caustic Vent Thermal Incinerator will have a design heat input of 10 MMBtu/hr. It will be designed to control VOC emissions from the spent caustic oxidizer stripper, and tank emissions from the spent caustic, flow equalization, and recovered oil tanks.
Section C - Air Cleaning Device (Spent Caustic Vent Thermal Incinerator) (Utilities and General Facility) (Continued)
11. Oxidizer/Afterburners Equipment Specifications Manufacturer To be determined
Type Thermal Catalytic Model No.
Design Inlet Volume (SCFM)
Combustion chamber dimensions (length, cross-sectional area, effective chamber volume, etc.)
Describe design features, which will ensure mixing in combustion chamber.
Describe method of preheating incoming gases (if applicable).
Describe heat exchanger system used for heat recovery (if applicable).
Catalyst used
Life of catalyst
Expected temperature rise across catalyst (°F)
Dimensions of bed (in inches). Height: Diameter or Width: Depth:
Are temperature sensing devices being provided to measure the temperature rise across the catalyst? Yes No If yes, describe.
Describe any temperature sensing and/or recording devices (including specific location of temperature probe in a drawing or sketch.
Burner Information
Burner Manufacturer
Model No.
Fuel Used
Number and capacity of burners
Rated capacity (each)
Maximum capacity (each)
Describe the operation of the burner
Attach dimensioned diagram of afterburner
Operating Parameters
Inlet flow rate (ACFM) @ °F Outlet flow rate (ACFM) @ °F
State pressure drop range across catalytic bed (in. of water).
Describe the method adopted for regeneration or disposal of the used catalyst.
Describe the warning/alarm system that protects against operation when unit is not meeting design requirements.
Emissions Data: See Appendix B of the Plan Approval Application
Pollutant Inlet Outlet Removal Efficiency (%)
Section C - Air Cleaning Device (Wastewater Treatment Plant (WWTP)) 1. Precontrol Emissions*
Pollutant
Maximum Emission Rate Calculation/ Estimation
Method Specify Units Pounds/Hour Hours/Year Tons/Year PM PM10 SOx CO NOx VOC Others: (e.g., HAPs) ----- ----- ----- ----- ----- * These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating
schedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emission values were determined. Attach calculations.
Describe the system in detail.
The wastewater treatment plant (WWTP) will consist of primary flow equalization and oil removal, followed by a secondary activated sludge bioreactor (including clarifiers), and a tertiary sand filter to treat the wastewater streams from process units and potentially contaminated storm water runoff from process paved areas. A more detailed description of the WWTP follows.
Several wastewater streams from the facility, including those streams containing volatile organic compounds, will flow into one of two flow equalization oil removal (FEOR) tanks (T-59707A/B). Each tank will be a fixed roof tank equipped with an internal floating roof. Oil rising to the top of these tanks will be skimmed off and will flow to a recovered oil storage tank (T-59708) for off-site disposal.
Effluent from the FEOR tanks will then be routed to the biotreater aeration tank. Internal WWTP recycle streams will also flow into this tank, as well as small nutrient additive and ph adjustment streams. Biotreater effluent will flow to two secondary clarifier tanks, and the clarifiers’ overflow stream will be pumped through a sand filter. Clarifier underflow will be pumped to a biosludge holding tank that will feed a centrifuge used for concentrating clarifier solids into a cake. Cooling tower blowdown will be pumped directly to the sand filter, and effluent from this filter will be discharged through an outfall to the Ohio river. Sand filter backwash will be pumped into a tank, and will be recycled back to the biotreater aeration tank.
Emissions from the two flow equalization (T-59707A/B) and recovered oil storage ((T-59708) tanks will be equipped with a closed vent system, and collected vapors will be routed to the spent caustic incinerator with a VOC destruction efficiency of 99% or greater. All other WWTP sources are designated as other WWTP equipment (W-1001).
Maximum EmissionRate Factor
Pollutantmillion gal/day
lb/million gal lb/hr hrs/year TPY lb/hr hrs/year TPY
VOC N/A N/A 0.381 8,760 0.755 0.004 8,760 0.008 Emissions model EPA TANKS 4.0.1daPrecontrol emissions were calculated based on tanks equipped with internal floating roofs.BasisPrecontrol emissions, both lb/hr VOC and TPY VOC, were calculated using EPA's TANKS 4.0.1d. software.Combustion source control efficiency: 99% for VOCExample Calculation0.004 lb/hr VOC [post-control] = (0.381 lb VOC/hr) x (100% - 99%) / 100%
Wastewater Treatment Plant
2 Flow Equalization and Oil Removal Tanks (T-5307A/B) - Emissions Summary
Precontrol Emissionsa Controlled EmissionsCalculation/Estimation
MethodEmission Factor
Reference
Maximum EmissionRate Factor
Pollutantmillion gal/day
lb/million gal lb/hr hrs/year TPY lb/hr hrs/year TPY
VOC N/A N/A 0.289 8,760 1.26 0.003 8,760 0.013 Emissions model EPA WATER9
Others: (e.g., HAPs) - - - - - - - - -
Benzene N/A N/A 0.051 8,760 0.22 0.0005 8,760 0.0022 Emissions model EPA WATER9
Ethylbenzene N/A N/A 0.039 8,760 0.17 0.0004 8,760 0.0017 Emissions model EPA WATER9
Toluene N/A N/A 0.199 8,760 0.87 0.002 8,760 0.0087 Emissions model EPA WATER9
Phenol N/A N/A 9.05E-07 8,760 3.96E-06 9.05E-09 8,760 3.96E-08 Emissions model EPA WATER9
BasisPrecontrol emissions were calculated using EPA's WATER9 modeling software.Emissions were calculated for worst-case conditions of dry weather flow.Combustion source control efficiency: 99% for VOC and HAPsExample Calculations0.003 lb VOC/hr [post-control] = (0.289 lb VOC/hr) x (100% - 99%) / 100%1.26 ton VOC/yr [pre-control] = (0.298 lb/hr) x (8,760 hrs/year) / (2,000 lb/ton)
Biotreater Aeration Tank (T-5309) - Emissions Summary
Precontrol Emissions Controlled EmissionsCalculation/Estimation
MethodEmission Factor
Reference
Section E - Compliance Demonstration (Utilities and General Facility)
Note: Complete this section if source is not a Title V facility. Title V facilities must complete Addendum A.
Method of Compliance Type: Check all that apply and complete all appropriate sections below
Monitoring Testing Reporting
Recordkeeping Work Practice Standard
Monitoring: a. Monitoring device type (Parameter, CEM, etc): b. Monitoring device location: c. Describe all parameters being monitored along with the frequency and duration of monitoring each parameter:
Testing:
a. Reference Test Method: Citation b. Reference Test Method: Description
Recordkeeping:
Describe what parameters will be recorded and the recording frequency:
Reporting:
a. Describe what is to be reported and frequency of reporting:
Reporting of required monitoring in compliance with regulations listed in Appendix G of the Plan Approval Application. Submittal of reports of required monitoring semi-annually per 25 Pa. Code § 127.511(c)
b. Reporting start date:
Work Practice Standard:
Describe each: VOC Control System and Refrigerated Flare– Waste gas minimization and operation to achieve good destruction removal efficiency. Flare will be designed to meet limitations on maximum exit velocity, as set forth in the general provisions at 40 CFR 60.18 and 63.11. Flare will be operated to meet minimum net heating value requirements for gas streams combusted in flares as set forth in 40 CFR 60.18. Further details on the VOC Control System compliance methods is presented in Section 5.0 of the Plan Approval Application. Spent Caustic Vent Thermal Incinerator will be designed and operated to ensure 99% DRE. The LP Thermal Incinerator will be designed and operated to ensure 99.5% DRE.
Section F - Flue and Air Contaminant Emission (Carbon Canisters) (Utilities and General Facility)
1. Estimated Atmospheric Emissions* Refer to Appendix B for emissions calculations
Pollutant
Maximum emission rate Calculation/
Estimation Method specify units lbs/hr tons/yr. PM
PM10
SOx
CO
NOx
VOC
Others: ( e.g., HAPs) ----- ----- ----- -----
* These emissions must be calculated based on the requested operating schedule and/or process rate e.g., operating schedule for maximum limits or restricted hours of operation and /or restricted throughput. Describe how the emission values were determined. Attach calculations.
2. Stack and Exhauster Refer to Appendix C of the Plan Approval Application
Stack Designation/Number
List Source(s) or source ID exhausted to this stack: EGEN1/2/3/4
% of flow exhausted to stack: 100
Stack height above grade (ft.) Grade elevation (ft.)
Stack diameter (ft) or Outlet duct area (sq. ft.)
f. Weather Cap YES NO
Distance of discharge to nearest property line (ft.). Locate on topographic map.
Does stack height meet Good Engineering Practice (GEP)? Yes
If modeling (estimating) of ambient air quality impacts is needed, attach a site plan with buildings and their dimensions and other obstructions. Refer to Appendix C of the Plan Approval Application
Location of stack** Latitude/Longitude
Latitude Longitude
Point of Origin Degrees Minutes Seconds Degrees Minutes Seconds Stack exhaust
Volume ACFM Temperature °F Moisture %
Indicate on an attached sheet the location of sampling ports with respect to exhaust fan, breeching, etc. Give all necessary dimensions. Exhauster (attach fan curves) in. of water HP @ RPM.
** If the data and collection method codes differ from those provided on the General Information Form-Authorization Application, provide the additional detail required by that form on a separate form.
Section F - Flue and Air Contaminant Emission (LP Ground Flare)
(Utilities and General Facility)
1. Estimated Atmospheric Emissions* Refer to Appendix B for emissions calculations
Pollutant
Maximum emission rate Calculation/
Estimation Method specify units lbs/hr tons/yr. PM
PM10
SOx
CO
NOx
VOC
Others: ( e.g., HAPs) ----- ----- ----- -----
* These emissions must be calculated based on the requested operating schedule and/or process rate e.g., operating schedule for maximum limits or restricted hours of operation and /or restricted throughput. Describe how the emission values were determined. Attach calculations.
2. Stack and Exhauster Refer to Appendix C of the Plan Approval Application
Stack Designation/Number LPGFLARE
List Source(s) or source ID exhausted to this stack: See Appendix D
% of flow exhausted to stack:
Stack height above grade (ft.) Grade elevation (ft.)
Stack diameter (ft) or Outlet duct area (sq. ft.)
f. Weather Cap YES NO
Distance of discharge to nearest property line (ft.). Locate on topographic map.
Does stack height meet Good Engineering Practice (GEP)? Yes
If modeling (estimating) of ambient air quality impacts is needed, attach a site plan with buildings and their dimensions and other obstructions. Refer to Appendix C of the Plan Approval Application
Location of stack** Latitude/Longitude
Latitude Longitude
Point of Origin Degrees Minutes Seconds Degrees Minutes Seconds Stack exhaust
Volume ACFM Temperature °F Moisture %
Indicate on an attached sheet the location of sampling ports with respect to exhaust fan, breeching, etc. Give all necessary dimensions. Exhauster (attach fan curves) in. of water HP @ RPM.
** If the data and collection method codes differ from those provided on the General Information Form-Authorization Application, provide the additional detail required by that form on a separate form.
Section F - Flue and Air Contaminant Emission (HP Ground Flares (2x))
(Utilities and General Facility)
1. Estimated Atmospheric Emissions* Refer to Appendix B for emissions calculations
Pollutant
Maximum emission rate Calculation/
Estimation Method specify units lbs/hr tons/yr. PM
PM10
SOx
CO
NOx
VOC
Others: ( e.g., HAPs) ----- ----- ----- -----
* These emissions must be calculated based on the requested operating schedule and/or process rate e.g., operating schedule for maximum limits or restricted hours of operation and /or restricted throughput. Describe how the emission values were determined. Attach calculations.
2. Stack and Exhauster Refer to Appendix C of the Plan Approval Application
Stack Designation/Number HPGFLARE
List Source(s) or source ID exhausted to this stack: See Appendix D
% of flow exhausted to stack: 100
Stack height above grade (ft.) Grade elevation (ft.)
Stack diameter (ft) or Outlet duct area (sq. ft.)
f. Weather Cap YES NO
Distance of discharge to nearest property line (ft.). Locate on topographic map.
Does stack height meet Good Engineering Practice (GEP)? Yes
If modeling (estimating) of ambient air quality impacts is needed, attach a site plan with buildings and their dimensions and other obstructions. Refer to Appendix C of the Plan Approval Application
Location of stack** Latitude/Longitude
Latitude Longitude
Point of Origin Degrees Minutes Seconds Degrees Minutes Seconds Stack exhaust
Volume ACFM Temperature °F Moisture %
Indicate on an attached sheet the location of sampling ports with respect to exhaust fan, breeching, etc. Give all necessary dimensions. Exhauster (attach fan curves) in. of water HP @ RPM.
** If the data and collection method codes differ from those provided on the General Information Form-Authorization Application, provide the additional detail required by that form on a separate form.
Section F - Flue and Air Contaminant Emission (HP Flare System – Elevated Flare)
(Utilities and General Facility)
1. Estimated Atmospheric Emissions* Refer to Appendix B for emissions calculations
Pollutant
Maximum emission rate Calculation/
Estimation Method specify units lbs/hr tons/yr. PM
PM10
SOx
CO
NOx
VOC
Others: ( e.g., HAPs) ----- ----- ----- -----
* These emissions must be calculated based on the requested operating schedule and/or process rate e.g., operating schedule for maximum limits or restricted hours of operation and /or restricted throughput. Describe how the emission values were determined. Attach calculations.
2. Stack and Exhauster Refer to Appendix C of the Plan Approval Application
Stack Designation/Number HPEFLARE
List Source(s) or source ID exhausted to this stack:
% of flow exhausted to stack: 100
Stack height above grade (ft.) Grade elevation (ft.)
Stack diameter (ft) or Outlet duct area (sq. ft.)
f. Weather Cap YES NO
Distance of discharge to nearest property line (ft.). Locate on topographic map.
Does stack height meet Good Engineering Practice (GEP)? Yes
If modeling (estimating) of ambient air quality impacts is needed, attach a site plan with buildings and their dimensions and other obstructions. Refer to Appendix C of the Plan Approval Application
Location of stack** Latitude/Longitude
Latitude Longitude
Point of Origin Degrees Minutes Seconds Degrees Minutes Seconds Stack exhaust
Volume ACFM Temperature °F Moisture %
Indicate on an attached sheet the location of sampling ports with respect to exhaust fan, breeching, etc. Give all necessary dimensions.
Exhauster (attach fan curves) in. of water HP @ RPM.
** If the data and collection method codes differ from those provided on the General Information Form-Authorization Application, provide the additional detail required by that form on a separate form.
Section F - Flue and Air Contaminant Emission (Spent Caustic Vent Thermal Incinerator)
(Utilities and General Facility)
1. Estimated Atmospheric Emissions* Refer to Appendix B for emissions calculations
Pollutant
Maximum emission rate Calculation/
Estimation Method specify units lbs/hr tons/yr. PM
PM10
SOx
CO
NOx
VOC
Others: ( e.g., HAPs) ----- ----- ----- -----
* These emissions must be calculated based on the requested operating schedule and/or process rate e.g., operating schedule for maximum limits or restricted hours of operation and /or restricted throughput. Describe how the emission values were determined. Attach calculations.
2. Stack and Exhauster Refer to Appendix C of the Plan Approval Application
Stack Designation/Number
List Source(s) or source ID exhausted to this stack:
% of flow exhausted to stack: 100
Stack height above grade (ft.) Grade elevation (ft.)
Stack diameter (ft) or Outlet duct area (sq. ft.)
f. Weather Cap YES NO
Distance of discharge to nearest property line (ft.). Locate on topographic map.
Does stack height meet Good Engineering Practice (GEP)? Yes
If modeling (estimating) of ambient air quality impacts is needed, attach a site plan with buildings and their dimensions and other obstructions. Refer to Appendix C of the Plan Approval Application
Location of stack** Latitude/Longitude
Latitude Longitude
Point of Origin Degrees Minutes Seconds Degrees Minutes Seconds Stack exhaust
Volume ACFM Temperature °F Moisture %
Indicate on an attached sheet the location of sampling ports with respect to exhaust fan, breeching, etc. Give all necessary dimensions.
Exhauster (attach fan curves) in. of water HP @ RPM.
** If the data and collection method codes differ from those provided on the General Information Form-Authorization Application, provide the additional detail required by that form on a separate form.
Section F - Flue and Air Contaminant Emission (Refrigerated Atmospheric Storage Flare)
(Utilities and General Facility)
1. Estimated Atmospheric Emissions* Refer to Appendix B for emissions calculations
Pollutant
Maximum emission rate Calculation/
Estimation Method specify units lbs/hr tons/yr. PM
PM10
SOx
CO
NOx
VOC
Others: ( e.g., HAPs) ----- ----- ----- -----
* These emissions must be calculated based on the requested operating schedule and/or process rate e.g., operating schedule for maximum limits or restricted hours of operation and /or restricted throughput. Describe how the emission values were determined. Attach calculations.
2. Stack and Exhauster Refer to Appendix C of the Plan Approval Application
Stack Designation/Number
List Source(s) or source ID exhausted to this stack:
% of flow exhausted to stack: 100
Stack height above grade (ft.) Grade elevation (ft.)
Stack diameter (ft) or Outlet duct area (sq. ft.)
f. Weather Cap YES NO
Distance of discharge to nearest property line (ft.). Locate on topographic map.
Does stack height meet Good Engineering Practice (GEP)? Yes
If modeling (estimating) of ambient air quality impacts is needed, attach a site plan with buildings and their dimensions and other obstructions. Refer to Appendix C of the Plan Approval Application
Location of stack** Latitude/Longitude
Latitude Longitude
Point of Origin Degrees Minutes Seconds Degrees Minutes Seconds Stack exhaust
Volume ACFM Temperature °F Moisture %
Indicate on an attached sheet the location of sampling ports with respect to exhaust fan, breeching, etc. Give all necessary dimensions.
Exhauster (attach fan curves) in. of water HP @ RPM.
** If the data and collection method codes differ from those provided on the General Information Form-Authorization Application, provide the additional detail required by that form on a separate form.
Section D - Additional Information
Will the construction, modification, etc. of the sources covered by this application increase emissions from other sources at the facility? If so, describe and quantify.
No.
If this project is subject to any one of the following, attach a demonstration to show compliance with applicable standards. In accordance with the PSD and NSR requirements, the Plan Approval Application contains all of the materials required for a complete PSD/NSR application including BACT/LAER analyses, air quality impacts analysis/offsets requirements, additional impacts/alternative site evaluation and a complete regulatory analysis and detailed emissions increase calculations. The Plan Approval Application also contains proposed methods of compliance for the applicable standards denoted below. a. Prevention of Significant Deterioration permit (PSD), 40 CFR 52? (NO2, CO, PM, & PM10) YES NO b. New Source Review (NSR), 25 Pa. Code Chapter 127, Subchapter E? (NOx, VOC, & PM2.5) YES NO c. New Source Performance Standards (NSPS), 40 CFR Part 60? YES NO (If Yes, which subpart) Kb, VV, VVa, DDD, NNN, RRR, YYY (stayed), IIII, KKKK, & TTTT (proposed) d. National Emissions Standards for Hazardous Air Pollutants (NESHAP), YES NO 40 CFR Part 61? (If Yes, which subpart) J, V, & FF e. Maximum Achievable Control Technology (MACT) 40 CFR Part 63? YES NO (If Yes, which part) SS, UU, WW, XX, YY, FFFF, YYYY (stayed for natural gas-fired CTs), & ZZZZ Attach a demonstration showing that the emissions from any new sources will be the minimum attainable through the use of best available technology (BAT). See the control technology reviews included in Section 5.0 of the Plan Approval Application.
Provide emission increases and decreases in allowable (or potential) and actual emissions within the last five (5) years for applicable PSD pollutant(s) if the facility is an existing major facility (PSD purposes).
Section D - Additional Information (Continued)
Indicate emission increases and decreases in tons per year (tpy), for volatile organic compounds (VOCs) and nitrogen oxides (NOx) for NSR applicability since January 1, 1991 or other applicable dates (see other applicable dates in instructions). The emissions increases include all emissions including stack, fugitive, material transfer, other emission generating activities, quantifiable emissions from exempted source(s), etc.
Permit number
(if applicable) Date
issued
Indicate Yes or No if
emission increases and
decreases were used
previously for netting Source I. D. or Name
VOCs NOx Emission increases
in potential to emit
(tpy)
Creditable emission
decreases in actual
emissions (tpy)
Emission increases
in potential to emit
(tpy)
Creditable emission
decreases in actual
emissions (tpy)
If the source is subject to 25 Pa. Code Chapter 127, Subchapter E, New Source Review requirements, a. Identify Emission Reduction Credits (ERCs) for emission offsets or demonstrate ability to obtain suitable ERCs for
emission offsets. b. Provide a demonstration that the lowest achievable emission rate (LAER) control techniques will be employed (if
applicable). See the LAER subsections in Section 5.0 of the Plan Approval Application. c. Provide an analysis of alternate sites, sizes, production processes and environmental control techniques demonstrating
that the benefits of the proposed source outweigh the environmental and social costs (if applicable). See Section 1.0 and Appendix E.2 of the Plan Approval Application.
Attach calculations and any additional information necessary to thoroughly evaluate compliance with all the applicable requirements of Article III and applicable requirements of the Clean Air Act adopted there under The Department may request additional information to evaluate the application such as a standby plan, a plan for air pollution emergencies, air quality modeling, etc. See the Plan Approval Application for this information.
Section G - Attachments Number and list all attachments submitted with this application below:
The contents of this Plan Approval Application are organized as follows:
Section 1.0 provides an overview of the Project, a description of the proposed site’s location and surrounding terrain and local climate in Beaver County, Pennsylvania, and a summary of the pollutant-by-pollutant emissions increases.
Section 2.0 contains a summary of the permit application requirements.
Section 3.0 contains the process description. Each of the manufacturing processes which comprise the proposed Project are described along with the points and types of emissions from each point. Also included is a description of the various outside the boundary limits (OSBL) elements of the Project.
Section 4.0 contains an overview of all of the air regulatory requirements to which the proposed Project is subject. This includes a description of both state and federal requirements.
Section 5.0 contains the Lowest Achievable Emissions Rate (LAER), Best Available Control Technology (BACT) and Pennsylvania Best Available Technology (PaBAT) analyses required in support of the plan approval process.
Section 6.0 contains a summary of the results from the air dispersion modeling analysis performed in support of the plan approval process for the PSD criteria pollutant for which the Project is subject to review (i.e., NO2, CO, and PM10).
Section 7.0 contains the additional impacts analysis required under 40 CFR §52.21(o).
Appendices A – Plan Approval Application Forms B – Detailed Emissions Increase Calculations C – Air Dispersion Modeling Report D – Trade Secret and/or Confidential Proprietary Information (Not in Public Version) E – 25 Pa. Code §127.205(5) Analysis F – Additional Support Material G – Summary of Compliance Demonstration
Appendix B
Emissions Estimates
1.0 GENERAL DISCUSSION For purposes of evaluating applicability of PSD and NSR nonattainment and determining the potential to emit of the proposed facility, the methodology used for evaluating emissions increases is the actual-to-potential test described at 40 CFR § 52.21(a)(2)(d) and incorporated by reference at 25 Pa. Code §127.83. Since this project is a greenfield facility, emissions increases under the actual-to-potential test are equal to the potential to emit of all of the equipment that will be constructed as part of the project. Baseline actual emissions from all units are zero.
The following discussion provides a summary of the methodology used determine the potential to emit from all units to be constructed project.
1.1 Emissions Units Table 1-1 lists the categories of emissions units to be constructed as part of the project and identifies the general methodology used to estimate the potential to emit for each unit type. A specific discussion of each of the calculation methodologies is provided in the following subsections.
Table 1-1. List of Emissions Units and Emissions Estimation Methods
EU Description Methodology
Ethane Cracking Furnaces (Emission Factor/Proposed Limit) x (Firing Rate) Combustion Turbines (Emission Factor/Proposed Limit) x (Firing Rate) Emergency Generator Engine (Emission Factor/Proposed Limit) x (Capacity) x (Op. Hours) Fire Water Pump Engine (Emission Factor/Proposed Limit) x (Capacity) x (Op. Hours)
Fugitive Equipment Leaks (SOCMI Leak Factors) x (Component Counts) x (1 – Ctrl. Efficiency) x (Component Pollutant Concentration)
PEU Particulate Emissions Vendor Estimates of Potential Emissions PE Handling, Storage & Loading PM (Emission Factor) x (Throughput-Based Air Flows) PE Handling, Storage & Loading VOC (Emission Factor/Proposed Limit) x (Throughput) Tanks VOC (not vented to flare) (TANKS 4.09d) x (1 – Ctrl. Efficiency) WWTP Units (not vented to TI) EPA WATER9 Model Cooling Tower PM AP-42 Methodology; PSD from Reisman & Frisbie Cooling Tower VOC (Proposed Limit) x (Circulation Rate) Organic Liquid Loading AP-42 Methodology (Chapter 5, Section 2) C3+ Loading (Emission Factor) x (Throughput) Caustic and LP TI (Emission Factor) x (Capacity) Flares (Emission Factor) x (Maximum Expected Flaring Rate) Plant Haul Roads AP-42 Methodology (Chapter 13, Section 2)
B-1
1.2 Ethane Cracking Furnaces Seven ethane cracking furnaces will be constructed. During normal operation, six of the furnaces will be operating at max capacity while the seventh will be in some other mode of operation related to decoking, etc. For some pollutants, the alternative modes of operation have different emission characteristics than normal operations. To address this situation, a model was developed that estimates the amount of time each year that a furnace will be in the various operating modes. Emissions are estimated based on the expected average annual time in each operating mode multiplied by the average firing rate in that mode multiplied by a mode-specific emissions factor. The emissions estimates are dominated by normal operations at the maximum firing rates. See Tables B-4 through B-6 for the complete documentation of the emissions factors used as well as the calculation methodology.
1.3 Combustion Turbine/Cogen Units Three Cogen Units will be constructed. These units are expected to operate at or near maximum capacity for most of the year. With the exception of NOx and CO, potential emissions from these units are estimated based on proposed BACT/LAER limits applied to the maximum firing rate assuming full-time (i.e., 8,760 hours per year) operation at that rate. In the case of NOx and CO, emissions during startup are expected to be significantly higher (on a pound per hour basis) than emissions during normal full-load operation. Thus, for purposes of estimating potential emissions of these pollutants, the maximum startup emissions rates were assumed to occur for 7 hours per year, with the remaining hours per year (i.e., 8,753) assumed to be at full-load. See Tables B-7 and B-8 for the complete documentation of the emissions factors used as well as the calculation methodology.
1.4 Emergency Use Engines A total of seven (7) emergency diesel-fueled internal combustion engines will be constructed. Normal (i.e., non-emergency) operation of these units is limited to 100 hours per year or less. Potential emissions from these units are estimated based on proposed BACT/LAER limits applied to the maximum firing rate assuming 100 hours per year of operation. See Tabled B-9 through B-12 for complete documentation of the emissions factors used as well as the calculation methodology.
1.5 Fugitive Equipment Leaks (SOCMI Leak Factors) U.S. EPA developed methodologies for estimating fugitive emissions of VOC from various components (e.g., valves, flanges, pump seals, etc.) organic chemical manufacturing plants, petroleum refineries, and petroleum marketing operations. Some of these methodologies provide estimates of fugitive emissions based on the service-type of (e.g., vapor) each component and the number and types of components in a facility. U.S. EPA’s analysis and the various methodologies developed are documented in a report titled Protocol for Equipment Leak Emission Estimates.1
1 See: Protocol for Equipment Leak Emission Estimates, U.S. EPA, Office of Air Quality Planning and Standards, Research Triangle Park, North Carolina 27711, EPA-453/R-95-017, 1995.
B-2
The default factors for the synthetic organic chemical manufacturing industry (SOCMI) are used to estimate fugitive emissions from equipment leaks. To account for the effect emissions control resulting from implementing an LDAR program on these emissions sources, control efficiencies developed by the Texas Commission on Environmental Quality (TCEQ) have been applied to the uncontrolled SOCMI emissions factors for various components.2
Estimates are made of fugitive emissions of VOC, CH4, and HAP. These estimates are based on the controlled leak rate from a component and the concentration of the relevant species in the gas or liquid serviced by the component. See Tables B-13 through B-15 for complete documentation of the emissions factors used as well as the component counts, control efficiencies, and species concentrations used in estimating these emissions.
1.6 PE Unit Particulate Emissions A small quantity of particulate will be emitted from operations within the three PE production units. Estimates of these emissions have been provided by prospective process licensers and these estimates are summarized in Tables B-16 and B-17. Where appropriate, the vendor estimates have been scaled-up to 8,760 hours per year of operation. Certain assumptions regarding operating schedules were made to estimate short-term emissions from these operations for purposes of air quality modeling.
1.7 PE Pellet Handling, Storage, and Loadout A small quantity of particulate will be emitted from operations involving handling, storage, blending, and loadout of the product PE pellets. In general, these operations are relatively dust-free. However, some particulate is created in the processing and handling of the PE pellets. Particulate emissions from these operations are estimated based on an assumed particulate mass loading multiplied by an estimate of the ratio of exhaust air flows required or created by these operations to the potential PE pellet production capacity of the proposed plant. See Table B-18 for complete documentation of the emissions factors used as well as the calculation methodology.
In the case VOC emissions from these operations, potential emissions are estimated based on a maximum residual VOC concentration in the pellets multiplied by the potential pellet production rate. This estimation approach conservatively assumes that 100% of the residual VOC is emitted in the handling, storage, or loadout operations.
1.8 Storage Tank Emissions Uncontrolled emissions from certain fixed-roof atmospheric storage tanks (Table B-20) are estimated using U.S. EPA’s TANKS 4.09d software. This software implements the emissions estimation methodology outlined in AP-42, Chapter 7, Section 1. Controlled emissions from
2 See: TCEQ – Control Efficiencies for TCEQ Leak Detection and Repair Programs, Revised 07/11 (APDG 6129v2) available at: http://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/control_eff.pdf
B-3
these tanks are estimated by assigning a 95% control efficiency based on the use of carbon canisters that will be installed on the vents from these tanks. No routine emissions, other than fugitive emissions from equipment components, are estimated from pressurized storage tanks (i.e., the C3+ storage spheres). These tanks are sealed and pressurized so that working and breathing losses do not occur. Emissions from storage tanks with vents routed to the flare headers are accounted for in the estimated emissions from the LP Thermal and Spent Caustic Vent Thermal Incinerators.
1.9 Wastewater Treatment Plant Emissions Uncontrolled emissions from the wastewater treatment unit operations are estimated using EPA’s WATER9 air emissions model. Emissions from certain controlled WWTP tanks were estimated using EPA’s TANKS software. These emissions are accounted for in the controlled emissions estimates from Spent Caustic Vent Thermal Incinerator.
1.10 Process and Cogen Cooling Towers Particulate emissions for the Process and Cogen Cooling Towers are estimated based on the design drift rate, the cooling water recirculation rate, the TDS of the cooling water, an estimated dry particle size distribution, and assumed full-time operation (i.e., 8,760 hours per year) of the tower. The “Reisman and Frisbie” methodology for determining the PM10 and PM2.5 size distribution of the PM emissions is used to estimate fine particulate emissions.3 For the TDS level in the plant cooling water systems, the PM10 fraction predicted by this methodology is 57.2 wt. % and the PM2.5 fraction is 0.21 wt. %. VOC emissions from the process cooling towers are estimated based on the proposed VOC LAER limit and the design cooling water circulation rate. See Tables B-22 and B-23 for documentation of the calculation methodology used to estimate PM and VOC emissions.
1.11 Organic Liquid Loading VOC emissions from loading of organic liquids (other than C3+ liquids) into transport trucks and railcars are estimated using the methodology found in AP-42, Chapter 5, Section 2. The VOC emissions estimates from these operations are based on an assumed VOC vapor pressure of 0.5 psia, a surrogate VOC vapor molecular weight, and the use of submerged loading. See Table B-24 for documentation of the calculation methodology used to estimate emissions.
1.12 C3+ Liquid Loading C3+ liquids will be store in pressure spheres and loaded into pressurized transport vehicles. VOC emissions from these operations have been estimated based on a study of LPG loading
3 See “Calculating Realistic PM10 Emissions from Cooling Towers,” Joel Reisman and Gordon Frisbie, Environmental Progress (Vol. 21, No. 2), July 2002, p. 127 – 129.
B-4
conducted by the South Coast Air Quality Management District (SCAQMD) in California.4 An emissions factor of 13.3 lb VOC per railcar loaded was derived from the SCAQMD study and applied to the maximum expected volume of C3+ that will be shipped from the proposed plant.
1.13 Thermal Incinerators Two thermal incinerators will be used to control certain VOC emissions sources within the proposed plant. Emissions from these incinerators are estimated based on the expected maximum vent rates to the control devices, the design VOC destruction efficiency of the controls, and emissions factors for various pollutants produced during the combustion process. Emissions consist of products of combustion (e.g., NOx) along with unoxidized VOC and non-VOC organic compounds (e.g., CH4). See Tables B-26 and B-28 for documentation of the emissions factors as well as the calculation methodology used to estimate emissions from these control devices.
1.14 Flares Five flares will be constructed to control VOC emissions from the proposed plant. Emissions from the flares are estimated based on the expected maximum vent rates to the flares, the VOC destruction efficiency of the flares, and emissions factors for various pollutants produced during the combustion process. Emissions consist of products of combustion (e.g., NOx) along with unoxidized VOC and non-VOC organic compounds (e.g., CH4). For the most part, these flares are only used for short-periods during startup, shutdown, or emergency events. Potential emissions from these control devices are estimated based on a number of worst-case assumptions about the flaring rates expected to occur during routine, foreseeable operations. See Table B-27 for documentation of the emissions factors as well as the calculation methodology used to estimate emissions from the flares.
1.15 Plant Roads Particulate emissions from plant roads are estimated using the methodology described in AP-42, Chapter 13, Section 2.1 – Paved Roads. Specifically, Equation 2 in this section is used to determine a paved road emissions factor and then that factor is applied to the estimated truck travel distance based on the estimated maximum number of trucks that will enter and leave the facility. The derivation of the pollutant-specific emissions factors are documented in the spreadsheet printouts provided in Table B-29.
1.16 Cocatalyst Feed Pots Table B-34 contains an estimate of emissions of hexane that occur during the transfer of cocatalyst from delivery containers to the feed pots. The estimate assumes compliance with 40 CFR Part 63 Subpart FFFF. The vent stream cannot be controlled by the VOC Control System due to the highly pyrophoric nature of the cocatalyst. As a result, the stream vents to a remote
4 See Final Staff Report Proposed Rule 1177 – Liquefied Petroleum Gas Transfer and Dispensing, South Coast Air Quality Management District, June 2012; available at: http://www.aqmd.gov/hb/attachments/2011-2015/2012Jun/2012-Jun1-031.pdf; (see Attachment F)
B-5
sand pit for safe destruction. Since the % destruction cannot be measured, a 20ppm hexane exhaust concentration is used for the calculation. Documentation of the calculation methodology used to estimate the emissions is also presented in the table.
B-6
Attachment B1 - Tables
B-7
PollutantCracking Furnaces
Polyethylene Units
Combined Cycle Units
Flares & Incinerators
Tanks & Loadout
FugitivesSupport
UnitsTotal
Carbon Monoxide 670 - 43.5 277 - - 0.6 991Nitrogen Oxides 181 - 67.9 74.8 - - 2.8 327PM 34.1 15.3 16.9 4.6 - - 8.3 79PM10 86.8 4.9 59.8 8.2 - - 4.7 164PM2.5 86.8 4.9 59.8 8.2 - - 0.1 160Sulfur Dioxide 3.6 - 13.3 5.0 - - 0.0 22VOC 32.4 96.6 31.9 219 14.1 47.5 42.7 484CO2e 1,048,668 - 1,061,680 147,708 - 138 1,272 2,259,466Sulfuric Acid Mist 0.1 - 0.5 0.2 - - 0.0 0.9§112 HAP 18.2 <0.1 9.3 3.4 1.77 5.40 3.9 41.9Support Units include: fire pump and emergency generator engines, cooling towers, wastewater treatment and plant roads.Polyethylene Units include: PE processing equipment exluding fugitive, flare, and incinerator emissions.
Potential Annual Emissions (tons per year)
Table B-1. Summary of Potential Annual Emissions
B-9
PollutantCracking Furnaces
Polyethylene Units
Combined Cycle Units
Flares & Incinerators
Tanks & Loadout
FugitivesEmergency
EnginesWWTP
Cooling Tower
Total
1,3-Butadiene 3.90E-032-Methylnaphthalene 2.31E-043-Methylchloranthrene 1.73E-057,12-Dimethylbenz(a)anthrac 1.54E-04Acenaphthene 1.73E-05 3.64E-05Acenaphthylene 7.17E-05Acetaldehyde 3.63E-01 1.96E-04Acrolein 5.80E-02 6.13E-05Anthracene 2.31E-05 9.56E-06Arsenic 1.93E-03Benzene 2.02E-02 1.09E-01 6.03E-03 4.24E-01Benzo(a)anthracene 1.73E-05 4.84E-06Benzo(a)pyrene 1.16E-05 2.00E-06Benzo(b)fluoranthene 1.73E-05 8.63E-06Benzo(g,h,i)perylene 1.16E-05Benzo(g,h,l)perylene 4.32E-06Benzo(k)fluoranthene 1.73E-05 1.69E-06Beryllium 1.16E-04Cadmium 1.06E-02Chromium 1.35E-02Chrysene 1.73E-05 1.19E-05Cobalt 8.09E-04Dibenzo(a,h)anthracene 1.16E-05 2.69E-06Dichlorobenzene 1.16E-02Ethylbenzene 2.90E-01Fluoranthene 2.89E-05 3.13E-05Fluorene 2.70E-05 9.95E-05Formaldehyde 7.22E-01 6.44E+00 6.13E-04Hexane 1.73E+01Indeno(1,2,3-cd)pyrene 1.73E-05 3.22E-06Manganese 3.66E-03Mercury 2.50E-03Naphthalene 5.87E-03 1.18E-02 1.01E-03Nickel 2.02E-02PAH 1.99E-02Phenanthrene 1.64E-04 3.17E-04Phenol 4.10E-05Propylene Oxide 2.63E-01Pyrene 4.81E-05 2.88E-05Selenium 2.31E-04Toluene 3.27E-02 1.18E+00 2.18E-03Xylenes 5.80E-01 1.50E-03TOTAL HAP 1.82E+01 9.31E+00 3.4 1.8 5.4 1.22E-02 4.24E-01 3.42 4.19E+01Support Units include: fire pump and emergency generator engines, cooling towers, wastewater treatment and plant roads.Polyethylene Units include: PE processing equipment exluding fugitive, flare, and incinerator emissions.
Potential Annual Emissions (tons per year)
Table B-2. Summary of Potential Hazardous Air Emissions
<0.1
<0.1
B-10
Source/Basis
grams per pound = 453.6 g/lb standard conversion factorpounds per kilo = 2.205 lb/kg standard conversion factorHydrogen HHV = 61,000 Btu/lb http://en.wikipedia.org/wiki/Heat_of_combustionEthylene HHV = 21,884 Btu/lb http://www.engineeringtoolbox.com/heating-values-fuel-gases-d_823.html
Butane HHV = 20,900 Btu/lb http://en.wikipedia.org/wiki/Heat_of_combustionPentane HHV = 20,908 Btu/lb http://www.engineeringtoolbox.com/heating-values-fuel-gases-d_823.html
Ethane HHV = 22,400 Btu/lb http://en.wikipedia.org/wiki/Heat_of_combustionMethane HHV = 23,900 Btu/lb http://en.wikipedia.org/wiki/Heat_of_combustion
Natural Gas HHV = 23,000 Btu/lb http://en.wikipedia.org/wiki/Heat_of_combustionNatural Gas HHV = 1,020 Btu/SCF AP-42, Table 1.4-1 (footnote "a").
kW per bhp = 0.7457 kW/bhp standard conversion factorMolecular Weight of Air = 28.84 lb/lb-mole Based on 21% O2 & 79% N2.
Gas Law Constant R = 10.732 ft3∙psi/°R∙lb-mol standard conversion factorStandard Pressure = 14.696 psia standard for environmental calcuations
Standard Temperature = 68 °F standard for environmental calcuationsMolar Volume = 385.6 scf/lb-mole Molar voume at 14.696 psia and 68 °F.
VOC Molecular Weight = 44 lb/lb-mole VOC assumed to be propane for purposes of calculating mass emissions from ppmv values.Tons per Metric Tonne = 1.102 T/MT standard conversion factor
Gallons per Cubic Meter = 264.2 gal/m3 standard conversion factorHorsepower per Megawatt (mechanical) = 1,341 hp/MWm standard conversion factorICE Avg Brake-specific Fuel Consumption = 7,000 Btu/hp-hr AP-42, Table 3.3-1, footnote 'a'.
CH4 Global Warming Potential = 25 lb/lb CO2 40 CFR 98, Table A-1.N2O Global Warming Potential = 298 lb/lb CO2 40 CFR 98, Table A-1.
Natural Gas CO2 Emissions Factor = 117.0 lb/MMBtu 40 CFR 98, Table C-1 (HHV basis).Natural Gas CH4 Emissions Factor = 2.2E-03 lb/MMBtu 40 CFR 98, Table C-2 (HHV basis).Natural Gas N2O Emissions Factor = 2.2E-04 lb/MMBtu 40 CFR 98, Table C-2 (HHV basis).
Natural Gas CO2e Emissions Factor = 117.1 lb/MMBtu Sum of CO2, CH4, and N2O factors adjusted for global warming potentials.Natural Gas CO2e-toCO2 Ratio = 1.001 lb CO2e/lb CO2 = (Natural Gas CO2e Emissions Factor) / (Natural Gas CO2 Emissions Factor)
Ethane CO2 Emissions Factor = 131.4 lb/MMBtu 40 CFR 98, Table C-1 (HHV basis).Fuel Gas N2O Emissions Factor = 1.3E-03 lb/MMBtu 40 CFR 98, Table C-2 (HHV basis).Fuel Gas CH4 Emissions Factor = 6.6E-03 lb/MMBtu 40 CFR 98, Table C-2 (HHV basis).
Methane CO2 Emissions Factor = 114.8 lb/MMBtu Based on a methane HHV of 23,900 Btu/lb.Fuel Gas CO2 Emissions Factor = 130.1 lb/MMBtu 40 CFR 98, Table C-1 (HHV basis).
Natural Gas Condensable PM10/PM2.5 EF = 0.0056 lb/MMBtu AP-42, Table 1.4-2 (condensable only); Smokless flare assumed to produce no filterable PM.Natural Gas Filterable PM/PM10/PM2.5 EF 0.0019 lb/MMBtu AP-42, Table 1.4-2 (filterable only); Smokless flare assumed to produce no filterable PM.
Natural Gas VOC EF = 0.0054 lb/MMBtu AP-42, Table 1.4-2.Natural Gas CO EF = 0.0824 lb/MMBtu AP-42, Table 1.4-1.
Natural Gas Lead EF = 4.9E-07 lb/MMBtu AP-42, Table 1.4-2.Natural Gas F-Factor Conversion = 2.3E-05 lb-mol/MMBtu-ppmvd 40 CFR 60, Table 19-2; dry basis, 0% O2, 68°F.
Parameter ValueStandard Conversion Factors and Constants:
Standard Emissions Factors:
Table B-3. Constants
B-11
Source/BasisParameter Value
Specific Gravity of LDPE = 57.28 lb/ft3 Industry standard value.natural gas sulfur content = 5,000 gr/MMSCF Preliminary design specification.
Natural Gas SO2 EF = 0.0015 lb/MMBtu Based on sulfur content and AP-42, Table 1.4-2, Footnotes "a" and "d".Natural Gas H2SO4 EF = 0.0001 lb/MMBtu AP-42, Table 1.3-1; estimated based on SO3-to-SO2 emissions ratio for distillate oil.
Avg. % H2 used to fire Cracking Furnaces = wt. % Preliminary design basis.Flare Pilot Burner Size = 1 MMBtu/hr Preliminary design specification.
HP Flare Header Sweep Gas Rate = 1 MT/hr Based on use of natural gas as sweep gas in flare header.Annual PE Pellet Production Capacity = 1,600,000 MT/yr Facility design basis (metric tonnes).Annual PE Pellet Production Capacity = 1,763,696 T/yr Facility design basis (short tons).
Max PE Out by Rail = 95% wt. % A max-case estiamte of the mass of pellets that will be loaded out by rail.Max PE Out by Truck = 20% wt. % A max-case estiamte of the mass of pellets that will be loaded out by truck.
ECU Maximum Firing Rate = 620 MMBtu/hr Preliminary design basis @ 110% of nominal rate.NG to TG Header = 9.4 T/hr NG added to TG header at ECU design firing rate of 620 MMBtu/hr & 6 furnaces operating.
CO2 Emissions from Decoking = 1,461 lb/hr Preliminary design basis; excludes CO2 from NG combustion.Tail Gas HHV = 461 Btu/scf Excludes NG that is added to tail gas; based on TG composition below.
Tail Gas H2 Content = 48.3% % of HHV Based on 79 mol% H2 in tail gas and 9.4 tons per hour NG to TG header @ design firing rate.Tail Gas CH4 Content = 40.1% % of HHV Based on 21 mol% CH4 in tail gas and 9.4 tons per hour NG to TG header @ design firing rate.Tail Gas NG Content = 11.6% % of HHV Based on 9.4 T/hr NG added to TG header at design firing rate.
VOC Content of Gases to HP Ground Flare = 60% wt. % Preliminary design specification (average ethylene content)
Project-Specific Constants & Factors:
Table B-3. Constants (cont'd)
B-12
HeatInput
Fuel Source
Event Frequency
Duration per Event
Annual EventDuration
NOx Emissions
PM10 Emissions
COEmissions
Furnace Operating Modes MMBtu/hr # per yr hrs hrs/yr lb/hr lb/hr lb/hrNormal Operation (ST) 620 TG 9.30 3.10 21.7Normal Operation (LT) 620 TG 7,509 6.20 3.10 21.7Decoking 180 TG 12 36 432 2.70 1.86 52.2Feed In 277 NG 12 2 24 4.16 1.39 9.70Feed Out 277 NG 12 2 24 4.16 1.39 9.70Hot Steam Standby 173 NG 12 60 723 4.33 0.87 6.06Startup 86.5 NG 1 24 24 15.57 0.43 25.1Shutdown 86.5 NG 1 24 24 15.57 0.43 25.1
Annual Emissions =Decoking Cycle ST Rates = 4.33 1.86 52.2
Normal Ops ST Rates = 9.30 3.10 21.7Normal Ops LT Rates = 6.20 3.10 21.7
Average Annual Rates = 5.91 2.83 21.9
Table B-4. Cracking Furnace Emission Estimates
B-13
Furnace Operating ModesNormal Operation (ST)Normal Operation (LT)DecokingFeed InFeed OutHot Steam StandbyStartup Shutdown
Annual Emissions =Decoking Cycle ST Rates =
Normal Ops ST Rates =Normal Ops LT Rates =
Average Annual Rates =
NOx EF PM EFPM10/2.5
EF CO EF SO2 EF VOC EF CO2 EF CH4 EF N2O EF CO2e EF H2SO4 EF Pb EFlb/MMBtu lb/MMBtu lb/MMBtu lb/MMBtu lb/MMBtu lb/MMBtu lb/MMBtu lb/MMBtu lb/MMBtu lb/MMBtu lb/MMBtu lb/MMBtu
0.015 0.002 0.0050 0.035 0.0002 0.0019 59.5 0.0011 0.00022 59.6 6.8E-06 5.7E-080.010 0.002 0.0050 0.035 0.0002 0.0019 59.5 0.0011 0.00022 59.6 6.8E-06 5.7E-080.015 0.010 0.0103 0.290 0.0002 0.0019 67.7 0.0011 0.00022 67.8 6.8E-06 5.7E-080.015 0.002 0.0050 0.035 0.0015 0.0019 117.0 0.0011 0.00022 117.1 6.8E-06 5.7E-080.015 0.002 0.0050 0.035 0.0015 0.0019 117.0 0.0011 0.00022 117.1 6.8E-06 5.7E-080.025 0.002 0.0050 0.035 0.0015 0.0019 117.0 0.0011 0.00022 117.1 6.8E-06 5.7E-080.180 0.002 0.0050 0.290 0.0015 0.0019 117.0 0.0011 0.00022 117.1 6.8E-06 5.7E-080.180 0.002 0.0050 0.290 0.0015 0.0019 117.0 0.0011 0.00022 117.1 6.8E-06 5.7E-08
Table B-4. Cracking Furnace Emission Estimates (cont'd)
B-14
Furnace Operating ModesNormal Operation (ST)Normal Operation (LT)DecokingFeed InFeed OutHot Steam StandbyStartup Shutdown
Annual Emissions =Decoking Cycle ST Rates =
Normal Ops ST Rates =Normal Ops LT Rates =
Average Annual Rates =
NOx Emissions
PM Emissions
PM10/2.5 Emissions
CO Emissions
SO2 Emissions
VOC Emissions
CO2 Emissions
CH4 Emissions
N2O Emissions
CO2e Emissions
H2SO4 Emissions
PbEmissions
T/yr T/yr T/yr T/yr T/yr T/yr T/yr T/yr T/yr T/yr T/yr T/yr
23.28 4.34 11.64 81.47 0.40 4.42 138,613 2.65 0.51 138,832 1.6E-02 1.3E-040.58 0.40 0.40 11.28 0.01 0.07 2,631 0.04 0.01 2,634 2.7E-04 2.2E-060.05 0.01 0.02 0.12 0.00 0.01 389 0.00 0.00 389 2.3E-05 1.9E-070.05 0.01 0.02 0.12 0.00 0.01 389 0.00 0.00 389 2.3E-05 1.9E-071.56 0.12 0.31 2.19 0.09 0.12 7,316 0.07 0.01 7,322 4.3E-04 3.6E-060.19 0.00 0.01 0.30 0.00 0.00 121 0.00 0.00 122 7.1E-06 5.9E-080.19 0.00 0.01 0.30 0.00 0.00 121 0.00 0.00 122 7.1E-06 5.9E-0825.9 4.87 12.4 95.8 0.51 4.63 149,580 2.78 0.54 149,810 1.7E-02 1.4E-04
Table B-4. Cracking Furnace Emission Estimates (cont'd)
B-15
ETHYLENE CRACKING FURNACE CALCULATION NOTES/BASISGeneral:
• Cracking Furnace Emission Unit IDs = F-11101, F-12101, F-13101 ,F-14101, F-15101, F-16101, F-17101.• Calculation is for 1 furnace.• ST = short-term; this mode represents the possibility of reduced SCR performance due to short-term process fluctiations. No more than 2 furnaces expected to be in this mode at any one time.• LT = long-term; this mode represents the average NOx limit achievable by the SCR system including short-term fluctuations.• Furnace operating mode parameters are estimated based on 7 furnaces with 6 in normal operation at all times.• Each furnace is assumed to require decoking a maximum of 12 times per year.• Each furnace is assumed to undergo one startup/shutdown cycle per year.• Heat input estimates for decoking-related operating modes are the average for an acitivity over the period (e.g., "Feed In" value is average of 160MMBtu/hr at start and 395 MMBtu/hr at end of "Feed In").• Annual Emissions (T/yr) = (Mode Heat Input - MMBtu/hr) x (Hours/Year in Mode) x (EF - lb/MMBtu) / (2,000 lb/T)• Hourly Emissions (lb/hr) = (Mode Heat Input - MMBtu/hr) x (EF - lb/MMBtu)
BASIS OF EMISSION FACTORS:NOx:
• Normal Operation: ST and LT rates based on proposed LAER limits.• Decoking, Feed In, Feed Out, Hot Standby and Shutdown: based on preliminary vendor data / expected SCR performance.• Startup = SCR Offline.
CO:• Normal Operation, Feed In, Feed Out and Hot Steam Standby = Proposed BACT limit.• Decoking, Startup, Shtudown: factors equivalent to proposed lb/hr BACT limit for decoking.
SO2/H2SO4:• All Modes: SO2 EF based on a natural gas sulfur content of 5,000 gr/MMSCF and an average NG firing rate of 11.6% of heat input to furance (remainder is Tail Gas).• All Modes: Tail Gas fired in furnace does not contain any sulfur.• All Modes: H2SO4-to-SO2 ratio is assumed equal to ratio for firing distillate oil (see AP-42, Table 1.3-1).
VOC • All modes: VOC EF is equivalent to proposed LAER limit at max firing rate.PM/PM10/PM2.5:
• PM emissions do not include condensable particulate.• Normal Operation, Feed In, Feed Out, Hot Standby, Startup and Shutdown: EF based on preliminary vendor data.• Decoking: based on preliminary vendor data; hourly emissions during decoking are estimated at 1.86 lb/hr; value shown is normalized to lb/MMBtu for consistency with calculation methodology.
GHGs• All modes except decocking: emissions factors for CO2, CH4, and N2O are from 40 CFR 98, Tables C-1 and C-2.• Firing H2 does not produce any CO2 or CH4 emissions so CO2 and CH4 emissions factors are adjusted to account for Tail Gas H2 concentrationof 48.3% where applicable.• N2O emissions factor for NG used for both Tail Gas and Natural Gas firing.• CO2e emissions during decoking include emissions from fuel combustion as well as emissions from coke burn-off. See 'Constants' sheet forcoke burn-off emissions rate.
• CO2e emissions equal total of CO2, CH4, and N2O emissions adjusted for global warming potentials of 1, 25, and 298 respectively.Lead
• All Modes = Pb EF based on a AP-42 natural gas emissions factor (see Table 1.4-2) and an average NG firing rate of 12% of gas fired in furance (remainder is Tail Gas).• All Modes = Tail Gas fired in furnace does not contain any lead.
Table B-5. Ethylene Cracking Furnace Calculation Notes
B-16
Emission Unit IDs = Ethylene Cracking Furnace HAP PTEMax CH4+NG Input = 320 (MMBtu/hr) Based on 620 MMBtu/hr and 51.7% of heat in from CH4+NG.*
Annual Hours @ 100% Load = 8,760 hr/yr Conservatively assumes full-time at 100% load.Hourly Emissions = (Max Heat Input - MMBtu/hr) x (1 SCF/1,020 Btu) x (EF - lb/MMSCF)Annual Emissions = (Max Heat Input - MMBtu/hr) x (1 SCF/1,020 Btu) x (EF - lb/MMSCF) x (Annual Operating Hours) / (2,000 lb/T)
PollutantEF
(lb/MMSCF) EF SourceEF
(lb/MMBtu) §112 HAP?
PTE1 Cracking Furnace
(lb/hr)
PTE1 Cracking Furnace
(T/yr)2-Methylnaphthalene 2.40E-05 AP42; Table 1.4-3; 7/98. 2.35E-08 YES 7.54E-06 3.30E-053-Methylchloranthrene <1.8E-06 AP42; Table 1.4-3; 7/98. <1.76E-09 YES <5.65E-07 <2.48E-067,12-Dimethylbenz(a)anthracene <1.6E-05 AP42; Table 1.4-3; 7/98. <1.57E-08 YES <5.02E-06 <2.20E-05Acenaphthene <1.8E-06 AP42; Table 1.4-3; 7/98. <1.76E-09 YES <5.65E-07 <2.48E-06Anthracene <2.4E-06 AP42; Table 1.4-3; 7/98. <2.35E-09 YES <7.54E-07 <3.30E-06Benzo(a)anthracene <1.8E-06 AP42; Table 1.4-3; 7/98. <1.76E-09 YES <5.65E-07 <2.48E-06Benzene 2.10E-03 AP42; Table 1.4-3; 7/98. 2.06E-06 YES 6.59E-04 2.89E-03Benzo(a)pyrene <1.2E-06 AP42; Table 1.4-3; 7/98. <1.18E-09 YES <3.77E-07 <1.65E-06Benzo(b)fluoranthene <1.8E-06 AP42; Table 1.4-3; 7/98. <1.76E-09 YES <5.65E-07 <2.48E-06Benzo(g,h,i)perylene <1.2E-06 AP42; Table 1.4-3; 7/98. <1.18E-09 YES <3.77E-07 <1.65E-06Benzo(k)fluoranthene <1.8E-06 AP42; Table 1.4-3; 7/98. <1.76E-09 YES <5.65E-07 <2.48E-06Butane 2.10E+00 AP42; Table 1.4-3; 7/98. 2.06E-03 NO 6.59E-01 2.89E+00Chrysene <1.8E-06 AP42; Table 1.4-3; 7/98. <1.76E-09 YES <5.65E-07 <2.48E-06Dibenzo(a,h)anthracene <1.2E-06 AP42; Table 1.4-3; 7/98. <1.18E-09 YES <3.77E-07 <1.65E-06Dichlorobenzene 1.20E-03 AP42; Table 1.4-3; 7/98. 1.18E-06 YES 3.77E-04 1.65E-03Ethane 3.10E+00 AP42; Table 1.4-3; 7/98. 3.04E-03 NO 9.73E-01 4.26E+00Fluoranthene 3.00E-06 AP42; Table 1.4-3; 7/98. 2.94E-09 YES 9.42E-07 4.13E-06Fluorene 2.80E-06 AP42; Table 1.4-3; 7/98. 2.75E-09 YES 8.79E-07 3.85E-06Formaldehyde 7.50E-02 AP42; Table 1.4-3; 7/98. 7.35E-05 YES 2.35E-02 1.03E-01Hexane 1.80E+00 AP42; Table 1.4-3; 7/98. 1.76E-03 YES 5.65E-01 2.48E+00Indeno(1,2,3-cd)pyrene <1.8E-06 AP42; Table 1.4-3; 7/98. <1.76E-09 YES <5.65E-07 <2.48E-06Naphthalene 6.10E-04 AP42; Table 1.4-3; 7/98. 5.98E-07 YES 1.92E-04 8.39E-04Pentane 2.60E+00 AP42; Table 1.4-3; 7/98. 2.55E-03 NO 8.16E-01 3.58E+00Phenanthrene 1.70E-05 AP42; Table 1.4-3; 7/98. 1.67E-08 YES 5.34E-06 2.34E-05Propane 1.60E+00 AP42; Table 1.4-3; 7/98. 1.57E-03 NO 5.02E-01 2.20E+00Pyrene 5.00E-06 AP42; Table 1.4-3; 7/98. 4.90E-09 YES 1.57E-06 6.88E-06Toluene 3.40E-03 AP42; Table 1.4-3; 7/98. 3.33E-06 YES 1.07E-03 4.68E-03Arsenic 2.00E-04 AP42; Table 1.4-4; 7/98. 1.96E-07 YES 6.28E-05 2.75E-04Barium 4.40E-03 AP42; Table 1.4-4; 7/98. 4.31E-06 NO 1.38E-03 6.05E-03Beryllium <1.2E-05 AP42; Table 1.4-4; 7/98. <1.18E-08 YES <3.77E-06 <1.65E-05Cadmium 1.10E-03 AP42; Table 1.4-4; 7/98. 1.08E-06 YES 3.45E-04 1.51E-03Chromium 1.40E-03 AP42; Table 1.4-4; 7/98. 1.37E-06 YES 4.40E-04 1.93E-03Cobalt 8.40E-05 AP42; Table 1.4-4; 7/98. 8.24E-08 YES 2.64E-05 1.16E-04Copper 8.50E-04 AP42; Table 1.4-4; 7/98. 8.33E-07 NO 2.67E-04 1.17E-03Manganese 3.80E-04 AP42; Table 1.4-4; 7/98. 3.73E-07 YES 1.19E-04 5.23E-04Mercury 2.60E-04 AP42; Table 1.4-4; 7/98. 2.55E-07 YES 8.16E-05 3.58E-04Molybdenum 1.10E-03 AP42; Table 1.4-4; 7/98. 1.08E-06 NO 3.45E-04 1.51E-03Nickel 2.10E-03 AP42; Table 1.4-4; 7/98. 2.06E-06 YES 6.59E-04 2.89E-03Selenium <2.4E-05 AP42; Table 1.4-4; 7/98. <2.35E-08 YES <7.54E-06 <3.30E-05Vanadium 2.30E-03 AP42; Table 1.4-4; 7/98. 2.25E-06 NO 7.22E-04 3.16E-03Zinc 2.90E-02 AP42; Table 1.4-4; 7/98. 2.84E-05 NO 9.11E-03 3.99E-02Total § 112 HAPs from 1 Cracking Furnace = <5.93E-01 <2.60E+00Total § 112 HAPs from 7 Cracking Furnaces = <4.15E+00 <1.82E+01* No HAP emissions have been attributed to combustion of H2 in the cracking furnaces.
F-11101 - F17010
Table B-6. Cracking Furnace Hazardous Air Pollutant Emission Estimates
B-17
Emission Unit(s) ID = Combustion Turbine & Duct Burner RNSRP PTEParameter
Calcuation Inputs:Max Heat Input [HHV] = 690 MMBtu/hr
Turbine/Duct Burner PM EF = 0.0019 lb/MMBtuTurbine/Duct Burner PM10 EF = 0.0066 lb/MMBtu
Turbine/Duct Burner PM2.5 EF = 0.0066 lb/MMBtuTurbine/Duct Burner VOC EF = 0.00352 lb/MMBtuTurbine/Duct Burner NOx EF = 0.00736 lb/MMBtuTurbine/Duct Burner SO2 EF = 0.0015 lb/MMBtuTurbine/Duct Burner CO EF = 0.00448 lb/MMBtu
Turbine/Duct Burner CO2 EF = 117.0 lb/MMBtuTurbine/Duct Burner N2O EF = 2.2E-04 lb/MMBtuTurbine/Duct Burner CH4 EF = 2.2E-03 lb/MMBtu
Turbine/Duct Burner H2SO4 EF = 5.9E-05 lb/MMBtuTurbine/Duct Burner Pb EF = 4.9E-07 lb/MMBtu
Turbine/Duct Burner Fluoride EF = 0 lb/MMBtuStartup NOx EF = 113 lb/hr
Startup CO EF = 276 lb/hrStartup Hours = 7 hr/yrAnnual Hours = 8,760 hr/yr
Annual Emissions Calculations (for 1 unit):PM Emissions = 5.63 T/yr
PM10 Emissions = 19.95 T/yrPM2.5 Emissions = 19.95 T/yr
VOC Emissions = 10.64 T/yr
NOx Emissions = 22.6 T/yrSO2 Emissions = 4.44 T/yr
CO Emissions = 14.5 T/yrCO2 Emissions = 353,528 T/yrN2O Emissions = 0.67 T/yrCH4 Emissions = 6.66 T/yr
H2SO4 Emissions = 0.18 T/yrPb Emissions = 0.00 T/yr
Fluoride Emissions = 0.00 T/yrCO2e Emissions = 353,893 T/yr
Short-Term Emissions (for 1 unit):PM Emissions = 1.29 lb/hr
PM10 Emissions = 4.55 lb/hrPM2.5 Emissions = 4.55 lb/hr
VOC Emissions = 2.43 lb/hrNOx Emissions = 5.17 lb/hrSO2 Emissions = 1.01 lb/hrCO Emissions = 276 lb/hr
CO2 Emissions = 80,714 lb/hrN2O Emissions = 0.15 lb/hrCH4 Emissions = 1.52 lb/hr
H2SO4 Emissions = 0.04 lb/hrPb Emissions = 0.00 lb/hr
Fluoride Emissions = 0.00 lb/hrCO2e Emissions = 80,798 lb/hr
Summary of Results
PM PM10 PM2.5 VOC NOx SO2 CO GHGm CO2e H2SO4One Unit = 5.6 19.9 19.9 10.64 22.6 4.44 14.5 353,536 353,893 0.18
Three Units = 16.9 59.8 59.8 31.92 67.9 13.33 43.5 1,060,607 1,061,680 0.54
Potential Emissions (tons per year)
= (Max Heat Input [HHV]) x (Turbine/Duct Burner VOC EF)= Annual Average Value for Modeling Purposes.= (Max Heat Input [HHV]) x (Turbine/Duct Burner SO2 EF)= Startup Max Rate for Modeling Purposes= (Max Heat Input [HHV]) x (Turbine/Duct Burner CO2 EF)= (Max Heat Input [HHV]) x (Turbine/Duct Burner N2O EF)= (Max Heat Input [HHV]) x (Turbine/Duct Burner CH4 EF)= (Max Heat Input [HHV]) x (Turbine/Duct Burner H2SO4 EF)= (Max Heat Input [HHV]) x (Turbine/Duct Burner Pb EF)= (Max Heat Input [HHV]) x (Turbine/Duct Burner Fluoride EF)= Sum of CO2, N2O and CH4 emissions adjusted for NO2 and CH4 GWPs of 298 and 25.
= (Max Heat Input [HHV]) x (Turbine/Duct Burner PM2.5 EF)
= (Max Heat Input [HHV]) x (Turbine/Duct Burner SO2 EF) x (Annual Hours) / (2000 lb/T)= [(Max Heat Input [HHV]) x (Turbine/Duct Burner CO EF) x (Annual Hours - Startup Hours ) + (Startup CO EF) x (Startup Hours )] / (2000 lb/T)= (Max Heat Input [HHV]) x (Turbine/Duct Burner CO2 EF) x (Annual Hours) / (2000 lb/T)= (Max Heat Input [HHV]) x (Turbine/Duct Burner N2O EF) x (Annual Hours) / (2000 lb/T)= (Max Heat Input [HHV]) x (Turbine/Duct Burner CH4 EF) x (Annual Hours) / (2000 lb/T)= (Max Heat Input [HHV]) x (Turbine/Duct Burner H2SO4 EF) x (Annual Hours) / (2000 lb/T)= (Max Heat Input [HHV]) x (Turbine/Duct Burner Pb EF) x (Annual Hours) / (2000 lb/T)= (Max Heat Input [HHV]) x (Turbine/Duct Burner Fluoride EF) x (Annual Hours) / (2000 lb/T)= Sum of CO2, N2O and CH4 emissions adjusted for NO2 and CH4 GWPs of 298 and 25.
= (Max Heat Input [HHV]) x (Turbine/Duct Burner PM EF)= (Max Heat Input [HHV]) x (Turbine/Duct Burner PM10 EF)
= [(Max Heat Input [HHV]) x (Turbine/Duct Burner NOx EF) x (Annual Hours - Startup Hours ) + (Startup NOx EF) x (Startup Hours )] / (2000 lb/T)
40 CFR 98, Table C-1; EF for natural gas.40 CFR 98, Table C-2; EF for natural gas.40 CFR 98, Table C-2; EF for natural gas.AP-42, Table 1.3-1; estimated based on SO3-to-SO2 emissions ratio for distillate oil.AP-42, Table 1.4-2.Not emitted.
= (Max Heat Input [HHV]) x (Turbine/Duct Burner PM EF) x (Annual Hours) / (2000 lb/T)= (Max Heat Input [HHV]) x (Turbine/Duct Burner PM10 EF) x (Annual Hours) / (2000 lb/T)= (Max Heat Input [HHV]) x (Turbine/Duct Burner PM2.5 EF) x (Annual Hours) / (2000 lb/T)= (Max Heat Input [HHV]) x (Turbine/Duct Burner VOC EF) x (Annual Hours) / (2000 lb/T)
Worst-case estimate.
Design estimate.Design estimate.
Equivalent to proposed LAER limit at max load (based on 2 ppmvd @ 15% O2).
CT1/2/3Value Source / Basis
Total maximum heat input to each turbine/duct burner unit.AP-42, 3.1-2a (filterable only).Proposed BACT limit.Proposed LAER limit.Equivalent to proposed LAER limit at max load (based on 1 ppmvd @ 15% O2 as C3H8).Equivalent to proposed LAER limit at max load (based on 2 ppmvd @ 15% O2 as NO2).Based on max NG sulfur content; see "Constants" sheet for details.
Table B-7. Combustion Turbine & Duct Burner Emission Estimates
B-18
Emission Unit(s) ID = Combustion Turbine & Duct Burner HAP PTEMax CH4+NG Input : 690 (MMBtu/hr) Total heat input to turbines plus duct burners.*
Annual Hours @ 100% Load : 8,760 hr/yr Conservatively assumes full-time at 100% load.Hourly Emissions : (Max Heat Input - MMBtu/hr) x (EF - lb/MMBtu)Annual Emissions : (Max Heat Input - MMBtu/hr) x (EF - lb/MMBtu) x (Annual Operating Hours) / (2,000 lb/T)
EF SourceEF
(lb/MMBtu) §112 HAP?
PTE1 CT/DB(lb/hr)
PTE1 CT/DB
(T/yr)1,3-Butadiene : AP42; Table 3.1-3; 4/00. <4.30E-07 YES <2.97E-04 <1.30E-03Acetaldehyde : AP42; Table 3.1-3; 4/00. 4.00E-05 YES 2.76E-02 1.21E-01
Acrolein : AP42; Table 3.1-3; 4/00. 6.40E-06 YES 4.42E-03 1.93E-02Benzene : AP42; Table 3.1-3; 4/00. 1.20E-05 YES 8.28E-03 3.63E-02
Ethylbenzene : AP42; Table 3.1-3; 4/00. 3.20E-05 YES 2.21E-02 9.67E-02Formaldehyde : AP42; Table 3.1-3; 4/00. 7.10E-04 YES 4.90E-01 2.15E+00
Naphthalene : AP42; Table 3.1-3; 4/00. 1.30E-06 YES 8.97E-04 3.93E-03PAH : AP42; Table 3.1-3; 4/00. 2.20E-06 YES 1.52E-03 6.65E-03
Propylene Oxide : AP42; Table 3.1-3; 4/00. <2.90E-05 YES <2.00E-02 <8.76E-02Toluene : AP42; Table 3.1-3; 4/00. 1.30E-04 YES 8.97E-02 3.93E-01Xylenes : AP42; Table 3.1-3; 4/00. 6.40E-05 YES 4.42E-02 1.93E-01
Total § 112 HAPs from 1 Cogen Unit = <7.09E-01 <3.10E+00Total § 112 HAPs from 3 Cogen Units = <2.13E+00 <9.31E+00* HAP emissions from duct burners assumed to have the same profile as HAP emissions from the turbines.
CT1/2/3
Pollutant
Table B-8. Combustion Turbine & Duct Burner HAP Emission Estimates
B-19
Emission Unit(s) ID = Emergency Generator IC EnginesParameter Value Units
Calculation InputsGen-Set Output = 3.0 MWe
Gen-Set Efficiency = 80% kWe/kWmRated Horsepower, each engine = 5,028 bhp
No. of Engines = 4Rated Horespower, Total = 20,110 bhp
PM EF = 4.41E-05 lb/bhp-hrPM10 EF = 4.23E-05 lb/bhp-hr
PM2.5 EF 3.97E-05 lb/bhp-hr VOC EF = 7.80E-03 lb/bhp-hrNOx EF = 2.34E-03 lb/bhp-hr SO2 EF = 1.09E-05 lb/bhp-hr
CO EF = 4.41E-05 lb/bhp-hrCO2 EF = 1.14E+00 lb/bhp-hrCH4 EF = 4.63E-05 lb/bhp-hrN2O EF = 9.26E-06 lb/bhp-hr
CO2e EF = 1.15E+00 lb/bhp-hrH2SO4 EF = 4.37E-07 lb/bhp-hr
Annual Operating Hours = 100 hrs/yr/engineHourly Emissions Calculations (each engine)
PM Hourly Max = 0.22 lb/hrPM10 Hourly Max = 0.21 lb/hr
PM2.5 Hourly Max = 0.20 lb/hrVOC Hourly Max = 39.24 lb/hrNOx Hourly Max = 11.75 lb/hrSO2 Hourly Max = 0.05 lb/hrCO Hourly Max = 0.22 lb/hr
CO2 Hourly Max = 5,738 lb/hrCH4 Hourly Max = 0.233 lb/hrN2O Hourly Max = 0.047 lb/hr
CO2e Hourly Max = 5,758 lb/hrH2SO4 Hourly Max = 0.002 lb/hr
Annual Emissions Calculations (all engines)PM PTE = 0.04 tpy
PM10 PTE = 0.04 tpyPM2.5 PTE = 0.04 tpy
VOC PTE = 7.85 tpyNOx PTE = 2.35 tpySO2 PTE = 0.01 tpyCO PTE = 0.04 tpy
CO2 PTE = 1,148 tpyCH4 PTE = 0.047 tpyN2O PTE = 0.009 tpy
CO2e PTE = 1,152 tpyH2SO4 PTE = 0.0004 tpy
EGEN1/2/3/4
PM10 = 96% of PM from AP-42, Table B.2-2, Category 1.
Source / Basis
= (Gen-Set Output MWe) x (1,341 bhp/MWm) / (Gen-Set Efficiency)Design basis of project= (Rated Horsepower, each engine) x (No. of Engines)= 2X Vendor's "Nominal Emissions" value.
= (Rated Horsepower, each engine) x (PM10 EF)
PM2.5 = 90% of PM from AP-42, Table B.2-2, Category 1.= (Proposed NOx+VOC LAER limit) - (NOx EF)= 2X Vendor's "Nominal Emissions" value.Based on: fuel sulfur = 15 ppmw; 7,000 Btu/hp-hr; oil HHV = 19,300 Btu/lb. = 2X Vendor's "Nominal Emissions" value.40 CFR 98, Table C-1 (Fuel Oil No. 2) @ 7,000 Btu/bhp-hr.40 CFR 98, Table C-2 @ 7,000 Btu/bhp-hr.40 CFR 98, Table C-2 @ 7,000 Btu/bhp-hr.Sum of CO2, N2O, & CH4 adjusted for GWP.
Proposed permit limit.
= (Rated Horsepower, each engine) x (PM EF)
AP-42, Table 1.3-1; estimated at based on SO3-to-SO2 emissions ratio for distillate oil.
= (PM10 Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (PM2.5 Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)
= (Rated Horsepower, each engine) x (PM2.5 EF)= (Rated Horsepower, each engine) x ( VOC EF)= (Rated Horsepower, each engine) x (NOx EF)= (Rated Horsepower, each engine) x ( SO2 EF)= (Rated Horsepower, each engine) x (CO EF)= (Rated Horsepower, each engine) x (CO2 EF)
= (Rated Horsepower, each engine) x (H2SO4 EF)
= (H2SO4 Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)
= (N2O Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (CO2e Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)
Design basis of projectStandard gen-set efficiency.
= (VOC Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (NOx Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (SO2 Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (CO Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (CO2 Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (CH4 Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)
= (Rated Horsepower, each engine) x (CH4 EF)= (Rated Horsepower, each engine) x (N2O EF)= (Rated Horsepower, each engine) x (CO2e EF)
= (PM Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)
Table B-9. Emergency Generator Emission Estimates
B-20
PollutantEF
(lb/MMBtu) Source §112 HAP?Emissions Rate (lb/hr)
Emissions Rate (T/yr)
Acetaldehyde 2.52E-05 AP42; Table 3.4-3; 10/96. YES 3.55E-03 1.77E-04Acrolein 7.88E-06 AP42; Table 3.4-3; 10/96. YES 1.11E-03 5.55E-05Benzene 7.76E-04 AP42; Table 3.4-3; 10/96. YES 1.09E-01 5.46E-03Formaldehyde 7.89E-05 AP42; Table 3.4-3; 10/96. YES 1.11E-02 5.55E-04Propylene 2.79E-03 AP42; Table 3.4-3; 10/96. NO 3.93E-01 1.96E-02Toluene 2.81E-04 AP42; Table 3.4-3; 10/96. YES 3.96E-02 1.98E-03Xylenes 1.93E-04 AP42; Table 3.4-3; 10/96. YES 2.72E-02 1.36E-03Naphthalene 1.30E-04 AP42; Table 3.4-4; 10/96. YES 1.83E-02 9.15E-04Acenaphthylene 9.23E-06 AP42; Table 3.4-4; 10/96. YES 1.30E-03 6.50E-05Acenaphthene 4.68E-06 AP42; Table 3.4-4; 10/96. YES 6.59E-04 3.29E-05Fluorene 1.28E-05 AP42; Table 3.4-4; 10/96. YES 1.80E-03 9.01E-05Phenanthrene 4.08E-05 AP42; Table 3.4-4; 10/96. YES 5.74E-03 2.87E-04Anthracene 1.23E-06 AP42; Table 3.4-4; 10/96. YES 1.73E-04 8.66E-06Fluoranthene 4.03E-06 AP42; Table 3.4-4; 10/96. YES 5.67E-04 2.84E-05Pyrene 3.71E-06 AP42; Table 3.4-4; 10/96. YES 5.22E-04 2.61E-05Benzo(a)anthracene 6.22E-07 AP42; Table 3.4-4; 10/96. YES 8.76E-05 4.38E-06Chrysene 1.53E-06 AP42; Table 3.4-4; 10/96. YES 2.15E-04 1.08E-05Benzo(b)fluoranthene 1.11E-06 AP42; Table 3.4-4; 10/96. YES 1.56E-04 7.81E-06Benzo(k)fluoranthene <2.18E-07 AP42; Table 3.4-4; 10/96. YES <3.07E-05 <1.53E-06Benzo(a)pyrene <2.57E-07 AP42; Table 3.4-4; 10/96. YES <3.62E-05 <1.81E-06Indeno(1,2,3-cd)pyrene <4.14E-07 AP42; Table 3.4-4; 10/96. YES <5.83E-05 <2.91E-06Dibenzo(a,h)anthracene <3.46E-07 AP42; Table 3.4-4; 10/96. YES <4.87E-05 <2.44E-06Benzo(g,h,l)perylene <5.56E-07 AP42; Table 3.4-4; 10/96. YES <7.83E-05 <3.91E-06Total PAH <1.68E-04 AP42; Table 3.4-4; 10/96. NO <2.36E-02 <1.18E-03
<2.22E-01 <1.11E-02Calcualtion Basis: Hourly Emissions = EF x Max Heat In x No. of Engines
Annual Emissions = Hourly x Hrs/yr / 2000.
Emergency Generator Diesel ICE HAP PTE - EGEN1/2/3/4(total for all engines)
Total § 112 HAP =
Table B-10. Emergency Generator HAP Emission Estimates
B-21
Emission Unit(s) ID = Fire Pump IC EnginesParameter Value Units
Calculation InputsRated Horsepower, each engine = 700 bhp
No. of Engines = 3Rated Horespower, Total = 2,100 bhp
PM EF = 3.31E-04 lb/bhp-hrPM10 EF = 3.17E-04 lb/bhp-hr
PM2.5 EF 2.98E-04 lb/bhp-hr VOC EF = 2.51E-03 lb/bhp-hrNOx EF = 4.10E-03 lb/bhp-hr SO2 EF = 1.09E-05 lb/bhp-hr
CO EF = 5.73E-03 lb/bhp-hrCO2 EF = 1.14E+00 lb/bhp-hrCH4 EF = 4.63E-05 lb/bhp-hrN2O EF = 9.26E-06 lb/bhp-hr
CO2e EF = 1.15E+00 lb/bhp-hrH2SO4 EF = 4.37E-07 lb/bhp-hr
Annual Operating Hours = 100 hrs/yr/engineHourly Emissions Calculations (each engine)
PM Hourly Max = 0.231 lb/hrPM10 Hourly Max = 0.222 lb/hr
PM2.5 Hourly Max = 0.208 lb/hrVOC Hourly Max = 1.760 lb/hrNOx Hourly Max = 2.870 lb/hrSO2 Hourly Max = 0.008 lb/hrCO Hourly Max = 4.012 lb/hr
CO2 Hourly Max = 799.0 lb/hrCH4 Hourly Max = 0.032 lb/hrN2O Hourly Max = 0.006 lb/hr
CO2e Hourly Max = 801.7 lb/hrH2SO4 Hourly Max = 0.001 lb/hr
Annual Emissions Calculations (all engines)PM PTE = 0.035 tpy
PM10 PTE = 0.033 tpyPM2.5 PTE = 0.031 tpy
VOC PTE = 0.264 tpyNOx PTE = 0.430 tpySO2 PTE = 0.001 tpyCO PTE = 0.602 tpy
CO2 PTE = 119.8 tpyCH4 PTE = 0.005 tpyN2O PTE = 0.001 tpy
CO2e PTE = 120.3 tpyH2SO4 PTE = 0.0001 tpy
Summary of Results
PM PM10 PM2.5 VOC NOx SO2 CO GHGm CO2e H2SO4Fire Pump ICE Emissions (3 units) = 0.03 0.03 0.03 0.264 0.430 0.001 0.602 120 120 0.000
= (CO2 Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (CH4 Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (N2O Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (CO2e Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)
Potential Emissions (tons per year)
= (H2SO4 Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)
= (CO Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)
= (Rated Horsepower, each engine) x (CO EF)= (Rated Horsepower, each engine) x (CO2 EF)= (Rated Horsepower, each engine) x (CH4 EF)= (Rated Horsepower, each engine) x (N2O EF)= (Rated Horsepower, each engine) x (CO2e EF)
= (PM Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (PM10 Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (PM2.5 Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (VOC Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (NOx Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (SO2 Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)
= (Rated Horespower, Total) x (H2SO4 EF)
= (Rated Horsepower, each engine) x ( SO2 EF)
NSPS Subpart IIII; Table 4; 600 - 750 HP; 2009+.40 CFR 98, Table C-1 (Fuel Oil No. 2) @ 7,000 Btu/bhp-hr.40 CFR 98, Table C-2 @ 7,000 Btu/bhp-hr.40 CFR 98, Table C-2 @ 7,000 Btu/bhp-hr.Sum of CO2, N2O, & CH4 adjusted for GWP.
Proposed permit limit.
= (Rated Horsepower, each engine) x (PM EF)= (Rated Horsepower, each engine) x (PM10 EF)= (Rated Horsepower, each engine) x (PM2.5 EF)= (Rated Horsepower, each engine) x ( VOC EF)= (Rated Horsepower, each engine) x (NOx EF)
AP-42, Table 1.3-1; estimated at based on SO3-to-SO2 emissions ratio for distillate oil.
FWP1/2/3
Based on: fuel sulfur = 15 ppmw; 7,000 Btu/hp-hr; oil HHV = 19,300 Btu/lb.
Source / Basis
C18 ACERT™ Fire PumpDesign basis of project= (Rated Horsepower, each engine) x (No. of Engines)NSPS Subpart IIII limit.PM10 = 96% of PM from AP-42, Table B.2-2, Category 1.PM2.5 = 90% of PM from AP-42, Table B.2-2, Category 1.AP-42; 10/96; Table 3.3-1NSPS Subpart IIII; Table 4; 600 - 750 HP; 2009+; assumes NOx = NMHC + NOx - VOC EF.
Table B-11. Fire Pump Emission Estimates
B-22
PollutantEF
(lb/MMBtu) Source §112 HAP?Emissions Rate (lb/hr)
Emissions Rate (T/yr)
Acetaldehyde 2.52E-05 AP42; Table 3.4-3; 10/96. YES 3.70E-04 1.85E-05Acrolein 7.88E-06 AP42; Table 3.4-3; 10/96. YES 1.16E-04 5.79E-06Benzene 7.76E-04 AP42; Table 3.4-3; 10/96. YES 1.14E-02 5.70E-04Formaldehyde 7.89E-05 AP42; Table 3.4-3; 10/96. YES 1.16E-03 5.80E-05Propylene 2.79E-03 AP42; Table 3.4-3; 10/96. NO 4.10E-02 2.05E-03Toluene 2.81E-04 AP42; Table 3.4-3; 10/96. YES 4.13E-03 2.07E-04Xylenes 1.93E-04 AP42; Table 3.4-3; 10/96. YES 2.84E-03 1.42E-04Naphthalene 1.30E-04 AP42; Table 3.4-4; 10/96. YES 1.91E-03 9.56E-05Acenaphthylene 9.23E-06 AP42; Table 3.4-4; 10/96. YES 1.36E-04 6.78E-06Acenaphthene 4.68E-06 AP42; Table 3.4-4; 10/96. YES 6.88E-05 3.44E-06Fluorene 1.28E-05 AP42; Table 3.4-4; 10/96. YES 1.88E-04 9.41E-06Phenanthrene 4.08E-05 AP42; Table 3.4-4; 10/96. YES 6.00E-04 3.00E-05Anthracene 1.23E-06 AP42; Table 3.4-4; 10/96. YES 1.81E-05 9.04E-07Fluoranthene 4.03E-06 AP42; Table 3.4-4; 10/96. YES 5.92E-05 2.96E-06Pyrene 3.71E-06 AP42; Table 3.4-4; 10/96. YES 5.45E-05 2.73E-06Benzo(a)anthracene 6.22E-07 AP42; Table 3.4-4; 10/96. YES 9.14E-06 4.57E-07Chrysene 1.53E-06 AP42; Table 3.4-4; 10/96. YES 2.25E-05 1.12E-06Benzo(b)fluoranthene 1.11E-06 AP42; Table 3.4-4; 10/96. YES 1.63E-05 8.16E-07Benzo(k)fluoranthene <2.18E-07 AP42; Table 3.4-4; 10/96. YES 3.20E-06 <1.60E-07Benzo(g,h,l)perylene <5.56E-07 AP42; Table 3.4-4; 10/96. YES 8.17E-06 <4.09E-07Total PAH <1.68E-04 AP42; Table 3.4-4; 10/96. NO 2.47E-03 <1.23E-04
<2.31E-02 <1.16E-03Calculation Basis: Hourly Emissions = EF x Max Heat In x No. of Engines
Annual Emissions = Hourly x Hrs/yr / 2000.
Fire Pump ICE HAP PTE - FWP1/2/3(total for all engines)
Total § 112 HAP =
Table B-12. Fire Pump HAP Emission Estimates
B-23
SOCMI Average Emissions Factor
VOC CH4 HAPLAER Control
EfficiencyComponent
Count
(lb/hr/src) (wt. %) (wt. %) (wt. %) % # VOC CH4 HAPGas/Vapor 0.0132 100.0 0.0 100.0 97 67 0.12 0.00 0.12Gas/Vapor 0.0132 100.0 0.0 50.0 97 34 0.06 0.00 0.03Gas/Vapor 0.0132 100.0 0.0 0.0 97 846 1.47 0.00 0.00Gas/Vapor 0.0132 98.2 1.8 0.0 97 179 0.30 0.01 0.00Gas/Vapor 0.0132 95.0 5.0 10.0 97 890 1.47 0.08 0.15Gas/Vapor 0.0132 92.4 7.6 0.0 97 315 0.50 0.04 0.00Gas/Vapor 0.0132 33.2 66.8 0.0 97 1111 0.64 1.29 0.00Light Liquid 0.0089 100.0 0.0 100.0 97 946 1.11 0.00 1.11Light Liquid 0.0089 100.0 0.0 50.0 97 226 0.26 0.00 0.13Light Liquid 0.0089 100.0 0.0 0.0 97 901 1.05 0.00 0.00Light Liquid 0.0089 98.7 1.3 0.0 97 94 0.11 0.00 0.00Light Liquid 0.0089 92.4 7.6 0.0 97 92 0.10 0.01 0.00Heavy liquid 0.0005 100.0 0.0 0.0 0 234 0.51 0.00 0.00Gas/Vapor 0.0039 100.0 0.0 100.0 97 180 0.09 0.00 0.09Gas/Vapor 0.0039 100.0 0.0 50.0 97 96 0.05 0.00 0.02Gas/Vapor 0.0039 100.0 0.0 0.0 97 2265 1.16 0.00 0.00Gas/Vapor 0.0039 98.2 1.8 0.0 97 480 0.24 0.00 0.00Gas/Vapor 0.0039 95.0 5.0 10.0 97 3288 1.60 0.08 0.17Gas/Vapor 0.0039 92.4 7.6 0.0 97 887 0.42 0.03 0.00Gas/Vapor 0.0039 33.2 66.8 0.0 97 3431 0.58 1.17 0.00Light Liquid 0.0005 100.0 0.0 100.0 97 2720 0.18 0.00 0.18Light Liquid 0.0005 100.0 0.0 50.0 97 715 0.05 0.00 0.02Light Liquid 0.0005 100.0 0.0 0.0 97 2596 0.17 0.00 0.00Light Liquid 0.0005 98.7 1.3 0.0 97 211 0.01 0.00 0.00Light Liquid 0.0005 92.4 7.6 0.0 97 252 0.02 0.00 0.00Heavy liquid 0.00007 100.0 0.0 0.0 30 710 0.15 0.00 0.00Gas/Vapor 0.2293 100.0 0.0 50.0 97 35 1.05 0.00 0.53Gas/Vapor 0.2293 33.2 66.8 0.0 97 35 0.35 0.70 0.00Light liquid 0.0439 100.0 0.0 50.0 93 26 0.35 0.00 0.17Light liquid 0.0439 92.4 7.6 0.0 93 4 0.05 0.00 0.00
Heavy liquid 0.0190 100.0 0.0 0.0 0 4 0.33 0.00 0.00Gas/Vapor 0.5027 100.0 0.0 50.0 95 14 1.54 0.00 0.77Gas/Vapor 0.5027 95.0 5.0 10.0 95 10 1.05 0.06 0.11Gas/Vapor 0.5027 33.2 66.8 0.0 95 8 0.29 0.59 0.00
Total Cracker Fugitive Emissions = 17.4 4.1 3.6Calculation Basis:
• Average Emission Factors from: Protocol for Equipment Leak Emission Estimates (EPA-453/R-95-017), Table 2-1.• Component counts derived from preliminary design estimates for ethylene cracker unit equipment.• Emissions = (Component Count) x (EF - lb/hr/scr) x (1 - Control Efficiency) x (wt. % compound in stream)• LAER control efficiency based on TCEQ 28 LAER LDAR program control effectiveness.
http://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/control_eff.pdf• Pump and compressor counts doubled to account for 2 seals per unit.• 10 relief valves per furnace assumed.
EMISSIONS (tpy)
CRACKER FUGITIVE EMISSION COUNTS & VOC/CH4/HAP EMISSIONS
Pumps
Compressor Seals
Equipment Service
Valves
Connectors/Flanges
Relief Valves
Table B-13. Fugitive Emissions Estimate - Cracking Furnaces
B-24
Equipment ServiceSOCMI Average
Emissions Factorlb/hr/src
LAER Control Efficiency %
Component CountVOC Emissions
(tpy)
Gas/Vapor 0.0132 97 1,414 2.45Light Liquid 0.0089 97 332 0.39
Relief Valves Gas/Vapor 0.2293 97 50 1.51Pumps Light Liquid 0.0439 93 32 0.43
Compressor Seals Gas/Vapor 0.5027 95 4 0.44Gas/Vapor 0.0089 97 2,348 2.75Light Liquid 0.0005 97 803 0.05
Subtotal of PE 1 & 2 VOC Emissions (total for 2 units) = 16.0
Gas/Vapor 0.0132 97 1,116 1.94Light Liquid 0.0089 97 957 1.12
Relief Valves Gas/Vapor 0.2293 97 50 1.51Pumps Light Liquid 0.0439 93 32 0.43
Compressor Seals Gas/Vapor 0.5027 95 4 0.44Agitators Light Liquid 0.0439 93 3 0.04
Gas/Vapor 0.0039 97 5,197 2.66Light Liquid 0.0005 97 2,090 0.14Heavy Liquid 0.00007 30 0 0.00
Subtotal of PE 3 VOC Emissions = 8.27Total VOC Emissions from PE Units 1 - 3 = 24.3Total HAP Emissions from PE Units 1 - 3 = 1.2
• Average Emission Factors from: Protocol for Equipment Leak Emission Estimates (EPA-453/R-95-017), Table 2-1.• Component counts derived from preliminary design estimates for PE ISBL equipment.• PE 1 and 2 relief valve and pump counts assumed equal to PE3.• Emissions = (Component Count) x (EF - lb/hr/scr) x (1 - Control Efficiency)• LAER control efficiency based on TCEQ 28 LAER LDAR program control effectiveness.
http://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/control_eff.pdf• Agitator seal control efficiency assumed equal to pump seal LAER efficiency.
Valves
Connectors/Flanges
POLYETHYLENE UNITS 1 & 2(emissions and counts shown are for each unit)
POLYETHYLENE UNIT 3
Valves
Connectors/Flanges
Table B-14. Fugitive Emissions Estimate - Polyethylene Units
B-25
Equipment Service SOCMI Average Emissions Factor (lb/hr/src) Pollutant
LAER ControlEfficiency
(%)
Component Count
EMISSIONS(tpy)
Fuel/NG 0.0132 CH4 97 284 0.49Gas/Vapor 0.0132 VOC 97 355 0.62Light liquid 0.0089 VOC 97 618 0.72
Heavy liquid 0.0005 VOC 0 68 0.15Fuel/NG 0.2293 CH4 97 4 0.12
Gas/Vapor 0.2293 VOC 97 37 1.11Light liquid 0.0089 VOC 97 37 0.04
Heavy liquid 0.0089 VOC 97 5 0.01Fuel/NG 0.0037 CH4 97 185 0.09
Gas/Vapor 0.0037 VOC 97 147 0.07Light liquid 0.0037 VOC 97 90 0.04
Heavy liquid 0.0037 VOC 97 5 0.00Light liquid 0.0439 VOC 93 56 0.75
Heavy liquid 0.0190 VOC 0 6 0.50Compressor Seals Gas/Vapor 0.5027 VOC 95 6 0.66
Fuel/NG 0.0039 CH4 97 1419 0.73Gas/Vapor 0.0039 VOC 97 1617 0.83Light liquid 0.0005 VOC 97 2235 0.15
Heavy liquid 0.00007 VOC 30 234 0.05VOC Emissions = 5.7
CH4 Emissions 1.4HAP Emissions 0.6
Calculation Basis:• Average Emission Factors from: Protocol for Equipment Leak Emission Estimates (EPA-453/R-95-017), Table 2-1.• Component counts derived from preliminary design estimates for OSBL equipment.• Emissions = (Component Count) x (EF - lb/hr/scr) x (1 - Control Efficiency)• LAER control efficiency based on TCEQ 28 LAER LDAR program control effectiveness:
http://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/control_eff.pdf• HAP content of streams assumed equal to 10% as conservative estimate.
Connectors/Flanges
OSBL FUGITIVE EMISSION COUNTS & VOC/CH4 EMISSIONS
Valves
Relief Valves
Open-ended Lines
Pumps
Table B-15. Fugitive Emissions Estimate - OSBL
B-26
Table B-‐16. Polyethylene Units 1 & 2 Process Vent Particulate Matter Emissions Estimates
Line 1/2 Vent Descriptions Emission Point IDs Vent TypePM/PM10/PM2.5
Emissions (T/yr/line)24-‐hr Avg PM/PM10 Rate (lb/hr/line) Basis / Discussion
Continuous 0.9439 0.2155Annual rate based on preliminary vendor data scaled to 8,760 hr/yr; 24-‐hour rates estimated based on 8,760 hr/yr of operation.
Intermittent 0.1397 0.0350Annual rate based on preliminary vendor data; 24-‐hour rates estimated based on 333 days per year of operation.
1.0836 0.2505 Total of above rates.2.1671 0.5009 2X above totals.
NOTES:• Assumed operating days for intermittant vents = 333 days/yr• 24-‐hr Rate for Intermittant Vents = (Annual Emissions -‐ T/yr) x (2,000 lb/T) / (333 days/yr * 24 hr/day)• 24-‐hr Rate for Continuous Vents = (Annual Emissions -‐ T/yr) x (2,000 lb/T) / (8,760 hr/yr)• Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law.
PEU 1 & 2 Process Vent Particulate Emissions Estimates
Totals per Line =Totals Line 1 + Line 2 =
B-27
Line 3 Vent Descriptions EU IDsPM/PM10/PM2.5 Emissions (T/yr)
24-hr Avg PM/PM10 Rate
(lb/hr) Basis / Discussion
S2003A, S2003B 0.037 0.008Annual rate based on preliminary vendor data @ 8,760 hr/yr; 24-hour rates estimated based on 8,760 hr/yr of operation.
S4005A/B, E4001 0.000 0.000 Vented to LP Flare. Emissions accounted for at flare.
C6005 0.062 0.014Annual rate based on preliminary vendor data @ 8,760 hr/yr; 24-hour rates estimated based on 8,760 hr/yr of operation.
Q6002A, Q6002B, Q6002C, Q6002D 0.005 0.001
Annual rate based on preliminary vendor data @ 8,760 hr/yr; 24-hour rates estimated based on 8,760 hr/yr of operation.
C60040.126 0.029
Annual rate based on preliminary vendor data @ 8,760 hr/yr; 24-hour rates estimated based on 8,760 hr/yr of operation.
C6003 0.664 0.152Annual rate based on preliminary vendor data scaled to 8,760 hr/yr; 24-hour rates estimated based on 8,760 hr/yr of operation.
V6007 0.039 0.009Annual rate based on preliminary vendor data @ 8,760 hr/yr; 24-hour rates estimated based on 8,760 hr/yr of operation.
0.932 0.213 Total of above rates.NOTES:
• All vents are assumed to be continuous although many are intermittent.• 24-hr Rate = (Annual Emissions - T/yr) x (2,000 lb/T) / (8,760 hr/yr)• Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law.
PE Unit 3 Process Vent Particulate Emissions Estimates
Totals =
Table B-17. Polyethylene Unit 3 Process Vent Particulate Matter Emissions Estimates
B-28
Parameter Units Blending Silo
Railcar Handling &
Storage
Truck Handling &
StorageDeDuster
VentsRailcar Loading
Truck Loading Source / Basis
Calculation Inputs: (rates for all three lines)
Annual Rate MT/yr 3,000,000 1,520,000 320,000 1,600,000 1,520,000 320,000 Based on 1.6 MM MT/yr production w/ 95% max via rail and 20% max by truck.
Max PE Pellet Rate MT/hr 410 240 160 400 200 130 Prelimiary design: 24-hr average max rates.
Normal PE Pellet Rate MT/hr 375 190 60 250 190 60 Prelimiary design: annual average rates.
Pellet-to-Air Ratio lb/lb 10 10 10 22 766 766 10:1 ratio for conveying; 22:1 for DeDuster; Loading air displacement based on 1 scf air per ft3 PE loaded.
PM Exit Grain Loading gr/dscf 0.010 0.010 0.010 0.010 0.010 0.010 LAER Limit.
PM10/2.5 Exit Grain Loading gr/dscf 0.0017 0.0017 0.0017 0.0001 0.010 0.010 Equivalent to proposed hourly emission limit at max rates.Annual Operating Hours hr/yr 8,000 8,000 5,333 8,000 8,000 5,333 Annual operating hours at normal rates. Hours may be higher if rates are lower.
Calculated Values:
Max Exhaust Rate scfh 1,208,429 707,373 471,582 535,889 7,697 5,003 = (Max PE Pellet Rate) x (2,204.6 lb/MT) / (Pellet-to-Air Ratio) / (28.84 lb/lb-mol) x (385.57 scf/lb-mol)
Normal Exhaust Rate scfh 1,105,271 560,004 176,843 334,930 7,312 2,309 = (Normal PE Pellet Rate) x (2,204.6 lb/MT) / (Pellet-to-Air Ratio) / (28.84 lb/lb-mol) x (385.57 scf/lb-mol)
24-hr PM10 Rate lb/hr 0.293 0.17 0.11 0.01 0.01 0.01 = (PM10/2.5 Exit Grain Loading) x (Max Exhaust Rate) / (7,000 gr/lb)
Annual Average PM10 Rate lb/hr 0.25 0.12 0.03 0.00 0.01 0.00 = (PM10/2.5 Exit Grain Loading) x (Normal Exhaust Rate) / (7,000 gr/lb) x (Annual Operating Hours ) / (8760 hr/yr)
Annual PM PTE T/yr 6.32 3.20 0.67 1.91 0.04 0.01 = (Normal Exhaust Rate) x (Annual Operating Hours ) x (PM Exit Grain Loading) / (7,000 gr/lb) / (2000 lb/T)Annual PM10/2.5 PTE T/yr 1.07 0.54 0.11 0.02 0.04 0.01 = (Normal Exhaust Rate) x (Annual Operating Hours ) x (PM10/2.5 Exit Grain Loading) / (7,000 gr/lb) / (2000 lb/T)
EU List:Blending Silos: PE1BLEND A/B/C/D/E; PE2BLEND A/B/C/D/E; V7001A; V7001B; V7001C; V7001D
Railcar Handling & Storage: PE1RAILSILO - A/B/C/D, PE2RAILSILO - A/B/C/D; PE3RAILSILO - A/B/C/DTruck Handling & Storage: PE1TRUCKSILO- A/B/C/D/E/F/G/H/I/J; PE2TRUCKSILO- A/B/C/D/E/F/G/H/I/J; PE3TRUCKSILO- A/B/C/D/E/F/G/H/I/J/K/L/M/N/O/P/Q/R
DeDuster Vents: PE1RAILDEDUSTA/B; PE2RAILDEDUSTA/B; PE1TRUCKDEDUST A/B/C/D/E; PE2TRUCKDEDUST A/B/C/D/E; PE3RAILDEDUSTA/B; PE3TRUCKDEDUST A/B/C/D/E/F/G/H/I
PE Pellet Transport, Storage, Blending and Loading Operations
Table B-18. PE Handling & Loadout PM PTE
B-29
Emission Unit(s) ID = VOC Emissions from Pellet Handling OperationsParameter Value Units Source / Basis
Calculation InputsPellets Produced = 1,931,247 T/yr Design basis of Franklin plant ratioed to 8,760 hrs/yr.
Residual VOC = 50 ppmw Proposed LAER limit.Fraction of VOC Emitted = 100% Worst-case assumption.
Annual Emissions CalculationsVOC PTE = 96.6 T/yr = (Pellets Produced - T/yr) x (Residual VOC - ppmw) x (Fraction of VOC Emitted) / (1,000,000 ppmw)
NOTES:• Refer to Tables D-2 and D-3 of Appendix D for Listing pf EUs covered by this estimate.• Residual VOC in PE pellets contain no OHAP.
See Note
Table B-19. Residual VOC Estimate
B-30
Tank Name EU ID Tank TypeVolume
[m3]Dianeter
[m]
Height / Length
[m]
Operating Temperature
[°C]
Surrogate Liquid
Annual Throughput
(gal/yr)Emission Control
Uncontrolled VOC/HAP
Emissions*(T/yr)
Control Efficiency
(%)
Controlled VOC /HAP Emissions*
(T/yr)Diesel Locomotive Fuel NA Horizonal Fixed Roof 38 2.4 8.2 38.0 No. 2 Oil 412,000 Carbon Canister 2.7E-03 95% 1.3E-04Pyrolysis Tar Tank T-64201 Vertical Fixed Roof 130 4.6 8.0 150.0 No. 2 Oil 2,520,000 Carbon Canister 9.4E-03 95% 4.7E-04Emergency Generator Diesel Fuel T-58901A Horizonal Fixed Roof 38 2.4 8.2 38.0 No. 2 Oil 55,000 Carbon Canister 1.0E-03 95% 5.2E-05Emergency Generator Diesel Fuel T-58901B Horizonal Fixed Roof 38 2.4 8.2 38.0 No. 2 Oil 55,000 Carbon Canister 1.0E-03 95% 5.2E-05Emergency Generator Diesel Fuel T-58901C Horizonal Fixed Roof 38 2.4 8.2 38.0 No. 2 Oil 55,000 Carbon Canister 1.0E-03 95% 5.2E-05Emergency Generator Diesel Fuel T-58901D Horizonal Fixed Roof 38 2.4 8.2 38.0 No. 2 Oil 55,000 Carbon Canister 1.0E-03 95% 5.2E-05Spent Caustic Storage Tank T-53501 Internal Floating Roof 900 10.7 10.0 20.0 Jet Kerosene 26,151,000 See Note 1.0E-01 95% 5.0E-03Unoxidized Spent Caustic Storage Tank T-53502 Internal Floating Roof 8,630 26.2 16.0 20.0 Jet Kerosene 26,151,000 See Note 2.7E-01 95% 1.3E-02Fire Water Pump Diesel Fuel T-59101A Horizonal Fixed Roof 7 1.6 3.7 38.0 No. 2 Oil 7,200 Carbon Canister 1.8E-04 95% 8.8E-06Fire Water Pump Diesel Fuel T-59101B Horizonal Fixed Roof 7 1.6 3.7 38.0 No. 2 Oil 7,200 Carbon Canister 1.8E-04 95% 8.8E-06Fire Water Pump Diesel Fuel T-59101C Horizonal Fixed Roof 7 1.6 3.7 38.0 No. 2 Oil 7,200 Carbon Canister 1.8E-04 95% 8.8E-06* NOTES: Totals = 0.39 0.02
• This sheet summarizes emissions from those tanks not vented to a common control device.• The tanks listed in this sheet are vented to individual carbon canisters installed on each tank.• As a conservative assumption, 100% of VOC emissions from these tanks are assumed to be HAP.
Table B-20. Storage Tank Emissions
Tank vapors vented to Spent Caustic Vent Incinerator•
B-31
Maximum EmissionRate Factor
Pollutantmillion gal/day lb/million gal lb/hr hrs/year TPY lb/hr hrs/year TPY
VOC N/A N/A 0.097 8,760 0.42 0.097 8,760 0.42 Emissions model EPA WATER9
Benzene N/A N/A 0.097 8,760 0.42 0.097 8,760 0.42 Emissions model EPA WATER9
Phenol N/A N/A 9.4E-06 8,760 4.1E-05 9.4E-06 8,760 4.1E-05 Emissions model EPA WATER9
Basis:Emissions were modeled under worst-case conditions of dry weather flow.Example Calculations:0.42 ton VOC/yr = (0.097 lb/hr) x (8,760 hrs/year) / (2,000 lb/ton)
WWTP Equipment (W-1001) include:Biotreater Aeration Tank, two Secondary Clarifiers, Biosludge Holding Tank, Biosludge Dewatering Tank, Centrate Sump, Sand Filter, Sand Filter Backwash Receiver and Outfall. The Flow Equalization and Oil Removal Tanks (T-5307A/B) are vented to the Spent Caustic Vent Incinerator (A5401).
WWTP Equipment (W-1001) - Emissions SummaryPrecontrol Emissions Controlled Emissions
Calculation/Estimation
Method Emission Factor Reference
Table B-21. Wastewater Treatment Emissions Summary
B-32
Emission Unit(s) ID = Cogen Cooling TowerParameter Source / Basis
Calculation InputsNumber of Cells = 4 Design Specification (GM1-001-U5000-AA-7704-00001, Rev. 00)
Cell Circulation Rate = 11,000 gal/min/cell Design Specification (GM1-001-U5000-AA-7704-00001, Rev. 00)Annual Operating Hours = 8,760 hrs/yr Maximum potential use.
Drift Loss Factor = 0.00050% wt. % Design specification. Basis for proposed BACT limit.Cooling Water Rate = 44,000 gal/min = Cell Circulation Rate * Number of CellsCooling Water TDS = 2,400 ppmw Annual average BACT/LAER proposal.
Calculation ResultsPM10 Fraction of PM = 57.2% wt. % See particle size distribution calculation -->
PM2.5 Fraction of PM = 0.21% wt. % See particle size distribution calculation -->Hourly PM PTE [per cell] = 0.1 lb/hr = (Cell Circulation Rate) x (60 min/yr) x (8.34 lb/gal) x (Drift Loss Factor) x (Cooling Water TDS) / (1,000,000)
Annual PM PTE [total] = 1.2 tpy = (Hourly PM PTE [per cell]) x (Annual Operating Hours) / (2,000 lb/T) x (Number of Cells)Hourly PM10 PTE [per cell] = 0.0378 lb/hr = (PM10 Fraction of PM) x (Hourly PM PTE [per cell])
Annual PM10 PTE [total] = 0.7 tpy = (PM10 Fraction of PM) x (Annual PM PTE [total])Hourly PM2.5 PTE [per cell] = 0.00 lb/hr = (PM2.5 Fraction of PM) x (Hourly PM PTE [per cell])
Annual PM2.5 PTE [total] = 0.0 tpy = (PM2.5 Fraction of PM) x (Annual PM PTE [total])
CogenCWTValue
Table B-22. Cogen Cooling Tower Emission Estimates
B-33
=
10 524 5.24E-04 1.26E-06 1 1.03 0.00020 4189 4.19E-03 1.01E-05 5 2.06 0.19630 14137 1.41E-02 3.39E-05 15 3.09 0.226 0.240 33510 3.35E-02 8.04E-05 37 4.12 0.51450 65450 6.54E-02 1.57E-04 71 5.15 1.80660 113097 1.13E-01 2.71E-04 123 6.18 5.70270 179594 1.80E-01 4.31E-04 196 7.21 21.34890 381704 3.82E-01 9.16E-04 416 9.26 49.812
110 696910 6.97E-01 1.67E-03 760 11.32 70.509 57.2130 1150347 1.15E+00 2.76E-03 1255 13.38 82.023150 1767146 1.77E+00 4.24E-03 1928 15.44 88.012180 3053628 3.05E+00 7.33E-03 3331 18.53 91.032210 4849048 4.85E+00 1.16E-02 5290 21.62 92.468240 7238229 7.24E+00 1.74E-02 7896 24.71 94.091270 10305995 1.03E+01 2.47E-02 11243 27.79 94.689300 14137167 1.41E+01 3.39E-02 15422 30.88 96.288350 22449298 2.24E+01 5.39E-02 24490 36.03 97.011400 33510322 3.35E+01 8.04E-02 36557 41.18 98.340450 47712938 4.77E+01 1.15E-01 52050 46.32 99.071500 65449847 6.54E+01 1.57E-01 71400 51.47 99.071600 113097336 1.13E+02 2.71E-01 123379 61.77 100.000
1.00 g/cc2.20 g/cc
2,400 ppmw57.20 wt. %
PM2.5 fraction of PM = 0.21 wt. %From "Calculating Realistic PM10 Emissions from Cooling Towers"; Reisman & Frisbie (uses EPRI wet droplet size distribution).
Cooling Tower Design TDS =PM10 fraction of PM =
Specific Gravity of Dried Solids =Specific Gravity of Water =
Wet Droplet Diameter(μm)
Wet Droplet Volume(μm3)
Wet Droplet Mass(μg)
Dry Particle Mass(μg)
Cogen Cooling TowerCogenCWTEmission Unit(s) IDDry Particle
Volume(μm3)
Dry Particle Diameter
(um)
wt. % Mass Smaller Than
DropletWt% PM10 in
PM EmissionsWt% PM2.5 in
PM Emissions
Table B-22. Cogen Cooling Tower Emission Estimates (cont'd)
B-34
Emission Unit(s) ID = Process Cooling TowerParameter Source / Basis
Calculation InputsNumber of Cells = 26 Design Specification
Cell Circulation Rate = 10,000 gal/min/cell Design Specification (GM1-001-U5000-AA-7704-00001, Rev. 00)Annual Operating Hours = 8,760 hrs/yr Maximum potential use.
Drift Loss Factor = 0.00050% wt. % Design specification. Basis for proposed BACT limit.Cooling Water Rate = 260,000 gal/min = Cell Circulation Rate * Number of CellsCooling Water TDS = 2,400 ppmw Annual average BACT/LAER proposal.
VOC Emissions Limit = 0.50 lb/MMgal Proposed LAER limit.OHAP Fraction of VOC = 10% wt. % ROM estimate; few HAP-containing streams in process.
Calcualtion Results Hourly VOC PTE [per cell] = 0.30 lb/hr = (Cell Circulation Rate - gpm) x (60 min/hr) x (VOC Emissions Limit - lb/MMGal) / (1,000,000)
Annual VOC PTE [total] = 34.2 T/yr = ( Hourly VOC PTE [per cell]) x (Annual Operating Hours) / (2,000 lb/T) x (Number of Cells) Annual HAP PTE [total] = 3.4 T/yr = (OHAP Fraction of VOC) x ( Annual VOC PTE [total])
PM10 Fraction of PM = 57.2% wt. % See particle size distribution calculation -->PM2.5 Fraction of PM = 0.21% wt. % See particle size distribution calculation -->
Hourly PM PTE [per cell] = 0.1 lb/hr = (Cell Circulation Rate) x (60 min/yr) x (8.34 lb/gal) x (Drift Loss Factor) x (Cooling Water TDS) / (1,000,000)Annual PM PTE [total] = 6.8 tpy = (Hourly PM PTE [per cell]) x (Annual Operating Hours) / (2,000 lb/T) x (Number of Cells)
Hourly PM10 PTE [per cell] = 0.034 lb/hr = (PM10 Fraction of PM) x (Hourly PM PTE [per cell])Annual PM10 PTE [total] = 3.9 tpy = (PM10 Fraction of PM) x (Annual PM PTE [total])
Hourly PM2.5 PTE [per cell] = 0.00 lb/hr = (PM2.5 Fraction of PM) x (Hourly PM PTE [per cell])Annual PM2.5 PTE [total] = 0.0143 tpy = (PM2.5 Fraction of PM) x (Annual PM PTE [total])
PCTValue
Table B-23. Process Cooling Tower Emission Estimates
B-35
=
10 524 5.24E-04 1.26E-06 1 1.03 0.00020 4189 4.19E-03 1.01E-05 5 2.06 0.19630 14137 1.41E-02 3.39E-05 15 3.09 0.226 0.240 33510 3.35E-02 8.04E-05 37 4.12 0.51450 65450 6.54E-02 1.57E-04 71 5.15 1.80660 113097 1.13E-01 2.71E-04 123 6.18 5.70270 179594 1.80E-01 4.31E-04 196 7.21 21.34890 381704 3.82E-01 9.16E-04 416 9.26 49.812
110 696910 6.97E-01 1.67E-03 760 11.32 70.509 57.2130 1150347 1.15E+00 2.76E-03 1255 13.38 82.023150 1767146 1.77E+00 4.24E-03 1928 15.44 88.012180 3053628 3.05E+00 7.33E-03 3331 18.53 91.032210 4849048 4.85E+00 1.16E-02 5290 21.62 92.468240 7238229 7.24E+00 1.74E-02 7896 24.71 94.091270 10305995 1.03E+01 2.47E-02 11243 27.79 94.689300 14137167 1.41E+01 3.39E-02 15422 30.88 96.288350 22449298 2.24E+01 5.39E-02 24490 36.03 97.011400 33510322 3.35E+01 8.04E-02 36557 41.18 98.340450 47712938 4.77E+01 1.15E-01 52050 46.32 99.071500 65449847 6.54E+01 1.57E-01 71400 51.47 99.071600 113097336 1.13E+02 2.71E-01 123379 61.77 100.000
1.00 g/cc2.20 g/cc
2,400 ppmw57.20 wt. %
PM2.5 fraction of PM = 0.21 wt. %From "Calculating Realistic PM10 Emissions from Cooling Towers"; Reisman & Frisbie (uses EPRI wet droplet size distribution).
Specific Gravity of Water =Specific Gravity of Dried Solids =
Cooling Tower Design TDS =PM10 fraction of PM =
Wet Droplet Diameter(μm)
Wet Droplet Volume(μm3)
Wet Droplet Mass(μg)
Dry Particle Mass(μg)
Emission Unit(s) ID PCT Process Cooling TowerDry Particle
Volume(μm3)
Dry Particle Diameter
(um)
wt. % Mass Smaller Than
DropletWt% PM10 in
PM EmissionsWt% PM2.5 in
PM Emissions
Table B-23. Process Cooling Tower Emission Estimates (cont'd)
B-36
ParameterPyrolysis Tar
Loading Slop Oil LoadingSpend Caustic
Loading Units Source / BasisT-64201 T-59708 T-53501,T-53502
Material Loaded Pyrolysis Tar Slop Oil Spent Caustic
Surrogate Material No. 6 Residual Oil Jet Kerosene Jet Kerosene Selected as conservatively volatile species representing actual materials.
Material Temperature 180 30 30 °C Pyrolysis tar is heated; Slop Oil is ≈ maximum daily avg temperature in July
Material Temperature 816 546 546 °R = (Material Temperature - °C) x (1.8) + (32) + (460)
VOC Vapor Pressure 0.5000 0.5000 0.5000 psia Proposed LAER/BACT Vapor Pressure Limit.
VOC Vapor MW 190 130 130 lb/lb-mole TANKS 4.09D value for surrogate material.
Type of Loadout Operation RAIL & TRUCK RAIL & TRUCK RAIL & TRUCK
Type of Loading System SUBMERGED SUBMERGED SUBMERGED Proposed design/work practice.
Annual Loading Rate 2,520 210 504 103gal/yr Loading rates are from preliminary facility design basis.
Saturation Factor 0.60 0.60 0.60 S from AP-42 equation (see below)VOC Loading Loss Factor 1.110 0.992 0.992 lbs/103gal LL from AP-42 equation (see below) using LAER limit Vp.
Control Efficiency 0% 0% 0% wt. % No controls applied due to low Vp
Annual VOC Emissions 1.40 0.10 0.25 T/yr = (Annual Loading Rate) x (VOC Loading Loss Factor) x (1 - Control Efficiency) / (2000 lb/T)
VOC Vapor Pressure 3.45 3.45 3.45 kPa = (6.895 kPa/psi ) x (VOC Vapor Pressure)
Estimated HAP Fraction 100% 100% 100% wt. % Worst-case estimate.
Annual HAP Emissions 1.40 0.10 0.25 T/yr = (Annual VOC Emissions) x (Estimated HAP Fraction)
Emissions Estimates based on Equation 1 in AP-42, Chapter 5, Section 2 (Jan-1995 version):
Table B-24. Low Organic Vapor Pressure Liquid Loadout Operations Emission Estimates
B-37
Emission Unit(s) ID = C3+ Loading EmissionsParameter Value Units Source / Basis
Calculation InputsC3+ Produced = 212,000 m3/yr Design basis of plant.
Volume of 1 Railcar = 115 m3 Standard railcar volumeAnnual Railcars Filled = 1,843 #/yr = (C3+ Produced) / (Volume of 1 Railcar)
VOC EF -g/fill = 6,044 g/fill SCAQMD Controlled Emission Factor for LPG vehicle loading.VOC EF - lb/fill = 13.3 lb/fill = (VOC EF -g/fill) / (453.6 g/lb)
Annual Emissions CalculationsVOC PTE = 12.3 tpy = (VOC EF - lb/fill) x (Annual Railcars Filled - #/yr) / (2,000 lb/ton)
NOTES:• EF source: Final Staff Report Proposed Rule 1177 – Liquefied Petroleum Gas Transfer and Dispensing (June 2012).
C3LOAD
Table B-25. C3+ Loading Emission Estimates
B-38
Emission Unit(s) ID = Spent Caustic Vent IncineratorParameter
Calcuation InputsDesign Heat Input [HHV] = 10.7 MMBtu/hr
Heat Input from VOC [HHV] = 0.7 MMBtu/hrDesign DRE = 99% wt. %
PM EF = 0.0019 lb/MMBtuPM10 EF = 0.0075 lb/MMBtu
PM2.5 EF = 0.0075 lb/MMBtuVOC EF = 0.0302 lb/MMBtuNOx EF = 0.0680 lb/MMBtuSO2 EF = 0.0879 lb/MMBtuCO EF = 0.3700 lb/MMBtu
CO2 EF = 124.8 lb/MMBtuN2O EF = 2.2E-04 lb/MMBtuCH4 EF = 2.2E-03 lb/MMBtu
H2SO4 EF = 3.5E-03 lb/MMBtuHAP EF = 0.0302 lb/MMBtu
Annual Hours = 8,760 hr/yrAnnual Emissions Calculations
PM Emissions = 0.09 T/yrPM10 Emissions = 0.35 T/yr
PM2.5 Emissions = 0.35 T/yrVOC Emissions = 1.42 T/yrNOx Emissions = 3.2 T/yrSO2 Emissions = 4.13 T/yrCO Emissions = 17.4 T/yr
CO2 Emissions = 5,864 T/yrN2O Emissions = 0.01 T/yrCH4 Emissions = 0.10 T/yr
H2SO4 Emissions = 0.17 T/yrHAP Emissions = 1.42 T/yr
CO2e Emissions = 5,870 T/yrShort-Term Emissions Calculations
PM Emissions = 0.02 lb/hrPM10 Emissions = 0.08 lb/hr
PM2.5 Emissions = 0.08 lb/hrVOC Emissions = 0.32 lb/hrNOx Emissions = 0.73 lb/hrSO2 Emissions = 0.94 lb/hrCO Emissions = 3.97 lb/hr
CO2e Emissions = 1,339 lb/hrN2O Emissions = 0.00 lb/hrCH4 Emissions = 0.02 lb/hr
H2SO4 Emissions = 0.04 lb/hrHAP Emissions = 0.32 lb/hr
CO2e Emissions = 1,340 lb/hrSummary of Results
PM PM10 PM2.5 VOC/HAP NOx SO2 CO GHGm CO2e H2SO4Caustic TO PTE = 0.09 0.35 0.35 1.42 3.19 4.13 17.38 5,864 5,870 0.17
= (Design Heat Input [HHV]) x (CO EF) x (Annual Hours) / (2000 lb/T)
= (Design Heat Input [HHV]) x (N2O EF) x (Annual Hours) / (2000 lb/T)
Assumed full-time operation.
= (Design Heat Input [HHV]) x (PM EF) x (Annual Hours) / (2000 lb/T)= (Design Heat Input [HHV]) x (PM10 EF) x (Annual Hours) / (2000 lb/T)= (Design Heat Input [HHV]) x (PM2.5 EF) x (Annual Hours) / (2000 lb/T)= (Design Heat Input [HHV]) x (VOC EF) x (Annual Hours) / (2000 lb/T)
= (Design Heat Input [HHV]) x (SO2 EF) x (Annual Hours) / (2000 lb/T)
Value
= (Design Heat Input [HHV]) x (PM10 EF)
= (Design Heat Input [HHV]) x (VOC EF)
A5401
= Sum of CO2, N2O and CH4 emissions adjusted for NO2 and CH4 GWPs.
= (Design Heat Input [HHV]) x (PM2.5 EF)
= (Design Heat Input [HHV]) x (CH4 EF) x (Annual Hours) / (2000 lb/T)
= (Design Heat Input [HHV]) x (CO2 EF) x (Annual Hours) / (2000 lb/T)
Based on 0.05 g/Nm3 H2S in offgas to oxidizer. AP-42, Table 13.5-1, 9/91.
= (Design Heat Input [HHV]) x (NOx EF) x (Annual Hours) / (2000 lb/T)
40 CFR 98, Table C-2 (as of July-2013); EF for natural gas.40 CFR 98, Table C-2 (as of July-2013); EF for natural gas.AP-42, Table 1.3-1; estimated at based on SO3-to-SO2 emissions ratio for distillate oil.Controlled EF; conservatively assumes HAP is 100% of VOC.
40 CFR 98, Table C-1 (as of July-2013); EF for natural gas + 8.4 g/Nm3 CO2 in influent gas.
Potential Emissions (tons per year)
= (Design Heat Input [HHV]) x (N2O EF)= (Design Heat Input [HHV]) x (CH4 EF)
= sum of CO2, N2O and CH4 emissions adjusted for NO2 and CH4 .
= (Design Heat Input [HHV]) x (H2SO4 EF)= (Design Heat Input [HHV]) x (HAP EF)
= (Design Heat Input [HHV]) x (CO2 EF)
= (Design Heat Input [HHV]) x (H2SO4 EF) x (Annual Hours) / (2000 lb/T)= (Design Heat Input [HHV]) x (HAP EF) x (Annual Hours) / (2000 lb/T)
= (Design Heat Input [HHV]) x (PM EF)
= (Design Heat Input [HHV]) x (CO EF)
= (Design Heat Input [HHV]) x (NOx EF)= (Design Heat Input [HHV]) x (SO2 EF)
Controlled EF: based on 3.2 g/Nm3 VOC in offgas to oxidizer and 99% DRE. AP-42, Table 13.5-1, 9/91.
Source / Basis
Preliminary design basis based on treated gas flow and composition (VOC + NG)
AP-42, Table 1.4-2, 7/98.AP-42, Table 1.4-2, 7/98.AP-42, Table 1.4-2, 7/98.
Preliminary design basis based on treated gas flow and composition (VOC only)Preliminary design basis based on treated gas flow and composition.
Table B-26. Spent Caustic Vent Thermal Incinerator Emissions Estimates
B-39
MMBtu/hr VOC to Flare VOC DRE NOx SO2 PM2.5 VOC CO2 CH4 N2O CO2e CO PM PM10 H2SO4 HAP PbHP Ground Flares / Short-Term Max 2,687 31 MT/hr 0.068 0.37 0.0075HP Ground Flares / Annual Average 82 0.98 MT/hr 98.0% DRE 0.068 0.0015 0.0075 0.3146 131.4 0.0066 0.0013 132.0 0.37 0.0019 0.0075 0.00006 0.00185 4.9E-07HP Elevated Flare / Normal Ops 51.7 NG only 0.068 0.0015 0.0075 0.0054 117.0 0.0022 0.0002 117.1 0.37 0.0019 0.0075 0.00006 0.00185 4.9E-07LP Ground Flare / Normal Ops 1.0 NG only 0.068 0.0015 0.0075 0.0054 117.0 0.0022 0.0002 117.1 0.37 0.0019 0.0075 0.00006 0.00185 4.9E-07Refrigerated Tank Flare / Short-Term Max 72 0 MT/hr 0.068 0.37 0.0075Refrigerated Tank Flare / Annual Avg. 2.3 0 MT/hr 98.0% DRE 0.068 0.0015 0.0075 0.0000 131.4 0.0066 0.0013 132.0 0.37 0.0019 0.0075 0.00006 0.00185 4.9E-07
MMBtu/hr NOTES NOx CO PM10HP Ground Flares / Short-Term Max 2,687 [A] 36.5 994 20.0HP Ground Flares / Annual Average 82 [B] 5.6 0.61HP Elevated Flare / Normal Ops 51.7 [C] 3.5 19.1 0.39LP Ground Flare / Normal Ops 1.0 [D] 0.1 0.4 0.01Refrigerated Tank Flare / Short-Term Max 72 [E] 1.0 26.7 0.54Refrigerated Tank Flare / Annual Avg. 2.3 [F] 0.2 0.02
Hours/yr MMBtu/yr NOx SO2 PM2.5 VOC CO2 CH4 N2O CO2e CO PM PM10 H2SO4 HAP PbHP Ground Flares / Annual Average 8,760 720,146 24.5 0.53 2.68 113.3 47,312 2.38 0.48 47,513 133.2 0.67 2.68 0.02 0.67 1.8E-04HP Elevated Flare / Normal Ops 8,760 452,947 15.40 0.33 1.69 1.22 26,492 0.50 0.05 26,520 83.80 0.42 1.69 0.01 0.42 1.1E-04LP Ground Flare / Normal Ops 8,760 8,760 0.30 0.01 0.03 0.02 512 0.01 0.00 513 1.62 0.01 0.03 0.00 0.01 2.1E-06Refrigerated Tank Flare / Annual Avg. 8,760 19,871 0.68 0.01 0.07 0.00 1,305 0.07 0.01 1,311 3.68 0.02 0.07 0.00 0.02 4.9E-06
BasisFLARE EMISSIONS CALCULATIONS
VOC to Flare
FLARE / FLARING MODE
FLARE / FLARING MODE
NSR POLLUTANT EMISSION FACTORS (lb/MMBtu)
NSR POLLUTANT RATES USED IN AMBIENT IMPACT MODELING (lb/hr)
NSR POLLUTANT PTE (T/yr)
Basis
Basis
Table B-27. VOC Control System Flares Emissions Estimates
B-40
FLARE EMISSIONS CALCULATIONS NOTES:General:
• VOC mass flaring rates are based on preliminary vendor data associated with various potential scenarios (e.g., a cold-startup).• Short-term VOC mass flaring rates represent maximum expected short-term rates excluding emergency flaring.• Annual average VOC mass flaring rates represent annual average anticipated flaring rates excluding emergency flaring.• Where applicable, flare destruction efficiencies represent LAER or beyond-LAER control levels.
Calculation Methodology:• Hourly Emissions = (Heat Input - MMBtu/hr) x (Emissions Factor - lb/MMBtu)• Annual Emissions = (Heat Input - MMBtu/hr) x (Annual Hours) x (Emissions Factor - lb/MMBtu) x (1 ton/2,000 lb)
Basis for Emissions Factors:• NOx/NO2 and CO = AP-42, Table 13.5-1.• SO2 = Natural gas SO2 emissions factor (see "Constants" sheet); Factor applied to pilot flame only; Flared process gases do not contain sulfur.• PM10/2.5 = Natural gas external combustion emissions factor (see "Constants" sheet); Somkeless flares have zero filterable PM (see AP-43, Table 13.5-1).• VOC from HP Ground Flares: based on 98.00% DRE of incoming VOC; VOC content of flared gases = 60.1 wt.%.• VOC from Refrigerated Tank Flares: flared gases contain no VOC.• VOC emissions factor for emergency-only flares pilot fuel = AP-42, Table 1.4-2.• CO2 from pilot fuel is based on natural gas firing = weighted U.S. average NG CO2 emissions factor from 40 CFR 98, Table C-1.• CO2 from VOC flaring is assumed to result from ethane flaring = ethane CO2 emissions factor from 40 CFR 98, Table C-1.• CH4 and N2O from pilot fuel is based on natural gas firing = NG emissions factors from 40 CFR 98, Table C-1.• CH4 and N2O from VOC flaring is assumed to result from fuel gas flaring = fuel gas emissions factors from 40 CFR 98, Table C-2.• CO2e = sum of CO2, CH4 and N2O emissions adjusted for global warming potentials; see "Constants" table for details.• PM = AP-42, Table 1.4-2; Natural gas filterable emissions factor used as conservative estimate since flares are smokeless.• H2SO4 = AP-42, Table 1.3-1; estimated based on SO3-to-SO2 emissions ratio for distillate oil.• Little HAP-containing gas will be flared; HAP emissions estimated based on the total of all AP-42 HAP emissions factors for external combustion of natural gas.
[A] - HP Ground Flares Short-Term Maximum Emissions Rates: • Short-term max heat input based on flaring 52 MT/hr which is maximum anticipated rate from various SU/SD modes.• Heat input also includes 1.0 MMBtu/hr of pilot gas at all times.• The 1-hr maximum NOx rate used for short-term NO2 modeling is divided by 5 because SU/SD events expected to occur less than once every five years.
[B] - HP Ground Flares Annual Average Emissions Rates: • Annual average heat input based on assuming 1 startup and 1 shutdown occur in a year.• Annual average heat input also includes flaring events associated with reasonably anticipated maintenance events at a rate of 1 of each event/year/furnace.• Annual average heat input also includes 1.0 MMBtu/hr of pilot gas at all times.
[C] - HP Elevated Flare Annual Average Emissions Rates:• Heat input based on 1.0 MMBtu/hr of pilot gas plus 1.0 MT/hr of natural gas as sweep gas.
[D] - LP Ground Flare Annual Average Emissions Rates:• Heat input based on 1.0 MMBtu/hr of pilot gas.• All other flaring is emergency-use only.
[E] - Refrigerated Tank Flare Short-Term Maximum Emissions Rates:• Short-term max heat input based on flaring 1.4 MT/hr of ethane which is maximum anticipated rate from various SU/SD modes.• Heat input also includes 1.0 MMBtu/hr of pilot gas at all times.• The 1-hr maximum NOx rate is divided by 5 because SU/SD events expected to occur at most once every five years.
[F] - Refrigerated Tank Flare Annual Average Emissions Rates:• Annual average heat input based on assuming 1 startup and 1 shutdown occur in a year with anticipated flaring of 225 MT of ethane/event in this flare.• Annual average heat input also includes 1.0 MMBtu/hr of pilot gas at all times.
Table B-27a. VOC Control System Flares Emissions Estimates Notes
B-41
Emission Unit(s) ID = LP Thermal IncineratorParameter
Calcuation InputsPotential Heat Input [HHV] = 103 MMBtu/hr
Design DRE = 99.5% wt. %PM EF = 0.0075 lb/MMBtu
PM10 EF = 0.0075 lb/MMBtuPM2.5 EF = 0.0075 lb/MMBtu
VOC EF = 0.2280 lb/MMBtuNOx EF = 0.0680 lb/MMBtuSO2 EF = 0 lb/MMBtuCO EF = 0.0824 lb/MMBtu
CO2 EF = 145.4 lb/MMBtuN2O EF = 1.3E-03 lb/MMBtuCH4 EF = 6.6E-03 lb/MMBtu
H2SO4 EF = 0 lb/MMBtuHAP EF = 1.9E-03 lb/MMBtu
Annual Hours = 8,760 hr/yrAnnual Emissions Calculations
PM Emissions = 3.37 T/yrPM10 Emissions = 3.37 T/yr
PM2.5 Emissions = 3.37 T/yrVOC Emissions = 103.08 T/yrNOx Emissions = 30.7 T/yrSO2 Emissions = 0.00 T/yrCO Emissions = 37.2 T/yr
CO2 Emissions = 65,728 T/yrN2O Emissions = 0.60 T/yrCH4 Emissions = 2.99 T/yr
H2SO4 Emissions = 0.00 T/yrHAP Emissions = 0.84 T/yr
CO2e Emissions = 65,981 T/yrShort-Term Emissions Calculations
PM Emissions = 0.77 lb/hrPM10 Emissions = 0.77 lb/hr
PM2.5 Emissions = 0.77 lb/hrVOC Emissions = 23.53 lb/hrNOx Emissions = 7.02 lb/hrSO2 Emissions = 0.00 lb/hrCO Emissions = 8.50 lb/hr
CO2e Emissions = 15,006 lb/hrN2O Emissions = 0.14 lb/hrCH4 Emissions = 0.68 lb/hr
H2SO4 Emissions = 0.00 lb/hrHAP Emissions = 0.19 lb/hr
CO2e Emissions = 15,064 lb/hrSummary of Results
PM PM10 PM2.5 VOC NOx SO2 CO GHGm CO2e H2SO4 HAPLP TI PTE = 3.37 3.37 3.37 103.08 30.74 0.00 37.22 65,732 65,981 0.00 0.84
Potential Emissions (tons per year)
= (Potential Heat Input [HHV]) x (VOC EF)= (Potential Heat Input [HHV]) x (NOx EF)= (Potential Heat Input [HHV]) x (SO2 EF)= (Potential Heat Input [HHV]) x (CO EF)= (Potential Heat Input [HHV]) x (CO2 EF)= (Potential Heat Input [HHV]) x (N2O EF)= (Potential Heat Input [HHV]) x (CH4 EF)= (Potential Heat Input [HHV]) x (H2SO4 EF)= (Potential Heat Input [HHV]) x (HAP EF)= Sum of CO2, N2O and CH4 emissions adjusted for NO2 and CH4 GWPs of 298 and 25.
= (Potential Heat Input [HHV]) x (PM2.5 EF)
= (Potential Heat Input [HHV]) x (SO2 EF) x (Annual Hours) / (2000 lb/T)= (Potential Heat Input [HHV]) x (CO EF) x (Annual Hours) / (2000 lb/T)= (Potential Heat Input [HHV]) x (CO2 EF) x (Annual Hours) / (2000 lb/T)= (Potential Heat Input [HHV]) x (N2O EF) x (Annual Hours) / (2000 lb/T)= (Potential Heat Input [HHV]) x (CH4 EF) x (Annual Hours) / (2000 lb/T)= (Potential Heat Input [HHV]) x (H2SO4 EF) x (Annual Hours) / (2000 lb/T)= (Potential Heat Input [HHV]) x (HAP EF) x (Annual Hours) / (2000 lb/T)= Sum of CO2, N2O and CH4 emissions adjusted for NO2 and CH4 GWPs of 298 and 25.
= (Potential Heat Input [HHV]) x (PM EF)= (Potential Heat Input [HHV]) x (PM10 EF)
= (Potential Heat Input [HHV]) x (NOx EF) x (Annual Hours) / (2000 lb/T)
40 CFR 98, Table C-1 (as of July-2013); EF for ethylene.40 CFR 98, Table C-2 (as of July-2013); EF for fuel gas.40 CFR 98, Table C-2 (as of July-2013); EF for fuel gas.No sulfur in PE vents.Based on the total of all AP-42 HAP emissions factors for external combustion of natural gas.Assumed full-time operation at max rate as worst-case.
= (Potential Heat Input [HHV]) x (PM EF) x (Annual Hours) / (2000 lb/T)= (Potential Heat Input [HHV]) x (PM10 EF) x (Annual Hours) / (2000 lb/T)= (Potential Heat Input [HHV]) x (PM2.5 EF) x (Annual Hours) / (2000 lb/T)= (Potential Heat Input [HHV]) x (VOC EF) x (Annual Hours) / (2000 lb/T)
AP-42, Table 1.4-1, 7/98.
LPINCINERATORValue Source / Basis
Preliminary design basis.Preliminary design basis.AP-42, Table 1.4-2, 7/98 & proposed BACT limit.AP-42, Table 1.4-2, 7/98 & proposed BACT limit.AP-42, Table 1.4-2, 7/98 & proposed LAER limit.Preliminary design basis of 2.4 T/hr VOC to TI and a DRE of 99.50%.Preliminary design basis.No sulfur in PE vents.
Table B-28. VOC Control System Low Pressure Thermal Incinerator Emissions Estimates
B-42
Parameter Reference & Calculation Basis
k for PM 0.011 lb/VMT AP-42, Table 13.2.1-1k for PM10 0.0022 lb/VMT AP-42, Table 13.2.1-1
k for PM2.5 0.00054 lb/VMT AP-42, Table 13.2.1-1sL 0.20 g/m2 Estimated value based on application of LAER controls.W 25 tons average weight (tons) of the vehicles traveling the road.P 150 days Number of days with rain fall greater than 0.01 inchN 365 days Number of days in the averaging period.
EF for PM 0.059 lb/VMT EF = k (sL)0.91 (W)1.02 (1 –1.2 P/(4*N))EF for PM10 0.0119 lb/VMT EF = k (sL)0.91 (W)1.02 (1 –1.2 P/(4*N))
EF for PM2.5 0.00292 lb/VMT EF = k (sL)0.91 (W)1.02 (1 –1.2 P/(4*N))Vehicles per day 22 vehicles/day Design estimate.
Hours per day of vehicle traffic 24 hr/day Annual average value.Road Length 0.97 miles Round trip distance from current plot plan.
VMT hourly = 0.9 VMT/hr = (Vehicles per day) / (Hours per day of vehicle traffic) x (Road Length)PM Emissions [hourly] 0.053 lb/hr = (VMT hourly =) x (EF for PM)
PM10 Emissions [hourly] 0.011 lb/hr = (VMT hourly =) x (EF for PM10)PM2.5 Emissions [hourly] 0.003 lb/hr = (VMT hourly =) x (EF for PM2.5)
PM Emissions [annual] 0.231 tpy = (PM Emissions [hourly]) x (8,760 hr/yr) / (2,000 lb/T)PM10 Emissions [annual] 0.046 tpy = (PM10 Emissions [hourly]) x (8,760 hr/yr) / (2,000 lb/T)
PM2.5 Emissions [annual] 0.011 tpy = (PM2.5 Emissions [hourly]) x (8,760 hr/yr) / (2,000 lb/T)
TRANSPORT TRUCK ROAD PARTICULATE MATTER EMISSIONS(Annual Rate)
ValueCalculation based based on paved Road Equation from AP-42 section 13.2.1 for hourly emissions
Table B-29. Transport Truck Road PM Emissions Estimates
B-43
Parameter Reference & Calculation Basis
k for PM 0.011 lb/VMT AP-42, Table 13.2.1-1k for PM10 0.0022 lb/VMT AP-42, Table 13.2.1-1
k for PM2.5 0.00054 lb/VMT AP-42, Table 13.2.1-1sL 0.20 g/m2 Estimated value based on application of LAER controls.W 25 tons average weight (tons) of the vehicles traveling the road.P 0 hours Number of hours with rain fall greater than 0.01 inch.N 24 hours Number of hours in the averaging period.
EF for PM 0.068 lb/VMT EF = k (sL)0.91 (W)1.02 (1 –1.2 P/(4*N))EF for PM10 0.0136 lb/VMT EF = k (sL)0.91 (W)1.02 (1 –1.2 P/(4*N))
EF for PM2.5 0.00333 lb/VMT EF = k (sL)0.91 (W)1.02 (1 –1.2 P/(4*N))Vehicles per day 22 vehicles/day Design estimate.
Hours per day of vehicle traffic 8 hrs/day Assumes 8 hours per day of traffic as worst-case for short-term rate.Road Length 0.97 miles Round trip distance from current plot plan.
VMT hourly = 2.7 VMT/hr = (Vehicles per day) / (Hours per day of vehicle traffic) x (Road Length)PM Emissions [hourly] 0.180 lb/hr = (VMT hourly =) x (EF for PM)
PM10 Emissions [hourly] 0.036 lb/hr = (VMT hourly =) x (EF for PM10)PM2.5 Emissions [hourly] 0.009 lb/hr = (VMT hourly =) x (EF for PM2.5)
PM Emissions [annual] 0.789 tpy = (PM Emissions [hourly]) x (8,760 hr/yr) / (2,000 lb/T)PM10 Emissions [annual] 0.158 tpy = (PM10 Emissions [hourly]) x (8,760 hr/yr) / (2,000 lb/T)
PM2.5 Emissions [annual] 0.039 tpy = (PM2.5 Emissions [hourly]) x (8,760 hr/yr) / (2,000 lb/T)
TRANSPORT TRUCK ROAD PARTICULATE MATTER EMISSIONS(Hourly Rate)
ValueCalculation based based on paved Road Equation from AP-42 section 13.2.1 for hourly emissions
Table B-29. Transport Truck Road PM Emissions Estimates (cont'd)
B-44
Parameter Discussion / BasisCO2 Capture & Concentration - Capital Costs
CO2 flow from Furnaces and Cogen Units = 5,774 T/d Based on 365 d/yr operation (assumes no APHT installed on heaters)Assumed CO2 Capture Efficiency = 90% wt. % Assumed overall efficiency of capture and concentration system.
Base Cost CO2 flow to CCS = 5,353 T/d Case 14 NETL Report , p. 478.Base CO2 Concentration = 4.04% Case 14 NETL Report , p. 478.
Influent Gas CO2 Concentration = 3.54% Estimate.June 2011 CPI = 676.162 From: http://www.economagic.com/em-cgi/data.exe/blscu/CUUR0000AA0Feb 2014 CPI = 703.300 From: http://www.economagic.com/em-cgi/data.exe/blscu/CUUR0000AA0
Base Cost CO2 Removal System TCI = 259,459,000 $2011 Case 14 NETL Report Update , p. 44 (June 2011 costs).Base Cost CO2 Removal System TCI = 269,872,478 $2014 Adjusted using CPI ratios.
Size Adjustment Exponent (SAE) = 0.60 Peters & Timmerhaus , p 166.CO2 Scrubber & Regen TCI = 305,503,045 $2014 Based on NETL Report Update costs, Case 14 using ratio of CO2 flow/concentration and SAE.
Capital to Duct 7 Furnaces and 3 Cogen Units to 1 CCS System = 10,000,000 $2014 ROM estimate @ $1.0 MM/unit.CO2 Capture System TCI 315,503,045 $2014 Scrubber/regen system cost.
CO2 Compression - Capital CostsBase Cost CO2 Compression & Drying TCI = 35,960,000 $2011 Case 14 NETL Report Update , p. 44 (June 2011 costs).Base Cost CO2 Compression & Drying TCI = 37,403,267 $2014 Adjusted using CPI ratios.
Size Adjustment Exponent = 0.60 Peters & Timmerhaus , p 166.Estimated Compression System TCI = 39,142,327 $2014 Estimate based on NETL Case 14 using ratio of CO2 flows and Size Adjustment Exponent.
CO2 Injection Well - Capital CostsCost for Saline Formation Injection Well System = 46,049,328 $2008 Final CO2 GS Rule Cost Analysis (Large-scale project well costs).
Jan-2008 CPI = 632.300 $2008 From: http://www.economagic.com/em-cgi/data.exe/blscu/CUUR0000AA0Feb-2014 CPI = 703.300 $2014 From: http://www.economagic.com/em-cgi/data.exe/blscu/CUUR0000AA0
Estimated CO2 GS Well System TCI = 51,220,137 $2014 TCI adjusted to $2014 using CPI ratios.CO2 Capture & Concentration - Annualized Costs
CO2 Capture Unit Steam Use = 3.2 103lb/T Case 14 NETL Report , p. 478 (stream 8).CO2 Capture Unit Power Use = 43 kWh/T Case 14 NETL Report , p. 479 (amine system auxiliaries).
Unit Power Cost = $/kW Site power cost basis.Unit Steam Cost = $/103lb See Steam Cost and EFs Basis sheet.
CO2 Capture Annual Power Cost = $/yr = (Unit Steam Use - Mlb/T) x (CO2 flow to CCS - T/d) x (365 d/yr) x (Steam Cost - $/Mlb)CO2 Capture Annual Steam Cost = $/yr = (Unit Power Use - kWh/T) x (CO2 flow to CCS - T/d) x (365 d/yr) x (Power Cost - $/kWh)
Annual O&M Labor & Materials @ 4% of TCI = $/yr Peters & Timmerhaus , average for simple processes, p. 201.Administrative, Taxes, Insurance @ 4% of TCI = 12,620,122 $/yr OAQPS Control Cost Manual.
Total Annual O&M Costs = 8 $/yrCapital Recovery Rate = 7% %/yr
Capital Recovery Period = 15 yrsCapital Recovery Factor = 11.0% % of TCI OAQPS CCM.
Annualized Capital Costs = $/yrSubtotal CO2 Capture Annualized Costs = 120,612,072 $/yr
CO2 Compression and Injection Well - Annualized CostsCO2 Compression Power Use = 105 kWh/T See CCS Power Calc sheet; value is per ton of CO2 captured by the system.
CO2 Compression Annual Power Cost = $/yr
CCS Impacts AnalysisValue
Table B-30. CCS Impacts Analysis
B-45
$2008 Well O&M Costs = 4,396,289 $/yr Final CO2 GS Rule Cost Analysis (Pilot project well costs).$2014 Well O&M Costs = 4,889,942 $/yr Adjusted using CPI ratios.
Allocated Annual O&M, Taxes, Ins., Admin. & Capital Costs = 17,150,310 $/yr Scaled from TCI: Capital Recovery Factor =10.98%, O&M = 4%, and Taxes, Ins. & Admin = 4%.Subtotal CO2 Compression & Well System Annualized Costs = 29,000,508 $/yr
Total CCS Process - Annualized CostsAnnualized CO2 Capture Costs = 120,612,072 $/yr
Annualized CO2 Compression and Well System Costs = 29,000,508 $/yrTotal CCS Annualized Costs = 149,612,580 $/yr
Process Heaters CCS - Cost Effectiveness Determination
CCS Steam Use = 6,712,998 103lb/yr = (CO2 Capture Unit Steam Use) x (CO2 flow from Furnaces and Cogen Units) x (365 d/yr)
CCS Power Use = 289,577,652 kWh/yr= ((CO2 Capture Unit Power Use) + (CO2 Compression Power Use) x (90% capture)) x (CO2 flow from Furnaces and Cogen Units) x (365 d/yr)
Gross CO2 Recovered = 1,896,881 T/yr Based on 90% capture of all combustion unit CO2.GHGs to produce steam for CO2 capture = 483,597 T/yr Based on a GHG EF of 144.1 lb/Mlb steam produced. See 'Steam Cost and EFs Basis' sheet.
GHGs Emitted by off-site power production = 180,122 T/yr Based on an incremental GHG EF of 2.23 lb CO2e/kWh (EPA 2010 eGRID database for LA).Net CO2 Recovered = 1,233,162 T/yr = Gross CO2 Recovered - GHGs emitted by Steam Generator - GHGs emitted by LA power plants.
Net Control Cost-Effectivness = 121 $/T = (Total CCS Annualized Costs) ÷ (Net CO2 Recovered)Process Heaters CCS Environmental Impacts
State ID = PA Two-letter state ID; location of CCS system & assumed source of electric power for that system.Off-site Power SO2 EF = 0.0065 lb/kWh EPA 2010 eGrid database; incremental power production factor for PA.Off-site Power NOx EF = 0.0018 lb/kWh EPA 2010 eGrid database; incremental power production factor for PA.
Off-site Power CO2e EF = 1.64 lb/kWh EPA 2010 eGrid database; incremental power production factor for PA.Steam Boiler NOx EF = 0.062 lb/103lb steam See Steam Cost and EFs Basis sheet.
Off-site Power SO2 = 942 T/yr = (CCS Power Use) x (Off-site Power SO2 EF) / (2000 lb/T)Off-site Power NOx = 266 T/yr = (CCS Power Use) x (Off-site Power NOx EF) / (2000 lb/T)
Steam Boiler NOx = 207 T/yr = (CCS Power Use) x (Steam Boiler NOx EF) / (2000 lb/T)NETL Report = Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity Revision 2 ; November 2010; DOE/NETL-2010/1397.NETL Report Update = Updated Costs (June 2011 Basis) for Selected Bituminous Baseline Cases ; August 2012; DOE/NETL-341/082312.Peters & Timmerhaus = Plant Design and Economics for Chemical Engineers (3rd ed.) , Peters, M.S., and Timmerhaus, K.D. (1980),McGraw‐Hill.Final CO2 GS Rule Cost Analysis = Cost Analysis for the Federal Requirements Under the Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (Final GS Rule), U.S. EPA, EPA 816-R10- Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law.
Table B-30. CCS Impacts Analysis (cont'd)
B-46
Discussion/BasisTIC [$2008] = 46,049,328 $2008 Ref. 1; Cost for large-scale saline formation injection project under RA3; Large-scale project costs used
as injection volume most closely approximates project CO2 rates.Annual O&M [$2008] = 4,396,289 $2008 Ref. 1; Cost for large-scale saline formation injection project under RA3; Large-scale project costs used
as injection volume most closely approximates project CO2 rates.Jan-2008 CPI = 632.3 $2008 See: http://www.economagic.com/em-cgi/data.exe/blscu/CUUR0000AA0Jan-2014 CPI = 700.71 $2014 See: http://www.economagic.com/em-cgi/data.exe/blscu/CUUR0000AA0
TIC = 51,031,512 $2014 = ($Jan-2014 CPI) / ($Jan-2008 CPI) x (TIC [$2008])Annual O&M = 4,871,934 $2014 = ($Jan-2014 CPI) / ($Jan-2008 CPI) x (Annual O&M [$2008])
CO2 Geologic Sequestration Saline Well CostsParameter Value
Ref. 1: Cost Analysis for the Federal Requirements Under the Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (Final GS Rule), U.S. EPA, EPA 816-R10-013, Nov-2010.
Table B-31. Geologic Sequestration Saline Well Costs
B-47
Pump Power CalculationCO2mass Captured= 5,197 MT/day
Pinitial = 0.10 MPaPfinal = 15.0 MPa
Pcut-off = 7.38 MPaρ = 630 kg/m3
ηp = 0.75Wp = 970 kW
Compressor Power CalcalationGeneral Parameters
R = 8.314 kJ/kmol-oKM = 44.01 lb/lb-mol
Tin = 313.15 oKηis = 0.75CR= 2.36 per stage
Stage 1 ParametersZs1 = 0.995ks1 = 1.277
Ws1 = 4,465 kWStage 2 Parameters
Zs2 = 0.985ks2 = 1.286
Ws2 = 4,431 kWStage 3 Parameters
Zs3 = 0.97ks3 = 1.309
Ws3 = 4,390 kWStage 4 Parameters
Zs4 = 0.935ks4 = 1.379
Ws4 = 4,305 kWStage 5 Parameters
Zs5 = 0.845ks5 = 1.704
Ws5 = 4,141 kWTotal Compressor Power
Stage 1 - 5 = 21,731 kWTotal Transport PowerPump + Compressor = 22,701 kW
Source: Techno-Economic Models for Carbon Dioxide Compression, Transport, and Storage; Institute of Transportation Studies University of California, Davis 2006; pubs.its.ucdavis.edu/download_pdf.php?id=1047
Table B-32. CCS Compression and Pumping Energy Calculation
B-48
Estimated Gas Cost =Steam Cost (fuel only) = 5.72 $/Mlb
Steam Cost (fuel + O&M + CR) = 8.57 $/MlbSteam GHG EF = 144.1 lb/MlbSteam NOx EF = 0.01 lb/Mlb
Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law.
Based on above equation and energy content values and 40 CFR Part 98 NG GHG EFs.Based on an assumed NOx emissions rate of 0.01 lb/MMBtu.
Steam Cost and EFs Basis
From: http://www.energystar.gov/buildings/sites/default/uploads/tools/bnch_cost.pdfShell's estimate of fuel costs.See above equation and energy content values; assumes 88% efficiency.Assumes O&M + Capital Recovery ≈ 50% of Fuel Cost.
Table B-33. Steam Cost and Emission Factor Basis
B-49
Input Data Unit SourceMass Flowrate of Transfer Line = lb/hr Licensor providedConcentration Hexane = 20 ppm MON ComplianceMole Weight Hexane = 86.17 lb/lb-mole ConstantMole Weight Nitrogen = 28.02 lb/lb-mole ConstantNumber of Venting Episodes times/yr Licensor/Shell ProvidedDuration of Venting Episode hours/episodeLicensor/Shell Provided
Hourly Emission Rate = 0.03 lb/hrAnnual PTE = 9.11E-04 tpy
Calculation Basis:Hourly Emissions = Annual Emissions =
Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law.
(Hourly) x (Hrs/episode) x (episodes/yr) / 2000
Hexane Emissions Estimates from Cocatalyst Transfer Line EU=COCATFD1/2
Emissions Estimate
Calculation Basis
(Mass Flowrate)x(Concentration of hexane)*(Mole Wt Hexane/Mole Weight N2)
Table B-34. Cocatalyst Feed Pot Emissions Estimate
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APPENDIX C
AIR DISPERSION MODELING AND CLASS II VISIBILITY ANALYSIS FOR THE PROPOSED SHELL CHEMICAL
APPALACHIA LLC PETROCHEMICALS COMPLEX PROJECT IN BEAVER COUNTY PENNSYLVANIA
Prepared for: Shell Chemical Appalachia LLC
910 Louisiana Houston TX 77002
Prepared by: RTP Environmental Associates
304A West Millbrook Road Raleigh, North Carolina 27609
April 2014
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Table of Contents
1.0 INTRODUCTION AND SUMMARY OF RESULTS .............................................. 1-1 2.0 PROJECT DESCRIPTION .................................................................................. 2-1 3.0 SITE DESCRIPTION ........................................................................................... 3-1 4.0 MODEL SELECTION AND MODEL INPUT ........................................................ 4-1
4.1 Model Selection ................................................................................................ 4-1 4.2 Model Control Options and Land Use .............................................................. 4-1 4.3 Source Data ..................................................................................................... 4-2 4.4 Ambient Monitoring and Monitored Background Data ...................................... 4-8 4.5 Receptor Data ................................................................................................ 4-16 4.6 Meteorological Data ....................................................................................... 4-17
5.0 MODELING METHODOLOGY ............................................................................ 5-1 5.1 Pollutants Subject to Review ............................................................................ 5-1 5.2 Turbine Load/Operating Conditions .................................................................. 5-1 5.3 Furnace Operating Conditions.......................................................................... 5-1 5.4 Significant Impact Analysis ............................................................................... 5-2 5.5 NAAQS Analysis .............................................................................................. 5-2 5.6 NO2 Analyses ................................................................................................... 5-4
6.0 RESULTS ............................................................................................................ 6-1 6.1 Turbine Load Analysis Results ........................................................................ 6-1 6.2 Furnaces Operating Condition Results ............................................................. 6-1 6.3 Significant Impact Analysis Results .................................................................. 6-1 6.4 NAAQS Analysis Results ................................................................................. 6-4 6.5 Summary and Conclusions .............................................................................. 6-7
7.0 CLASS II VISIBILITY ANALYSIS ........................................................................ 7-1 8.0 CLASS I AREA IMPACTS ................................................................................... 8-1
8.1 Class I AQRV Analysis ..................................................................................... 8-1 8.2 Class I Significant Impacts Analysis ................................................................. 8-1
List of Tables
Table 1. Proposed Background Concentrations 2010-2012 ...................................... 4-11 Table 2. Beaver Falls 98% Hourly NO2 (ppb) By Season and Hour of Day ............... 4-11 Table 3. Receptor Grid Spacing ................................................................................ 4-17 Table 4. PSD Class II Significant Impact Levels ......................................................... 5-3 Table 5. Load Analysis Results ................................................................................... 6-2 Table 6. Worst Case Furnace Analysis Results .......................................................... 6-3 Table 7. Class II Significant Impact Analysis Results .................................................. 6-3 Table 8. Class I Significant Impact Analysis Results ................................................... 6-4 Table 9. NAAQS Analysis Results .............................................................................. 6-5 Table 10. Shell Contribution to the Modeled 1-hr NO2 NAAQS Exceedences ............ 6-6 Table 11. Class II Visibility Analysis Results for Raccoon Creek State Park ............... 7-3 Table 12. Class I Significant Impact Analysis Results ................................................. 8-1
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List of Figures
Figure 1. General Location of the Shell Facility ........................................................... 3-2 Figure 2. Specific Location of the Shell Facility ........................................................... 3-3 Figure 3. Land Use within Three Kilometers ............................................................... 4-3 Figure 4. Shell Facility Plot Plan .................................................................................. 4-6 Figure 5. Shell Three Dimensional Plot Plan (View from SW) ..................................... 4-7 Figure 6. Ambient Air Quality Monitors in the Vicinity of the Shell Site ........................ 4-9 Figure 7. Shell Near-field Receptor Grid ................................................................... 4-18 Figure 8. First Energy Meteorological Tower Location Relative to Shell ................... 4-20 Figure 9. Beaver Valley Windrose 2006-2010 ........................................................... 4-21 Figure 10. Pittsburgh International Airport Location Relative to Shell ....................... 4-22 Figure 11. Meteorological Data Representativeness Analysis Results ..................... 4-23 Figure 13. Class I Areas Located within Three Hundred Kilometers of Shell and
Modeled Receptors ................................................................................................ 8-2
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1.0 INTRODUCTION AND SUMMARY OF RESULTS
This document presents the results of the air quality dispersion modeling analysis
conducted for the proposed Shell Chemical Appalachia, LLC Ethane
Cracker/Polyethylene Plants Project ("Shell") to be constructed in Beaver County
Pennsylvania.
The analysis evaluated emissions of the criteria pollutants regulated under the
Prevention of Significant Deterioration ("PSD") regulations of 40 CFR 52.21 as
implemented under 25 Pa. Code Chapter 127, Subchapter D. The criteria pollutant
analysis was conducted to insure that the proposed project will not cause or contribute
to air pollution in violation of a National Ambient Air Quality Standard ("NAAQS") or PSD
increments.
The analyses quantify only the impacts of the pollutants that are emitted in amounts in
excess of the significant emission rates ("SERs"). For the proposed project, emissions
of nitrogen oxides ("NOX"), carbon monoxide ("CO"), and particulate matter with an
aerodynamic diameter of less than 10 µm ("PM10") will be emitted in significant
quantities.
Only the emissions from the proposed Shell facility were initially evaluated for
determining if the project would significantly impact local air quality. The resultant
modeled concentrations were compared to the ambient Significant Impact Levels
("SILs") for Class I and Class II areas. The results of this significant impacts analysis
demonstrate that the proposed project will result in ambient impacts in excess of the
Class II SIL only for the 1-hour NO2 standard. Impacts for all other pollutants were
determined to be less than the Class I and Class II SILs. Therefore, a refined air quality
analysis to calculate concentrations for comparison to the NAAQS was required for the
1-hr NO2 standard.
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The results of the NAAQS analysis for the 1-hour NO2 standard indicate modeled NO2
violations in the vicinity of the proposed Shell site. These modeled violations are
attributable to existing sources in the vicinity of the proposed Shell site. The proposed
project is shown not to cause or contribute to an existing modeled violation.
Class II visibility impacts were also evaluated at the Pittsburgh International Airport and
determined to be acceptable.
The analysis conforms to the modeling procedures outlined in the Environmental
Protection Agency’s Guideline on Air Quality Models1 ("Guideline") and associated EPA
modeling policy and guidance as well as with the modeling protocol submitted to and
approved by the Pennsylvania Department of Environmental Protection ("PADEP") on
February 19, 2014.2
.
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2.0 PROJECT DESCRIPTION The proposed Shell facility will produce approximately 1,600,000 metric tons per year of
ethylene and 1,600,000 metric tons per year of polyethylene. From an air emissions
modeling perspective, the facility will consist of seven ethane cracking furnaces, a
number of diesel engines to provide emergency power and power fire water pumps,
incinerators, flares, a cooling tower, three catalyst activation heaters, and three
combustion turbines with heat recovery systems to provide steam and electric power to
the facility and electric power for sale.
The project will result in increases in emissions of nitrogen oxides ("NOx"), particulate
matter with an aerodynamic diameter of less than 10 microns (PM10"), and carbon
monoxide ("CO") that are in excess of PSD SERs. Please note that the portion of
Beaver County where the Shell facility is to be located is classified as non-attainment for
ozone, sulfur dioxide ("SO2"), PM2.5, and lead ("Pb"). These pollutants are therefore
subject to non-attainment review and were not required to be evaluated under PSD.
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3.0 SITE DESCRIPTION
The Shell facility will occupy approximately 400 acres on the site of the zinc smelter
currently owned by the Horsehead Corporation. The site is located adjacent to the Ohio
River in the Borough of Monaca, Pennsylvania in Beaver County. The approximate
Universal Transverse Mercator ("UTM") coordinates of the facility are 556,129 meters
east and 4,502,450 meters north (UTM Zone 17, NAD 83). Figure 1 shows the general
location of the facility. Figure 2 shows the specific facility location on a 7.5-minute U.S.
Geological Survey ("USGS") topographic map.
The facility will be classified under the regulations governing PSD (40 CFR 52.21) and
Title V (40 CFR 70.2) as a major source of air pollution. The portion of Beaver County
where the Shell facility is to be located is classified as attainment or unclassifiable for all
regulated pollutants except ozone, SO2, PM2.5, and Pb.a
a A portion of Beaver Co is non-attainment for the 1997 and 2008 8-hour ozone standards, the 2010 1-hr SO2 standard, the 1997 annual PM2.5 standard, the 2006 24-hr PM2.5 standard, and the 2008 lead (Pb) standard.
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Figure 1. General Location of the Shell Facility
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Figure 2. Specific Location of the Shell Facility
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4.0 MODEL SELECTION AND MODEL INPUT 4.1 Model Selection The latest version of the AMS/EPA Regulatory Model (AERMOD, Version 13350) was
used to conduct the dispersion modeling analysis. AERMOD is a Gaussian plume
dispersion model that is based on planetary boundary layer principals for characterizing
atmospheric stability. The model evaluates the non-Gaussian vertical behavior of
plumes during convective conditions with the probability density function and the
superposition of several Gaussian plumes. AERMOD is a modeling system with three
components: AERMAP is the terrain preprocessor program, AERMET is the
meteorological data preprocessor and AERMOD includes the dispersion modeling
algorithms.
AERMOD is the most appropriate model for calculating ambient concentrations near the
Shell facility based on the model's ability to incorporate multiple sources and source
types. The model can also account for convective updrafts and downdrafts and
meteorological data throughout the plume depth. The model also provides parameters
required for use with up to date planetary boundary layer parameterization. The model
also has the ability to incorporate building wake effects and to calculate concentrations
within the cavity recirculation zone. All model options were selected as recommended
in the EPA Guideline on Air Quality Models.
Oris Solution's BEEST Graphical User Interface ("GUI") was used to run AERMOD.
The GUI uses an altered version of the AERMOD code to allow for flexibility in the file
naming convention. The dispersion algorithms of AERMOD were not altered. A model
equivalency evaluation has been submitted to PADEP pursuant to Section 3.2 of 40
CFR 51, Appendix W.
4.2 Model Control Options and Land Use AERMOD was run in the regulatory default mode for all pollutants except NO2. The
NO2 modeling included the non-regulatory default Plume Volume Molar Ratio Method
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("PVMRM") in the NAAQS analysis. This non-default option is discussed in more detail
in Section 5.5.
The default rural dispersion coefficients in the model were used. This rural classification
is supported by the Land Use Procedure consistent with subsection 7.2.3(c) of the
Guideline and Section 5.1 of the AERMOD Implementation Guide.
The USGS 2006 National Land Cover Data (NLCD) within 3km of the site were
converted to Auer 1978 land use types, using recommendations from the PADEP, and
evaluated.3 It was determined that the land use in the vicinity of Shell is predominantly
rural (less than 15% of the area is classified as urban - Figure 3). Based upon this rural
determination, the potential for urban heat island affects, which are regional in
character, should not be of concern.
4.3 Source Data Modeled source input data and emissions are included in Attachment A of this report. Source Characterization Point Sources Most emission sources at the Shell site will vent to stacks with a well defined opening.
These sources were modeled as point sources in AERMOD. Several other types of
sources such as fugitive emissions, flares, horizontal releases and merged flues also
required evaluation.
Fugitive Emissions Fugitive emissions were modeled as volume sources. The initial dispersion coefficients
(sigma y and sigma z) were calculated based upon the dimensions of the area of
release and the equations contained in Table 3-1 of the AERMOD User’s Guide.
Haul roads were modeled pursuant to procedures adopted by the EPA Haul Road
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Figure 3. Land Use within Three Kilometers
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Workgroup4 as developed by the Texas Commission on Environmental Quality and
outlined in the six steps below:
Step 1: The adjusted width of the “road” was calculated as the actual road width plus 6 meters. The additional width represents turbulence caused by the vehicle as it moves along the road. Step 2: The number of volume sources was calculated by dividing the length of the road by the adjusted width. This was the maximum numer of volume sources modeled. Step 3: The height of the volume was set to 1.7 times the height of the vehicle generating the emissions. Step 4: The initial horizontal sigma for each volume was calculated by dividing the adjusted width by 2.15. Step 5: The initial vertical sigma was calculated by dividing the height of the volume determined in Step 2 by 2.15. Step 6: The release point height was calculated as the height of the volume divided by two. This point is in the center of the volume.
Flares There will also be flares at the facility: ground flares and elevated, candlestick flares.
Several of the flares will only be operated during periods of malfunction. Malfunction
emissions are not required to be modeled per 40 CFR Part 51 Appendix W. Therefore,
only the emissions associated with the pilot lights were modeled for the flares that are
used for malfunction. However, flares used for startup or shutdown (i.e., non-
emergency flaring) were model using the SCREEN3 proceedures developed by the
EPA as described by the Ohio EPA5. The effective stack height (H, in meters) was
computed as a function of heat release rate according to the following equation, where
Q is the heat release rate of the flare in MMBty/hr:
Hequivalent = Hactual + 0.944(Q)0.478
The effective flare diameter (d, in meters) was computed as a function of heat release
rate according to the following equation, where Q is the heat release rate of the flare in
MMBty/hr:
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dequivalent = 0.1755(Q)0.5
An exit temperature of 1273°K and velocity of 20 m/sec was assumed.
All source locations were based upon a NAD83, UTM Zone 17 projection. The source
elevations for all Shell sources were determined from facility survey data, not from
AERMAP.
Good Engineering Practice Stack Height Analysis A Good Engineering Practice (GEP) stack height evaluation was conducted to
determine appropriate building dimensions to include in the model and to calculate the
GEP formula stack height used to justify stack height credit for stacks to be constructed
in excess of 65m. Procedures used were in accordance with those described in the
EPA Guidelines for Determination of Good Engineering Practice Stack Height
(Technical Support Document for the Stack Height Regulations-Revised).6 GEP
formula stack height, as defined in 40 CFR 51, is expressed as GEP = Hb + 1.5L, where
Hb is the building height and L is the lesser of the building height or maximum projected
width. Building/structure locations were determined from a facility plot plan. The
structure locations and heights were input to the EPA’s Building Profile Input Program
(BPIP-PRIME) computer program to calculate the direction-specific building dimensions
needed for AERMOD. The Shell facility plot plan is shown in Figure 4. A three
dimensional rendering of the facility is shown in Figure 5.
Merged Exhaust Streams The three combustion turbines will each vent to an individual flue contained within a
common stack. For the modeling analysis, the exhaust streams from the turbines were
“merged,” such that the exhaust streams from the three units are emitted through a
single flue in a combined stack. Such merging is permissible under the GEP
regulations and is not considered a “dispersion technique” prohibited under 40 CFR §
52.21(h)(1)(ii) and § 51.100(hh).
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Figure 4. Shell Facility Plot Plan
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Figure 5. Shell Three Dimensional Plot Plan (View from SW)
A dispersion technique is “any technique which attempts to affect the concentration of a
pollutant in the ambient air by … [i]ncreasing final exhaust gas plume rise by
manipulating source process parameters, exhaust gas parameters, stack parameters,
or combining exhaust gases from several existing stacks into one stack; or other
selective handling of exhaust gas streams so as to increase the exhaust gas plume
rise.” 40 CFR § 51.100(hh)(1)(iii).
Specifically excluded from the prohibition is “[t]he merging of exhaust gas streams
where … [t]he source owner or operator demonstrates that the facility was originally
designed and constructed with such merged gas streams.” 40 CFR § 51.100(hh)(2)(ii).
Because the original design and construction of the facility will include merged gas
streams, the exclusion applies; merging in these circumstances is not a dispersion
technique and the modeling must take into account the merged flue.
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The merged flues were modeled by calculating an equivalent diameter of the merged
flues. The equivalent diameter was based the following formula:
Square root of (the total area of the combined flues divided by 3.14) x 2.
The stack velocity was calculated based upon the combined flow and the total area of
the combined flues.
4.4 Ambient Monitoring and Monitored Background Data Pursuant to 40 CFR 52.21(i)(5), as adopted at 25 Pa. Code Chapter 127, Subchapter D,
requirements for ambient monitoring data may be waived by the permitting authority if
projected increases in ambient concentrations due to the project are less than the
Significant Monitoring Concentrations. As shown in Section 6.2 herein, the Shell project
would qualify for such a waiver with respect to all listed pollutants because the
maximum modeled impacts are less than the Class II SILs and, therefore, also less than
the Significant Monitoring Concentrations ("SMC") (please note there is no SMC for NO2
for the 1-hour average). In light of the decision of the D.C. Circuit Court of Appeals
Sierra Club v. EPA last year,7 Shell has elected not to request such a waiver. However,
it should be noted that the PSD regulations in effect for this project would not require
ambient monitoring data.
The Monitoring Guidelines, other EPA interpretive guidance, and EPA administrative
decisions clarify that representative, existing air quality monitoring data may be used to
fulfill the PSD pre-construction monitoring requirements and establish the background
concentrations needed for assessing NAAQS compliance, in lieu of monitoring data
from the area in the vicinity of the proposed source or modification. EPA’s Monitoring
Guidelines suggest specific criteria to determine representativeness of off-site data:
quality of the data, currentness of the data, and monitor location.
There are two ambient monitors in close vicinity (within 10km) of the proposed Shell site
(Figure 6). The Brighton Township monitor, on Sebring Road (AQS #42-007-0005), is
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Figure 6. Ambient Air Quality Monitors in the Vicinity of the Shell Site
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located just across the river from the site to the north. However, only SO2 and O3 are
monitored at this location. The second monitor is located in Beaver Falls (AQS #42-
007-0014). PM10, PM2.5, NO2, O3, and SO2 are monitored at this location. There are
no CO monitors in Beaver Co (Please note that CO was monitored at the Beaver Falls
site. However, the CO monitor was inactivated in 2008). The nearest CO monitor is the
Pittsburgh monitor in Allegheny County (AQS# 42-003-0010).
RTP proposes to use the most recent available, quality assured PM10 and NO2 data
(2010-2012) from the Beaver Falls monitor to establish representative background
concentrations. This monitor best represents background concentrations as it is the
closest monitor with data for the pollutants of concern and is in the vicinity of the site. It
is also not likely significantly influenced by the localized source impacts of the AES and
First Energy facilities. CO from the Pittsburgh monitor will also be used. The proposed
background data are presented in Tables 1 and 2. The proposed existing monitoring
data satisfy the criteria provided in EPA’s Ambient Monitoring Guidelines8 as being
representative of the Shell site and should therefore be allowed for use.
A range of monitored background NO2 values that consider seasonal and diurnal
variation was used to assess compliance with the 1-hr NAAQS. These seasonal values
reflect the three year average (2010-2012) of the 98th percentile value by hour of day
and by season. These seasonal NO2 values were added to the modeled value within
AERMOD.
Monitor Location The Beaver Falls monitor is located less than 9 kilometers from the proposed Shell
facility. It is also located in an adjacent river valley, absent the influence of any major,
localized industry. While the CO monitor is more distant at 40km, measurements from
this site should provide a conservative representation of the air quality in the vicinity of
the Shell site.
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Table 1. Proposed Background Concentrations 2010-2012
Pollutant Averaging Time
Maximum Monitored Value
(µg/m3) Monitor Site
Location PM10 24-hour 78.0 Beaver Falls NO2 Annual 21.5 CO 1-hour 4571 Pittsburgh 8-hour 3086
Table 2. Beaver Falls 98% Hourly NO2 (ppb) By Season and Hour of Day
Model Ending Hour Winter Spring Summer Fall
01 32.0 31.0 23.0 25.3 02 34.7 32.3 23.3 25.7 03 33.7 31.7 22.7 25.0 04 32.7 33.3 22.3 24.7 05 33.3 32.0 21.7 24.0 06 33.3 32.7 22.3 25.0 07 34.0 34.7 23.7 25.0 08 35.0 34.0 23.0 26.0 09 37.3 33.3 23.7 29.0 10 36.3 33.0 25.0 31.7 11 35.0 31.7 18.7 30.0 12 33.3 24.3 13.7 25.3 13 30.7 21.7 10.3 20.7 14 28.3 16.3 10.3 16.3 15 27.7 15.7 10.0 15.3 16 29.0 15.3 9.0 16.0 17 28.0 16.0 7.7 21.7 18 29.3 16.7 10.7 27.3 19 31.3 21.3 13.3 26.0 20 31.0 27.7 15.7 26.3 21 30.3 28.3 18.3 26.0 22 32.7 29.7 22.7 28.0 23 32.7 31.0 22.0 27.3 24 32.7 31.3 20.7 25.3
Note: Maximum 1-hr NO2 value is 37.3 ppb or 70.4 µg/m3.
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Data Quality The existing ambient monitors were established and air quality data were collected as
part of EPA's ambient air quality monitoring network. Federal regulations at 40 CFR
Part 58, Appendix A, require that these data meet quality assurance ("QA")
requirements. The existing ambient air quality data also meet the data quality
requirements of Section 2.4.2 of the Monitoring Guidelines. The QA requirements for
monitoring criteria pollutants at PSD sites are very similar to the QA requirements for
monitoring sites for NAAQS compliance. The data presented in Section 5.3 meet the
data quality criterion.
Currentness of Data The Monitoring Guidelines suggest that air quality monitoring data used to meet PSD
data requirements should be “collected in the 3-year period preceding the permit
application.”9 The data presented herein are current and meet this criterion.
Relevant EPA Decisions Recent actions by U.S. EPA, including permit approvals by Regional Offices and
decisions by the Environmental Appeals Board, support reliance on regional monitors to
fulfill the one year PSD ambient air quality monitoring requirements for NO2, PM10, and
CO in the Shell application. Several relevant actions are summarized below, beginning
with the final PSD permit decision recently issued by U.S. EPA for Energy Answers
Arecibo, LLC (“EA”). In that matter, the agency stated:
EA provided EPA with monitoring data for all criteria pollutants subject to PSD even though those pollutants were less than the Significant Monitoring Concentrations in 40 C.F.R. 52.21(i)(5)(i)…. Energy Answers requested approval to use existing data for all of the criteria pollutants instead of obtaining new, site-specific monitoring data in May and September 2011. EPA approved this request based on the fact that representative existing ambient monitoring data was provided. The existing data that is available was collected at sites that have higher concentrations than Arecibo since they are located in more industrial areas, such as Catano, Barceloneta, and San Juan (see Response to Comment 3 in this section for further details). *
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* [The Monitoring Guidelines document] allows the use of monitors in other geographical areas provided they are representative. In this case, the monitors are located in more industrialized area so they represent a conservative estimate. EPA allowed the use of these monitors for background in this case since these monitors measure more than the “natural, minor or major distant sources” in Arecibo (Guideline on Air Quality Models section 8.) They also measure concentrations from other large sources.10
The decision by U.S. EPA to approve the use of existing, representative monitoring data
from regional monitors in the EA permit review was made notwithstanding the fact that
complex terrain exists within 5 km of the EA project site.11 These regional monitors are
located in industrialized areas and are outside the project’s maximum impact area –
more than 70 km from the EA project site in the case of the San Juan monitoring data
used for PM10 and CO. Moreover, none of the data from the regional monitors were
gathered in the year preceding the submittal of the permit application; the NO2 and SO2
data were collected by EA outside the three-year time window suggested by the
Monitoring Guidelines. U.S. EPA’s decision with respect to EA supports Shell’s reliance
upon data from the selected off-site monitoring locations; the data relied upon by Shell
are arguably more representative and more current than the data accepted by the
agency in that matter.
The EA permit decision is consistent with long-standing EPA policy that, with respect to
approval of representative, existing ambient monitoring data from regional monitors,
“the guidelines are very broad and leave much to the discretion of the permitting
authority.”12 Notably, EA was the first PSD permit approval from U.S. EPA since the
decision in Sierra Club v. EPA, vacating the SMCs, making the approach in the EA
permit review especially informative. The agency’s determination in the EA matter
confirms that the court’s decision in Sierra Club v. EPA cannot be read to narrow the
agency’s broad discretion on this PSD requirement. Over the 25 years since U.S. EPA
issued the Monitoring Guidelines, the agency has consistently used its discretion to
accept existing, representative ambient air quality data in permit decisions and formal
administrative decisions. More examples follow:
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• In Hibbing Taconite, the U.S. EPA Administrator determined that the permitting
authority acted within its discretion in determining that the project site was not in
an area of multisource emissions, as that term is used in the Monitoring
Guidelines, although “there are eleven SO2 sources within 65 kilometers of [the
project site].”13 On the basis of this determination, the agency approved the use
of existing, representative ambient monitoring data.
• In Encogen Cogeneration, the U.S. EPA Environmental Appeals Board
determined that the permitting authority acted within its discretion in approving
the use of existing, representative ambient monitoring data from a regional
monitor located approximately 70 km from the project site because “the choice of
appropriate data sets for the air quality analysis is an issue largely left to the
discretion of the permitting authority” and “[t]he use of background data with
higher pollution concentrations, in essence, provides an additional margin of
safety for future air quality at the site.”14
• In support of its decision to issue a PSD permit for Shell’s Chukchi Sea
Exploration Drilling Program, U.S. EPA Region 10 approved the use of ambient
monitoring data from a regional monitor located more than 100 km from the
project site. The agency justified this decision on the basis that it would be
inconvenient to install, operate, and maintain ambient air quality monitoring
equipment near the project site and because “[m]onitoring data from an onshore
location near a village or other onshore sources is expected to be conservative
when compared to monitoring data that would be collected miles offshore
because onshore data will be more influenced by the local emission sources.”15
• In support of its decision to issue a PSD permit for the Diamond Wanapa project,
U.S. EPA Region 10 waived the preconstruction ambient monitoring
requirements for all pollutants other than PM10. For PM10, the agency approved
the use of ten-year-old data from a regional monitor located approximately 24 km
from the project site. The agency did not document any analysis of whether the
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area includes complex terrain or is an area of multisource emissions. With
respect to spatial representativeness, the agency’s description of its analysis, in
its entirety, is as follows:
With regard to monitoring location, the existing data should be representative of three types of areas: (1) the location(s) of maximum concentration increase from the proposed source or modification; (2) the location(s) of the maximum air pollutant concentrations from existing sources; and (2) the location(s) of the maximum impact area. See Ambient Monitoring Guidelines at p.6. EPA has determined that this factor is satisfied because both areas are rural, have similar topography, have similar land use and climate, and are located in the same airshed.16
• In support of its final PSD permit decision for the Bonanza Power Plant in 2007,
U.S. EPA Region 8 approved as representative the use of ambient monitoring
data from the period 1991-1993, more than ten years prior to permit application
submittal.17
• In support of its final PSD permit decision for the Pio Pico Energy Center in 2012,
U.S. EPA Region 9 waived the preconstruction ambient monitoring requirements
for all pollutants other than NO2 and PM2.5.18 For both NO2 and PM2.5, the
agency approved as representative the use of existing ambient monitoring data
from a regional monitoring site located 15 km from the project site; in granting
this approval, the agency dismissed as not representative of background
concentrations the monitoring data from the Otay Mesa monitor located only
2 km from the project site, due to localized impacts from mobile sources at that
monitor.19 In responding to public comments, the agency also made clear that
the considerations set forth in the Modeling Guidelines afford discretion to the
permitting authority:
[W]e note that guidance documents on representativeness of data identify important factors to consider in evaluating the need for site-specific data collection, but do not dictate exactly when site-specific data must be used rather than data from nearby locations. * *
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As a result, the analyses conducted in this case using the Chula Vista data are consistent with the principles from the 1987 Guidelines cited by the commenter and achieve the objectives reflected in these Guidelines in an alternative manner. Furthermore, the use of modeled emissions from nearby sources such as the Otay Mesa Power Plant, rather than background data in the immediate vicinity of those sources, is a more conservative approach to determining NAAQS compliance, because such modeling takes into account potential emissions, which could be higher than the actual emissions from the sources at issue that would be reflected in the background data.20
The U.S. EPA’s Environmental Appeals Board recently upheld this waiver, more
than six months after the court’s decision in Sierra Club v. EPA, which manifests
a determination by the agency that the Significant Monitoring Concentrations and
associated exemption remain in effect. 21
PADEP has broad discretion to accept the monitoring data provided for NO2, PM10, and
CO in Shell’s permit application. The off-site data relied upon by Shell to fulfill the
ambient air quality monitoring requirement for this PSD application satisfies the criteria
outlined in EPA’s Monitoring Guidelines: data quality, currentness of the data, and
location of the monitors, and represents the ambient air quality in the area of Shell’s
proposed project. Representative, existing data provided for NO2, PM10, and CO fulfill
the one year pre-construction data requirement.
4.5 Receptor Data Modeled receptors were placed in all areas considered as "ambient air" pursuant to 40
CFR 50.1(e). Ambient air is defined as that portion of the atmosphere, external to
buildings, to which the general public has access. Approximately 22,700 receptors
were used in the AERMOD 1-hr NO2 significant impacts analysis. The receptor grid
consists of four cartesian grids and receptors spaced at 25m intervals along the facility
fenceline and the railroad that transects the facility.. The first cartesian grid extended to
approximately 1km from the fence in all directions. Receptors in this region were
spaced at 50m intervals. The second grid extended to 3km. Receptor spacing in this
region was 100m. The third grid extended to 10km with a spacing of 500m.
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The fourth grid extended to 50km with a receptor spacing of 1,000m. Receptors with
flagpole elevations were also placed along the Highway 376 bridge east of the facility.
The receptor grid was designed such that maximum facility impacts fall within the 50m
spacing of receptors. Such an expansive grid will be used as significant 1-hr NO2
concentrations extended to a distance of 43km from the proposed facility.
The receptor grid spacing is presented in Table 3.
Table 3. Receptor Grid Spacing
Receptor Spacing (m) Distance from Facility
Fence (m) 50 1,000
100 3,000 500 10,000
1,000 50,000 The Shell facility will be located in western Pennsylvania. Terrain within 10km of the
site is gently rolling; however, there is terrain in excess of stack top elevation. Receptor
elevations and hill height scale factors were calculated with AERMAP (11103). The
elevation data was obtained from the USGS 1 arc second National Elevation Data
(NED) obtained from the USGS. Locations were based upon a NAD83, UTM Zone 17
projection. The near-field receptor grid is presented in Figure 7.
4.6 Meteorological Data
Data Selection and Representativeness
The 2006-2010, 5-year sequential hourly surface meteorological data collected at the
First Energy Beaver Valley Nuclear Generating Station (Beaver Valley) and upper air
data from the Pittsburgh International Airport (KPIT, WBAN 94823) were used in the
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Figure 7. Shell Near-field Receptor Grid
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analysis. The First Energy surface data were collected as part of a continuous data
collection program required by the U.S. Nuclear Regulatory Commission (NRC). The
meteorological data adequately represent atmospheric boundary layer conditions within
the Shell analysis domain for AERMOD to properly characterize the transport and
dispersion of the Shell emissions plumes. A profile base elevation of 228.6m was
employed which corresponds to the base elevation of the Beaver Valley tower.
The First Energy station is located approximately 8km downstream of the proposed
Shell site, also on the Ohio River. The Beaver Valley meteorological station and
proposed Shell site also share a similar orientation in relation to the Ohio River. As can
be seen in Figure 8, the river flows from the northeast to southwest relative to both the
proposed Shell site and the Beaver Valley meteorological station. The topography is
also similar at each location. The wind patterns are therefore likely similar at each
location (see the wind rose Figure 9). Wind speed, direction and standard deviation of
the horizontal wind direction are measured at three levels at the Beaver Valley station
(10.7m, 45.7m, and 152.4m). Temperature is also measured at the 10.7m level. These
three levels provide adequate representation of plume behavior at the various release
heights to be seen at the Shell site.
The Pittsburgh International Airport is located approximately 21km southeast of the
facility (Figure 10). Station pressure, cloud cover, and twice daily sounding data from
Pittsburgh were used. These meteorological parameters are of synoptic scale and are
adequately representative of the Beaver Valley area.
According to the EPA’s AERMOD Implementation Guide22, the surface characteristics
should be similar for the meteorological station and the study site. RTP compared the
surface characteristics at the First Energy station and the proposed site. The
AERSURFACE program was run to determine the characteristics for comparison. The
results of the surface roughness comparison, by season, are shown in Figure 11. As
can be seen, the surface characterisitics values for the two sites, when compared on a
seasonal and sector basis, are similar.
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Figure 8. First Energy Meteorological Tower Location Relative to Shell
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Figure 9. Beaver Valley Windrose 2006-2010
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Figure 10. Pittsburgh International Airport Location Relative to Shell
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Figure 11. Meteorological Data Representativeness Analysis Results
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Data Processing The meteorological data were provided to RTP Environmental by the PADEP. The
PADEP processed the Beaver Valley surface data, Pittsburgh International Airport
(KPIT) surface data and KPIT upper air data using the meteorological preprocessor
AERMET (Ver. 12345). Since these data were provided to RTP Environmental, the
EPA issued a newer version of AERMET (Ver. 13350). In response RTP Environmental
re-ran the PADEP's AERMET Stage 3 inputs using the more recent version of
AERMET. In AERMET Stage 1, KPIT surface meteorological data in the Integrated
Surface Data (ISD) format were extracted. KPIT upper air meteorological data in the
Forecast Systems Laboratory (FSL) format were also extracted.
Also, the MODIFY keyword was entered to fill missing temperatures in the upper air
data with interpolated values. In AERMET Stage 3, values of the surface characteristics
(noon-time albedo, Bowen ratio, and surface roughness length) representative of the
Beaver Valley surface meteorological site, were entered.
These surface characteristics values were calculated by AERSURFACE 13016 using
USGS National Land Cover Data ("NLCD") for 1992. The following options were
selected in AERSURFACE: default 1-km radius and default twelve 30-degree sectors
for surface roughness length, seasonal temporal resolution, non-airport site and non-
arid region. AERSURFACE was executed for each surface moisture condition
(average, dry, and wet), assuming both no continuous snow cover and continuous snow
cover during the winter (i.e., AERSURFACE was executed six times). AERMET
Stage 3 was then executed for each set of surface characteristics to produce six (6)
surface (.sfc) files. The final AERMET surface file was assembled by season based on
actual estimates of surface moisture condition and snow cover during the
meteorological data period. Estimates of surface moisture condition were based on
precipitation data for Pennsylvania Climate Division 9. Snow cover was based on
National Climatic Data Center (NCDC) Local Climatological Data from KPIT.
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5.0 MODELING METHODOLOGY
5.1 Pollutants Subject to Review Only the regulated NSR pollutants whose emissions increases exceed the PSD SERs
and are therefore subject to PSD review were evaluated in the modeling analysis.
5.2 Turbine Load/Operating Conditions The combustion turbines will occasionally operate at a reduced load. Therefore, a
range of load conditions and operating modes representing potential unit operation were
evaluated to identify the condition which results in the worst-case impact for each
averaging period of concern. Three load conditions were evaluated for each turbine:
100%, 75%, and 45%. In addition, three turbine operating modes were evaluted: three
turbine mode, two turbine mode, and single turbine mode. A unit (i.e., 1 lb/hr) emission
rate was assumed to represent the 100% load condition for each turbine and the
emissions and flows for the other loads and operating modes scaled from the 100%
load condition. The condition resulting in the worst-case impacts was carried forward
for the remainder of the analysis.
5.3 Furnace Operating Conditions The furnaces will also have different modes of operation for short durations. Only the
pollutant emission rate will be affected by the operational model. When in decoking
mode, the CO emission rate will be elevated. Since only one furnace will be in decoking
mode at any point in time, the elevated, short-term CO emission rate was only assigned
to a single furnace. The NOx control on the furnaces may also have a reduction in short
term performance due to process fluctuations. Only two furnaces will operate in this
mode at any one time. It was therefore necessary to identify the furnaces with the worst
case short-term impacts. Each furnace was modeled with a unit emission rate. The two
furnaces that generated the worst case impacts were assigned these two operating
modes.
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5.4 Significant Impact Analysis The criteria pollutant air quality analysis was conducted in two phases: an initial or
significant impact analysis, and a refined phase including an increment analysis and a
NAAQS analysis. In the significant impacts analysis, the calculated maximum impacts
were determined for each pollutant with a net emissions increase that exceeds the PSD
significant emission level. These impacts determine the net change in air quality
resulting from the proposed project. Maximum modeled concentrations were compared
to the pollutant-specific significance levels for all pollutants and averaging times except
for the 1-hr NO2 impact. The five year average of the maximum impact at each receptor
was used to assess significance for the 1-hr NO2 average.
Pollutants with impacts that exceed the ambient air significance levels, as defined in
40 CFR 51.165, were included in both the NAAQS and increment analyses. In these
latter analyses, impacts from the Shell facility were added to concentrations calculated
from other nearby sources, plus a regional background concentration. The resultant
total concentration was compared to the NAAQS and increments to determine
compliance. The PSD Class II Significant Impact Levels are listed in Table 4.
Five years of meteorological data were used in the significant impact analysis. The
maximum distance to significant impact was determined for each pollutant and
averaging period. The maximum concentration was used to determine significance. 5.5 NAAQS Analysis Following the determination of significant impacts, a refined air quality analysis to
determine compliance with the NAAQS was conducted. A refined analysis was
conducted to determine compliance with the NAAQS only for the 1-hr NO2 standard as
this is the only pollutant and averaging time modeled as having significant impacts in
the initial analysis. Please note that no PSD increment evaluation was required as
there is no PSD increment for NO2 for the 1-hr average and the maximum annual NO2
impact was determined to be less than the SIL.
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Table 4. PSD Class II Significant Impact Levels
Pollutant Averaging Time PSD Class II Significant Impact Levels (µg/m3) 1
PM10 24-hour 5.0Annual 1.0
NO2 1-hour 7.5 2
Annual 1.0CO 1-hour 2000
8-hour 5001. Please note that on January 22, 2013, the US Court of Appeals for the District of Columbia Circuit Court granted a
request from the EPA to vacate and remand the PM2.5 SILs. EPA has stated that as long as the differencebetween the background monitored PM2.5 value and the NAAQS is greater than the SIL, the SIL can still be used inevaluating significance (see the March 3, 2013, "Draft Guidance for PM2.5 Permit Modeling"). The PADEP isfollowing this guidance for PM2.5 as well as other pollutants. The difference between Beaver Falls backgroundvalues and the NAAQS were evaluated and determined to be greater than the SILs (Please see Tables 1 & 2).
2. Please also note that there is no 1-hr NO2 SIL promulgated at 40 CFR 51.165. Consistent with to the June 28,2010 EPA Policy Memorandum from Anna Marie Wood to the Regional Air Directors, an interim 1-hr NO2 SIL of 4ppb (7.5µg/m3) has been adopted by the PADEP (see the December 1, 2010 Memorandum from Andrew Fleck tothe Regional Air Program Managers).
The receptors modeled in the 1-hr NO2 NAAQS analyses were limited to those showing
a significant impact in the initial analysis. Each source's potential emission rate will be
used. Five years of meteorological data were again used in the 1-hr NO2 NAAQS
analysis.
Nearby Source Inventory
Off-site sources were included in the 1-hr NO2 NAAQS analysis. Pursuant to the
March 1, 2011 Clarification Memorandum (see page 16 of reference no. 8), only
sources within 10km of the proposed Shell facility were considered for inclusion in the 1-
hr NAAQS analysis. The PADEP provided RTP Environmental with an inventory of
sources located within 10km of the proposed Shell site.23 The inventory included the
potential hourly emission rates that were calculated pursuant to Table 8-2 in the
“Guideline on Air Quality Models” (40 CFR 51, Appendix W).
NAAQS Compliance Assessment
Appropriate ambient background concentrations (as discussed in more detail in Section
4.3) were then added to the modeled concentrations to assess NAAQS compliance.
The five year average of the 98th percentile maximum daily 1-hr NO2 modeled value
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was added to the three year average of the 98th percentile NO2 monitor value by
season and hour of day within AERMOD. The resultant concentration was compared to
the 1-hr NO2 NAAQS. The methodology for combining NO2 background concentrations
in the 1-hour cumulative analysis is based upon the methodology outlined in the March
1, 2011 Additional Clarification memorandum.24
As discussed below, modeled exceedances of the 1-hr NO2 NAAQS were identified.
These modeled exceedences are due to existing sources in the vicinity of the proposed
Shell site. Shell employed the EPA's post-processor "MAXDCONT" to demonstrate that
the proposed project does not significantly contribute to an existing modeled
exceedance. This demonstration is receptor and averaging time specific. 5.6 NO2 Analyses Following recent USEPA guidance, the NO2 modeling analyses used the recommended
three tier screening approach. Initially, Tier 1 was employed with the conservative
assumption that 100% of the available NOx converts to NO2. The annual NO2 impact
under this assumption exceeded the SIL. The Tier 2 (Ambient Ratio Method, or ARM)
was therefore employed with the EPA recommended NOx to NO2 conversion factor of
0.75 for the annual average and 0.80 for the hourly average. Tier 3 was employed to
assess the 1-hr NO2 NAAQS. Tier 3 accounts for the chemical reactions that convert
NOx to NO2 in the presence of ozone.
Tier 3 Option There are two Tier 3 methods currently available in AERMOD for simulating the
conversion of NOx to NO2: the Ozone Limiting Method (OLM) and the Plume Volume
Molar Ratio Method (PVMRM). Each method is considered to be an alternative model,
use of which must be formally approved prior to use. Shell has employed PVMRM. A
formal request has been submitted to PADEP that addresses the five criteria of
Section 3.2.2(e) of 40 CFR 51 Appendix W. PADEP also requested formal approval
from EPA Region 3. Approval was received on April 21, 2014.
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The EPA's default NO2/NOx in stack ratio of 0.50 has been employed for all sources
except for the First Energy Bruce Mansfield and the AES Beaver Valley sites. A
NO2/NOx in stack ratio of 0.05 was employed for the uncontrolled emissions from the
First Energy coal boilers. This value was used based upon footnote "c" of Table 1.1-3
in AP-42, which states that 95% or more of NOx present in combustion exhaust will be
in the form of NO, the rest is NO2. An in stack ratio of 0.17 was employed for the AES
Beaver Valley coal boilers due to the preferential removal of NO2 due to the selective
non-catalytic reduction ("SNCR") employed on these units. In addition, a NO2/NOx
equilibrium ratio of 0.90 was employed.
Hourly ozone concentrations from the Sebring monitor, concurrent with the 2006-2010
meteorological data period, were employed. Missing data were filled with data from the
Tomlinson Road O3 monitor in southwestern Beaver County. The month of March is
missing for several years for both the Sebring and Tomlinson Road monitors. These
data were filled with data from the Harrison and Lawrenceville O3 monitors in Pittsburgh.
Intermittent Emissions Emissions from sources that emit intermittently (i.e., emergency generators, firewater
pumps, flares, and certain furnace operating scenarios, and startups and shutdowns)
were modeled in the 1-hr NO2 analysis pursuant to the March 1, 2011 EPA guidance.
Pursuant to this guidance, any source with emissions that do not have the potential to
contribute significantly to the annual distribution of the daily maximum concentrations
will either be excluded from the analysis or the emissions will be based on an average
hourly rate, rather than the maximum hourly rate. Sources that are not likely to
contribute include those with emission duration of less than 24-hours and with
operational frequency of less than seven occurrences per year.
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6.0 RESULTS
Attachment B to this report provides the model summary output as well as contour plots
of the results. AERMOD input and output files, including the BPIP-PRIME files, are
included on the enclosed CD.
6.1 Turbine Load Analysis Results The results of the load analysis are presented in Table 5. As shown, the 100% load
scenario with three turbines operational was found to generate the highest impacts for
the turbines. The 100% load case was therefore used in the remainder of the modeling
analysis.
6.2 Furnaces Operating Condition Results The results of the worst-case furnace analysis are presented in Table 6. As shown, the
Furnace Nos. 1&2 were found to generate the highest short-term impacts. These two
furnaces were therefore assigned the elevated CO and NOx emissions associated with
the short-term furnace operating modes.
6.3 Significant Impact Analysis Results The Class II and Class I significant impact analysis results are presented in Table 7 and
Table 8, respectively. As shown in Table 7, the project is expected to result in
significant impacts for NO2 for the 1-hr average. A more refined NAAQS analysis was
therefore conducted for NO2 for the 1-hour averaging period. Please note that there is
no PSD increment for NO2 for the 1-hour average. Therefore, no increment analysis
was required. Please also note that the significant monitoring concentration levels were
not predicted to be exceeded for any pollutant. As shown in Table 8, the project will not
result in a significant impact at the closest Class I area, the Otter Creek Wilderness
Area. Therefore, no additional Class I increment modeling was conducted.
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Table 5. Load Analysis Results
Averaging Period Source Name
Modeled Concentration
(μg/m3) Source Description
1-hr
3CT100 3.13 Three turbines, 100% load 2CT100 2.83 Two turbines, 100% load 1CT100 2.19 One turbine, 100% load 1CT75 2.02 One turbine, 75% load 1CT45 1.78 One turbine, 45% load
24-hr
3CT100 0.53 Three turbines, 100% load 2CT100 0.46 Two turbines, 100% load 1CT100 0.38 One turbine, 100% load 1CT75 0.36 One turbine, 75% load 1CT45 0.37 One turbine, 45% load
8-hr
3CT100 1.15 Three turbines, 100% load 2CT100 0.98 Two turbines, 100% load 1CT100 0.75 One turbine, 100% load 1CT75 0.81 One turbine, 75% load 1CT45 0.77 One turbine, 45% load
Annual
3CT100 0.040 Three turbines, 100% load 2CT100 0.040 Two turbines, 100% load 1CT100 0.039 One turbine, 100% load 1CT75 0.040 One turbine, 75% load 1CT45 0.039 One turbine, 45% load
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Table 6. Worst Case Furnace Analysis Results
Averaging Period Source Name
Modeled Concentration
(μg/m3) Source Description
1-hr
EC#1 1.81 Ethane Cracking Furnace #1 EC#2 1.80 Ethane Cracking Furnace #2 EC#3 1.69 Ethane Cracking Furnace #3 EC#4 1.48 Ethane Cracking Furnace #4 EC#5 1.52 Ethane Cracking Furnace #5 EC#6 1.45 Ethane Cracking Furnace #6 EC#7 1.45 Ethane Cracking Furnace #7
24-hr
EC#1 0.18 Ethane Cracking Furnace #1 EC#2 0.18 Ethane Cracking Furnace #2 EC#3 0.18 Ethane Cracking Furnace #3 EC#4 0.18 Ethane Cracking Furnace #4 EC#5 0.18 Ethane Cracking Furnace #5 EC#6 0.17 Ethane Cracking Furnace #6 EC#7 0.17 Ethane Cracking Furnace #7
8-hr
EC#1 0.40 Ethane Cracking Furnace #1 EC#2 0.40 Ethane Cracking Furnace #2 EC#3 0.39 Ethane Cracking Furnace #3 EC#4 0.39 Ethane Cracking Furnace #4 EC#5 0.39 Ethane Cracking Furnace #5 EC#6 0.39 Ethane Cracking Furnace #6 EC#7 0.38 Ethane Cracking Furnace #7
Table 7. Class II Significant Impact Analysis Results
Pollutant Averaging
Period
Maximum Modeled Impact (μg/m3)
PSD Significant
Class II Impact Level
(μg/m3)
Significant Monitoring
Concentration (μg/m3)
Maximum Distance to a Significant Impact (km)
PM10 24-hr 4.14 5.0 10 NA
Annual 0.80 1.0 N/A NA
NO2a 1-hr 44.2 7.5 N/A 43.0
Annual 0.79 1.0 14 N/A
CO 1-hr 434 2000 N/A N/A
8-hr 169 500 575 N/A aNO2 impacts include ARM of 0.75 for the annual average and 0.80 for the 1-hr average. N/A – not applicable
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Table 8. Class I Significant Impact Analysis Results
Pollutant Averaging
Period
Maximum Modeled Impact (μg/m3)
PSD Significant
Class I Impact Level
(μg/m3)
PM10 24-hr 0.21 0.30
Annual 0.01 0.20
NO2a Annual 0.02 0.10
aNO2 impact includes ARM of 0.75 for the annual average.
6.4 NAAQS Analysis Results Following the determination of significant impacts, an analysis was conducted to assess
compliance with the 1-hr NO2 NAAQS. All major and minor sources located within
10km of the proposed facility were modeled in conjunction with the proposed Shell
facility. Background NO2 concentrations were added to the model results to assess
compliance. Evaluation of compliance with the 1-hour NO2 NAAQS was based on the
five-year average of the 98th percentile of the annual distribution of daily maximum 1-
hour concentrations.
The results of the NAAQS analysis are presented in Table 9. As shown, the model
indicates that 1-hour NO2 concentrations are in excess of the NAAQS. However, the
modeled violations are attributable to existing sources that were modeled as part of the
off-site inventory and not the proposed Shell facility. The Shell contribution to each
modeled concentration in excess of the NAAQS was determined using the
"MAXDCONT" option in AERMOD. This option allows for the calculation of the impact
due to Shell consistent in both time and space with each modeled concentration in
excess of the standard. Table 10 presents the ten highest concentrations from Shell at each modeled value in
excess of 188 µg/m3 for the 5 year modeled period. This table also presents the 10
highest overall modeled concentrations. Since the concentrations from the proposed
Shell project are insignificant (i.e., less than 7.5 µg/m3), the proposed project will not
contribute to any existing modeled 1-hr NO2 NAAQS violation.
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Table 9. NAAQS Analysis Results
Pollutant Averaging
Period
Modeled Concentration
(µg/m3)1 Standard (µg/m3) Comment
NO2 1-hour 3644 188 Maximum concentration due to off-site sources. Project impact is insignificant as paired in time and space.
1 Based on the 98th percentile of the annual distribution of maximum daily 1-hour concentrations, averaged across the 5 years of meteorological data modeled. PVMRM was employed for the 1-hr calculations. ARM of 0.75 used to calculate the annual impact.
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Table 10. Shell Contribution to the Modeled 1-hr NO2 NAAQS Exceedences
Receptor Location (UTM X, m)
Receptor Location (UTM Y, m)
Total Modeled Concentration
(µg/m3)a Shell Project
Contribution (µg/m3)Top Ten Concentrations Sorted by Shell Contribution to Existing Violation
557,100 4,503,000 287.90 5.92 557,200 4,503,000 304.85 5.87 556,950 4,502,800 321.35 5.81 557,550 4,503,250 288.38 5.73 557,100 4,502,900 304.45 5.72 557,300 4,502,950 324.83 5.54 558,200 4,503,700 270.31 5.46 557,100 4,502,950 286.72 5.39 557,600 4,503,150 311.87 5.32 557,150 4,503,050 289.25 5.26 Top Ten Concentrations Sorted by Overall Maximum Modeled Concentration554050 4500600 3644.031 0.0006 554050 4500600 3509.551 0.03751 554050 4500600 3275.415 0.00545 554050 4500600 3120.157 0.00035 554050 4500600 3043.719 0.00052 554050 4500600 2852.118 0.0116 554050 4500600 2724.927 0.12449 554050 4500600 2672.093 0.03037 554050 4500600 2589.843 0.19152 554050 4500600 2553.22 0.00065
a Based on the 98th percentile of the annual distribution of maximum daily 1-hour concentrations, averaged over the 5 years of meteorological data modeled. PVMRM was employed for the 1-hr calculations. Only the top 10 receptors, sorted by the project contribution to maximum, are shown in this table. Please refer to the MAXDCONT output on the enclosed CD for a complete listing of all receptors with an impact in excess of 188 µg/m3.
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6.5 Summary and Conclusions
Emissions of regulated pollutants were evaluated in a dispersion modeling analysis.
The modeling demonstrates that the proposed Shell facility will not cause or contribute
to ground level concentrations of any pollutant in excess of the levels designed to
protect human health and welfare. The modeling input and output files are provided on
the attached CD. Model summary results are presented in Attachment B to this report.
The summary results list the model file names associated with each phase of the
analysis.b
b As a general rule, the AERMOD input files have a “dta” extension. The AERMOD output files have a “lst” extension.
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7.0 CLASS II VISIBILITY ANALYSIS The CAA Amendments of 1977 require evaluation of new and modified emission
sources to determine potential impacts on visibility. The maximum increase in hourly
particulate matter and NOX emissions from the proposed Shell facility were used as
input parameters in the visibility analysis. Emissions were evaluated as described in the
EPA Workbook for Plume Visual Impact Screening and Analysis25 to determine potential
contribution to atmospheric discoloration and visual range reduction.
Generally, atmospheric discoloration occurs when NO emissions from combustion
sources react in the presence of atmospheric oxygen to form NO2, a reddish-brown gas.
Another form of atmospheric discoloration may be caused by particulate emissions and
secondary aerosols formed by gaseous precursor emissions. The visual range
reduction (increased haze) is caused primarily by particulate emissions and secondary
aerosols such as sulfates and nitrates.26 Both secondary sulfate and primary particulate
emissions are accounted for in the analysis. Emission of other pollutants do not
materially affect visibility.
U.S. EPA visibility impairment analysis guidelines were followed in conducting the
analysis. The analysis was performed for the Raccoon Creek State Park, located 16km
southwest of the proposed Shell site.
This analysis requires inputs of emission rates (PM and NOX), regional visual range,
distance between the source and the object of study, and worst-case dispersion
parameters (i.e., wind speed and stability). Outputs from the model include:
• Plume contrast against the sky and terrain; and,
• Perceptibility of the plume (Delta E criteria).
Emission rates for PM and NO2 for the analyses were set to 47.9 and 74.6 lb/hr,
respectively. These emissions represent the total facility proposed emissions. The
background visual range was set to 20km, which was determined from Figure 9 of the
VISCREEN manual. The VISCREEN default screening values for Delta E (2.0) and
contrast (0.05) were assumed.
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The results visibility analysis are shown in Table 11. As shown, there should be no
plumes from the Shell facility visible at the Raccoon Creek park. The VISCREEN model
files are provided on the enclosed CD.
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Table 11. Class II Visibility Analysis Results for Raccoon Creek State Park
Viewing Background
Theta (degrees)
Azimuth (degrees)
Distance (km)
Alpha (degrees)
Delta E Green Contrast Criterion Plume Criterion Plume
SKY 10 146 23 23 2 1.565 0.05 0.012 SKY 140 146 23 23 2 0.306 0.05 -0.01 TERRAIN 10 146 23 23 2 0.043 0.05 0.0 TERRAIN 140 146 23 23 2 0.01 0.05 0.0
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8.0 CLASS I AREA IMPACTS 8.1 Class I AQRV Analysis There are three Class I areas located within 300km of the Shell facility.c Each Class I
area is located in excess of 50km from the proposed Shell facility. The FLM’s Q/D
(maximum daily emissions in tons per year over distance in kilometers) method was
used to determine the potential for adverse Air Quality Related Values ("AQRV")
impacts for each Class I area. AQRVs include impacts to Class I area soils, vegetation,
and visibility. The maximum Q/D value was calculated to be 3.9 (Q= 733.7 tpy, D = 189
km for Otter Creek). The Q/D evaluation has been presented to the FLMs. The FLMs
reviewed the Q/D evaluation and have stated that no Class I Air Quality Related Values
(AQRV) evaluation will be required for the proposed Shell facility.27
8.2 Class I Significant Impacts Analysis The air quality impacts at each Class I area within 300km was determined using
AERMOD. An arc of receptors spaced at 1 degree, located in the direction of the
Class I areas, was placed at 50km from the proposed Shell site (Figure 12). The model
results were compared to the proposed Class I significant impact levels (Table 12). As
shown, the impacts are less that the Class I SILs. The proposed facility will not
therefore threaten a Class I increment.
Table 12. Class I Significant Impact Analysis Results
Pollutant Averaging
Period
Maximum Modeled Impact (μg/m3)
Proposed Class I
Significant Impact Level
(μg/m3) % Class I
SIL
PM10 24-hr 0.21 0.30 70%
Annual 0.01 0.20 6%
NO2 Annual 0.02 0.10 21%
c Class I areas are pristine areas (e.g., National Parks and Wilderness Areas) that have been designated by Congress and are afforded a greater degree of air quality protection. All other areas are designated as Class II areas.
Shell Chemical Appalachia LLC Plan Approval Application Beaver County, Pennsylvania Petrochemicals Complex
8-2
Figure 12. Class I Areas Located within Three Hundred Kilometers of Shell and Modeled Receptors
Shenandoah
Shell Facility
Dolly Sods
Otter Creek
Arc or Receptors Spaced at 1 Degree, 50km from Shell
Virginia
Ohio
Pennsylvania
New YorkOntario
West VirginiaMaryland
Delaware
Michigan
Kentucky
New Jersey
®0 68,000 136,000 204,000 272,00034,000Meters
REFERENCES 1. Guidelines on Air Quality Models, (Revised). EPA-450/2-78-027R, Appendix W of 40 CFR Part 51, U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research Triangle Park, North Carolina. November 2005. 2. February 19, 2014 letter from Andrew Fleck, PADEP, to David Keen, RTP Environmental. 3. Auer, Jr., A.H. "Correlation of Land Use and Cover with Meteorological Anomalies." Journal of Applied Meteorology, 17:636-643, 1978. 4. Haul Road Workgroup Final Report, EPA Region 5, December 6, 2011. 5. Engineering Guide #69, Air Dispersion Modeling Guidance. Ohio EPA, Division of Air Pollution Control, 2003. 6. Guideline for Determination of Good Engineering Practice Stack Height (Technical Support Document for Stack Height Regulations (Revised). EPA-450/4-80-023R, U.S. Environmental Protection Agency, June 1985. 7. Sierra Club v. EPA, No. 10-1413, 2013 WL 216018 (Jan. 22, 2013). 8. Ambient Monitor Guidelines for Prevention of Significant Deterioration, EPA-450/4-87-007, USEPA, May 1987. 9. Monitoring Guidelines at p. 9. 10. Responses to Public Comments on the Clean Air Act Prevention of Significant Deterioration of Air Quality Draft Permit for Energy Answers Arecibo, LLC. U.S. EPA Region 2. June 2013. Pages 92-94. 11. PSD Air Quality Modeling Analysis (Revised PM10/PM2.5 Analysis). Energy Answers Arecibo, LLC. Revised October 2011. 12. In the Matter of Hibbing Taconite Co., PSD Appeal No. 87-3, 2 E.A.D. 838 (Adm’r 1989). 13. In the Matter of Hibbing Taconite Co., PSD Appeal No. 87-3, 2 E.A.D. 838 (Adm’r 1989). 14. In re: Encogen Cogeneration Facility, PSD Appeal Nos. 98-22 through 98-24, 8 E.A.D. 244 (EAB 1999). 15. Supplemental Response to Public Comments for Outer Continental Shelf Prevention of Significant Deterioration Permits: Noble Discoverer Drillship. U.S. EPA Region 10. September 2011. Page 63.
16. Response to Public Comments: Diamond Wanapa I, L.P., Wanapa Energy Center. U.S. EPA Region 10. August 2005. Page 12. 17. Final Statement of Basis for Permit No. PSD-OU-0002-04.00: Deseret Power Electric Cooperative, Bonanza Power Plant, Waste Coal Fired Unit. U.S. EPA Region 8. August 2007. Page 155. 18. Responses to Public Comments on the Proposed Prevention of Significant Deterioration Permit for the Pio Pico Energy Center. U.S. EPA Region 9. November 2012. Pages 37-44. 19. Fact Sheet and Ambient Air Quality Impact Report for a Clean Air Act Prevention of Significant Deterioration Permit: Pio Pico Energy Center. U.S. EPA Region 9. June 2012. Pages 28-29. 20. Responses to Public Comments on the Proposed Prevention of Significant Deterioration Permit for the Pio Pico Energy Center. U.S. EPA Region 9. November 2012. Page 43. 21. In re: Pio Pico Energy Center. PSD Appeal Nos. 12-04 through 12-06. August 2, 2013. 22. AERMOD Implementation Guide, EPA, September 27, 2005. 23 . February 6, 2014 email from Alan Binder, PADEP, to Irene Kuo, RTP Environmental. 24. Additional Clarification Regarding Application of Appendix W Modeling Guidance for the 1-hour NO2 National Ambient Air Quality Standard, Memo from Tyler Fox, US EPA, to Regional Air Division Directors, March 1, 2011. 25. Workbook for Plume Visual Impact Screening and Analysis. US EPA, EPA Pub. No. 450/4-88-015. RTP, NC. September 1988. 26. Workbook for Estimating Visibility Impairment. US EPA, EPA Pub. No. 450/4-80-031. RTP, NC. November 1980. 27. February 11, 2014 email from Melanie Pitrolo, US Forest Service, to David Keen, RTP Environmental. February 12, 2014 email from Don Sheperd, National Parks Service, to David Keen, RTP Environmental. February 13, 2014 email from Claire O'Dea, US Forest Service, to David Keen, RTP Environmental.
ATTACHMENT A MODELED SOURCE INPUT DATA
Shell Franklin Model Input Data (NAD83, Zone 17)Point Source (updated 4/11/14)
Source ID Source Description Easting (X) (m)Northing (Y)
(m)
Base Elevation
(ft)Stack
Height (ft)Temperature
(°F)Exit Velocity
(ft/sec)
Stack Diameter
(ft)NO2 (lb/hr) NOx (lb/hr) CO (lb/hr)
PM‐ST (lb/hr)
PM‐LT (lb/hr)
EC#1 Ethane Cracking Furnace #1 555501.14 4502188.87 795.0 280.0 284.0 49.4 8.50 9.300 5.913 52.200 2.480 2.264EC#2 Ethane Cracking Furnace #2 555511.76 4502175.45 795.0 280.0 284.0 49.4 8.50 9.300 5.913 25.085 2.480 2.264EC#3 Ethane Cracking Furnace #3 555527.98 4502157.00 795.0 280.0 284.0 49.4 8.50 6.200 5.913 25.085 2.480 2.264EC#4 Ethane Cracking Furnace #4 555538.60 4502143.59 795.0 280.0 284.0 49.4 8.50 6.200 5.913 25.085 2.480 2.264EC#5 Ethane Cracking Furnace #5 555550.90 4502128.49 795.0 280.0 284.0 49.4 8.50 6.200 5.913 25.085 2.480 2.264EC#6 Ethane Cracking Furnace #6 555563.76 4502115.07 795.0 280.0 284.0 49.4 8.50 6.200 5.913 25.085 2.480 2.264EC#7 Ethane Cracking Furnace #7 555579.42 4502098.86 795.0 280.0 284.0 49.4 8.50 6.200 5.913 25.085 2.480 2.264CTS Combustion Turbines 1‐3 555997.63 4502118.90 795.0 213.2 230.0 85.5 17.32 15.500 15.500 282.186 11.385 11.385GFLARE1 Ground Flare 1 555470.39 4502011.07 788.0 244.9 1832.0 65.62 29.83 18.270 2.795 497.043 7.507 0.230GFLARE2 Ground Flare 2 555420.07 4502085.43 788.0 244.9 1832.0 65.62 29.83 18.270 2.795 497.043 7.507 0.230HPFLARE HP Elevated Flare 555387.08 4502007.16 786.0 337.0 1832.0 65.62 4.14 3.516 3.516 19.131 0.289 0.289LPFLARE LP Ground Flare ‐ pilot 556466.10 4502507.88 795.0 75.0 1832.0 0.03 30.00 0.068 0.068 0.370 0.007 0.007REFFLARE Refrigerated Tank Flare 556042.79 4502603.60 795.0 256.1 1832.0 65.62 4.88 0.982 0.154 26.724 0.404 0.017INCIN LP Incinerator 556444.09 4502531.19 795.0 250.0 1600.0 82.6 4.50 7.017 7.017 8.499 0.769 0.769COI Caustic Oxidizer 555233.89 4502080.96 713.0 200.0 1600.0 45.0 2.00 0.729 0.729 3.966 0.080 0.080COOLTWR1 C li T 1 555836 14 4502495 23 795 0 70 0 71 0 20 0 45 00 0 000 0 000 0 000 0 106 0 106COOLTWR1 Cooling Tower 1 555836.14 4502495.23 795.0 70.0 71.0 20.0 45.00 0.000 0.000 0.000 0.106 0.106COOLTWR2 Cooling Tower 2 555858.65 4502515.06 795.0 70.0 71.0 20.0 52.00 0.000 0.000 0.000 0.125 0.125COOLTWR3 Cooling Tower 3 555881.16 4502534.89 795.0 70.0 71.0 20.0 52.00 0.000 0.000 0.000 0.125 0.125COOLTWR4 Cooling Tower 4 555903.67 4502554.73 795.0 70.0 71.0 20.0 52.00 0.000 0.000 0.000 0.125 0.125COOLTWR5 Cooling Tower 5 555926.18 4502574.56 795.0 70.0 71.0 20.0 52.00 0.000 0.000 0.000 0.125 0.125COOLTWR6 Cooling Tower 6 555948.69 4502594.40 795.0 70.0 71.0 20.0 52.00 0.000 0.000 0.000 0.125 0.125FWP1 Fire Water Pump 1 555233.89 4502089.91 713.0 30.0 885.0 113.0 1.00 0.033 0.033 4.012 0.074 0.003FWP2 Fire Water Pump 2 555226 06 4502080 96 713 0 30 0 885 0 113 0 1 00 0 033 0 033 4 012 0 074 0 003FWP2 Fire Water Pump 2 555226.06 4502080.96 713.0 30.0 885.0 113.0 1.00 0.033 0.033 4.012 0.074 0.003FWP3 Fire Water Pump 3 555252.33 4502079.29 713.0 30.0 885.0 113.0 1.00 0.033 0.033 4.012 0.074 0.003GEN1 Generator 1 556100.05 4502113.84 795.0 30.0 882.5 125.0 2.00 0.134 0.134 0.222 0.071 0.002GEN2 Generator 2 556079.18 4502093.93 795.0 30.0 882.5 125.0 2.00 0.134 0.134 0.222 0.071 0.002GEN3 Generator 3 556055.00 4502074.01 795.0 30.0 882.5 125.0 2.00 0.134 0.134 0.222 0.071 0.002GEN4 Generator 4 556028.00 4502047.00 795.0 30.0 882.5 125.0 2.00 0.134 0.134 0.222 0.071 0.002
Volume Sources
Source ID Source Description Easting (X) Northing (Y)
Base Elevation
(ft)Release
Height (ft)
Horizontal Dimension
(ft)
Vertical Dimension
(ft) NO2 (lb/hr)NOx (lb/hr) CO (lb/hr)
PM‐ST (lb/hr)
PM‐LT (lb/hr)
PEBLD PE Blending Silos 556322.06 4502332.48 795.0 131.2 29.0 61.0 0.00 0.00 0.00 2.93E‐01 2.45E‐01PERC PE Rail Loading Silos 556359.33 4502324.12 795.0 151.0 66.7 70.2 0.00 0.00 0.00 1.90E‐01 1.38E‐01PETK PE Truck Loading Silos 556544.99 4502174.37 854.0 151.0 54.7 70.2 0.00 0.00 0.00 1.29E‐01 3.25E‐02PEU1 LDPE Vents 556263.39 4502415.83 795.0 131.2 30.4 61.0 0.00 0.00 0.00 2.50E‐01 2.47E‐01PEU2 LDPE Vents 556363.24 4502496.66 795.0 131.2 30.4 61.0 0.00 0.00 0.00 2.50E‐01 2.47E‐01PEU3 HDPE Vents 556183.45 4502346.54 795.0 131.2 30.4 61.0 0.00 0.00 0.00 2.13E‐01 2.13E‐01RD_1 PE Haul Road 556401.89 4501780.43 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_2 PE Haul Road 556379.96 4501801.60 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD 3 PE Haul Road 556358 03 4501822 76 854 0 12 8 20 9 11 9 0 00 0 00 0 00 7 35E 04 2 15E 04RD_3 PE Haul Road 556358.03 4501822.76 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_4 PE Haul Road 556336.10 4501843.93 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_5 PE Haul Road 556314.16 4501865.10 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_6 PE Haul Road 556311.47 4501894.44 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_7 PE Haul Road 556329.12 4501918.33 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_8 PE Haul Road 556351.41 4501939.13 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD 9 PE Haul Road 556373.70 4501959.92 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_9 PE Haul Road 556373.70 4501959.92 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E 04 2.15E 04RD_10 PE Haul Road 556395.98 4501980.71 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_11 PE Haul Road 556418.27 4502001.50 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_12 PE Haul Road 556440.56 4502022.29 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_13 PE Haul Road 556462.85 4502043.09 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_14 PE Haul Road 556485.13 4502063.88 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_15 PE Haul Road 556507.42 4502084.67 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_16 PE Haul Road 556529.71 4502105.46 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_17 PE Haul Road 556552.00 4502126.25 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_18 PE Haul Road 556574.28 4502147.04 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_19 PE Haul Road 556596.57 4502167.84 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_20 PE Haul Road 556618.86 4502188.63 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_21 PE Haul Road 556641.15 4502209.42 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_22 PE Haul Road 556662.22 4502230.89 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_23 PE Haul Road 556668.19 4502260.78 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_24 PE Haul Road 556652.46 4502284.45 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_25 PE Haul Road 556625.52 4502294.81 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_26 PE Haul Road 556599.22 4502286.50 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_27 PE Haul Road 556576.93 4502265.72 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD 28 PE Haul Road 556554 63 4502244 94 854 0 12 8 20 9 11 9 0 00 0 00 0 00 7 35E 04 2 15E 04RD_28 PE Haul Road 556554.63 4502244.94 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_29 PE Haul Road 556532.33 4502224.15 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_30 PE Haul Road 556510.04 4502203.37 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_31 PE Haul Road 556487.74 4502182.59 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_32 PE Haul Road 556465.44 4502161.81 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_33 PE Haul Road 556448.37 4502137.37 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD 34 PE Haul Road 556436.52 4502109.29 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04_3 au oad 556 36 5 50 09 9 85 0 8 0 9 9 0 00 0 00 0 00 35 0 5 0
Volume Sources
Source ID Source Description Easting (X) Northing (Y)
Base Elevation
(ft)Release
Height (ft)
Horizontal Dimension
(ft)
Vertical Dimension
(ft) NO2 (lb/hr)NOx (lb/hr) CO (lb/hr)
PM‐ST (lb/hr)
PM‐LT (lb/hr)
RD_35 PE Haul Road 556424.66 4502081.21 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_36 PE Haul Road 556412.80 4502053.14 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_37 PE Haul Road 556400.94 4502025.06 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_38 PE Haul Road 556382.32 4502001.71 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_39 PE Haul Road 556360.02 4501980.94 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_40 PE Haul Road 556337.71 4501960.17 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_41 PE Haul Road 556315.40 4501939.40 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_42 PE Haul Road 556297.28 4501915.14 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD 43 PE Haul Road 556292 21 4501886 74 854 0 12 8 20 9 11 9 0 00 0 00 0 00 7 35E 04 2 15E 04RD_43 PE Haul Road 556292.21 4501886.74 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_44 PE Haul Road 556304.90 4501861.06 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_45 PE Haul Road 556326.72 4501839.79 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_46 PE Haul Road 556349.08 4501819.08 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_47 PE Haul Road 556371.55 4501798.48 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_48 PE Haul Road 556394.01 4501777.88 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD 49 PE Haul Road 556407.18 4501765.80 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_49 PE Haul Road 556407.18 4501765.80 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E 04 2.15E 04
Combustion Turbine Load Analysis Model Input
Source ID Source Description Easting (X) (m)Northing (Y)
(m)
Base Elevation
(ft)Stack
Height (ft)Temperature
(°F)Exit Velocity
(ft/sec)
Equivalent Stack
Diameter (ft)
Unit Emission (lb/hr)
Combined Flue Area
(ft2)
Combined Flue Flow (acfm)
Individual Actual Flue Diameter (ft)
Single Turbine Flow (acfm)
3CT100 3 Turbines 100% Load 555997.63 4502118.90 795.0 213.2 230 85.5 17.32 3.00 235.6 1,208,259 10.0 402,7532CT100 2 Turbines 100% Load 555997.63 4502118.90 795.0 213.2 230 85.5 14.14 2.00 157.1 805,506,1CT100 1 Turbine 100% Load 555997.63 4502118.90 795.0 213.2 230 85.5 10.00 1.00 78.5 402,7531CT75 1 Turbine 75% Load 555997.63 4502118.90 795.0 213.2 230 68.4 10.00 0.82 78.5 322,2021CT45 1 Turbine 45% Load 555997.63 4502118.90 795.0 213.2 230 51.3 10.00 0.64 78.5 241,652Note: Turbine emissions and flow are decrease at lower loads though the relationship is not linear.
Shell Franklin Off‐Site Source Model Input Data (Only Sources within 10km of Shell Site) (NAD83, Zone 17)
Source ID
Stack Release Type (Beta)
FLAT (Non‐Default) Source Description
Easting (X) (m)
Northing (Y) (m)
Base Elevation
(ft)Stack
Height (ft)Temperature
(°F)
Exit Velocity (ft/sec)
Stack Diameter
(ft)NO2 (lb/hr)
BASF_S02 BASF Thermal Oxidation Unit 555298 4501272 743.2 40.0 70 4.72 0.3 7.50AES_S02 AES Beaver Valley (No. 2 Boiler) 554599.9 4500896.1 754.8 200.0 135 53.20 7.8 385.0AES_S03 AES Beaver Valley (No. 3 Boiler) 554610.0 4500895.4 754.8 200.0 135 52.30 7.8 385.0AES_S04 AES Beaver Valley (No. 4 Boiler) 554619.5 4500892.5 755.0 200.0 135 58.60 7.8 385.0AES_S05 AES Beaver Valley (No. 5 Boiler) 554628.2 4500889.2 755.1 200.0 135 79.60 4.8 219.5NOVA_S01 Nova Chem Beaver Valley D3 D4 EPS 554033.5 4500593.4 755.0 40.0 460 71.90 4.8 4.40NOVA_Z07 Nova Chem Beaver Valley Gen Plant 554033.5 4500593.4 755.0 1.0 70 0.03 1.0 0.38EATON_S01 Eaton Boilers 557399 4504911 765.9 49.0 550 28.00 4.7 1.96ANCH_S01 Anchor Hocking Misc NG 560718 4504581 739.1 1.0 200 0.03 1.0 1.61ANCH_S02 Anchor Hocking Melt Tank 560718 4504581 739.1 100.0 800 4.33 5.0 17.20ANCH_S115 Anchor Hocking Dec LEHR 560718 4504581 739.1 1.0 70 0.03 1.0 0.23ANCH_Z01 Anchor Hocking Quench LEHR 560718 4504581 739.1 40.0 68 0.03 1.0 0.37ANCH_Z02 Anchor Hocking Anneal LEHR 560718 4504581 739.1 40.0 68 0.03 1.0 2.33ANCH_Z107 Anchor Hocking Glass Form Lub 560718 4504581 739.1 1.0 600 0.03 1.0 0.08FEBV_S01 First Energy Nuclear Beaver Valley Aux Boil A 548011.9 4497013.1 734.3 122.0 601 17.10 7.0 6.74FEBV_S02 First Energy Nuclear Beaver Valley Aux Boil B 548011.9 4497013.1 734.3 122.0 601 17.10 7.0 6.74FEBV_S101 First Energy Nuclear Beaver Valley Dies Eng 548011.9 4497013.1 734.3 20.0 635 0.03 1.0 156.0FEBV_S102 First Energy Nuclear Beaver Valley Dies Eng 548011.9 4497013.1 734.3 20.0 635 0.03 1.0 156.0FEBV_S103 First Energy Nuclear Beaver Valley Dies Eng 548011.9 4497013.1 734.3 20.0 900 0.03 1.0 173.3FEBV_S104 First Energy Nuclear Beaver Valley Dies Eng 548011.9 4497013.1 734.3 20.0 900 0.03 1.0 173.3FEBV_S105 First Energy Nuclear Beaver Valley Emg Res Gen 548011.9 4497013.1 734.3 1.0 1000 0.03 1.0 156.0FEBV_Z109 First Energy Nuclear Beaver Valley Misc 548011.9 4497013.1 734.3 1.0 70 0.03 1.0 375.9FEBM_S02 First Energy Bruce Mansfield (Unit #1) 549490.5 4498345.9 729.4 950.0 126 75.11 19.2 3959.0FEBM_S03 First Energy Bruce Mansfield (Unit #2) 549490.5 4498345.9 729.4 950.0 126 75.11 19.2 3959.0FEBM_S06 First Energy Bruce Mansfield (Unit #3) 549490.5 4498345.9 729.4 600.0 126 75.11 19.2 3959.0FEBM_S07 First Energy Bruce Mansfield (Aux Boils) 549490.5 4498345.9 729.4 136.0 585 6.89 12.0 129.02NGC_S09 NGC Ind Shippingport Board Dryer 548962 4497373 771.9 1.0 250 0.03 1.0 20.96NGC_S100 NGC Ind Shippingport IMP Mill 548962 4497373 771.9 30.0 350 53.10 2.0 15.72NGC_S11 NGC Ind Shippingport Cage Mill 548962 4497373 771.9 20.0 200 61.40 5.7 12.10USGYP_S1 US Gypsum S1 564369 4497719 740.5 54.0 203 50.20 8.5 7.46USGYP_S2 US Gypsum #1 Kettle 564369 4497719 740.5 97.0 600 139.00 1.4 4.21USGYP_S3 US Gypsum #2 Kettle 564369 4497719 740.5 98.0 600 139.00 1.4 4.21USGYP_S4 US Gypsum #1 Dryer Mill 564369 4497719 740.5 100.0 220 51.60 5.1 2.50USGYP_S5 US Gypsum #2 Dryer Mill 564369 4497719 740.5 100.0 220 51.60 5.1 2.50USGYP_S6 US Gypsum Gauging Water Heater 564369 4497719 740.5 25.0 600 52.40 0.9 0.49Offsite source data from PADEP. See workbook called "NOx Sources PA DEP Update 2‐6‐14".
Step 1: Adjusted Width of RoadRoad Width (ft) of 25 + 20 ft (6 m) = 45 ft
Step 2: Maximum No. of SourcesRoad Length (ft) of 4752 / Adj. Width = 106
Step 3: Height of VolumeVehicle height (ft) of 15 X 1.7 = 25.5 ft
Step 4: Initial Sigma Y (Horizontal Dimension)Adjusted road width (ft) of 45 / 2.15 = 20.93 ft
Step 5: Initial Sigma Z (Vertical Dimension)Height of volume (ft) of 25.5 / 2.15 = 11.86 ft
Step 6: Height of ReleaseHeight of volume (ft) of 25.5 / 2 = 13 ft
Step 7: Emission rateTotal PM10 short termemission rate (lb/hr) of 0.036 /# sources = 0.000735 lb/hr
Total PM10 annual emission rate (lb/hr) of 0.011 /# sources = 0.000215 lb/hr
Truck Roadway Volume Source Parameter Calculation
Model ID Source Description Length (ft) Width (ft)
Square Root of Area (ft)
Structure Height/Vertical Dimension (ft)
Release Height (ft)
Initial Horizontal
Dimension sY (ft)
Initial Vertical Dimension sZ (ft) Reference
PEBLD PE Blending Silos 190.0 82.0 124.8 131.2 131.2 29.03 61.0 Note 1, 2, and 3PERC PE Rail Loading Silos 235 0 350 0 286 8 151 0 151 0 66 70 70 2 Note 1 2 and 3
Shell Franklin Non-Road Volume Source Parameter CalculationSource Dimensions Initial Dispersion Coefficients
PERC PE Rail Loading Silos 235.0 350.0 286.8 151.0 151.0 66.70 70.2 Note 1, 2, and 3PETK PE Truck Loading Silos 235.0 235.0 235.0 151.0 151.0 54.65 70.2 Note 1, 2, and 3PEU1&2 LDPE Vents 190.0 90.0 130.8 131.2 131.2 30.41 61.0 Note 1, 2, and 3PEU3 HDPE Vents 190.0 90.0 130.8 131.2 131.2 30.41 61.0 Note 1, 2, and 3
Note 1: Release height equal to top of structure as process is aspirated and emissions will occur at the top of the structure.
Note 2: Sigma Y value calculated as the square root of the area, or average length of side, divided by 4.3 (Table 3-1 of AERMOD Manual for single volume source).
N 3 Si Z l f l d dj b ildi l l d h b ildi h i h di id d b 2 1 (T bl 3 1 f AERMOD M l f El d S Adj B ildi )
Note 2: Sigma Y value calculated as the square root of the area, or average length of side, divided by 4.3 (Table 3-1 of AERMOD Manual for single volume source).
Note 3: Sigma Z values for elevated sources on or adjacent to a building calculated as the building height divided by 2.15 (Table 3-1 of AERMOD Manual for Elevated Source on or Adjacent to Building).
ATTACHMENT B MODEL SUMMARY RESULTS
Turbine Load Analysis Results (4/14/14)Model File Pollutant Average Group Rank Conc/Dep East (X) North (Y) Elev Hill Flag Time Met File Sources Groups ReceptorsAerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 1‐HR 1CT100 1ST 2.19036 556514.8 4502316.1 246.73 342.68 0 8071201 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 1‐HR 1CT100 1ST 2.13971 556950 4501600 312.31 336.53 0 9020901 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 1‐HR 1CT100 1ST 1.95197 556100 4501150 336.46 340.15 0 7062704 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 1‐HR 1CT100 1ST 1.72661 557250 4502450 319.18 341.93 0 6031103 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 1‐HR 1CT100 1ST 1.71558 556514.8 4502316.1 246.73 342.68 0 10051005 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 1‐HR 1CT45 1ST 1.77824 556467.42 4502258.8 249.95 337.02 0 6100901 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 1‐HR 1CT45 1ST 1.75547 556377.51 4502171.9 244.21 337.02 0 10052704 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 1‐HR 1CT45 1ST 1.685 556514.8 4502316.1 246.73 342.68 0 8071201 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 1‐HR 1CT45 1ST 1.68326 556000 4501150 324.2 340.28 0 7062704 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 1‐HR 1CT45 1ST 1.51032 556950 4501800 323.1 334.23 0 9020901 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 1‐HR 1CT75 1ST 2.01595 556514.8 4502316.1 246.73 342.68 0 8071201 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 1‐HR 1CT75 1ST 1.8708 556050 4501100 338.92 338.92 0 7062704 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 1‐HR 1CT75 1ST 1.85049 556950 4501700 333.51 333.51 0 9020901 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 1‐HR 1CT75 1ST 1.76011 556431.02 4502224.5 248.96 337.02 0 6100901 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 1‐HR 1CT75 1ST 1.68973 556377.51 4502171.9 244.21 337.02 0 10052704 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 1‐HR 2CT100 1ST 2.83105 557150 4500900 293.37 358.2 0 9020901 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 1‐HR 2CT100 1ST 2.63299 557550 4502350 341.79 341.79 0 6031103 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 1‐HR 2CT100 1ST 2.52732 554700 4502500 330.67 347.29 0 7090623 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 1‐HR 2CT100 1ST 2.41952 557550 4502700 336.01 341.15 0 10061722 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 1‐HR 2CT100 1ST 2.32568 554950 4502700 322.91 344 0 8042522 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 1‐HR 3CT100 1ST 3.13463 556427.79 4503499.6 208.13 355.56 43 10102524 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 1‐HR 3CT100 1ST 2.98092 557250 4502300 333.8 333.8 0 9121623 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 1‐HR 3CT100 1ST 2.9547 554450 4502850 337.79 352.07 0 7090623 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 1‐HR 3CT100 1ST 2.86316 554600 4502550 343.41 343.41 0 6050124 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 1‐HR 3CT100 1ST 2.70158 555000 4502900 343.75 343.75 0 8042522 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 24‐HR 1CT100 1ST 0.37783 556527.97 4502337.3 244.53 343.02 0 10030724 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 24‐HR 1CT100 1ST 0.35014 556514.8 4502316.1 246.73 342.68 0 6071624 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 24‐HR 1CT100 1ST 0.31997 557150 4502350 319.7 337.02 0 7090324 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 24‐HR 1CT100 1ST 0.28571 557100 4502750 308.85 338.9 0 8081824 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 24‐HR 1CT100 1ST 0.2537 556613.73 4502595.8 239.26 343.02 0 9042524 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 24‐HR 1CT45 1ST 0.37448 556514.8 4502316.1 246.73 342.68 0 7090324 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 24‐HR 1CT45 1ST 0.34631 556501.63 4502294.8 248.75 340.98 0 8110624 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 24‐HR 1CT45 1ST 0.30837 556514.8 4502316.1 246.73 342.68 0 10030824 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 24‐HR 1CT45 1ST 0.29934 556527.97 4502337.3 244.53 343.02 0 6071624 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 24‐HR 1CT45 1ST 0.22955 556514.8 4502316.1 246.73 342.68 0 9071324 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 24‐HR 1CT75 1ST 0.35835 556514.8 4502316.1 246.73 342.68 0 7090324 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 24‐HR 1CT75 1ST 0.34906 556514.8 4502316.1 246.73 342.68 0 10030824 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 24‐HR 1CT75 1ST 0.34168 556514.8 4502316.1 246.73 342.68 0 6071624 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 24‐HR 1CT75 1ST 0.33155 556485.61 4502275.9 250.09 337.02 0 8110624 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 24‐HR 1CT75 1ST 0.24805 556514.8 4502316.1 246.73 342.68 0 9071324 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 24‐HR 2CT100 1ST 0.45935 556716.34 4502861.8 241.65 343.02 43 10011424 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 24‐HR 2CT100 1ST 0.40525 556767.7 4502692.1 244.96 345.63 0 9042524 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 24‐HR 2CT100 1ST 0.37981 556716.34 4502861.8 241.65 343.02 43 8060924 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load 2006 UNIT.SUM UNIT 24‐HR 2CT100 1ST 0.35088 556675.12 4502952.9 237.04 343.02 43 6121424 Beaver Valley 2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 24 HR 2CT100 1ST 0.35088 556675.12 4502952.9 237.04 343.02 43 6121424 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 24‐HR 2CT100 1ST 0.34414 557400 4502250 327.4 343.02 0 7090324 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 24‐HR 3CT100 1ST 0.52878 556716.34 4502861.8 241.65 343.02 43 10011424 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 24‐HR 3CT100 1ST 0.5165 556716.34 4502861.8 241.65 343.02 43 8060924 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 24‐HR 3CT100 1ST 0.48703 556767.7 4502692.1 244.96 345.63 0 9042524 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 24‐HR 3CT100 1ST 0.43403 556675.12 4502952.9 237.04 343.02 43 6121424 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 24‐HR 3CT100 1ST 0.40037 555350 4503200 286.28 354.3 0 7101824 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 8‐HR 1CT100 1ST 0.74701 556514.8 4502316.1 246.73 342.68 0 10072208 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 8‐HR 1CT100 1ST 0.74338 556501.63 4502294.8 248.75 340.98 0 9071308 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 8‐HR 1CT100 1ST 0.73303 556501.63 4502294.8 248.75 340.98 0 6070708 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 8‐HR 1CT100 1ST 0.72687 556527.97 4502337.3 244.53 343.02 0 7092908 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 8‐HR 1CT100 1ST 0.65924 556527.97 4502337.3 244.53 343.02 0 8081208 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 8‐HR 1CT45 1ST 0.76737 556514.8 4502316.1 246.73 342.68 0 6070708 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 8‐HR 1CT45 1ST 0.68269 556514.8 4502316.1 246.73 342.68 0 9071308 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 8‐HR 1CT45 1ST 0.67047 556527.97 4502337.3 244.53 343.02 0 7092908 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 8‐HR 1CT45 1ST 0.6624 556467.42 4502258.8 249.95 337.02 0 8110608 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 8‐HR 1CT45 1ST 0.60142 556074.06 4501874.4 230.65 340.28 0 10020624 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 8‐HR 1CT75 1ST 0.81153 556514.8 4502316.1 246.73 342.68 0 6070708 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 8‐HR 1CT75 1ST 0.77022 556527.97 4502337.3 244.53 343.02 0 7092908 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 8‐HR 1CT75 1ST 0.74029 556514.8 4502316.1 246.73 342.68 0 9071308 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 8‐HR 1CT75 1ST 0.70358 556527.97 4502337.3 244.53 343.02 0 10072208 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 8‐HR 1CT75 1ST 0.61544 556449.22 4502241.6 249.36 337.02 0 8110608 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 8‐HR 2CT100 1ST 0.97598 556158.1 4501507.2 289.58 340.28 0 10020624 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 8‐HR 2CT100 1ST 0.92486 557100 4502750 308.85 338.9 0 9121208 Beaver_Valley_2009.SFC 5 5 22746
AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 8‐HR 2CT100 1ST 0.88641 556150 4501400 311.92 338.71 0 7081808 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 8‐HR 2CT100 1ST 0.8544 557050 4502450 308.54 337.02 0 8010924 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 8‐HR 2CT100 1ST 0.84672 556675.12 4502952.9 237.04 343.02 43 6121408 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 8‐HR 3CT100 1ST 1.14705 556200 4501350 324.98 324.98 0 10020624 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 8‐HR 3CT100 1ST 1.10107 556675.12 4502952.9 237.04 343.02 43 6121408 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 8‐HR 3CT100 1ST 1.05795 556150 4501300 325.05 337.73 0 7081808 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 8‐HR 3CT100 1ST 1.01181 557250 4502400 331.76 336.42 0 8010924 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 8‐HR 3CT100 1ST 1.00734 557350 4502800 334.15 338.9 0 9121208 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT ANNUAL 1CT100 1ST 0.03869 556527.97 4502337.3 244.53 343.02 0 1 YEARS Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT ANNUAL 1CT100 1ST 0.03435 556527.97 4502337.3 244.53 343.02 0 1 YEARS Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT ANNUAL 1CT100 1ST 0.03272 556613.73 4502595.8 239.26 343.02 0 1 YEARS Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT ANNUAL 1CT100 1ST 0.03024 556613.73 4502595.8 239.26 343.02 0 1 YEARS Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT ANNUAL 1CT100 1ST 0.02856 556779.2 4502644.4 255.07 343.02 0 1 YEARS Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT ANNUAL 1CT45 1ST 0.03879 556527.97 4502337.3 244.53 343.02 0 1 YEARS Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT ANNUAL 1CT45 1ST 0.03579 556527.97 4502337.3 244.53 343.02 0 1 YEARS Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT ANNUAL 1CT45 1ST 0.03212 556613.73 4502595.8 239.26 343.02 0 1 YEARS Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT ANNUAL 1CT45 1ST 0.02946 556604.22 4502546.7 239.74 343.02 0 1 YEARS Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT ANNUAL 1CT45 1ST 0.02853 556604.22 4502546.7 239.74 343.02 0 1 YEARS Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT ANNUAL 1CT75 1ST 0.03981 556527.97 4502337.3 244.53 343.02 0 1 YEARS Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT ANNUAL 1CT75 1ST 0.03605 556527.97 4502337.3 244.53 343.02 0 1 YEARS Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT ANNUAL 1CT75 1ST 0.0328 556613.73 4502595.8 239.26 343.02 0 1 YEARS Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT ANNUAL 1CT75 1ST 0.0303 556527.97 4502337.3 244.53 343.02 0 1 YEARS Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT ANNUAL 1CT75 1ST 0.02887 556604.22 4502546.7 239.74 343.02 0 1 YEARS Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT ANNUAL 2CT100 1ST 0.0399 557250 4502300 333.8 333.8 0 1 YEARS Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT ANNUAL 2CT100 1ST 0.03658 556757.56 4502770.7 238.99 345.63 43 1 YEARS Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT ANNUAL 2CT100 1ST 0.03555 556757.56 4502770.7 238.99 345.63 43 1 YEARS Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT ANNUAL 2CT100 1ST 0.03217 556757.56 4502770.7 238.99 345.63 43 1 YEARS Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT ANNUAL 2CT100 1ST 0.03028 556757.56 4502770.7 238.99 345.63 43 1 YEARS Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT ANNUAL 3CT100 1ST 0.04 557700 4501900 352.7 353.04 0 1 YEARS Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT ANNUAL 3CT100 1ST 0.03681 556757.56 4502770.7 238.99 345.63 43 1 YEARS Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT ANNUAL 3CT100 1ST 0.03473 556757.56 4502770.7 238.99 345.63 43 1 YEARS Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT ANNUAL 3CT100 1ST 0.03152 556757.56 4502770.7 238.99 345.63 43 1 YEARS Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT ANNUAL 3CT100 1ST 0.03038 556757.56 4502770.7 238.99 345.63 43 1 YEARS Beaver_Valley_2007.SFC 5 5 22746
Turbine Load Analysis Results (4/14/14)Pollutant Average Group Rank Conc.UNIT 1‐HR 3CT100 1ST 3.13UNIT 1‐HR 2CT100 1ST 2.83UNIT 1‐HR 1CT100 1ST 2.19UNIT 1‐HR 1CT75 1ST 2.02UNIT 1‐HR 1CT45 1ST 1.78UNIT 24‐HR 3CT100 1ST 0.53UNIT 24‐HR 2CT100 1ST 0.46UNIT 24‐HR 1CT100 1ST 0.38UNIT 24‐HR 1CT75 1ST 0.36UNIT 24‐HR 1CT45 1ST 0.37UNIT 24‐HR 1CT45 1ST 0.37UNIT 8‐HR 3CT100 1ST 1.15UNIT 8‐HR 2CT100 1ST 0.98UNIT 8‐HR 1CT100 1ST 0.75UNIT 8‐HR 1CT75 1ST 0.81UNIT 8‐HR 1CT45 1ST 0.77UNIT ANNUAL 3CT100 1ST 0.040UNIT ANNUAL 2CT100 1ST 0.040UNIT ANNUAL 1CT100 1ST 0.039UNIT ANNUAL 1CT75 1ST 0.040UNIT ANNUAL 1CT45 1ST 0.039
Worst Case Furnace Analysis Results (4/14/14)Model File Pollutant Average Group Rank Conc/Dep East (X) North (Y) Elev Hill Flag Time Met File Sources Groups ReceptorsAerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 1‐HR EC#1 1ST 1.80809 554350 4502650 352.99 352.99 0 7090623 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 1‐HR EC#1 1ST 1.54581 555000 4502900 343.75 343.75 0 9120121 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 1‐HR EC#1 1ST 1.49846 554150 4503950 371.21 371.21 0 10040122 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 1‐HR EC#1 1ST 1.26121 553300 4502200 360.14 360.14 0 8102303 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 1‐HR EC#1 1ST 1.2507 554350 4502650 352.99 352.99 0 6100619 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 1‐HR EC#2 1ST 1.79526 554350 4502650 352.99 352.99 0 7090623 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 1‐HR EC#2 1ST 1.52881 555000 4502900 343.75 343.75 0 9120121 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 1‐HR EC#2 1ST 1.4812 554150 4503950 371.21 371.21 0 10120920 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 1‐HR EC#2 1ST 1.22966 554350 4502650 352.99 352.99 0 6100619 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 1‐HR EC#2 1ST 1.19096 554150 4503500 364.13 364.13 0 8110418 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 1‐HR EC#3 1ST 1.69294 554350 4502600 352.26 352.26 0 7090623 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 1‐HR EC#3 1ST 1.5251 554050 4503400 361.55 361.55 0 10043024 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 1‐HR EC#3 1ST 1.50136 555000 4502900 343.75 343.75 0 9120121 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 1‐HR EC#3 1ST 1.27648 553300 4502200 360.14 360.14 0 8032922 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 1‐HR EC#3 1ST 1.19496 554400 4502600 351.12 351.12 0 6100619 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 1‐HR EC#4 1ST 1.47894 555000 4502900 343.75 343.75 0 9120121 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 1‐HR EC#4 1ST 1.45098 554200 4503950 369.64 369.64 0 10120920 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 1‐HR EC#4 1ST 1.28151 554150 4503500 364.13 364.13 0 7092523 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 1‐HR EC#4 1ST 1.18378 554350 4502600 352.26 352.26 0 6100619 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 1‐HR EC#4 1ST 1.1539 554150 4503500 364.13 364.13 0 8110418 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 1‐HR EC#5 1ST 1.52046 554350 4502600 352.26 352.26 0 7090623 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 1‐HR EC#5 1ST 1.45159 555000 4502900 343.75 343.75 0 9120121 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 1‐HR EC#5 1ST 1.44593 554200 4503950 369.64 369.64 0 10120920 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 1‐HR EC#5 1ST 1.1764 554350 4502600 352.26 352.26 0 6100619 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 1‐HR EC#5 1ST 1.13989 554150 4503500 364.13 364.13 0 8110418 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 1‐HR EC#6 1ST 1.44662 554200 4503950 369.64 369.64 0 10120920 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 1‐HR EC#6 1ST 1.42328 555000 4502900 343.75 343.75 0 9120121 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 1‐HR EC#6 1ST 1.34588 554350 4502600 352.26 352.26 0 7090623 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 1‐HR EC#6 1ST 1.15432 554350 4502600 352.26 352.26 0 6100619 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 1‐HR EC#6 1ST 1.12933 554150 4503500 364.13 364.13 0 8110418 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 1‐HR EC#7 1ST 1.44529 554200 4503950 369.64 369.64 0 10120920 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 1‐HR EC#7 1ST 1.37452 555000 4502900 343.75 343.75 0 9120121 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 1‐HR EC#7 1ST 1.35683 554400 4502550 350.78 350.78 0 7090623 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 1‐HR EC#7 1ST 1.13309 554350 4502700 353.36 353.36 0 6041101 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 1‐HR EC#7 1ST 1.12227 554150 4503500 364.13 364.13 0 8110418 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 24‐HR EC#1 1ST 0.17884 554350 4502900 349.57 349.57 0 8082224 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 24‐HR EC#1 1ST 0.13557 557650 4501450 357.99 371.48 0 7031824 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 24‐HR EC#1 1ST 0.13174 557700 4502550 342.06 343.16 0 10030824 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 24‐HR EC#1 1ST 0.12124 557800 4501500 371.88 371.88 0 6110224 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 24‐HR EC#1 1ST 0.12074 557700 4501550 362.03 371.48 0 9120524 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 24‐HR EC#2 1ST 0.17908 554350 4502900 349.57 349.57 0 8082224 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 24‐HR EC#2 1ST 0.13777 554600 4502550 343.41 343.41 0 10032824 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 24‐HR EC#2 1ST 0.13609 557650 4501400 358.01 359.95 0 7031824 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace 2009 UNIT.SU UNIT 24‐HR EC#2 1ST 0.13172 554150 4503550 364.24 364.24 0 9020624 Beaver Valley 2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 24 HR EC#2 1ST 0.13172 554150 4503550 364.24 364.24 0 9020624 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 24‐HR EC#2 1ST 0.12317 557800 4501500 371.88 371.88 0 6110224 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 24‐HR EC#3 1ST 0.17805 554350 4502900 349.57 349.57 0 8082224 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 24‐HR EC#3 1ST 0.13794 557650 4501400 358.01 359.95 0 7031824 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 24‐HR EC#3 1ST 0.13753 557700 4502500 341.93 341.93 0 10030824 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 24‐HR EC#3 1ST 0.13021 554150 4503550 364.24 364.24 0 9020624 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 24‐HR EC#3 1ST 0.12558 557800 4501500 371.88 371.88 0 6110224 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 24‐HR EC#4 1ST 0.17827 554350 4502900 349.57 349.57 0 8082224 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 24‐HR EC#4 1ST 0.16002 554150 4503500 364.13 364.13 0 9020624 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 24‐HR EC#4 1ST 0.14192 554400 4502550 350.78 350.78 0 10032824 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 24‐HR EC#4 1ST 0.13909 557650 4501400 358.01 359.95 0 7031824 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 24‐HR EC#4 1ST 0.12729 557800 4501500 371.88 371.88 0 6110224 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 24‐HR EC#5 1ST 0.1762 554350 4502900 349.57 349.57 0 8082224 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 24‐HR EC#5 1ST 0.15857 554150 4503500 364.13 364.13 0 9020624 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 24‐HR EC#5 1ST 0.14247 557250 4502350 336.13 336.13 0 10030824 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 24‐HR EC#5 1ST 0.13998 557650 4501400 358.01 359.95 0 7031824 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 24‐HR EC#5 1ST 0.12924 557800 4501500 371.88 371.88 0 6110224 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 24‐HR EC#6 1ST 0.17495 554150 4503500 364.13 364.13 0 9020624 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 24‐HR EC#6 1ST 0.17482 554400 4502550 350.78 350.78 0 8051124 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 24‐HR EC#6 1ST 0.15939 554400 4502600 351.12 351.12 0 7090624 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 24‐HR EC#6 1ST 0.14763 557250 4502350 336.13 336.13 0 10030824 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 24‐HR EC#6 1ST 0.14575 554400 4502550 350.78 350.78 0 6050924 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 24‐HR EC#7 1ST 0.17115 554150 4503500 364.13 364.13 0 9020624 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 24‐HR EC#7 1ST 0.1702 554350 4502900 349.57 349.57 0 8082224 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 24‐HR EC#7 1ST 0.16155 554400 4502600 351.12 351.12 0 7090624 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 24‐HR EC#7 1ST 0.15238 557250 4502350 336.13 336.13 0 10030824 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 24‐HR EC#7 1ST 0.14847 554400 4502550 350.78 350.78 0 6050924 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 8‐HR EC#1 1ST 0.39608 554350 4502950 347.56 347.56 0 8082224 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 8‐HR EC#1 1ST 0.3562 557700 4501250 353.35 353.35 0 10030508 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 8‐HR EC#1 1ST 0.35119 557650 4501450 357.99 371.48 0 7031808 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 8‐HR EC#1 1ST 0.3411 557700 4501550 362.03 371.48 0 9120524 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 8‐HR EC#1 1ST 0.28288 557800 4501500 371.88 371.88 0 6110208 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 8‐HR EC#2 1ST 0.39539 554350 4502950 347.56 347.56 0 8082224 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 8‐HR EC#2 1ST 0.363 554400 4502600 351.12 351.12 0 10032808 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 8‐HR EC#2 1ST 0.35165 557650 4501450 357.99 371.48 0 7031808 Beaver_Valley_2007.SFC 7 7 22746
AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 8‐HR EC#2 1ST 0.3381 557700 4501550 362.03 371.48 0 9120524 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 8‐HR EC#2 1ST 0.28393 557800 4501500 371.88 371.88 0 6110208 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 8‐HR EC#3 1ST 0.39267 554400 4502900 346.63 346.63 0 8082224 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 8‐HR EC#3 1ST 0.36172 557700 4501250 353.35 353.35 0 10030508 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 8‐HR EC#3 1ST 0.35618 557650 4501400 358.01 359.95 0 7031808 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 8‐HR EC#3 1ST 0.33828 557750 4501500 364.08 372.11 0 9120524 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 8‐HR EC#3 1ST 0.31206 554050 4503350 361.71 361.71 0 6012824 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 8‐HR EC#4 1ST 0.39028 554400 4502900 346.63 346.63 0 8082224 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 8‐HR EC#4 1ST 0.36476 557750 4501150 356.79 356.79 0 10030508 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 8‐HR EC#4 1ST 0.35949 557650 4501400 358.01 359.95 0 7031808 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 8‐HR EC#4 1ST 0.35452 554150 4503550 364.24 364.24 0 9020624 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 8‐HR EC#4 1ST 0.34182 554050 4503350 361.71 361.71 0 6012824 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 8‐HR EC#5 1ST 0.38863 554350 4502900 349.57 349.57 0 8082224 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 8‐HR EC#5 1ST 0.36869 557750 4501150 356.79 356.79 0 10030508 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 8‐HR EC#5 1ST 0.36221 557650 4501400 358.01 359.95 0 7031808 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 8‐HR EC#5 1ST 0.35339 554150 4503200 357.68 357.68 0 6012824 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 8‐HR EC#5 1ST 0.35073 554150 4503550 364.24 364.24 0 9020624 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 8‐HR EC#6 1ST 0.39261 554150 4503500 364.13 364.13 0 9020624 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 8‐HR EC#6 1ST 0.38689 554550 4502600 347.25 347.25 0 8082308 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 8‐HR EC#6 1ST 0.37192 557750 4501150 356.79 356.79 0 10030508 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 8‐HR EC#6 1ST 0.3648 557650 4501400 358.01 359.95 0 7031808 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 8‐HR EC#6 1ST 0.35391 554150 4503200 357.68 357.68 0 6012824 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 8‐HR EC#7 1ST 0.38399 554150 4503500 364.13 364.13 0 9020624 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 8‐HR EC#7 1ST 0.379 554350 4502900 349.57 349.57 0 8082224 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 8‐HR EC#7 1ST 0.3755 557750 4501150 356.79 356.79 0 10030508 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 8‐HR EC#7 1ST 0.36703 557650 4501400 358.01 359.95 0 7031808 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 8‐HR EC#7 1ST 0.34565 554150 4503200 357.68 357.68 0 6012824 Beaver_Valley_2006.SFC 7 7 22746
Worst Case Furnace Analysis Results (4/14/14)Pollutant Average Group Rank Conc.UNIT 1‐HR EC#1 1ST 1.81UNIT 1‐HR EC#2 1ST 1.80UNIT 1‐HR EC#3 1ST 1.69UNIT 1‐HR EC#4 1ST 1.48UNIT 1‐HR EC#5 1ST 1.52UNIT 1‐HR EC#6 1ST 1.45UNIT 1‐HR EC#7 1ST 1.45UNIT 24‐HR EC#1 1ST 0.18UNIT 24‐HR EC#2 1ST 0.18UNIT 24‐HR EC#3 1ST 0.18UNIT 24‐HR EC#4 1ST 0.18UNIT 24‐HR EC#5 1ST 0.18UNIT 24‐HR EC#6 1ST 0.17UNIT 24‐HR EC#7 1ST 0.17UNIT 8‐HR EC#1 1ST 0.40UNIT 8‐HR EC#2 1ST 0.40UNIT 8‐HR EC#2 1ST 0.40UNIT 8‐HR EC#3 1ST 0.39UNIT 8‐HR EC#4 1ST 0.39UNIT 8‐HR EC#5 1ST 0.39UNIT 8‐HR EC#6 1ST 0.39UNIT 8‐HR EC#7 1ST 0.38
4/14/14 ‐ Shell Franklin Class II SIL Model ResultsModel File Pollutant Average Group Rank Conc/Dep East (X) North (Y) Elev Hill Flag Time Met File Sources Groups ReceptorsAerMod 13350 Shell Franklin Significance_2006_CO.SUM CO 1‐HR ALL 1ST 357.82418 554800 4502350 267.42 353.88 0 6100901 Beaver_Valley_2006.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2007_CO.SUM CO 1‐HR ALL 1ST 339.61616 557850 4501500 370.83 371.72 0 7010622 Beaver_Valley_2007.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2008_CO.SUM CO 1‐HR ALL 1ST 315.97833 557800 4501500 371.88 371.88 0 8032102 Beaver_Valley_2008.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2009_CO.SUM CO 1‐HR ALL 1ST 433.87082 554850 4502500 249.13 359.4 0 9062302 Beaver_Valley_2009.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2010_CO.SUM CO 1‐HR ALL 1ST 335.32911 557750 4501650 360.42 363.17 0 10121101 Beaver_Valley_2010.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2006_CO.SUM CO 8‐HR ALL 1ST 114.82163 554400 4501950 266.67 353.88 0 6112508 Beaver_Valley_2006.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2007_CO.SUM CO 8‐HR ALL 1ST 150.27682 557800 4501500 371.88 371.88 0 7031808 Beaver_Valley_2007.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2008_CO.SUM CO 8‐HR ALL 1ST 105.22263 554400 4501950 266.67 353.88 0 8092408 Beaver_Valley_2008.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2009_CO.SUM CO 8‐HR ALL 1ST 168.74595 557800 4501500 371.88 371.88 0 9120524 Beaver_Valley_2009.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2010_CO.SUM CO 8‐HR ALL 1ST 133.21505 557800 4501500 371.88 371.88 0 10012908 Beaver_Valley_2010.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_5yrs_NO2.SUM NO2 1ST‐HIGHEST MAX DAILY 1 ALL 1ST 55.27977 554200 4503950 369.64 369.64 0 5 YEARS Beaver_Valley_6_10.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2006_NOX.SUM NOX ANNUAL ALL 1ST 0.7882 557250 4502350 336.13 336.13 0 1 YEARS Beaver_Valley_2006.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2007_NOX.SUM NOX ANNUAL ALL 1ST 0.79555 557250 4502350 336.13 336.13 0 1 YEARS Beaver_Valley_2007.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2008_NOX.SUM NOX ANNUAL ALL 1ST 0.80139 557250 4502350 336.13 336.13 0 1 YEARS Beaver_Valley_2008.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2009_NOX.SUM NOX ANNUAL ALL 1ST 0.7874 557250 4502350 336.13 336.13 0 1 YEARS Beaver_Valley_2009.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2010_NOX.SUM NOX ANNUAL ALL 1ST 1.05445 557250 4502350 336.13 336.13 0 1 YEARS Beaver_Valley_2010.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2006_PM‐LT.SUM PM‐LT ANNUAL ALL 1ST 0.79273 556485.61 4502275.9 250.09 337.02 0 1 YEARS Beaver_Valley_2006.SFC 83 1 22746AerMod 13350 Shell Franklin Significance_2007_PM‐LT.SUM PM‐LT ANNUAL ALL 1ST 0.72996 556501.63 4502294.8 248.75 340.98 0 1 YEARS Beaver_Valley_2007.SFC 83 1 22746AerMod 13350 Shell Franklin Significance_2008_PM‐LT.SUM PM‐LT ANNUAL ALL 1ST 0.72323 556485.61 4502275.9 250.09 337.02 0 1 YEARS Beaver_Valley_2008.SFC 83 1 22746AerMod 13350 Shell Franklin Significance_2009_PM‐LT.SUM PM‐LT ANNUAL ALL 1ST 0.70918 556485.61 4502275.9 250.09 337.02 0 1 YEARS Beaver_Valley_2009.SFC 83 1 22746AerMod 13350 Shell Franklin Significance_2010_PM‐LT.SUM PM‐LT ANNUAL ALL 1ST 0.79985 556501.63 4502294.8 248.75 340.98 0 1 YEARS Beaver_Valley_2010.SFC 83 1 22746AerMod 13350 Shell Franklin Significance_2006_PM‐ST.SUM PM‐ST 24‐HR ALL 1ST 3.03771 556716.34 4502861.8 241.65 343.02 43 6101524 Beaver_Valley_2006.SFC 83 1 22746AerMod 13350 Shell Franklin Significance_2007_PM‐ST.SUM PM‐ST 24‐HR ALL 1ST 3.70084 556633.89 4503044 234.29 341.93 43 7090324 Beaver_Valley_2007.SFC 83 1 22746AerMod 13350 Shell Franklin Significance_2008_PM‐ST.SUM PM‐ST 24‐HR ALL 1ST 4.143 556716.34 4502861.8 241.65 343.02 43 8110624 Beaver_Valley_2008.SFC 83 1 22746AerMod 13350 Shell Franklin Significance_2009_PM‐ST.SUM PM‐ST 24‐HR ALL 1ST 3.326 557800 4501500 371.88 371.88 0 9120524 Beaver_Valley_2009.SFC 83 1 22746AerMod 13350 Shell Franklin Significance_2010_PM‐ST.SUM PM‐ST 24‐HR ALL 1ST 3.98477 556716.34 4502861.8 241.65 343.02 43 10100824 Beaver_Valley_2010.SFC 83 1 22746
4/14/14 ‐ Shell Franklin Class II SIL Model ResultsPollutant Average Group Rank Conc. Background Total Standard % Standard Analysis CommentPM‐ST 24‐HR ALL 1ST 4.14 NA 4.1 5 83% Class II SignificancePM‐LT ANNUAL ALL 1ST 0.80 NA 0.80 1 80% Class II Significance
NOx ANNUAL ALL 1ST 0.79 NA 0.8 1 79% Class II SignificanceNO2 1ST‐HIGHEST MAX DAILY 1 ALL 1ST 44.2 NA 44.2 7.5 590% Class II Significance
CO 1‐HR ALL 1ST 433.9 NA 433.9 2000 22% Class II SignificanceCO 8‐HR ALL 1ST 168.7 NA 168.7 500 34% Class II SignificanceNotes:1) 1‐hr NO2 impacts include ARM of 0.8 for 1‐hr and 0.75 for annual.
4/14/14 ‐ Shell Franklin Class I SIL Model ResultsModel File Pollutant Average Group Rank Conc/Dep East (X) North (Y) Elev Hill Flag Time Met File Sources Groups Receptorsg p / p ( ) ( ) g p pAerMod 13350 Shell Franklin Class I Significance_2006_NOX.SUMNOX ANNUAL ALL 1ST 0.02677 588800.58 4464383.4 375.2 375.2 0 1 YEARS Beaver_Valley_2006.SFC 22 1 40AerMod 13350 Shell Franklin Class I Significance_2007_NOX.SUMNOX ANNUAL ALL 1ST 0.0283 568938.58 4453822.6 378.7 436.9 0 1 YEARS Beaver_Valley_2007.SFC 22 1 40AerMod 13350 Shell Franklin Class I Significance_2008_NOX.SUMNOX ANNUAL ALL 1ST 0.02242 568938.58 4453822.6 378.7 436.9 0 1 YEARS Beaver_Valley_2008.SFC 22 1 40AerMod 13350 Shell Franklin Class I Significance_2009_NOX.SUMNOX ANNUAL ALL 1ST 0.02278 568938.58 4453822.6 378.7 436.9 0 1 YEARS Beaver_Valley_2009.SFC 22 1 40AerMod 13350 Shell Franklin Class I Significance_2010_NOX.SUMNOX ANNUAL ALL 1ST 0.0272 588800.58 4464383.4 375.2 375.2 0 1 YEARS Beaver_Valley_2010.SFC 22 1 40AerMod 13350 Shell Franklin Class I Significance_2006_PM‐LT.SU PM‐LT ANNUAL ALL 1ST 0.01052 588800.58 4464383.4 375.2 375.2 0 1 YEARS Beaver_Valley_2006.SFC 83 1 40AerMod 13350 Shell Franklin Class I Significance_2007_PM‐LT.SU PM‐LT ANNUAL ALL 1ST 0.01113 568938.58 4453822.6 378.7 436.9 0 1 YEARS Beaver_Valley_2007.SFC 83 1 40AerMod 13350 Shell Franklin Class I Significance_2008_PM‐LT.SU PM‐LT ANNUAL ALL 1ST 0.00868 568938.58 4453822.6 378.7 436.9 0 1 YEARS Beaver_Valley_2008.SFC 83 1 40AerMod 13350 Shell Franklin Class I Significance_2009_PM‐LT.SU PM‐LT ANNUAL ALL 1ST 0.00867 568938.58 4453822.6 378.7 436.9 0 1 YEARS Beaver_Valley_2009.SFC 83 1 40AerMod 13350 Shell Franklin Class I Significance_2010_PM‐LT.SU PM‐LT ANNUAL ALL 1ST 0.01059 588800.58 4464383.4 375.2 375.2 0 1 YEARS Beaver_Valley_2010.SFC 83 1 40AerMod 13350 Shell Franklin Class I Significance_2006_PM‐ST.SU PM‐ST 24‐HR ALL 1ST 0.1617 580997.63 4458817.6 368.6 368.6 0 6012124 Beaver_Valley_2006.SFC 83 1 40AerMod 13350 Shell Franklin Class I Significance_2007_PM‐ST.SU PM‐ST 24‐HR ALL 1ST 0.20107 568938.58 4453822.6 378.7 436.9 0 7081324 Beaver_Valley_2007.SFC 83 1 40AerMod 13350 Shell Franklin Class I Significance_2008_PM‐ST.SU PM‐ST 24‐HR ALL 1ST 0.21069 588800.58 4464383.4 375.2 375.2 0 8092824 Beaver_Valley_2008.SFC 83 1 40AerMod 13350 Shell Franklin Class I Significance_2009_PM‐ST.SU PM‐ST 24‐HR ALL 1ST 0.14874 588800.58 4464383.4 375.2 375.2 0 9022424 Beaver_Valley_2009.SFC 83 1 40AerMod 13350 Shell Franklin Class I Significance_2010_PM‐ST.SU PM‐ST 24‐HR ALL 1ST 0.18756 588800.58 4464383.4 375.2 375.2 0 10030424 Beaver_Valley_2010.SFC 83 1 40
4/14/14 ‐ Shell Franklin Class I SIL Model ResultsPollutant Average Group Rank Conc. Background Total Standard % Standard Analysis CommentNOx ANNUAL ALL 1ST 0.02 NA 0.02 0.1 21% Class I Significance
PM‐LT ANNUAL ALL 1ST 0.01 NA 0.01 0.2 6% Class I SignificancePM‐ST 24‐HR ALL 1ST 0.21 NA 0.21 0.3 70% Class I SignificanceNotes:1) NO2 impact includes ARM adjustment of 0.75.
2/8/14 ‐ Shell NAAQS Analysis ResultsModel File Pollutant Average Group Rank Conc/Dep East (X) North (Y) Elev Hill Flag Time Met File Sources Groups ReceptorsAerMod 13350 Shell Franklin NAAQS_5yrs_NO2.SUM NO2 8TH‐HIGHEST MAX DAILY 1ALL 1ST 3644.0311 554050 4500600 230.12 352.23 0 5 YEARS Beaver_Valley_6_10.SFC 57 3 9384
2/8/14 ‐ Shell NAAQS Analysis ResultsPollutant Average Group Rank Conc. Background Total Standard % Standard Analysis CommentNO2 8TH‐HIGHEST MAX DAILY 1ALL 1ST 3644.0 NA 3644.0 188 1938% NAAQS Shell not significant at exceedenceNotes: 1) NO2 background from Beaver Falls added to AERMOD results within the model. 2) Shell does not cause or contribute to exceedence. Maximum Shell impact as paired in time and space with an existing exceedence is 5.96 ug/m3. See MAXDCONT output.
Visual Effects Screening Analysis forSource: Shell
Class I Area: Raccoon Creek
*** Level-1 Screening *** Input Emissions for
Particulates 47.90 LB /HR NOx (as NO2) 74.60 LB /HR Primary NO2 0.00 LB /HR Soot 0.00 LB /HR Primary SO4 0.00 LB /HR
**** Default Particle Characteristics Assumed
Transport Scenario Specifications:
Background Ozone: 0.04 ppm Background Visual Range: 20.00 km Source-Observer Distance: 16.00 km Min. Source-Class I Distance: 23.00 km Max. Source-Class I Distance: 23.00 km Plume-Source-Observer Angle: 11.25 degrees Stability: 6 Wind Speed: 1.00 m/s
R E S U L T S
Asterisks (*) indicate plume impacts that exceed screening criteria
Maximum Visual Impacts INSIDE Class I AreaScreening Criteria ARE NOT Exceeded
Delta E Contrast =========== ============ Backgrnd Theta Azi Distance Alpha Crit Plume Crit Plume ======== ===== === ======== ===== ==== ===== ==== ===== SKY 10. 146. 23.0 23. 2.00 1.565 0.05 0.012 SKY 140. 146. 23.0 23. 2.00 0.306 0.05 -0.010 TERRAIN 10. 146. 23.0 23. 2.00 0.043 0.05 0.000 TERRAIN 140. 146. 23.0 23. 2.00 0.010 0.05 0.000
Maximum Visual Impacts OUTSIDE Class I AreaScreening Criteria ARE Exceeded
Delta E Contrast =========== ============ Backgrnd Theta Azi Distance Alpha Crit Plume Crit Plume ======== ===== === ======== ===== ==== ===== ==== ===== SKY 10. 20. 10.5 149. 2.00 2.308* 0.05 0.018 SKY 140. 20. 10.5 149. 2.00 0.531 0.05 -0.015 TERRAIN 10. 1. 1.0 168. 2.00 2.686* 0.05 0.029 TERRAIN 140. 1. 1.0 168. 2.00 0.736 0.05 0.029
Appendix D Information contained in this appendix constitutes Trade Secret and/or Confidential
Proprietary Information as defined in the Pennsylvania Right to Know Law
THIS APPENDIX HAS BEEN REDACTED
FROM THIS COPY OF THE PLAN APPROVAL APPLICATION
CONFIDENTIAL
APPENDIX E
25 PA. CODE §127.205(5) ANALYIS
1. Introduction
Pennsylvania air regulations, 25 Pa. Code §127.205(5), require that a major new or modified
facility provide an “analysis … of alternative sites, sizes, production processes and
environmental control techniques, which demonstrates that the benefits of the proposed facility
significantly outweigh the environmental and social costs imposed within this Commonwealth as
a result of its location, construction or modification.” This appendix provides the required
§127.205(5) analysis based on information available as of the date of this Plan Approval
application. Certain additional environmental and economic evaluations are anticipated to be
completed during the period when this Plan Approval application is under review, and Shell will
supplement the information contained in this appendix as appropriate to reflect the results of
those evaluations.
2. Analysis of Alternative Sites, Sizes, Production Processes and Environmental
Control Techniques
The fundamental Project purpose is to develop a petrochemical facility in the northeastern
United States that is capable of utilizing locally available ethane, a component of the liquids-rich
natural gas being produced in the western half of the Marcellus Shale and in the Utica Shale, to
make various grades of polyethylene, providing a critical material to the wide range of
polyethylene users in the region. Project alternatives (sites, processes, sizes, and environmental
control techniques) have been evaluated to minimize and mitigate environmental impacts.
2.1 Alternative Sites
Currently, most ethane cracking/ethylene and polyethylene manufacturing capacity is located in
the U.S. Gulf Coast region, a considerable distance from both the ethane producing areas of the
Marcellus/Utica Shales and many of the polyethylene using industries of the Northeastern and
Midwest regions. A fundamental objective of the Project was to site the facility in that portion of
the northeastern U.S. with relative proximity to both ethane sources associated with the “wet
gas” sections of the Marcellus and Utica formations, and to polyethylene customers. Potential
sites outside the region (such as another site along the Gulf Coast) would necessitate
development of new pipeline capacity transport ethane derived from the Marcellus and Utica
shales more than 1,000 miles, and in turn require transportation of the polyethylene back via rail,
truck or barge to the region’s polyethylene users.
Accordingly, the Project’s siting process focused on the Appalachia region in Ohio,
Pennsylvania and West Virginia. With respect to potential sites in the Appalachia region, Shell
employed a detailed site selection process utilizing multiple criteria in identifying a number of
potential sites before ultimately choosing the proposed site. As discussed below, key factors
included site size and constructability (a minimum of 250 acres); safety; relative environmental
impacts; land use compatibility; access to transportation infrastructure, including pipelines,
marine, rail and road; the availability of skilled local labor, both for construction and operation;
and access to the power grid. The governors of the target states also expressed a preference for
building the facility on a “brownfield” (former or existing industrial) site, redeveloping it for the
new use.
Starting with 44 potential sites in three states, each location was reviewed based on its ability to
satisfy key criteria. A short list of four potentially acceptable sites was derived.
Further assessments were conducted of the four sites. The selected site in Potter and Center
Townships, near Monaca, Pennsylvania scored highest on virtually all criteria, including safety
and environmental, land acquisition, workforce, community, constructability and operating costs.
The advantages of the selected site include:
• Logistical access – For safety and logistics, the Project’s construction and operations
depend on suitable transport options via ship, barge, road, rail and pipeline. The
preferred site satisfies these requirements. The site is located less than one mile from
a four-lane interstate, minimizing impacts on local traffic and road safety concerns.
The Ohio River will provide transport for construction supplies, removing traffic
from roads, and rail will be a key conduit for supplies and products.
• Lowest risk to public safety from traffic – Due to the volume of worker traffic and
movement of materials by truck during construction and truck traffic during
operations, the Project requires proximity to highway transport for access and to
ensure public safety. Of the final sites evaluated, the preferred site was located
closest to an interstate. Certain road upgrades and expansions will be warranted,
particularly for the construction phase, and the Project is proactively working with
local and state authorities to implement those upgrades.
• Fewest residential communities in/near site – Of all the top-ranked sites, the
preferred site is surrounded by the fewest number of residential and commercial
neighbors on its fenceline. The Project has obtained options to purchase property
from the few nearby residences and businesses to ensure an appropriate safety buffer.
This location, in an existing industrial area, will limit possible disturbances to the
surrounding community (such as noise, light, and traffic). The Project also considered
broad environmental justice factors to determine whether any of the final sites
presented considerable differences in sensitivity to industrial development. The
preferred site’s characteristics had the least potential environmental justice impacts.
• Minimal environmentally sensitive areas –
o The selected site is a brownfield location that will be redeveloped and addressed
under Pennsylvania Act 2 requirements for the new use. Project development also
will provide a long-term caretaker to manage the environmental impacts that have
accrued over a century of industrial use.
o Because of the site’s long history of industrial use in an industrial corridor, no
critical habitats for any threatened or endangered species as listed by the US Fish
& Wildlife Service or the state were identified on or adjacent to the site during
site selection evaluation.
o A Pennsylvania Natural Diversity Inventory (PNDI) search identified two types of
freshwater mussels listed as Special Concern Species by the Pennsylvania Fish
and Boat Commission as potentially present in the Ohio River. During an
evaluation of areas to be used for docks or other purposes, and working in
accordance with regulatory guidelines, trained crews found and relocated
specimens of these mussel species to undisturbed locations.
o The site includes approximately five acres of wetlands, which will be replaced in
accordance with regulatory guidelines. Site construction may impact several
streams which traverse the site, and the Project is working with regulatory
authorities on appropriate mitigation measures, including creating, recreating,
enhancing and preserving in-kind habitats. Planned mitigations also will help
better control run-off from the site into the river and groundwater.
• Water supply – The site’s proximity to the Ohio River provides access to the water
supply needed for facility operations. Through use of recirculating cooling water
systems, the Project water demand is estimated to be approximately 10 million
gallons per day (MGD), down from historic highs of more than 75 MGD withdrawn
at this location. Project withdrawals are minimal in comparison with Ohio River
flows and will not impact local supplies. The Project will also be able to use the
existing water intake structures, minimizing additional disturbance to the river.
• Industrial-skilled labor pool – Because of the size and composition of the Project’s
anticipated work force, the site’s location in the “labor pool nexus” provides the
requisite access to a large pool of potential employees within a one-hour commute.
The Project will employ 400 workers once operational and anticipates needing up to
10,000 workers at peak construction.
2.2 Alternative Sizes
The proposed ethylene/polyethylene manufacturing facility would include an ethane cracker with
an approximate annual average capacity of 1.5 million metric tons of ethylene; three
polyethylene units, including two gas-phase and one slurry unit, with a combined annual
production of approximately 1.6 million metric tons; and ancillary units including a cogeneration
unit, storage, logistics, cooling water facilities, industrial waste water treatment plant, emergency
flares, buildings and warehouses.
The facility size was determined by Shell’s goal to develop an integrated and cost-competitive
Project that uses as much local ethane as possible to produce polyethylene for use by regional
manufacturers. The size of available suitable sites in the region dictated use of a single-train
cracker. In turn, technology constraints determine the maximum output available with a single-
train ethylene cracker design.
One integrated facility of the proposed size will result in less air emissions and a smaller
environmental footprint in terms of land use, water, waste, biodiversity, community and other
impacts, than multiple smaller facilities producing an equivalent amount of product using a
similar volume of ethane. From an investment perspective, a single large facility also provides
economies of scale and a better return on investment.
2.3 Alternative Production Processes
The Project utilizes a series of processes, including (1) a cracker process to convert ethane to
ethylene, (2) a gas-phase polyethylene process, and (3) a slurry polyethylene process. The gas-
phase and slurry polyethylene technologies produce polyethylene with different grades and
characteristics. The Project has sought to use proven technology with high efficiency. Shell
evaluated global licensing suppliers of proven technology, evaluating the vendors for health,
safety and environmental performance, appropriateness of processes for the Project, and
demonstrated ease and reliability of operations. The technologies selected provide the most
energy efficient technology, producing the least emissions.
There is only one commercially viable technology to make ethylene from ethane, which is the
cracker process proposed for this Project. The cracker process uses very high temperatures, in
the presence of steam, to break up the ethane molecules and rearranging the atoms to form
ethylene. While research is being conducted with regard to processes to make ethylene from
other feedstocks such as methane or ethanol, none of these technologies are yet ready for
commercial development. While it is possible to produce ethylene from naphtha, extracted from
crude oil or from heavy oil, an alternative feedstock would change the basic definition of this
Project, which is intended to provide a beneficial use of ethane produced in conjunction with
shale gas extraction in the region. The Project is employing several measures to reduce
emissions from the cracker operations, including reuse of tail gas, supplemented by natural gas
as needed, to fuel the furnaces. Tail gas is a combination of methane and high percentages of
hydrogen, and is created as a byproduct of the ethylene production process. The use of hydrogen-
rich tail gas as fuel serves to reduce carbon dioxide emissions.
The Project is proposing use of a combination of gas-phase and slurry processes for conversion
of ethylene to polyethylene. Shell evaluated a number of alternatives before selecting industry-
leading technology providers based on efficiency, cost, flexibility and environmental impacts.
Again, the selected vendors provide the most energy efficient technology with the least
emissions. Shell has licensed a gas phase technology (to make LDPE and LLDPE) which is
currently used to produce nearly 25 percent of the world’s polyethylene including nearly 100
reactor lines in 25 countries. The licensed process can produce a wide range of commercial
products using just three pieces of major rotating equipment: a cycle gas compressor, a vent
recovery compressor and a pelleting system, in a process that eliminates the need for
intermediate storage, reducing costs and the facility’s footprint. Shell is similarly licensing a
proprietary slurry phase process from a technology provider who has more than 50 years of
experience in the market. Its slurry phase technology can produce a wide range of products for
low capital and operating costs.
The Project requires substantial quantities of steam and electricity for the ethane cracker,
polyethylene production and ancillary processes. Alternatives to provide such steam and
electricity include (1) installation of gas fired boilers to produce steam alone, coupled with
purchase of electricity from the grid; (2) purchase of electricity from the grid to heat boilers to
produce steam, as well as provide necessary Project power; and (3) installation of on-site natural
gas-fired combined cycle generation units capable of producing both electricity and steam in
proximity to the manufacturing process.
Given that the Project requires significant quantities of steam, on-site natural gas-fired combined
cycle (NGCC) units are the most energy efficient approach. NGCC units utilize gas fired
turbines driving electric generators, with the exhaust gas from the turbines routed to a heat
recovery steam generator (HRSG) that produces steam for the Project along with driving a steam
turbine linked to an additional electric generator. In terms of thermal efficiency (that is, the
efficiency of converting fuel energy to power), NGCC and NGCC cogeneration units are
significantly more efficient than conventional steam electric generation technology.
The alternative of using separate on-site gas-fired boilers to produce steam, while technically
feasible, would be less efficient, while necessitating acquisition of electric energy from a
regional grid which has a higher percentage of coal-fired and less-efficient oil or gas-fired
electric generating facilities with higher emission rates per unit of heat input. The “all electric”
option, purchasing electricity to heat boilers for steam generation plus the Project’s electric
power needs, is even less efficient, and again would rely on power generation from a mix of
generation facilities with higher NOx, SO2, PM and CO2 emission rates.
2.4 Alternative Environmental Control Techniques
Air emissions from the facility will be reduced and controlled through a combination of process
design and post-emission control technologies as described in Section 5 of this plan approval
application, which is incorporated in this analysis by reference. As noted in Sections 4 and 5,
facility processes are subject to a series of new source performance standards (NSPS) and
national emission standards for hazardous air pollutants (NESHAP) established under the
Federal Clean Air Act for particular industrial categories. Facility emissions of certain air
pollutants (such as nitrous oxides or NOx and PM2.5) are subject to non-attainment area new
source review, which includes a requirement for achieving the lowest achievable emissions rate
(LAER). For other pollutants, such as carbon monoxide (CO), nitrogen dioxide (NO2),
particulates (PM) and greenhouse gases, the facility is subject to prevention of significant
deterioration (PSD) best available control technology (BACT) requirements. Both LAER and
BACT are determined on the basis of a “top-down” analysis of potentially available control
technologies. Emissions of certain contaminants classified as hazardous air pollutants under
federal rules are subject to maximum available control technology (MACT), and the facility
overall is subject to Pennsylvania best available technology (PaBAT) requirements. Section 5 of
the plan approval application contains a detailed description of the alternative emission control
technologies considered, demonstrating how the selected technologies meet applicable NSPS,
LAER, BACT, MACT and PaBAT requirements.
3. Project Benefits
3.1 Economic Benefits
The Project is expected to provide significant benefits to Pennsylvania and the surrounding
region. As a starting point, the Project will take ethane, a byproduct from ongoing natural gas
production in the Marcellus/Utica region, and convert that resource into ethylene and
subsequently various grades of polyethylene, the key building block for a variety of plastic
products produced by industries across the region. The proposed complex would be the first
major U.S. project of its type built outside the U.S. Gulf Coast region in 20 years, and would
bring ethane to polyethylene manufacturing capabilities much closer to both the source of ethane
and to polyethylene customers in the region.
The multi-billion-dollar Project will deliver large and tangible benefits for the local and state
economies:
• 400 operational jobs, up to 10,000 at peak construction and thousands of indirect jobs;
• increased household earnings;
• additional tax revenues; and
• redevelopment of existing industrial “brownfield” sites.
If the Project is built, Shell will work to enhance local economic opportunities, including hiring
and buying locally. The Project is establishing a plan to provide full and fair opportunity to
qualified local and local minority workers to obtain employment with Shell and its contractors,
and full and fair opportunity to local businesses to compete for the provision of services for
which they are technically qualified.
The Pennsylvania Economy League of Greater Pittsburgh has evaluated the Project’s expected
economic impacts during the year of peak construction and during one year of plant operation. It
estimated the following impacts would likely flow from the Project to the 10-county region:
• Up to 10,000 direct jobs during peak construction and up to 18,000 total
• $2.8 billion in economic output that year
• 400 direct operational jobs and 2,000-8,000 total
• $4.8 billion total annual economic output from operations
Additional economic impact evaluations will e conducted, the results of which will be submitted
when available to supplement the analysis provided this Appendix.
3.2 Environmental Benefits
The Project will provide substantial environmental benefits through the redevelopment of an
existing brownfield site, including several properties that have been used for many decades for a
variety of industrial purposes. The site includes (1) approximately 200 acres used for zinc
smelting for almost a century, and (2) two adjacent abandoned sites, referred to as the “brick
yard” and “mall lot”. Project development will involve demolition and remediation, to the extent
required, of the former smelter site, together with capping and stabilization of other areas, and
long term stewardship of the site. Such brownfield redevelopment not only addresses concerns
as to future stabilization and productive use of the site, but also is anticipated to reduce future
public costs that would otherwise have been incurred to address previously abandoned
contaminated sites.
Providing excess electricity from the energy efficient natural gas-fired Cogen Units will help
improve air quality by reducing the grid’s carbon dioxide equivalent intensity.
Finally, by building a Project close to both supply and markets will minimize the environmental
impacts associated with transporting ethane via pipeline to the U.S. Gulf Coast for processing
and shipping the polyethylene back to the northeastern region via truck, rail, or barge. This
includes avoiding the significant capital required to build new pipeline capacity and the
environmental effects of such construction on water, wetlands, cultural heritage, air and other
impacts.
3.3 Community Benefits
In addition to the economic and environmental benefits discussed above, the Project will provide
significant community benefits. As part of its company values, Shell contributes to the
communities in which it operates with social investments that are sustainable, deliver lasting
benefits, are self-supporting after start-up, involve local support and have a measurable positive
impact, meeting community needs. Such Projects focus on education, civic/community,
environment, health and human services, and provide benefits to communities in close proximity
to Shell Projects. Shell also fosters and supports a culture of strong volunteerism by its
employees. Annually, Shell employees donate numerous hours to community Projects.
Significant community benefits are anticipated from training and education programs conducted
during both the construction and operation phases of the Project. Shell will require a significant
workforce during both construction and operations. The Project’s major and general contractors
are expected to employ up to 10,000 workers at peak construction. Training required for these
positions, including on-the-job training, training in certificate and apprentice programs and
accreditations from skilled craft certifying bodies, are expected to add to the skill sets of the
community workforce. Once operational, the facility will employ 400 workers in jobs ranging
from craft / maintenance to process technology and operations as well as other technical,
administrative and management jobs. Many of these jobs will require two-year associates
degrees and others undergraduate diplomas. Shell and its major contractor(s) will be working
with local schools, community and technical colleges, and local and regional leaders in the
construction industry, to support education and training programs that prepare students for
careers in construction, engineering and plant operations.
4. Minimization of Air Quality, Other Environmental Impacts and Social Costs
As detailed in the applications filed for other environmental permits required for the Project,
Shell is engaged in ongoing efforts to identify, evaluate, and avoid and/or mitigate environmental
impacts. To briefly summarize:
• Air emissions will be controlled and minimized through use of technologies described in
Section 5 of this Plan Approval application, meeting all applicable BACT, LAER and
PaBAT standards. Air quality modeling, applying conservative assumptions, indicates
that the resulting emissions will not cause or contribute to exceedance of any national
ambient air quality standard or any allowable incremental increase in ambient
concentrations of regulated pollutants. Flares, used to safely mange gases during non-
standard operating conditions or emergencies, are designed in accordance with accepted
best industry standards. The emergency flare tower system, although visible to the
community for some distance from the facility, is expected to be used only during rare
events, such as complete loss of power to the facility.
• The facility will withdraw approximately 10 million gallons per day from the Ohio River,
or approximately 15 percent of the total water demand from past-on-site operations. To
reduce water use, the Project will be utilizing a recirculating cooling water system. The
Project anticipates use of the existing site intake system, with withdrawal rates and
screens that meet the requirements of §316(b) of the Federal Clean Water Act to reduce
entrainment and impingement of aquatic organisms. The intake design and operation is
subject to review as part of the NPDES Permit for the facility.
• Storm water discharges during construction activities will be managed in accordance with
an erosion and sedimentation control plan and NPDES stormwater construction permit
approved by PaDEP under 25 Pa. Code Ch. 102.
• Process and stormwater discharges from the Project site will be managed under an
NPDES permit issued by PaDEP, and will be managed to meet all applicable technology-
based and water-quality based effluent limits to protect instream and downstream water
uses.
• Emergency and contingency plans will be developed and implemented in accordance
with the federal Spill Prevention Control and Countermeasure (SPCC) and PaDEP
guidelines for Environmental Emergency Response Plans, to include measures to avoid,
contain and respond to potential spills or accidental releases.
• Site development will involve filling of approximately 4.59 acres of wetlands and
placement of certain smaller streams traversing the site into stream enclosures or culverts
under permits issued by PaDEP pursuant to 25 Pa. Code Ch. 105 and by the U.S. Army
Corps of Engineers under Federal Clean Water Act §404. Mitigation (in the form of
wetland replacement or enhancement) will be provided as required by state and federal
regulations.
• Wastes generated will be managed (stored, treated, recycled and/or disposed) in
accordance with strict federal and state regulations. The Project has been designed to
recycle and reuse materials where practicable to minimize waste generation.
• Safety is addressed at all aspects of Project development and operation, following Shell’s
rigorous, systematic approach to process and operational safety. A comprehensive,
integrated safety system will be implemented to prevent accidents and incidents, and to
provide for appropriate response to events.
• Shell will maintain its own highly-trained team of emergency responders at the facility
for quick response, as well as a fire house with fire-fighting equipment, spill response
capabilities, and an on-site medical clinic. Shell will continue to confer and work with
local police, fire and other emergency response agencies on future cooperative endeavors,
including Shell’s active participation in the area’s mutual aid arrangements.
• Noise, lighting and vibration issues have been and will be addressed by a series of
studies, and are substantially mitigated by the fact that the site is located within an
already well-established industrial area with significant surrounding buffers to the nearest
non-industrial neighbors.
• Historic and cultural resource issues are being addressed through assessments submitted
to, and ongoing consultations with, the Pennsylvania Historic and Museum Commission
(the State Historic Preservation Officer).
• A traffic study has been conducted to evaluate the impact of Project construction and
operation on local traffic and road safety, with improvements recommended to address
and mitigate those impacts.
• Wildlife impacts are anticipated to be minimal, because the Project is utilizing an existing
industrial site that has been occupied for nearly a century. Two types of freshwater
mussels, listed as special concern species by the Pennsylvania Fish and Boat
Commission, were identified in the area to be used by docks, and trained crews found and
relocated specimens of those mussel species to undisturbed locations in accordance with
regulatory guidelines. Ospreys, which are not considered protected or endangered
species, have built nests in some electric transmission towers within the site vicinity.
Those power lines will be moved as a result of site development, but such work will be
conducted when the nests are not in use.
• The Project is located within areas designated as industrial zones by applicable township
zoning ordinances. The Project is consistent with local zoning and land development
plans.
• The Project will engender some level of impact to community services demands,
including police, fire and other emergency services. Because Shell is intending to
implement an on-site security force, on-site fire department, and on-site health clinic, the
impacts to local emergency response agencies will be mitigated. Throughout the process
of developing emergency response plans, Shell will be consulting with applicable
response agencies to assess current resources and capabilities and measures appropriate
to supplement those capabilities. Through that process, potential community service
impacts are expected to be mitigated.
• PaDEP’s Environmental Justice Public Participation Policy establishes requirements for
expanded public participation activities for certain permits authorizing Projects within or
within an “area of concern” around “Environmental Justice Areas,” defined as any census
tract with 30 percent or greater minority population or 20 percent or greater at or below
the poverty level. Three such Environmental Justice Areas are located in Beaver
County. However, none of the three areas are within a half-mile radius of the site, which
is one of the criteria defining an “area of concern.” The Project is consulting with the
community and PADEP to determine if any such area is likely to experience significant
impacts from the Project. Irrespective of that determination, however, Shell’s plans for
public participation in neighboring communities are believed to meet the guidelines for
enhanced public participation both within and beyond potential Environmental Justice
Areas.
Shell places a high value on community consultations and collaboration. The company will
continue to engage with the surrounding communities and other interested parties during Project
development, construction and operation. The purpose of such efforts is to share information
about the Project, understand community interests and work together to enhance potential Project
benefits and identify and address potential concerns. Information from this on-going
consultation process will be utilized to identify, evaluate and if necessary mitigate potential
community and environmental impacts.
5. Comparison of Project Benefits to Environmental and Social Costs
The proposed Shell ethylene/polyethylene manufacturing facility in Potter and Center
Townships, near Monaca, in Beaver County, Pennsylvania, would deliver real and quantifiable
benefits for the community, state and regional, including (1) 400 operational jobs, up to 10,000
at peak construction and thousands of indirect jobs; (2) increased household earnings; (3)
additional tax revenues; and (4) redevelopment of existing industrial “brownfield” sites. Shell
has conducted extensive work to date to identify and assess potential environmental and social
effects from this proposed Project, with substantial efforts throughout the planning process to
avoid, minimize and mitigate impacts to the extent possible and to enhance positive benefits.
Based on all currently available information, while there are environmental and social costs
associated with this Project – as there are with any major Project – on balance, the combination
of the Project’s benefits with Shell’s commitment to manage and mitigate those impacts results
in net benefits that significantly outweigh the environmental impacts and social costs resulting
from the Project’s location, construction and operation.
Appendix FAdditional Support Material
This appendix contains the following items:
1. General Information Forms2. Compliance Review Forms3. Municipality Notices and Receipt of Deliveries4. Cultural Resource Notification Submittal Information5. Burner NOx From Ethylene Cracking Furnaces6. RBLC Tables for PaBAT Analyses7. Copy of Permit Fee Check
From: Bellew, Serena [mailto:[email protected]] Sent: Wednesday, April 23, 2014 1:53 PMTo: Lingle, DavidSubject: PA SHPO review for Air Permit Beaver Co. project Dear Mr. Lingle, PHMC-BHP received an August 22, 2013 request to initiate consultation under Section 106 of the National Historic Preservation Act for the Proposed Petrochemicals Project, Beaver County, Pennsylvania. This project was submitted by URS on behalf of Horsehead Corporation and Shell Chemical. A second project submittal was sent to our office for the same undertaking as a result of the need for a Section 402 US Corps of Engineers permit. PHMC-BHP subsequently assigned Environmental Review (ER) No. 2013-2037-007 G & H for the overall project/undertaking. The US Corps of Engineers is considered the lead Federal agency by PHMC-BHP for the purposes of the Section 106 review process on the above referenced Beaver county project, so no additional information including updating or amending the original application and notice, is required for the project's Air Permit Application, as potential impacts to historic properties are being addressed via the US Corps Permit project review by PHMC-BHP. Thank you, Serena Georgia Bellew | Director & Deputy State Historic Preservation OfficerBureau for Historic Preservation | Pennsylvania Historical and Museum Commission400 North Street, 2nd Floor | Harrisburg, PA 17120-0093Phone: 717.705.4035 | Fax: 717.772.0920
Cultural Resource Notification Submittal Information
BURNER NOx FROM ETHYLENE CRACKING FURNACES Robert G. Kunz
RGK Environmental Consulting, L.L.C. Hillsborough, North Carolina
Abstract: Allowable emission limits for nitrogen oxides (NOx) remain under scrutiny as regulatory agencies continue to assess the impact of NOx emissions on ambient air quality for ground-level ozone. The ozone is formed in the atmosphere by the sunlight-induced reaction of NOx with certain hydrocarbons. It is understandable that operators of affected combustion sources would prefer to achieve compliance with any such NOx reductions by means of burner modifications, rather than through more costly and complex post-combustion controls, such as selective catalytic reduction (SCR). For smooth project execution, accurate prediction of the extent of burner-NOx reduction is critical. However, computational fluid dynamics (CFD), used to model flame patterns, furnace temperatures, and the like, has done a poor job in predicting burner NOx. Likewise, burner testing in a manufacturer’s pilot facility often produces low estimates for NOx when compared to a full-scale furnace. A viable alternative is an empirical approach based on kinetic theory and validated by numerous field data. This paper shows the results from a new correlation of NOx emissions for ethylene cracking furnaces. It is derived from an established NOx correlation for commercial steam-methane reformer (SMR) furnaces, while recognizing the differences in fuels and furnace conditions between the two processes. It uses adiabatic flame temperature (AFT), excess furnace oxygen (O2), and furnace temperatures. Calculations can be accomplished rapidly and allow one to compute absolute values of NOx, explore changes in NOx from a base case, and explain experimental observations. Calculated values compare favorably with available NOx data reported for commercial ethylene furnaces spanning a wide range of conditions. The correlation can also be tailored to fit individual furnace data for even better agreement.
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Introduction
Accurate prediction of NOx emissions before implementation of burner modifications to comply with changing regulatory mandates will avoid unpleasant surprises in the field after start-up. To that end, this presentation provides a tool to estimate NOx and/or changes in NOx from properly operating furnace burners over a wide variety of conditions. Step-by-step details of its development have been discussed previously.1 As before, the following caveat applies…
Disclaimer (“Some restrictions apply; batteries not included; your mileage may vary”)
The information contained herein is offered in good faith but without guarantee, warranty, or representation of any kind (expressed or implied) as to its usefulness, correctness, completeness, or fitness for any particular purpose. The user assumes all risk for its implementation and should seek independent professional verification of its accuracy. The author assumes no responsibility and shall not be liable for any loss of profit nor any special, incidental, consequential, or other damages which may result from the use of any of the information contained in this presentation, be it oral or written. Any statements concerning design, construction, operation, what constitutes regulatory compliance, and/or how to achieve such compliance should not be construed as recommendations on the part of the author and/or his organization.
Regulatory Considerations The majority of ethylene production in the United States is concentrated along a system of interconnected pipelines2 on the Texas-Louisiana Gulf Coast.3 Canadian production is contained in the provinces of Alberta, Ontario, and Quebec.3 A number of the U.S. ethylene plants are located in ozone nonattainment areas. In the Houston-Galveston-Brazoria (HGB) Nonattainment Area of Texas, especially, plants are faced with having to comply with increasingly more stringent emission-control limits for NOx. Along with certain hydrocarbons, NOx is a critical ingredient in the formation of ground-level ozone. Hydrocarbons specifically identified as “bad actors” in ozone formation include ethylene, propylene, butanes, and butadiene,4 emissions of which are also being closely regulated. As explained later in the text, ethylene pyrolysis furnaces typically fire what are essentially mixtures of hydrogen (H2) in methane (CH4),5 the primary constituent of natural gas. Historical NOx emissions from conventional burners in ethylene-plant furnaces are stated as 100-120 parts per million (ppm)6 and 220-250 ppm for a “hydrogen-rich” fuel gas.7 Test results for low-NOx burners range from 55-60 ppm for natural gas and from 70-100 ppm for 20-70% H2 in the fuel gas, presumably using ambient air for combustion; a typical range for ultra low-NOx burners was quoted in 1993 as 25-40 ppm.7 A more recent emission inventory for the HGB area indicates a range of 0.06-0.25 lb/MMBtu, based on the higher heating value (HHV) of the fuel.8 With certain exceptions, the current standard for pyrolysis reactors in the HGB area is 0.036 lb/MMBtu (HHV).9
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The relationship between ppm NOx (dry), corrected to 3% O2 on a dry basis in the flue gas (ppmd @ 3% O2, dry), varies slightly with the composition of the fuel being burned. The NOx standard of 0.036 lb/MMBtu (HHV) corresponds to a NOx concentration of 30 ppmd @ 3% O2 (dry) for natural gas/methane and roughly 44 ppmd @ 3% O2 (dry) for pure hydrogen. Values for the standard are shown in Figure 1 for the full range of methane-hydrogen mixtures. Other sets of corresponding values between ppmd @ 3% O2 (dry) and lb/MMBtu (HHV) for a given gas composition can be obtained by proration. The general relationship between ppm, pounds per hour (lb/hr), and lb/MMBtu has been discussed previously.10
28
30
32
34
36
38
40
42
44
46
0 10 20 30 40 50 60 70 80 90 100
Percent Hydrogen in Methane Fuel
ppm
d @
3%
O2
(dry
)
Figure 1. NOx Concentration Equivalent to 0.036 lb/MMBtu (HHV)
Additional NOx emission standards and the ground-level ozone standards in effect at the time of the previous presentation are discussed there in greater detail.1 It is still fair to say that the situation will continue to evolve.
Technical Considerations Driven by the plant operator’s desire to achieve NOx compliance in the most cost effective manner, burner developments have focused on making the latest regulatory NOx targets within reach using burners. However, lower NOx is often accompanied by flame instability – rollover and impingement on the furnace tubes11-13 – unless and until corrected by redesign. Part of the (re)design effort for ethylene-furnace burners has involved computational fluid dynamics (CFD) to study burner flame patterns and temperature profiles.11-14 CFD has been employed for steam-methane reformer (SMR) furnaces as well.15 Although CFD has proven to be a useful tool in the cited studies, it is unable to predict burner and furnace NOx emissions.11-14 That has prompted our investigation to develop a NOx-prediction technique for ethylene furnaces as a complement to CFD. The resulting model is an extension of a successful correlation for SMR-furnace burner NOx, whose functional form is derived from theory, with empirical constants based on experimental data. This approach is
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a proven technique for estimation of physical property data.16 The new correlation also turns out to be effective in its own right, independent of CFD, for a variety of situations.
NOx Correlation for SMR Furnace Burners The original correlation was first presented at the 1992 NPRA Annual Meeting17 and has been elaborated upon in a series of subsequent presentations and articles as more data have become available.10,18-23 Its generalized form [ln(NOx/O2) = A – B.10,000/AFT(°R)] is shown in Figure 2, with constants specified in the figure for conventional and low-NOx burners. NOx at the furnace is in parts per million by volume; furnace O2 is in vol. %. Concentration units for NOx and O2 at furnace flue-gas conditions must be consistent, either both wet or both dry. The existing generalized correlation contains lines only for conventional burners and low-NOx burners. A patient and careful count shows that these relationships are derived from regression of seventy data points. The two lines have come out virtually parallel, as one would hope, to avoid the anomaly of their crossing at some point along the x-axis.
0.0
1.0
2.0
3.0
4.0
5.0
2.3 2.5 2.7 2.9 3.1
10,000/AFT(oR)
ln [
NO
x (p
pm) /
O2
(%) ]
Conventional BurnersEquation of line: y = 12.6-3.58x
R2 = 83%s = 0.2757
Low-NOx BurnersEquation of line: y =12.2-3.60x
R2 = 77%s = 0.2474
Figure 2. SMR NOx Correlation Its functional form is derived from Zeldovich kinetics24 for the formation of nitric oxide (NO) from oxygen (O2) and nitrogen (N2) in the combustion air (thermal NOx). NO is the primary constituent (95%) of NOx along with nitrogen dioxide (NO2) (5%) in furnace combustion. It does not apply to prompt NOx, formed by a more rapid free-radical mechanism, nor to fuel NOx, arising from chemically-bound nitrogen compounds in the fuel. The variables identified were the temperature in the flame, where the thermal NOx reaction takes place, and the excess O2 concentration. The predicted dependence on the N2 concentration turns out not to be statistically significant for combustion with atmospheric air. The correlation employs the adiabatic flame temperature (AFT) for combustion of the given fuel under the specified conditions plus the furnace firebox excess O2, normally measured on a
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wet basis, as the independent variables. Firebox O2 and dry-basis O2 measured at the stack during source testing are not the same if significant infiltration of tramp air occurs in between. The theoretical AFT assuming complete combustion is the temperature attained when a fuel is burned, without mechanical work or gain or loss of heat, to the theoretical end products such as carbon dioxide (CO2) and water vapor (H2O), regardless of any equilibrium condition which might apply;25 it is a function of the heating value of the fuel, the combustion products generated, and the inlet conditions.17 Other research has shown the AFT to agree reasonably well with the actual peak temperature in a combustion flame.26-30 AFT is a useful surrogate for that temperature and therefore serves as a good correlating variable. Similarly, O2 concentration at the furnace exit is a surrogate for oxygen in the flame. Use of an additional parameter, the so-called elusive third variable, such as the furnace firebox temperature at the bridgewall, to reduce the scatter has been discussed.17 The rationale is that the calculated AFT more closely approaches the actual flame temperature the higher the overall temperature being maintained in the surrounding furnace into which the flame radiates. For an individual furnace, one can also improve on the prediction from the generalized correlation.21
Extension of the Correlation to Ethylene Cracking Furnaces The correlation of Figure 2 can be modified to apply to ethylene furnace burners by considering the similarities and differences between those burners and their fuels compared to the burners and fuels in a steam-methane reformer. The development of the new correlating equations, already discussed in great detail elsewhere,1 will only be summarized here. Processes Are Different – A Review SMR Process and Fuels. Steam-methane reforming (SMR) is a commercial process for the simultaneous production of hydrogen and carbon monoxide (CO). In this continuous process, steam and a desulfurized hydrocarbon feed react at elevated temperatures over a solid nickel-based catalyst,31-34 which is contained inside tubes suspended in a furnace.35,36 To maximize the H2 yield for a hydrogen plant, additional steam is provided in one or more shift-converter vessels downstream outside the furnace. Feed is usually natural gas but can also be refinery gas, propane, liquefied petroleum gas (LPG), butane, or straight-run naphtha.31,37,38 The H2 product is separated from the resulting synthesis gas (syngas), a generic term for mixtures of H2, CO, and CO2. In a hydrogen-carbon monoxide plant, where CO is a desired product (along with a hydrogen co-product), the CO is recovered by low-pressure distillation at cryogenic temperatures following CO2 removal by regenerative amine absorption and a drying step.10 In either case, the hydrogen is separated from the syngas in a pressure-swing-adsorption (PSA) unit. Other components in the syngas end up in the PSA purge gas resulting from the periodic regeneration of the PSA unit.22,23 Hydrogen-plant PSA purge gas contains unrecovered H2 plus the non-hydrogen constituents in the syngas – unreacted methane (CH4) excess steam (H2O), CO, CO2, and impurities such as nitrogen (N2) from the feed.17,22,23 Combustible components include H2, CO, and unreacted CH4, the so-called methane slip.35,36 A typical purge gas/natural gas composition can be found in previous publications.10,17,19
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The internally generated PSA purge gas is recycled as fuel to the reformer furnace burners. This purge gas can provide 50 %17 up to 90%17,31 of the fuel requirement for the furnace. The low-Btu hydrogen-plant PSA purge gas containing some 40% CO is supplemented by an auxiliary, or trim, fuel to make up the firing requirement, typically natural gas or refinery fuel gas.22,23 In contrast, the PSA purge gas from a hydrogen-carbon monoxide plant contains about 90% H2 and 10% CO without the high CO2 concentration usually found in hydrogen-plant PSA purge gas.10 Older hydrogen plants, built before the mid-1970s, typically used amine absorption, carbon dioxide removal, and methanation to make a final product of lower hydrogen purity.22-23 This design also produces high purity CO2, which can be liquefied for sale or used in further processing.17,39,40 These older SMR plants without a PSA are fired solely on external fuels. Ethylene Cracking Process and Fuels. In the continuous thermal cracking process for ethylene production, hydrocarbon feed is mixed with steam and reacted inside tubes known as radiant coils suspended in a furnace. The ethylene cracking unit is also referred to as a steam cracker, ethylene cracker, thermal cracker, or pyrolysis furnace.2,6,41,42 Hydrocarbons ranging from ethane, propane, butane, and liquefied petroleum gas (LPG) through naphtha, kerosene, and gas oil can be used as feed.5 Following thermal cracking to the desired conversion, the cracked gas exiting the furnace coils is rapidly quenched and separated downstream into its constituents. Many by-products or co-products are generated in addition to ethylene, with greater amounts formed from the heavier feeds, and the distribution of products is strongly influenced by operating conditions. Components in the cracked gas include ethylene, propylene, butadienes, butanes, butenes, higher olefins, and aromatics as useful products; hydrogen recovered as a product or used as fuel; methane used as fuel; and coke, which lays down on the inside surface of the radiant coils and interferes with the operation. To remove the unwanted by-product coke from inside the radiant coils, elements of the process train must be taken out of service periodically and “decoked” using a mixture of steam and air. The decoking offgas, containing CO, CO2, and carbon particles,6 is either diverted to quench water and a knockout pot2,6,43 and thence to atmosphere, or it is combusted in a firebox.6 This might be the ethylene furnace itself11,43 or some external heater with its own separate stack. The steam-cracking process generates an impure hydrogen-rich gas, which may be purified or upgraded for chemical uses or used as fuel,5 plus an impure methane stream known as methane-rich gas5 or the pyrolysis methane fraction2 that is used as fuel.2 The hydrogen-rich fuel is only 85% to a maximum of 95% pure.5,6 The methane fuel-gas stream consists of 95% methane with some minor impurities of hydrogen, carbon monoxide, and traces of ethylene.6 By-product ethane and propane may also be contained in the fuel.2 In addition, a so-called pyrolysis fuel oil product is obtained from cracking heavier feedstocks.5,41 A lighter cut known as pyrolysis gasoline,5,41 or pygas,41 a gasoline-like liquid high in unsaturated compounds and rich in aromatics (benzene, toluene, xylenes (BTX)),44 is used as a chemical feedstock. An ethylene cracking furnace can also be supplied or supplemented with other fuels available in a petroleum refinery or petrochemical complex.
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But Combustion Is Similar Although the processes are different, the combustion sides are quite similar. Both processes:
• Employ a furnace to supply the heat of reaction. • Use many small burners to deliver the required heat as uniformly as possible.45 • Must be capable of burning significant concentrations of hydrogen in the fuel mixture • Must be designed to prevent flame rollover and impingement on the tubes/coils.
Firebox Temperatures Are Different It is no secret that ethylene furnaces tend to run hotter than SMR furnaces, and this difference must be accounted for in predicting NOx. In Table 1,46 firebox temperature in an ethylene furnace is typically 1000-1200 °C (~1830-2200 °F).2 In a reformer furnace, flue-gas temperature exiting the radiant firebox, referred to as the bridgewall temperature,33 is 1800-1900 °F (~980-1040 °C).31,37 These figures average about 2000 °F (~1100 °C) and 1850 °F (~1010°C), respectively. Tube-metal temperatures, drawn from multiple sources and shown for information only, may not be completely consistent with the furnace temperatures.
Table 1. Approximate Temperatures in Process Furnaces
Process
Furnace
Tube-Metal
Ethylene
1830-2200 °F
1750-2100 °F
SMR
1800-1900 °F
1600-1925 °F
Adiabatic Flame Temperatures Are Both Different And Similar Adiabatic flame temperatures for typical fuel gases used in SMR and ethylene cracking furnaces are examined below. Adiabatic Flame Temperatures for Typical SMR Furnace Fuels. Adiabatic flame temperatures for fuels containing both hydrogen-plant PSA purge gas and for fuels containing hydrogen-carbon plant PSA purge gas can be found in the cited references.10,17,19 The AFT for a natural gas at various combustion air temperatures is also addressed.17 In summary, with hydrogen plant PSA purge gas (containing about 40% CO2 in the mixture) supplemented by natural gas, the AFT is some 400 °F (222 °C) ± below that for firing natural gas or pure methane alone. Because of this lower AFT, hydrogen plant furnaces have a natural tendency to produce lower NOx. However, hydrogen-carbon monoxide plant purge gas (H2 and CO without the high concentration of CO2) mixed with a natural gas trim fuel produces AFTs 100-200°F (56-111°C) above that of the natural gas/methane reference. Adiabatic Flame Temperatures for Typical Ethylene Furnace Fuels. Typical fuel gases combusted in an ethylene furnace are impure waste gases recovered in the process. These consist mainly of methane and hydrogen with some minor constituents. However, to keep things simple in the calculations that follow, the fuels are assumed to be various
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combinations of pure methane and pure hydrogen. Furthermore, “natural gas,” also a common fuel brought in to fire the furnace, is assumed to be 100% methane. AFTs for combustion of methane, hydrogen, and various mixtures thereof are shown in Figure 3. Its basis is fuel and air temperatures of 60 °F (15.6 °C) and 60% relative humidity for the ambient air. (Unless otherwise stated, that same basis is assumed here throughout.)
2700
2900
3100
3300
3500
3700
3900
4100
0.0 1.0 2.0 3.0 4.0 5.0 6.0Excess O2 ( % wet )
Adi
abat
ic F
lam
eTem
p. (o F)
Lines from Top to Bottom:
100% Hydrogen (H2)80% H2 / 20% Methane60% H2 / 40% Methane40% H2 / 60% Methane20% H2 / 80% Methane 100% Methane (CH4)
Figure 3. Adiabatic Flame Temperatures for CH4 / H2 Mixtures, Ambient Combustion Air As depicted in Figure 3, AFTs are higher as more hydrogen is present in the fuel. The curves are linear in excess O2 up to about 5-6%, although a slightly better fit can be obtained through the addition of a quadratic term. Slope of the line is on the order of 150 °F per %O2 (83 °C per %O2) but increases slightly with increasing hydrogen. The line for methane is essentially the same as that calculated for a typical natural gas in a previous presentation.17 The AFTs calculated for the methane-hydrogen blends fired in an ethylene cracker (Figure 3) are higher than for methane alone. Their AFTs are comparable to those for SMR hydrogen-carbon monoxide plant PSA purge gas (mixtures of H2 and CO) supplemented by natural gas10 and fall within the range of applicability of the SMR NOx correlation (Figure 2). AFT increases as fuel and air temperatures are raised. The effect is more dramatic for combustion air temperature (air preheat) because of the relative amounts of air and fuel taking part in the combustion process. AFTs for combustion of the fuel gases of Figure 3 recalculated for the same starting ambient air and a combustion air temperature of 350 °F (177 °C) are shown elsewhere.1 In round numbers, corresponding values between the cases depicted in Figure 3 and the air-preheat cases are about 200 °F (a delta of 111 °C) higher for preheated air, but the slopes of AFT vs. O2 remain nearly the same.
NOx Correlating Equations For Ethylene Furnaces The proposed correlating equations for NOx from ethylene cracking furnaces derived from the SMR correlation of Figure 2 are shown in Figure 4, with an additional line estimated for ultra
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low-NOx burners.1 The relationship to AFT is assumed to be the same. (The coefficient B, slope of NOx vs. 10,000/AFT(°R), equals 3.6 to two significant figures.) The constant A is taken as 13.0, 12.6, and 11.9, respectively, for conventional, low-NOx, and ultra low-NOx burners to account for a difference in furnace temperatures between the two processes (Table 1). It turns out that about 1½ times as much NOx would be generated from the “average,” or “typical” ethylene furnace compared to the “average,” or “typical” SMR furnace, caused by a difference in furnace temperature alone, everything else being equal. It is interesting to note that the low-NOx burner equation for ethylene furnaces (Figure 4) is nearly the same as the conventional-burner equation for SMRs (Figure 2). The decoking step in the ethylene process is not modeled in this correlation.
0.0
1.0
2.0
3.0
4.0
5.0
2.3 2.5 2.7 2.9 3.1
10,000/AFT(oR)
ln [
NOx (p
pm) /
O2 (%
) ]
Top Line - Conventional Burners Equation of line: y = 13.0-3.6x
Middle Line - Low-NOx BurnersEquation of line: y = 12.6-3.6x
Bottom Line - Ultra Low-NOx BurnersEquation of line: y = 11.9-3.6x
Figure 4. Proposed NOx Correlation for Ethylene Furnaces
Influence of the Variables Oxygen Dependence Oxygen dependence in the NOx correlation is both direct through the ln[NOx/O2] term and indirect through the AFT (Figure 3). The ln[NOx/O2] relationships from Figures 2 or 4 [ln(NOx/O2) = A – B.10,000/AFT(°R)] (1) can be plotted on linear coordinates as NOx vs. O2 for combustion of a given fuel at a specified set of fuel, air, and furnace conditions. There then results a curve passing through a maximum point, where the competing influences of excess O2 and AFT are in balance.17 Some previously published NOx data points17,19,20,21 and customized correlating curves for three commercial SMR furnaces firing natural gas are plotted against furnace excess O2 in Figure 5. NOx concentrations in the figure are expressed as ppm wet at conditions, as reported in the original publications. Concentrations in ppm at conditions on a dry basis would be about 20-25% higher,10,19 and adjustment of ppm (dry) to a flue-gas concentration of 3% O2 (dry) (a common regulatory standard) would shift the curves somewhat.10 As discussed
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previously,17,21 NOx values below about 1.5% O2 (wet) may not be reliable since the actual intercept is expected to be positive, rather than zero,47 and NOx in this region may be somewhat higher than predicted from the curve as drawn.
0
20
40
60
80
100
120
140
0.0 1.0 2.0 3.0 4.0 5.0Excess O2 ( % wet )
NO
x pp
m (w
et),
at c
ondi
tions
Conventional: 400oF Combustion Air
Low-NOx: 530oF Combustion Air
Conventional: Ambient Air
Figure 5. NOx from Natural-Gas Fired SMR Furnaces, Burners and Air Preheat as Noted Through the magic of differential calculus, it is possible to calculate the value of furnace oxygen corresponding to the peak of the ppm NOx wet at conditions vs. %O2 (wet) curve, such as those depicted in Figure 5. For the more general case of ln[NOx] = A – B.10,000/AFT(°R)] + C. ln[O2] (2) with an additional coefficient of the ln[O2] term, the O2 at the maximum point is given as O2 at the peak = {[(B.10,000/C) + 2.b] – SQRT[[(B.10,000/C) + 2.b]2 – 4. b2]}/(2.a) (3) where a = the absolute value of the linear slope of AFT vs. O2 (°F or °R per % O2) b = AFT(°R) at 0% O2 (linear intercept) (Note temperature in °R.) C = an additional constant that reduces to 1.0 for the standard NOx equation SQRT = the square-root operator Both the slope a and intercept b are obtained by regression of AFT against %O2 (wet), as plotted in Figure 3, but in °R. Flue-gas moisture (not shown) is also linear in %O2 (wet). NOx in ppmd @ 3% O2 (dry) vs. O2 curves predicted for ethylene cracking furnaces from the equations of Figure 4 are shown in Figures 6-9 for several representative cases, with ambient (60 °F) combustion air and with 350 °F air preheat.
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Peak values of NOx for these and other fuel compositions are listed in Table 2. The peak occurs at 3.0-3.2 %O2 (wet) for ambient air and at 3.3-3.6 %O2 (wet) for air preheat. Oxygen at the peak increases with higher AFT as H2 in the fuel increases (Figure3). The curves become steeper and the maximum point moves to the right with added air preheat.19
0
40
80
120
160
200
0.0 1.0 2.0 3.0 4.0 5.0 6.0Excess O2 ( % wet )
NO
x [ p
pmd
@ 3
% O
2 (dr
y) ]
Conventional Burners
Low-NOx Burners
Ultra Low-NOx Burners
Figure 6. Predicted Ethylene Furnace NOx: 100% Methane Fuel and 60 °F Air
0
40
80
120
160
200
0.0 1.0 2.0 3.0 4.0 5.0 6.0Excess O2 ( % wet )
NO
x [ p
pmd
@ 3
% O
2 (dr
y) ]
Conventional Burners
Low-NOx Burners
Ultra Low-NOx Burners
Figure 7. Predicted Ethylene Furnace NOx: 40% H2 / 60% Methane and 60 °F Air
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452
0
40
80
120
160
200
0.0 1.0 2.0 3.0 4.0 5.0 6.0Excess O2 ( % wet )
NO
x [ p
pmd
@ 3
% O
2 (dr
y) ]
Conventional Burners
Low-NOx Burners
Ultra Low-NOx Burners
Figure 8. Predicted Ethylene Furnace NOx: 100% Methane and 350 °F Air Preheat
0
40
80
120
160
200
0.0 1.0 2.0 3.0 4.0 5.0 6.0Excess O2 ( % wet )
NO
x [ p
pmd
@ 3
% O
2 (dr
y) ]
Conventional Burners
Low-NOx Burners
Ultra Low-NOx Burners
Figure 9. Predicted Ethylene Furnace NOx: 40% H2 / 60% Methane and 350 °F Air Preheat
Finding the peak value of the ppmd @ 3% O2 curve by calculus requires differentiating a more complicated function than Equation (2) followed by a trial-and-error solution for O2. It is more straightforward then to locate the maximum point from the function itself by iteration.
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Table 2. Predicted Ethylene Furnace NOx Peak Values, Burners and Air Preheat as Shown
ppmd @ 3% O2 (dry)
lb/MMBtu (HHV)
% H2 in Fuel
Ambient Conven-
tional Low-NOx Ultra Low-NOx
Conven-tional Low-NOx Ultra
Low-NOx 0 10 20 30 40 50 60 70 80 90 100
101 104 108 112 118 126 136 149 170 205 270
68 70 72 75 79 84 91 100 114 137 181
34 35 36 37 39 42 45 50 57 68 90
0.121 0.123 0.126 0.129 0.134 0.139 0.146 0.155 0.168 0.188 0.222
0.081 0.083 0.084 0.087 0.090 0.093 0.098 0.104 0.113 0.126 0.149
0.040 0.041 0.042 0.043 0.044 0.046 0.049 0.052 0.056 0.063 0.074
350°F Air 0 10 20 30 40 50 60 70 80 90 100
165 169 174 181 189 200 214 234 263 310 397
110 113 117 121 127 134 144 157 176 208 267
55 56 58 60 63 67 71 78 88 103 133
0.197 0.200 0.204 0.209 0.214 0.221 0.230 0.243 0.260 0.286 0.328
0.132 0.134 0.137 0.140 0.144 0.148 0.154 0.163 0.174 0.191 0.220
0.066 0.067 0.068 0.069 0.071 0.074 0.077 0.081 0.086 0.095 0.109
Combustion-Air Temperature Another way to depict the effect of combustion air temperature on AFT and NOx (Figures 6-9, Table 2) is to plot the relative concentration of NOx formed for a given combustion air temperature to NOx at some reference ambient air temperature, say 60 °F (15.6 °C). At otherwise constant conditions, the relative NOx can be derived from the functional form of the NOx correlation (Figures 2 and 4) to yield: NOx with air preheat/NOx ambient = exp[B.(10,000/AFT(°R)ambient – 10,000/AFT(°R)air preheat)] (4) This relationship comes from writing the NOx equation twice, once for each combustion air temperature chosen and subtracting. The explicit excess O2 concentrations, being the same, drop out as does the constant term A, indicative of burner type. The only things left
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are the coefficient B and the AFTs for combustion of the fuel with the preheated air and with the reference air. The AFT for the reference condition is actually a constant in the equation. According to the model, it follows that the relative NOx from combustion of a particular fuel gas at a given temperature and ambient-air conditions is a function of the combustion-air temperature and the excess O2. Relative NOx depends on the combustion-air temperature because the AFT is a function of that temperature. The AFT also provides an excess O2 functionality (Figure 3) even though the explicit excess O2 term drops out in the derivation of Equation (3). A graph of the above equation for combustion of three methane-hydrogen fuel compositions at 2% excess O2 (wet) is shown in Figure 10 for a coefficient B of 3.6, its value from Figure 2 to two significant places. The curves are distinct from one another, but the differences are minor. When plotted on linear coordinates, the curves clearly display an exponential character. Use of Equation (3) with experimental relative NOx data for preheated combustion air may be another way to determine the coefficient B.
0.0
1.0
2.0
3.0
0 100 200 300 400 500 600 700 800Combustion Air Temperature (oF)
NO
x Rel
ativ
e to
60
o F A
ir
Top Curve: 100% Methane
Middle Curve: 75% Hydrogen /
25% Methane
Bottom Curve: 100% Hydrogen
Figure 10. Relative NOx at 2% Excess O2 for Preheated Combustion Air, Fuels as Noted Curves of this type, plotted without numerical values on the axes, may be familiar from burner manufacturers’ literature, for example,47 and a rule of thumb quoted from industrial experience is that NOx can be expected to double as combustion air is preheated from ambient to the range of 500 °F (260 °C) 47 to 600 °F (316 °C). 47,48 Curves for methane containing up to about 75% hydrogen cross the Relative NOx = 2.0 line in Figure 10 within this temperature range. In addition, a similar set of curves (not shown) for an unspecified fuel and excess O2 but with numerical values48 is available showing relative NOx ranging from 1.85 (min.) to 2.3 (max.) at 750 °F (399 °C) with respect to a base temperature of 100 °F (37.8 °C). Correction between the two temperature bases is about 6%. Relative NOx from the published curves at
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350 °F (177 °C) is close to 1.2 and between 1.3 (min.) and 1.7 (max.) at 500 °F (260 °C) and 600 °F (316 °C), respectively. Although agreement between those curves and Figure 10 is not quite exact even on the same basis, Figure 10 is certainly in the same ball park while providing more conservative values of NOx. If desired, the coefficient B can be adjusted to make the relative NOx curves of the model coincide with one’s own experimental data. Fuel Temperature Relative NOx as a function of fuel temperature is plotted in Figure 11 using 60 °F (15.6 °C) as the basis. A range of 40 °F (4.4 °C) to 150 °F (65.6 °C)F is covered. Combustion air at 60 °F (15.6 °C) and 60% relative humidity (RH) is held constant. Excess O2 in the furnace is 2% (wet). Four curves are shown, each nearly linear, for 100% hydrogen fuel and 100% methane fuel at the extremes, 75% H2 in methane midway between them, and 50% H2 midway between 75% H2 and 100% methane. The difference over the temperature range investigated is only 6% for hydrogen fuel [4% between 60 °F (15.6 °C) and 150 °F (65.6 °C)] and 2 % for methane [1½% from 60 °F (15.6 °C) to 150 °F (65.6 °C)]. Since fuel volume is only about 10% of the combustion air or flue gas at typical excess air conditions for methane / natural gas (about ⅓ for a pure hydrogen fuel), it is not surprising that the impact of fuel temperature on AFT, and therefore NOx, is such a small fraction of the effect of combustion-air temperature, certainly for fuels containing high concentrations of methane.
0.99
1.00
1.01
1.02
1.03
1.04
1.05
40 50 60 70 80 90 100 110 120 130 140 150Fuel Temperature (oF)
NO
x Rel
ativ
e to
NO
x Fo
rmed
Usi
ng
60 o F
Fuel
Fuel Composition from Top to Bottom: 100 % H2, 75 % H2, 50 % H2, 0% H2 in Methane
Lines Calculated Using 60 oF, 60 % RH Ambient Air at 2 % Furnace Excess O2 (wet)
Figure 11. Relative NOx from Heated Fuel at 2% Excess O2 (wet) Ambient-Air Humidity Figure 12 shows the effect of humidity in the combustion air drawn in at ambient-air temperatures from 40-100 °F (4.4-37.8 °C). The relationship is depicted as a single, nearly
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linear curve with a negative slope since the miniscule differences in relative NOx with ambient-air temperature are imperceptible at the scale of the figure. For each temperature, the curve should be used only up to the saturation humidity at that temperature (Table 3, below).
0.60
0.65
0.70
0.75
0.80
0.85
0.90
0.95
1.00
0.00 0.01 0.02 0.03 0.04 0.05 0.06 0.07Absolute Humidity ( moles of water per mole of dry air)
Rel
ativ
e N
Ox
at S
ame
Am
bien
t-Air
Tem
pera
ture
Curve Calculated for 100 % Methane FuelFired at 2 % Excess O2 (wet)
for Ambient-Air Temperatures 40-100 oF
Figure 12. NOx Relative to NOx Formed Using Zero-Humidity Ambient Air Even though the predicted increase in NOx on days with lower humidity may be minimal compared to some other effects, it is still real. According to the figure, halving the humidity from 0.028 to 0.014 moles of water per mole of dry air (e.g., from 80% RH to 40% RH at 80 °F (26.7 °C)) results in a relative NOx increase of 9%, or an absolute increase of about 8 ppm NOx at 90 ppm, 5½ ppm at 60 ppm, and 3 ppm at 30 ppm. Such an increase, in general, has been alluded to in testing of burner emissions.12 This is especially important when ambient conditions cause the operation to approach NOx permit limits more closely.
Table 3. Saturation Humidity at Indicated Ambient Temperature and Atmospheric Pressure
Temperature (°F / °C)
Absolute Humidity (moles of water per mole of dry
air)
40 / 4.4 50 / 10.0 60 / 15.6 70 / 21.1 80 / 26.7 90 / 32.2 100 / 37.8
0.008330 0.012248 0.017735 0.025328 0.035735 0.049894 0.069074
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Hydrogen Content of Methane / Hydrogen Fuel Mixtures NOx relative to firing 100% methane for methane / hydrogen fuel blends is plotted in
Figure 13. Fuel-hydrogen content from 0-100% is investigated at 2% excess O2 (wet) in the furnace flue gas. A fuel temperature of 60 °F (15.6 °C) and combustion-air temperatures of 60, 350, and 750 °F (15.6, 177, and 399 °C) starting with ambient air at 60 °F (15.6 °C) and 60% RH were employed in the calculations. Basis for comparison is NOx concentration expressed as ppmd @ 3% O2 (dry) for 100% methane.
Three distinct curves result, progressing in order from top to bottom with the 60 °F (15.6 °C) combustion-air curve on top. Like Figure 10, these curves also are exponential in character. Relative NOx increases with increasing hydrogen, gradually at first, but then the curves begin to take off in the range of 50-60% H2.
Different curves with a lower relative NOx and a more gradual rise but with a similar take-off point are obtained when comparing NOx emissions in lb/MMBtu (HHV) rather than in ppmd @ 3% O2 (dry). This occurs because the ratio of ppm to lb/MMBtu changes with fuel hydrogen, as shown in Figure 1. The lb/MMBtu (HHV) relative-NOx curve for 60 °F (15.6 °C) combustion air is shown as the lowest curve in Figure 14, along with several others. The shape of this curve has been discussed previously,1 including the experimental observation of no measurable impact of H2 on NOx (as reported, tested up to about 50-60 vol% H2).14
1.0
1.2
1.4
1.6
1.8
2.0
2.2
2.4
2.6
0 10 20 30 40 50 60 70 80 90 100Hydrogen in Methane Fuel (vol %)
NO
x R
elat
ive
to
100
% M
etha
ne F
uel
Top Curve: 60 oF Combustion Air
Middle Curve: 350 oF Combustion Air
Bottom Curve: 750 oF Combustion Air
Curves Calculated Starting with 60 oF Fuel and 60 oF, 60 % RH Ambient Air
Figure 13. NOx with H2 in Fuel Relative to Firing 100% Methane, 2% Excess O2 (wet)
A published graph, termed “the classical and accepted curve for hydrogen influence on NOx emissions,” was found in the literature.48 However, its origin, basis, and non-hydrogen fuel composition are not clearly stated; the background fuel is assumed here to be natural gas fired with ambient combustion air. This curve, redrawn, appears in Figure 14 as well. Although it is noted as the flattest curve in the figure, it has been fitted for the plot using a third-order polynomial to capture the rise and inflection point exhibited by the original curve.
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458
The 60 °F (15.6 °C) combustion-air relative NOx curve at 2% excess O2 from Figure 13 and a slightly lower relative-NOx curve based on 10% excess air at the same combustion-air temperature are also shown in Figure 14. Both of these curves deviate from the literature curve by at most 5% up to a concentration of 70% H2. Beyond that point, the published curve increases slightly from a relative NOx of 1.4 at 70% H2 to just less than 1.6 at 100% H2, compared to a more conservative 2.4-2.6 ± estimated from the correlation for 100% H2.
1.0
1.2
1.4
1.6
1.8
2.0
2.2
2.4
2.6
0 10 20 30 40 50 60 70 80 90 100Hydrogen Content in Fuel ( vol %)
NO
x R
elat
ive
to 1
00%
M
etha
ne /
Nat
ural
Gas
Fue
l Top Curve (from Previous Figure) Based on 2 % O2 (wet) and ppmd @ 3% O2 (dry)
Second Curve Based on 10 % Excess Air and ppmd @ 3% O2 (dry)
Lowest Curve Based on lb/MMBtu (HHV)
Flattest Curve Redrawn from Cited Literature Reference; Origin,Basis, and Non-Hydrogen Composition of Fuel Not Stated Therein
Figure 14. Relative NOx from Hydrogen Content in Ethylene Furnace Fuel – A Comparison Acetylene Content of Methane and Hydrogen Fuels Now that hydrogen has been explored, let us now look at the implications of acetylene in ethylene-furnace flue gas. By-product acetylene in the cracked gas would end up in the fuel in the event that it is not being recovered or hydrogenated to ethane and ethylene in the normal processing sequence.49 Under comparable conditions, acetylene as a pure component is calculated to generate an AFT over 600 °F (333 °C delta) higher than hydrogen and about 950 °F (528 °C delta) higher than methane. Firing a significant concentration of acetylene, therefore, has the potential to increase ethylene-furnace NOx emissions substantially. Relative NOx from combustion of fuel gas containing percentage concentrations up to as high as 10% acetylene is shown in Figure 15. This range has been exaggerated to magnify differences. Two lines are indicated, one for 100% hydrogen (upper) and the other 100% methane (lower), both using 60°F (15.6 °C), 60% RH air for combustion at 2% excess O2 (wet). The relationships are nearly linear, with a relative NOx at 10% acetylene of approximately 1.30 compared to pure hydrogen for the hydrogen line, and 1.28 compared to pure methane for the methane line. With both lines anchored at 1.0 relative NOx for 0% acetylene, each of the ordinates at 100% acetylene swing down about 0.03 when this same combustion air is heated to 350 °F (177 °C), and an additional 0.03 for 750 °F (399 °C) combustion air.
447
459
1.00
1.05
1.10
1.15
1.20
1.25
1.30
0.0 2.0 4.0 6.0 8.0 10.0Acetylene Content in Fuel ( vol %)
NO
x Rel
ativ
e to
100
% H
ydro
gen
or
Met
hane
Fue
lTop Line: Hydrogen with
60 oF, 60 % RH Combustion Air
Bottom Line: Methane with60 oF, 60 % RH Combustion Air
Figure 15. Relative NOx from Acetylene in Ethylene Furnace Fuel at 2% Excess O2 (wet)
Experimental Verification of NOx Predictions NOx data for ethylene cracking furnaces in the open literature are few and far between, especially when accompanied by simultaneous operating conditions. Still, it is possible with a little detective work to squeeze out some data for comparison with NOx predictions by making reasonable assumptions to augment whatever meager information that has been reported. Often, the burner-NOx reported is incidental to the main subject under discussion. A number of usable cases were identified in the cited paper,1 with a synopsis of the data and circumstances for each case, an interpretation of experimental observations, and values predicted by the correlation. These were then summarized in an overall parity plot of predicted vs. observed NOx. In addition, two newly discovered commercial ethylene-furnace NOx data points48 are tabulated here in Appendix A, accompanied by corresponding predictions. The same source document48 also contains NOx data obtained in the burner manufacturer’s pilot test facility. Those data are not representative of full-scale operation, for reasons discussed by the manufacturer, and are not shown here. In other work, tests of multiple burners have produced significantly higher NOx levels than single-burner tests in a smaller furnace.50 The previously developed graph of predicted vs. observed NOx is reproduced in Figure 16, augmented by the additional data points of Appendix A. Reported measurements for all cases considered have been converted, where necessary, to a common unit of ppmd @ 3% O2 (dry). The typical NOx values mentioned in a previous section on Regulatory Considerations would also plot well in Figure 16. However, these are not included in the parity plot because they cannot be guaranteed to be from full-scale ethylene cracking furnaces, or even if so, conditions are not specified well enough to validate the model unequivocally. For example,
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the historical figure of 100-120 ppm NOx from conventional burners could arise at the maximum point of NOx-O2 curve, according to the correlation, for methane with up to 40% hydrogen in the blend fired with ambient air (Figures 6 and 7, Table 2), with 100% methane and air preheat up to about 160 °F (71 °C) (not shown), or from any number of other combinations.
0
20
40
60
80
100
0 20 40 60 80 100Observed NOx (ppmd @ 3% O2)
Pred
icte
d N
Ox
(ppm
d @
3%
O2)
Figure 16. Parity Plot – Predicted vs. Observed NOx Agreement between the correlated and measured values in Figure 16 is indeed satisfactory, especially considering that these data were not used in the derivation of the correlation. Regardless of the origin of the proposed equations, their use, as it turns out, appears promising in estimating NOx for a wide variety of situations encountered in ethylene plants.
Opportunities For Improvement The proposed correlating functions appear to check out well enough against spot data. However, the author has not yet come across a complete set of NOx data in the open literature showing a systematic variation in furnace excess O2 similar to the SMR data of Figure 5 to test it further. It is hoped that more complete data sets will become available to provide a definitive check of the NOx prediction equations for an ethylene cracking furnace. Data sufficient to correlate and predict NOx from a plant furnace can often be generated at minimal incremental expense during mandatory stack testing for regulatory
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purposes. Multiple regression of such data enables one to tailor the constants of the generalized function for a specific furnace, and constants are easily adjusted as more data become available. This can be especially useful when the furnace / burners can be considered the prototype for others of the same model already in service or yet to be built. Suggested data are listed in Appendix B; concomitant process conditions during emission testing can also be noted and recorded. Target operating conditions are outlined in Figure 4 of the cited reference,10 being careful to remain within one’s permit limits at all times.
Summary And Conclusions
• NOx Correlation Extended to Ethylene Cracking Furnace Burners • Correlation Provides Reasonable NOx Estimates. • Correlation Can Be Used to:
+ Estimate NOx Quickly + Evaluate Changing Conditions + Play “What-if” Games + Complement Other Techniques Such as CFD + Interpret Experimental Data
• Correlation Works for: + A Variety of Fuels and Fuel Temperatures + Ambient Air for Combustion + Preheated Combustion Air + Combustion Air with Varied Humidity
• Correct Inputs Are Required. • Additional Data Needed to:
+ Increase Confidence + Make Modifications, if Necessary
About The Author
Robert G. Kunz was an environmental engineering manager at Air Products and Chemicals, Inc., Allentown, PA before retiring after 26+ years of service. He joined Cormetech, Inc., Durham, NC in April 2001 as Technical Project Manager in support of sales and marketing efforts in the petroleum refining and petrochemical industries, advising on business development strategy, development of training materials, technical report writing, and evaluation of laboratory and field data. He held engineering positions previously at Esso Research and Engineering Company, Florham Park, NJ and The M.W. Kellogg Company, New York, NY and is currently an independent environmental consultant. “Dr. Bob” has earned a BChE degree in Chemical Engineering from Manhattan College, a PhD in Chemical Engineering from Rensselaer Polytechnic Institute, an MS in Environmental Engineering from Newark College of Engineering, and an MBA from Temple University. He has contributed numerous publications to the technical literature, including many on NOx measurement, prediction, correlation, and control. He is a member of the American Institute of Chemical Engineers (AIChE), the American Chemical Society (ACS), and the Air & Waste Management Association (A&WMA) and is a licensed professional engineer in several states.
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References
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6. Kroschwitz, J.I. and M. Howe-Grant, editors, “Kirk-Othmer Encyclopedia of Chemical Technology,” 4 ed., Vol. 9, pp.877-915, Wiley, New York (1994).
7. Patel, R., B.P. Evans, and W.K. Lam, “NOx Reduction Technologies for Pyrolysis Furnaces,” Proc. 5th Ethylene Producers’ Conf., 2, pp.416-431, AIChE, New York (1993).
8. Texas Commission on Environmental Quality (TCEQ), Emission Inventory Spreadsheet for HGB Ozone Nonattainment Area (circa 2001-2002).
9. 30 TAC Part I, Chap.17, Subchap. B, Div. 3, Sect. 117.206(c)(8)(B) (eff. May 19, 2005). 10. Kunz, R.G., D.D. Smith, and E.M. Adamo, “Predict NOx from Gas-Fired Furnaces,”
Hydrocarbon Processing, 75(11), 65-79 (Nov. 1996). 11. Just, R., “Flame Rollover and Other Flame Shape Problems,” Proc. 16th Ethylene
Producers’ Conf., 13, pp.594-601, AIChE, New York (2004). 12. Gartside, R.J., P.R. Ponzi, F.D. McCarthy, S.G. Chellappan, P.J. Chapman, and
R.T. Waibel, “Commercialization of Ultra-low NOx Burners for Ethylene Heaters,” Proc. 16th Ethylene Producers’ Conf., 13, pp.618-626, AIChE, New York (2004).
13. Tang, Q., B. Adams, M. Bockelie, M. Cremer, M. Denison, C. Montgomery, A. Sarofim, and D.J. Brown, “Towards Comprehensive CFD Modeling of Lean Premixed Ultra-Low NOx Burners in Process Heaters,” Proc.17th Ethylene Producers’ Conf., 14, pp.594-619, AIChE, New York (2005).
14. Stephens, G. and D. Spicer, “A Low NOx Burner Developed for ExxonMobil Ethylene Furnaces,” Proc. 17th Ethylene Producers’ Conf., 14, pp.487-499, AIChE, New York (2005).
15. Barnett, D. and D. Wu, “Flue-Gas Circulation and Heat Distribution in Reformer Furnaces,” Ammonia Plant Safety & Related Facilities: a Technical Manual, 41, pp.9-16, AIChE, New York (2001).
16. Reed, R.C. and T.K. Sherwood, “The Properties of Gases and Liquids – Their Estimation and Correlation,” p. 2, McGraw-Hill, New York (1958).
17. Kunz, R. G., D. D. Smith, N. M. Patel, G. P. Thompson, and G. S. Patrick, “Control NOx from Gas-Fired Hydrogen Reformer Furnaces,” AM-92-56, 1992 NPRA Annual Meeting, New Orleans, LA (March 22-24, 1992).
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18. Kunz, R.G., D.D. Smith, N.M. Patel, G.P. Thompson, and G.S. Patrick, “Control NOx fromGas-Fired Hydrogen Reformer Furnaces,” pp. 381-392 in Emission Inventory Issues –Proceedings of an International Specialty Conference, Durham, NC, Oct. 19-22, 1992,VIP-27, Air & Waste Management Association: Pittsburgh, PA (1993).
19. Kunz, R.G., D.D. Smith, N.M. Patel, G.P. Thompson, and G.S. Patrick, “Control NOx fromFurnaces,” Hydrocarbon Processing, 71(8), 57-62 (Aug. 1992).
20. Kunz, R.G.; Keck, B.R.; Repasky, J.M. “Mitigate NOx by Steam Injection,” ENV-97-15,1997 NPRA Environmental Conference, New Orleans, LA (Sept. 28-30, 1997).
21. Kunz, R.G.; Keck, B.R.; Repasky, J.M. “Mitigate NOx by Steam Injection” Hydrocarbon Processing, 77(2), 79-84 (Feb. 1998).
22. Kunz, R.G., D.C. Hefele, R.L. Jordan, and F.W. Lash, “Use of SCR in a Hydrogen PlantIntegrated with a Stationary Gas Turbine – Case Study: The Port Arthur Steam-MethaneReformer,” Paper No. 70093, Air and Waste Management Association (A&WMA) 96th
Annual Conference & Exhibition, San Diego, CA (June 22-26, 2003).23. Kunz, R.G., D.C. Hefele, R.L. Jordan, and F.W. Lash, “Consider SCR to Mitigate NOx
Emissions,” Hydrocarbon Processing, 82(11), 43-50 (Nov. 2003).24. Zeldovich, Ya. B., P. Ya. Sadovnikov, and D.A. Frank-Kamenetskii, “Oxidation of
Nitrogen in Combustion,” Academy of Sciences of the USSR, Institute of ChemicalPhysics, Moscow-Leningrad, translated by M. Shelef of the Scientific Research Staff ofthe Ford Motor Company (1947).
25. Hougen, O.A., K.M. Watson, and R.A. Ragatz, “Chemical Process Principles Part I:Material and Energy Balances,” 2 ed., pp.354-357, 408-411, Wiley, New York (1954).
26. Jones, G.W., B. Lewis, J.B. Friauf, and G. St. J. Perrot, “Flame Temperatures ofHydrocarbon Gases,” J. Am. Chem. Soc., 53(3), 869-883 (Mar. 1931).
27. Loomis, A.G. and G. St. J. Perrot, “Measurements of the Temperatures of StationaryFlames,” Ind. Eng. Chem., 20(10), 1004-1008 (Oct. 1928).
28. Singer, J.M., E.B. Cook, M.E. Harris, V.R. Rowe, and J. Grumer, “Flame CharacteristicsCausing Air Pollution: Production of Oxides of Nitrogen and Carbon Monoxide,” 33 pp.,U.S. Bureau of Mines R.I. 6958 (1967).
29. Grumer, J., M.E. Harris, V.R. Rowe, and E.B. Cook, “Effect of Recycling CombustionProducts on Production of Oxides of Nitrogen, Carbon Monoxide and Hydrocarbons byGas Burner Flames,” Preprint 37A, 60th Annual Meeting AIChE, NY (Nov. 26-30, 1967).
30. Lange, H.B., Jr., “NOx Formation in Premixed Combustion,” AIChE Symposium SeriesNo. 126, 17-27 (1972).
31. Kroschwitz, J.I. and M. Howe-Grant, editors, “Kirk-Othmer Encyclopedia of ChemicalTechnology,” 4 ed., Vol. 13, pp.838-894, Wiley, New York (1995).
32. McKetta, J.J., editor, “Encyclopedia of Chemical Processing and Design,” Vol. 47,pp.165-203, Marcel Dekker, Inc., New York (1994).
33. Elvers, B., S. Hawkins, M. Ravenscroft, and G. Schulz, editors, “Ullmann’s Encyclopediaof Industrial Chemistry,” 5 ed., Vol. A 13, pp.317-328, 435-438, VCH, New York (1989).
34. Gary, J.H. and G.E. Handwerk, “Petroleum Refining: Technology and Economics,” 4 ed.,pp. 261-285, 313-317, Marcel Dekker, New York (2001).
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35. O’Leary, J.R., R.G. Kunz, and T.R. von Alten, “Selective Catalytic Reduction (SCR) Performance in Steam-Methane Reformer Service: The Chromium Problem,” ENV-02-178, 2002 NPRA Environmental Conference, New Orleans, LA (Sept. 9-10, 2002).
36. O’Leary, J.R., R.G. Kunz, and T.R. von Alten, “Selective Catalytic Reduction (SCR) Performance in Steam-Methane Reformer Service: The Chromium Problem,” Environmental Progress, 23(3), 194-205 (Oct. 2004).
37. Tindall, B.M. and D.L. King, “Designing Steam Reformers for Hydrogen Production,” Hydrocarbon Processing, 73(7), 69-74 (July 1994).
38. Johansen, T., K.S. Ragharaman, and L.A. Hackett, “Trends in Hydrogen Plant Design,” Hydrocarbon Processing, 71(8), 119-127 (Aug. 1992).
39. Kunz, R.G. and W.F. Baade, “Predict Methanol and Ammonia in Hydrogen-Plant Process Condensate and Deaerator-Vent Emissions,” ENV-00-171, 2000 NPRA Environmental Conference, San Antonio, TX (Sept. 10-12, 2000).
40. Kunz, R.G. and W.F. Baade, “Predict Contaminant Concentrations in Deaerator-Vent Emissions,” Hydrocarbon Processing (Intl. Ed.), 80(6), 100-A to 100-O (June 2001).
41. Royal Dutch/Shell, “The Petroleum Handbook,” 6 ed., p.284, 309, 586, 689, Elsevier, Amsterdam (1983).
42. Bland, W.F. and R.L. Davidson, editors, “Petroleum Processing Handbook,” Section 14, pp. 14-1 to 14-46, McGraw-Hill, New York (1967).
43. Funahashi, K., T. Kobayakawa, K. Ishii, and H. Hata, “SCR DeNOx in New Maruzen Ethylene Plant,” Proc. 13th Ethylene Producers’ Conf., 10, pp.741-755, AIChE, New York (2001).
44. Wines, W.T., “Improve Contaminant Control in Ethylene Production,” Hydrocarbon Processing, 84(4), 41-46 (April 2005).
45. Baukal, C.E., Jr., and R.E. Schwartz, editors, “The John Zink Combustion Handbook,” p.111, CRC Press, Boca Raton, FL (2001).
46. Kunz, R.G. and T.R. von Alten, “SCR Treatment of Ethylene Furnace Flue Gas (A Steam-Methane Reformer in Disguise),” Paper presented at Institute of Clean Air Companies (ICAC) Forum ’02, Houston, TX (Feb. 2002).
47. Waibel, R.T., “Ultra Low NOx Burners for Industrial Process Heaters,” Paper presented at the Second International Conference on Combustion Technologies for a Clean Environment, Lisbon, Portugal (July 19-22, 1993).
48. Krotzer, K., D. Bishop, and D. Giles, “Retrofit Application of an Ultra Low NOx Burner in an Ethylene Furnaces,” (sic) Proc. 9th Ethylene Producers’ Conf., 6, pp.416-431, AIChE, New York (1997).
49. “Ullmann’s Encyclopedia of Industrial Chemistry,” Sixth, Completely Revised Edition, Vol. 12, pp.531-583, WILEY-VCH, Weinheim, Germany (2003).
50. Bussman, W., R. Poe, B. Hayes, J. McAdams, and J. Karan, “Low NOx Burner Technology for Ethylene Cracking Furnaces,” Proc. 13th Ethylene Producers’ Conf., 10, pp.774-796, AIChE, New York (2001).
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APPENDIX A
ADDITIONAL ETHYLENE-FURNACE NOx DATA
I. BURNER NOx DATA FROM HOUSTON OLEFINS PLANT
Synopsis of Reported Information and NOx Predictions. Some ultra low-NOx burner pilot data and furnace field data are contained in a presentation from the 1997 Ethylene Producers’ Conference.48 The Design Case and a field test on a plant fuel are summarized in Table A1; where not clearly specified, the basis for lb/MMBtu was taken as the LHV in accordance with the custom in the burner industry and usage elsewhere in the cited paper. The burners were also designed to achieve 0.08 lb/MMBtu (LHV) (~60 ppmd @ 3% O2 (dry)) on natural gas at 10% excess air (1.72% O2 (wet) and 2.10% O2 (dry)). NOx values were predicted using atmospheric air at 60 °F (15.6 °C) and 60% RH, heated to temperature. For prediction of NOx, the rather high field-test excess O2 (dry) was assumed to reflect furnace O2 without appreciable infiltration of tramp air between the furnace and the stack. Regardless, the predicted NOx curve between the reported O2 and a more typical operating level is fairly insensitive to O2. The ethane vs. ethylene composition of the field-test plant fuel, unclear in the paper, makes little difference in the NOx prediction as well. The pilot data obtained in the burner manufacturer’s test facility are not representative of full-scale operation, for reasons discussed by the manufacturer, and are not reproduced here.
Table A1. Summary of Design Basis, Field Data, and NOx Predictions
Plant Fuel (vol %) Design Case Field Test
Hydrogen (H2) Methane (CH4) Ethane (C2H6)
Ethylene (C2H4) Propane (C3H8)
Propylene (C3H6) Carbon Monoxide (CO)
Nitrogen (N2)
56.24 40.48 0.06 0.42 0.01 0.07 0.40 2.32
56.46 41.26 0.03 0.53
– –
0.14 1.54
Total 100.00 99.96 LHV (Btu/SCF) 533 539 (calc)
Combustion Air Temp. (°F / °C) 750 / 399 (max) 510 / 266
Flue Gas: Low Test
Point High Test
Point Excess Air (%) Excess O2 (% dry) Excess O2 (% wet) Measured NOx (lb/MMBtu (LHV)) Measured NOx (ppmd @ 3% O2) Predicted NOx (lb/MMBtu (LHV) Predicted NOx (ppmd @ 3% O2)
10 2.15 (calc) 1.68 (calc)
0.12 (design) 97.4 (calc)
0.111 90.1
31.1 (calc) 5.50
4.46 (calc) 0.102
82.9 (calc) 0.106 85.8
31.6 (calc) 5.57
4.52 (calc) 0.117
95.0 (calc) 0.105 85.4
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APPENDIX B
SUGGESTIONS FOR ETHYLENE-FURNACE NOx DATA
Table B1. Wish List for Data Sets for NOx Correlation
At Furnace: Fuel (Gaseous) Composition
Temperature Measured Heating Values (HHV and LHV), if available Flow Rate (units? wet or dry, actual or standard – basis for std cubic ft, etc., 60°F, 70°F, 68°F) (enables one to calculate mass flow rates of atmospheric contaminants)
Combustion Air Temperature of Ambient Air Humidity (or enough info, e.g., date and time of testing to get data on ambient air from Weather Bureau) Temperature of Preheated Air (if employed) Flow Rate (if available) (units? wet or dry, actual or standard – basis for std cubic ft, etc., 60°F, 70°F, 68°F)
Flue Gas Excess O2 (probably wet) at Furnace Furnace Bridgewall or Crossover Temperature
Type of Burners Manufacturer and Nomenclature Standard/Conventional Low-NOx (type of low-NOx) Ultra Low-NOx (type) Firing Orientation
At Stack: Flue Gas Contaminant Concentrations (NOx and possibly CO) Specify wet or dry.
Composition of Major Constituents (N2, CO2, O2, and H2O (moisture), or at least O2 and H2O) Temperature Flow Rate (units? wet or dry, actual or standard – basis for std cubic ft, etc., 60°F, 70°F, 68°F)
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Table F.1-1. Summary of Ethylene Cracking Furnace Precedents for SO2 in the RBLC
RBLC ID No. Facility Name Permit
Date Emission Unit
Description
Size in MMBtu/h
r Control Description SO2Limit 1
LA-0206 Baton Rouge Refinery 02/18/04 Feed Preparation
Furnaces F-30 & F-31 352 Limit concentration of H2S in fuel gas to 160 ppmv (0.01 gr/dscf)
0.18 lb/MMBtu
AZ-0046
Arizona Clean Fuels Yuma 04/14/05 Hydrogen Reformer
Heater 1435 S limited to 35 ppm (as H2S) 35 ppmw
AZ-0046
Arizona Clean Fuels Yuma 04/14/05 Atmospheric Crude
Charge Heater 346 35 ppm S limit in fuel. (as H2S) 35 ppmw
AZ-0046
Arizona Clean Fuels Yuma 04/14/05
Butane Conversion Unit Dehydrogenation
Reactor Interheater 328 Sulfur limit of 35 ppm in
fuel burned. (as H2S) 35 ppmw
AZ-0046
Arizona Clean Fuels Yuma 04/14/05
Butane Conversion Unit Dehydrogenation
Reactor Charge Heater
311 35 ppm S limit on fuel burned. (as H2s) 35 ppmw
AZ-0046
Arizona Clean Fuels Yuma 04/14/05
Butane Conversion Unit Isostripper
Reboiler 222 S limited to 35 ppm in
fuel burned. (as H2S) 35 ppmw
AZ-0046
Arizona Clean Fuels Yuma 04/14/05
Hydrocracker Unit Main Fractionator
Heater 211 S limited to 35 ppm. (as
H2S) 35 ppmw
TX-0475
Formosa Point Comfort Plant 05/09/05 Pyrolysis Furnaces
(1001-1008, 1009B) 250 0.38 lb/hr (0.0015 lb/MMBtu
TX-0475
Formosa Point Comfort Plant 05/09/05 Pyrolysis Furnace
(1010b) 250 0.41 lb/hr (0.0016 lb/MMBtu)
TX-0475
Formosa Point Comfort Plant 05/09/05 Pyrolysis Furnace
(1054-1056) 250 0.38 lb/hr (0.0015 lb/MMBtu)
TX-0475
Formosa Point Comfort Plant 05/09/05 Pyrolysis Furnace
(1057-1062, 1091) 250 0.38 lb/hr (0.0015 lb/MMBtu)
TX-0475
Formosa Point Comfort Plant 05/09/05 Pyrolysis Furnace
(N1011-1012) 250 0.41 lb/hr (0.0016 lb/MMBtu)
TX-0511
BASF Ethylene/ Propylene Cracker 02/03/06 Boiler (2) 425.4 12.1 lb/hr
(0.0284 lb/MMBtu) NM-0050 Artesia Refinery 12/14/07 Steam Methane
Reformer Heater 337 Pipeline quality natural gas
0.494 lb/hr (0.0015 lb/MMBtu)
RBLC ID No. Facility Name Permit
Date Emission Unit
Description
Size in MMBtu/h
r Control Description SO2Limit 1
OH-0308
Sun Company, Inc., Toledo Refinery 02/23/09 Boiler (2) 374 Boilers are the control 9.15 lb/hr
(0.0245 lb/MMBtu) *WY-0071 Sinclair Refinery 10/15/201
2 581 Crude Heater 233 Follow Subpart Ja Fuel gas H2S limits
Permit Equistar Channelview, TX Op-2 11/14/12 Furnace 640 No more than 5 grains
S/100dscf 5 gr/100 dscf
(0.0071 lb/MMBtu) Draft
Permit ExxonMobil Baytown,
TX 2/13 8 Furnaces 575 No more than 5 gr S/100 dscf
5 gr/100 dscf (0.0071 lb/MMBtu)
Permit Chevron /Phillips Cedar Bayou, Tx 08/06/13 8 Furnaces 500
Fuel limited to plant fuel gas, ethane, or pipeline-
quality, sweet natural gas 1. Precedents based on H2S content are eliminated from consideration because they do not take into account other reduced sulfur
compounds that are known to exist in these refinery fuel gases
Table F.1-2. Summary of Catalyst Activation Heater Precedent for SO2 in the RBLC RBLC ID No. Facility Name Permit
Date Unit Description Capacity MMBtu/hr Control Description SO2 Limit
OH-0276 Charter Steel 06/10/04 (3) Tundish Preheaters 12 0.007 lb/hr (0.0006 lb/MMBtu)
OH-0276 Charter Steel 06/10/04 Ladle Preheater & Dryer, 4 Units 10 0.006 lb/hr
(0.0006 lb/MMBtu)
AR-0077 Bluewater Project 07/22/04 Furnaces, Heaters, &, Dryers 11 Natural gas combustion
only 0.0006 lb/MMBtu
WI-0227 Port Washington Generating Station 10/13/04 Gas Heater
(P06, S06) 10 Natural gas fuel 0.02 lb/hr (0.002 l lb/MMBtu)
*PA-0284
AK Steel Corp/Butler Works 03/11/05 Boiler 21 (Htp) 16.6668 0.5 lb/MMBtu
MD-0031 Chalk Point 04/01/05 (2) Natural Gas Fuel Heaters 10 Use of low sulfur fuels 0.056 lb/hr
(0.0056 lb/MMBtu)
AK-0062 Badami Development Facility 08/19/05 Natco Miscible
Injection Heater 14.87 Limit sulfur content of fuel combusted 250 ppmv
OH-0302 Republic Engineered Products, Inc. 08/30/05 (2) Ladle
Dryers/Preheaters 14.5
Good engineering practices; Natural gas w/ S content less than 0.6
wt%
0.01 lb/hr (0.0007 lb/MMBtu)
AR-0090 Nucor Steel, Arkansas 04/03/06 Pickle Line Boilers, Sn-52 12.6
0.1 lb/hr (0.0079 lb/MMBtu)
FL-0286 FPL West County Energy Center 01/10/07 (2) Gas-Fueled Process
Heaters 10 2gr/100 scf
OH-0315 New Steel International, Inc., Haverhill 05/06/08 Vacuum Oxygen
Degasser (4) 16 0.11 lb/hr (0.0069 lb/MMBtu)
FL-0303 FPL West County Energy Center Unit 3 07/30/08 Two Natural Gas-Fired
Process Heaters 10 2 gr/100 scf
AL-0251 Hillabee Energy Center 09/24/08 Fuel Heater 11.64 Pipeline quality natural gas
OK-0135 Pryor Plant Chemical 02/23/09 Nitric Acid Preheaters #1, #3, & #4 20 0.03 lb/hr
(0.0015 lb/MMBtu)
OK-0134 Pryor Plant Chemical 02/23/09 Nitric Acid Preheaters No. 1 (EU 401, EUG
4) 20 Natural gas combustion 0.03 lb/hr
(0.0015 lb/MMBtu)
RBLC ID No. Facility Name Permit
Date Unit Description Capacity MMBtu/hr Control Description SO2 Limit
*IN-0167 Magnetation LLC 04/16/13 Ground Limestone /Dolomite Additive System Air Heater
19 Use of natural Gas &
good combustion practices
0.0005 lb/MMBtu
Table F.1-3. Summary of Natural Gas-fired Combustion Turbine Precedents for SO2 in the RBLC RBLC ID No. Facility Name Permit
Date Emission Unit
Description MW Control Description SO2 Limit
OK-0056 Horseshoe Energy Project 2/12/02
Turbines & Duct Burners (45 MW GE LM6000 With 185
MMBtu/hr Db)
45 Low Sulfur Fuel (Natural
Gas) 0.0056 lb/MMBtu
TX-0295 Sam Rayburn Generation Station 1/17/02
Combustion Turbines 7,8,9 (No DBs) (45MW
Each) 45 Firing Nat Gas 2.2 lb/hr
MD-0036 Dominion 03/10/06 Solar Titan 130s; 12.2 MW; 137 MMBtu/hr
(@77 F) 12.2 0.9 lb/MW-hr
MD-0035 Dominion 08/12/05 Combustion Turbine 21.7 0.58 lb/MW-hr
NE-0022 C. W. Burdick Generating Station 06/22/04 Gas-Fired Combustion
Turbine 40
Fuel Limited to Pipeline Quality NG, Low Ash &
Sulfur Content Under 0.05%.
5.4 lb/hr
TX-0482 Cobisa Greenville 06/03/05 Turbines & Ducts Firing Natural Gas - Scenario
1, Case 1 80
Firing Low Sulfur Pipeline-Quality Natural Gas And Fuel Oil Will Control SO2 & H2SO4
211.2 lb/hr
TX-0482 Cobisa Greenville 06/03/05 Turbines & Ducts Firing Natural Gas - Scenario
2, Case 1 80
Firing Low Sulfur Pipeline-Quality Natural Gas And Fuel Oil Will Control SO2 & H2SO4
211.4 lb/hr
TX-0482 Cobisa Greenville 06/03/05 Turbines & Ducts Firing Natural Gas - Scenario
3, Case 1 80
Firing Low Sulfur Pipeline-Quality Natural
Gas & Fuel Oil Will Control SO2 & H2SO4.
231.5 lb/hr
TX-0525 Texas Genco Units 1 & 2 09/13/05 80 MW Gas Turbine 80 Case 3: Turbines Firing Natural Gas With Duct
Burners Fired 0.7 lb/hr
Table F.1-4. Summary of Emergency Generator Precedents for SO2 in the RBLC
RBLC ID No. Facility Name Permit
Date Emission Unit
Description Size Size in
BHP Control Description SO2 Limit
TX-0440 Corpus Christi LNG 01/20/04 Emergency Diesel Generator 1500 KW 1983 4.44 lb/hr
WV-0023 Maidsville 03/02/04 Emergency Generator 1801 hp 1776 Sulfur content in the fuel
limited to 0.05 wt% 500 hr/yr Op
6.5 lb/hr
LA-0211 Garyville Refinery 12/27/06 Emergency Generators 1341 hp 1322 0.02 lb/hr
IA-0088 ADM Corn Processing - Cedar Rapids 06/29/07 Emergency Generator 1500 KW 1983
Burn low-sulfur diesel fuel 0.05 wt% or less not to exceed
the NSPS requirement. 0.17 g/bhp-hr
SC-0114 GP Allendale LP 11/25/08 Diesel Emergency Generator 1400 hp 1381 5.4 lb/hr
OK-0129 Chouteau Power Plant 01/23/09 Emergency Diesel Generator (2200 hp) 2200 hp 2170 Low sulfur diesel 0.05%S 0.89 lb/hr
SC-0115 GP Clarendon LP 02/10/09 Diesel Emergency Generator 1400 hp 1381
Tune-ups & inspections will be performed as outlined in
the good management practice plan.
5.4 lb/hr
LA-0231 Lake Charles Gasification Facility 06/22/09
Emergency Diesel Power Generator
Engines (2) 1341 hp 1322 Comply with 40 CFR 60
Subpart IIII 0.01 lb/hr
FL-0332 Highlands Biorefinery & Cogeneration Plant 09/23/11 600 hp Emergency
Equipment 600 hp 592 . 0.0015 wt%
IN-0166 Indiana Gasification, LLC 06/27/12 Two (2) Emergency
Generators 1341 hp 1322 Use of low-S diesel & limited
hours of non-emergency operation
15 ppmw
PA-0278 Moxie Liberty LLC/Asylum Power 10/10/12 Emergency Generator 0.005 g/bhp-hr
PA-0268 Moxie Energy LLC/ Patriot Generation Plant 01/31/13 Emergency Generator 0.005 g/bhp-hr
PA-0291 Hickory Run Energy Station 04/23/13 Emergency Generator 1135 bhp 1135 Ultra low sulfur distillate 0.01 lb/hr
OH-0352 Oregon Clean Energy Center 06/18/13 Emergency Generator 2250 KW 2975 0.03 lb/hr
Table F.1-5. Summary of Firewater Pump Engine Precedents for SO2 in the RBLC
RBLC ID No. Facility Name Permit
Date Emission Unit
Description Size Size in
BHP Control Description SO2 Limit
TX-0440 Corpus Christi LNG 01/20/04 Diesel Firewater Pump 660 HP 651 1.08 lb/hr
TX-0440 Corpus Christi LNG 01/20/04 Diesel Firewater
Booster Pump 525 HP 518 1.35 lb/hr
TX-0446 Jasper Oriented Strandboard Mill 02/09/04 Fire Water Pump 1.18 lb/hr
WV-0023 Maidsville 03/02/04 IC Engine, Fire Water Pump 85 HP 84 Sulfur content limited to
0.05 wt% 3.3 lb/hr
TX-0447 Carhage Oriented Strandboard Mill 3/16/04 Fire Water Pump 1.23 lb/hr
OH-0275 PSI Energy-Madison Station 08/24/04 Emergency Diesel Fire
Pump
1.6 MMBTU
/H 222
Sulfur limited to 0.05 wt%
Operations limited to 499 hr/yr
0.8 lb/hr
WI-0228 WPS - Weston Plant 10/19/04 Main Fire Pump
(Diesel Engine) 460 HP 454 Good combustion
practices, ULSD (0.003 Wt. % S)
0.94 lb/hr
NC-0112 Nucor Steel 11/23/04
Diesel Fired Emergency Generators
And Diesel Fired Emergency Water
Pumps
Operation limited to 100 hours for each emergency generator & water pump
per 12 month period
OH-0252 Duke Energy Hanging Rock Energy Facility
12/28/04 Fire Water Pump (1) 265 HP 261 Low sulfur fuel 0.1 lb/hr
LA-0192 Crescent City Power 06/06/05 Diesel Fired Water
Pump 425 HP 419 Good engine design &
Proper operating practices
0.61 lb/hr
NC-0101 Forsyth Energy Plant 09/29/05 IC Engine, Emergency
Firewater Pump
11.4 MMBTU
/H 1581 0.58 lb/hr
RBLC ID No. Facility Name Permit
Date Emission Unit
Description Size Size in
BHP Control Description SO2 Limit
TX-0511 BASF
Ethylene/Propylene Cracker
02/03/06 (2) Fire Water Pump Engine 1.05 lb/hr
IA-0088 ADM Corn Processing - Cedar Rapids
6/29/07 Fire Pump 540 HP 533
Burn low-Sulfur diesel Fuel. 0.05 wt% or less not to exceed the NSPS
requirement.
0.17 g/bhp-hr
IA-0089 Homeland Energy Solutions, LLC,
PN 06-672 08/08/07
Emergency Diesel Fire Water Pump, S110,
(07-A-982p) 300 BHP 300 None 0.203 g/kwh
MN-0070 Minnesota Steel Industries, LLC 09/07/07
Diesel Fire Water Pumps
(500 HP)
Limited sulfur In fuel; limited hours 0.05 wt%
LA-0224 Arsenal Hill Power Plant 03/20/08 DFP Diesel Fire Pump 310 HP 306
Use of low-sulfur fuels, limiting operating hours
& proper engine maintenance
0.64 lb/hr
FL-0304 Cane Island Power Park 09/08/08
Emergency Fired Pump 7 ULSD Oil Storage
Tank
IA-0095 Tate & Lyle Ingredients
Americas, Inc. 9/19/08 Fire Pump Engine 575 HP 567 Limit on sulfur in fuel 0.23 g/kwh
MD-0040 CPV St Charles 11/12/08 Internal Combustion Engine - Emergency
Fire Water Pump 300 HP 296
SC-0114 GP Allendale LP 11/25/08 Fire Water Diesel Pump 525 HP 518
Tune-ups & inspections will be performed as
outlined in good management practice
plan
0.39 lb/hr
OK-0129 Chouteau Power Plant 01/23/09 Emergency Fire Pump
(267-Hp Diesel) 267 HP 263 Low sulfur diesel 0.11 lb/hr
RBLC ID No. Facility Name Permit
Date Emission Unit
Description Size Size in
BHP Control Description SO2 Limit
SC-0115 GP Clarendon LP 02/10/09 Fire Water Diesel Pump 525 HP 518
Tune-ups & inspections will be performed as
outlined in good management practice
plan
0.39 lb/hr
LA-0231 Lake Charles Gasification
Facility 06/22/09 Fire Water Diesel
Pumps (3) 575 HP 567 Comply with 40 CFR 60 subpart IIII 0.01 lb/hr
FL-0318 Highlands Ethanol Facility 12/10/09 Emergency Fired Pump 360 HP 355 Ultra low sulfur fuel oil
(ULSFO) 15 ppmw
FL-0324 Palm Beach Renewable
Energy Park 12/23/10 Two emergency diesel
firewater pump engines 250 HP 246 15 ppmw
FL-0323 Gainesville Renewable
Energy Center 12/28/10 Emergency Diesel Fire
Pump - 275 HP 275 HP 271
The permittee shall adhere to the compliance
testing & certification requirements listed in 40
CFR 60.4211 and maintain records
demonstrating fuel usage and quality.
15 ppmw
SC-0113 Pyramax Ceramics, LLC 02/08/12 Fire Pump 500 HP 493
Use Of Low Sulfur Fuel Diesel, Sulfur Content
Less Than 0.0015 Percent. Operating Hours Less Than 100 Hours Per Year For Maintenace And
Testing.
IN-0166 Indiana Gasification, LLC 06/27/12 Three (3) Firewater
Pump Engines 575 HP 567 Use Of Low-S Diesel & Limited Hours Of Non-Emergency Operation
15 ppmw
RBLC ID No. Facility Name Permit
Date Emission Unit
Description Size Size in
BHP Control Description SO2 Limit
WY-0070 Cheyenne Prairie
Generating Station
08/28/12 Diesel Fire Pump Engine (EP16) 327 HP 322 Ultra Low Sulfur Diesel
PA-0278 Moxie Liberty LLC/ Asylum
Power Pl T 10/10/12 Fire Pump 0.005 g/bhp-hr
IN-0158 St. Joseph Energy Center, LLC 12/03/12 Two (2) Firewater
Pump Diesel Engines 371 BHP 371 Ultra Low Sulfur Distillate & Usage Limits 15 ppmw
PA-0286 Moxie Energy LLC/Patriot
Generation PLT 1/31/13 Fire Pump Engine - 460
BHP 460 BHP 460
0.005 g/hp-hr
IN-0167 Magnetation LLC 04/16/13 Fire Water Pump 300 HP 296 Use of Natural Gas &
Good Combustion Practices
0.0015 g/kwh
PA-0291 Hickory Run Energy Station 4/23/13
Emergency Firewater Pump (450 BHP)
3.25 MMBTU
/H 450
0.0055 lb/hr
OH-0352 Oregon Clean Energy Center 06/18/13 Emergency fire pump
engine 300 HP 296 0.003 lb/hr
NH3 BAT Analysis - RBLC Database Summaries
Table F.2-1 Summary of NH3 RBLC and Recent Permits for Furnaces RBLC ID
No. Facility Name Permit Date Emission Unit Description
Capacity (MMBtu/hr) NH3 Limit
TX-0505 Certainteed Insulation Fiber Glass & Ductliner Manufacturing 04/19/06 Bi Stack 73.85 lb/hr
TX-0526 Air Products Hydrogen, Steam, & Electricity Production 08/18/06
Reformer Furnace Stack 1373 24.9 lb/hr
TX-0496 Ineos Chocolate Bayou Facility 08/29/06 Furnace Emission Caps 27.47 lb/hr
NM-0050 Artesia Refinery 12/14/207 Steam Methane Reformer Heater 337 7 ppmv (WET)
TX-0580 Mckee Refinery Hydrogen Production Unit 12/30/210
Hydrogen Production Unit Furnace 355.65
10 ppmv
Not in RBLC BASF Fina Port Arthur, TX1 7/16/12 Cracking Furnace 487.5 10 ppmvd at 15% O2
Not in RBLC Equistar Channelview, TX Op-2 2 11/14/12 Furnace 640 10 ppmvd at 3% O2 hourly
Not in RBLC Equistar Channelview, TX Op-1 3 1/12/13 Furnace 640 10 ppmv at 3% O2
Not in RBLC ExxonMobil Baytown, TX 4
2/13 (DRAFT) Furnace 575 15 ppmvd at 3% O2 hourly
Not in RBLC Chevron/Phillips Cedar Bayou, TX 5 08/06/13 Furnace 500
10 ppmvd at 3% O2 hourly and annually
1. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Numbers 36644, PSDTX903M3, and N007M1, 7/2012
2. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Numbers 2933/PSDTX1270/N140, 11/20123. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Numbers 18978 PSDTX752M5, N162, 1/20134. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Numbers 1029825. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Numbers 1504A,PSDTX748M1/N148
Table F.2-2 Summary of NH3 RBLC Results for Combustion Turbines RBLC ID No. Facility Name Permit
Date Emission Unit Description Capacity NH3 Limit
OR-0043 Umatilla Generating Company, L.P. 05/11/04
Turbine, Combined Cycle &Amp; Duct Burner, Nat Gas (2) 2,007 MMBtu/hr 5 ppmvd @ 15% O2
NV-0037 Copper Mountain Power 05/14/04 Large Combustion Turbines, Combined Cycle &Amp; Cogeneration 600 MW 10 ppmvd
NV-0033 El Dorado Energy, LLC 08/19/04 Combustion Turbine, Combined Cycle &Amp; Cogen(2) 475 MW 10 ppmvd @ 15% O2
TX-0479 Dow Texas Operations Freeport 12/02/04 Piping Fugitives For Turbines (5) 0.26 lb/hr
TX-0479 Dow Texas Operations Freeport 12/02/04
Combustion Via Four Gas-Fired Steam Boilers 410 MMBtu/hr 1.7 lb/hr
TX-0479 Dow Texas Operations Freeport 12/02/04
2 WESTINGHOUSE 501F TURBINES WITH 2 735mmbtu/Hr DUCT BURNER (START UP) 735 MMBtu/hr
27.58 lb/hr
TX-0479 Dow Texas Operations Freeport 12/02/04
2 WESTINGHOUSE 501F TURBINES WITH 2 735mmbtu/Hr DUCT BURNER (START-UP, SHUTDOWN, MAINTENANCE) 735 MMBtu/hr
27.58 lb/hr
OH-0252 Duke Energy Hanging Rock Energy Facility 12/28/04
Turbines (4) (Model Ge 7fa), Duct Burners Off 172 MW 28 lb/hr
OH-0252 Duke Energy Hanging Rock Energy Facility 12/28/04
Turbines (4) (Model Ge 7fa), Duct Burners On 172MW 37.8 lb/hr
WA-0328 BP Cherry Point Cogeneration Project 01/11/05
Ge 7fa Combustion Turbine &Amp; Heat Recovery Steam Generator 174 MW 5 ppmvd
FL-0263 FPL Turkey Point Power Plant 02/08/05 170 Mw Combustion Turbine, 4 Units 170 MW 5 ppmvd @ 15% O2
TX-0482 Cobisa Greenville 06/03/05 Turbines And Ducts Firing Natural Gas - Scenario 4, Case 1 825 MMBtu/hr 127.4 lb/hr
TX-0482 Cobisa Greenville 06/03/05 Turbines And Ducts Firing Natural Gas - Scenario 2, Case 1 550 MMBtu/hr 138.9 lb/hr
TX-0482 Cobisa Greenville 06/03/05 Turbines And Ducts Firing Natural Gas - Scenario 1, Case 1 550 MMBtu/hr 144.3 lb/hr
TX-0482 Cobisa Greenville 06/03/05 Turbines And Ducts Firing Natural Gas - Scenario 3, Case 1 550 MMBtu/hr 157.9 lb/hr
OR-0041 Wanapa Energy Center 08/08/05 Combustion Turbine &Amp; Heat Recovery Steam Generator 2,384.1 MMBtu/hr 5 ppmvd @ 15% O2
RBLC ID No. Facility Name Permit
Date Emission Unit Description Capacity NH3 Limit
NJ-0066 AES Red Oak LLC 02/16/06 Combined Cycle Natural Gas Fired Combustion Turbines( 3) 63,122 MMscf/yr 29.1 lb/hr
TX-0509 Ponderosa Pine Energy Partners Cogeneration 03/15/06
Turbine And 375 MMBtu/hr Heat Recovery Steam System 250 MW 32.5 lb/hr
TX-0506 NRG Texas Electric Power Generation 04/19/06 Annual Limits 89.7 T/YR
TX-0504 Navasota Power Generation Facility 04/20/06
Turbines Without 165 MMBtu/hr Duct Burners 75 MW 9.6 lb/hr
TX-0504 Navasota Power Generation Facility 04/20/06 Startup, Shutdown, Maintenance 75 MW 10.8 lb/hr
TX-0504 Navasota Power Generation Facility 04/20/06
Turbines With 165 MMBtu/hr Duct Burners 75 MW 11.1 lb/hr
TX-0502 Nacogdoches Power Sterne Generating Facility 06/05/06
Westinghouse/Siemens Model SW501F Gas Turbine w/ 416.5 MMBtu Duct Burners 190 MW
16.8 lb/hr
TX-0497 Ineos Chocolate Bayou Facility 08/29/06
Cogeneration Train 2 & 3 (Turbine & Duct Burner Emissions) 35 MW 8.45 lb/hr
FL-0285 Progress Bartow Power Plant 01/26/07
Combined Cycle Combustion Turbine System (4-On-1) 1,972 MMBtu/hr 5 ppmvd
FL-0286 FPL West County Energy Center
01/10/07 Combined Cycle Combustion Gas Turbines - 6 Units
2,333 MMBtu/hr 5 ppmvd @ 15 % O2
PA-0260 Delta Power Plant 01/03/08 Gas Fired Turbines (6) (Simple Cycle) 11,240 5 ppmvd @ 15% O2 PA-0260 Delta Power Plant 01/03/08 Gas Fired Turbines (60 (Combined Cycle) 11,240 5 ppmvd @ 15% O2 CT-0151 Kleen Energy Systems,
LLC 02/25/08 Siemens SGT 6-5000F Combustion
Turbine #1 & #2 (Natural Gas Fired) w/ 445 MMBtu/hr Natural Gas Duct Burner
2.1 MMcf/hr 2 ppm @ 15 % O2 at steady state
5 ppm @ 15% O2 all other times
FL-0305 OUC Curtis H. Stanton Energy Center 05/12/08
300 MW Combined Cycle Combustion Turbine 1,765 MMBtu/hr 5 ppmvd
FL-0304 Cane Island Power Park 09/0808 300 MW Combined Cycle Combustion Turbine 1,860 MMBtu/hr 5 ppmvd
TX-0600 Thomas C. Ferguson Power Plant 09/01/11 Natural Gas-Fired Turbines 390 MW 7 ppmvd
PA-0276 York Generation Facility 03/01/12 Combustion Turbine, Dual Fuel, T01 & T02 (2 Units) 634 MMBtu/hr 5 ppm
PA-0278 Moxie Liberty LLC/Asylum Power PLT 10/10/12
Combined-Cycle Turbines (2) - Natural Gas Fired 3,277 MMBtu/hr 5 ppmvd at 15% O2
RBLC ID No. Facility Name Permit
Date Emission Unit Description Capacity NH3 Limit
OH-0356 Duke Energy Hanging Rock Energy 12/18/12
Turbines (4) (Model GE 7FA) Duct Burners Off 172 MW 28 lb/hr
OH-0356 Duke Energy Hanging Rock Energy 12/18/12
Turbines (4) (Model GE 7FA) Duct Burners On 172 MW 31.7 lb/hr
PA-0288 Sunbury Generation LP/Sunbury SES 04/01/13
Combined Cycle Combustion Turbine & Duct Burner (3) 2,538,000 MMBtu/hr 5 ppmvd at 15% O2
PA-0291 Hickory Run Energy Station 04/23/13
Combined Cycle Units #1 & #2 Natural Gas 3.4 MMcf/hr 110.2 tpy
1. 42 Pa.B. 4724 confirms 15% O2
2. 43 Pa.B. 1425 confirms 15% O2
Appendix G
Compliance Demonstration Certain information in this appendix has been redacted. Redacted information constitutes trade secret and/or
confidential proprietary information as defined in the Pennsylvania Right to Know Law
Table G-1. Summary of Compliance Demonstration
Process Area Equip. ID Emissions Unit Pollutant Affected Source Regulation Compliance Requirement
Compliance Demonstration
Recordkeeping & Reporting
Ethylene Production
§63.1103(e)(2) -Ethylene production or production unit means a chemical manufacturing process unit in which ethylene and/or propylene are produced by separation from petroleum refining process streams or by subjecting hydrocarbons to high temperatures in the presence of steam. The ethylene production unit includes the separation of ethylene and/or propylene from associated streams such as a C4 product, pyrolysis gasoline, and pyrolysis fuel oil. Ethylene production does not include the manufacture of SOCMI chemicals such as the production of butadiene from the C4 stream and aromatics from pyrolysis gasoline.
§63.1103(e)(1)(i) -The affected source shall comprise all emission points listed in paragraphs (e)(1)(i) (A) through (G) of this section that are associated with an ethylene production unit that is located at a major source, as defined in section 112(a) of the Act.
Equipment Leaks HAP §63.1103(e)(1)(i)(D), §63.1019 Part 63 Subpart YY
§63.1103(e)(3) - Table 7(f)(1); §63.1107
§§63.1022 - 63.1035 §63.1038, §63.1039
non-HAP Part 63 Subpart YY
§63.1103(e) (1)(ii)(A) -Exception: Not subject to control requirements of 63.1103(e)(3).
NA NA
Ethylene Production Unit HAP §63.11 Part 63 Subpart A, Part 63 Subpart YY
§63.1, §63.1108(a)(1),(2), (5), (6), (7)
§§63.5 - 63.9, §63.11, §63.1108(b)
§63.10, §63.1109,§63.1110
All waste streams associated with an ethylene production unit.
§63.1103(e)(1)(i)(E) Part 63 Subpart YY
§63.1103(e)(3) - Table 7(g)(1)(i)
§§63.1091 - 1094 as applicable, §63.1095(b)(1),§61.342(c)(1), (2),(3)(i); §61.348(a)
§61.356 as applicableexcept §61.356(b)(2)(ii), (b)(3) through (b)(5); §61.357 as applicableexcept submit the information required in §61.357(a) as part ofthe Initial Notification required in §63.1110(c), submit the information in §61.357(d)(1) and (d)(2) for spent caustic, dilution steam blowdown, and continuous butadiene waste streams, submit the information required in §61.357(d)(1) as part ofthe Notification of Compliance Status required in §63.1110(d) and do not comply with §61.357(d)(3) through(d)(5).
T59708 Recovered Oil Storage - Wastewater Tank
HAP §63.1103(e)(1)(i)(E) Part 63 Subpart XX
§63.1095(b)(1) §61.348(b)(1), (c)(2),(e)-(g); §61.343(a), (c), (d); §61.349 as applicable; §61.354 as applicable; §61.355 asapplicable but specifically (h)
T59709 Biotreater Aeration Tank - Wastewater Treatment
HAP §63.1103(e)(1)(i)(E) Part 63 Subpart XX
§63.1095(b)(1) §61.342(c)(1)(i);§61.348(b)(2), (c)(1),(f)(g); §61.354(b)(2); §61.355(c)(3), (g)
A5401 Spent Caustic Vent Incinerator - Closed Vent System and Control Device
HAP §63.1103(e)(1)(i)(E) Part 63 Subpart XX
§63.1095(b)(1) §61.342(c)(1)(i);§61.348(a)(1)(iii);§61.348(c)(2);§61.349(a)(1),(a)(2)(i), (b), (c)(2), (e) - (h); §61.354(a)(2), (c)(1),(f), (g); §61.355(f), (h), (i)
1
Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law
Table G-1. Summary of Compliance Demonstration
Process Area Equip. ID Emissions Unit Pollutant Affected Source Regulation Compliance Requirement
Compliance Demonstration
Recordkeeping & Reporting
Wastewater - Individual Drain System
HAP §63.1103(e)(1)(i)(E) Part 63 Subpart XX
§63.1095(b)(1) §61.346; §61.349 asapplicable; §61.354 as applicable; §61.355 asapplicable but specifically (h)
T59707A/B FEOR Tank - Wastewater OWS HAP §63.1103(e)(1)(i)(E) Part 63 Subpart XX
§63.1095(b)(1) §61.348(b)(1), (c),(e)-(g); §61.347 as applicable; §61.349 as applicable; §61.354 asapplicable; §61.355 as applicable but specifically (h)
T53501 Spent Caustic Storage - Wastewater Tank
HAP §63.1103(e)(1)(i)(E) Part 63 Subpart XX
§63.1095(b)(1) §61.348(b)(1), (c)(2),(e)-(g); §61.343(a), (c), (d); §61.349 as applicable; §61.354 as applicable; §61.355 asapplicable but specifically (h)
T53502 Unoxidized Spent Caustic Storage - Tank
HAP §63.1103(e)(1)(i)(A), §63.1060 Part 63 Subpart YY
§63.1103(e)(3) - Table 7(b)(1)(i)
§63.1062, §63.1063 §63.1065, §63.1066
2
Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law
Table G-1. Summary of Compliance Demonstration
Process Area Equip. ID Emissions Unit Pollutant Affected Source Regulation Compliance Requirement
Compliance Demonstration
Recordkeeping & Reporting
Ethylene process vents - 63.1103(e)(2) Definitions. Ethylene process vent means a gas stream with a flow rate greater than 0.005 standard cubic meters per minute containing greater than 20 parts per million by volume HAP that is continuously discharged during operation of an ethylene production unit, as defined in this section. Ethylene process vents are gas streams that are discharged to the atmosphere (or the point of entry into a control device, if any) either directly or after passing through one or more recovery devices. Ethylene process vents do not include relief valve discharges; gaseous streams routed to a fuel gas system; leaks from equipment regulated under this subpart; episodic or nonroutine releases such as those associated with startup, shutdown, and malfunction; and in situ sampling systems (online analyzers).
HAP §63.1103(e)(1)(i)(B) Part 63 Subpart YY
§63.1103(e)(3) - Table 7(d)(1)(i); §63.1104 except for paragraphs (d), (g), (h), (i), (j), (l)(1), and (n).
§63.982(b), §63.983 §63.998, §63.999
V64205/ V64206
C3+ Storage - Sphere HAP §63.1103(e)(1)(i)(A) Part 63 Subpart YY
§63.1103(e)(1)(ii)(K) -Exception: Not subject to control requirements of §63.1103(e)(3).
NA
T64207/ T64208
Light Gasoline Storage - Tank HAP §63.1103(e)(1)(i)(A) Part 63 Subpart YY
§63.1103(e)(3) - Table 7(b)(1)(ii)
§63.982(b), §63.983 §63.998, §63.999
T64201 Pyrolysis Tar Storage - Tank HAP §63.1103(e)(1)(i)(A) Part 63 Subpart YY
§63.1103(e)(1)(ii)(G) -Exception: Not subject to control requirements of §63.1103(e)(3).
NA
C3+ Loading - Transfer Rack HAP §63.1103(e)(1)(i)(C) Part 63 Subpart YY
§63.1103(e)(1)(ii)(I) -Exception: Not subject to control requirements of §63.1103(e)(3).
NA
Pyrolysis Tar Loading - Transfer Rack
HAP §63.1103(e)(1)(i)(C) Part 63 Subpart YY
§63.1103(e)(1)(ii)(H) -Exception: Not subject to control requirements of §63.1103(e)(3).
NA
3
Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law
Table G-1. Summary of Compliance Demonstration
Process Area Equip. ID Emissions Unit Pollutant Affected Source Regulation Compliance Requirement
Compliance Demonstration
Recordkeeping & Reporting
Ethylene cracking furnaces and associated decoking operations
HAP §63.1103(e)(1)(i)(G) Part 63 Subpart YY
§63.1103(e)(1)(ii)(J) -Exception: Not subject to control requirements of §63.1103(e)(3).
NA
HPGFLARE1/2, HPEFLARE, REFTANKFLARE
High Pressure Ground Flares, High Pressure Elevated Flare, Refrigerated Tank Flare
HAP §63.11(a)(1), (2) Part 63 Subpart A
§63.11(b) §63.11(b)(4), (5);§63.987; §63.997(a)- (c)
§63.998, §63.999
Stormwater from segregated sewers, water from fire-fighting and deluge systems in segregated sewers, Spills, Water from safety showers, Water from testing of fire-fighting and deluge systems, Vessels storing organic liquids that contain organic HAP as impurities, Vessels permanently attached to motor vehicles such as trucks, railcars, barges, or ships.
Non-HAP Part 63 Subpart YY
§63.1103(e)(1)(ii)(B) -(G), (L) Exception: Not subject to control requirements of §63.1103(e)(3).
NA
Heat Exchange System HAP §63.1103(e)(1)(i)(F), §63.1083, §63.1084 Part 63 Subpart YY
§63.1085 §§63.1086 - 63.1088 §63.1089, §63.1090
V64201/ V64202
Ethylene Storage - Sphere VOC §60.110b(a) Part 60 Subpart Kb
§60.112b(d)(2) - Thissubpart does not apply to the following: Pressure vessels designed to operate in excess of 204.9 kPa and without emissions to the atmosphere.
NA
§60.116b
V64205/ V64206
C3+ Storage - Sphere
V18831 DMDS Storage - Tank T-64201 Ethylene Refrigerated
Atmospheric Storage V-64203 Refrigerant Storage
T53501 Spent Caustic Storage - Wastewater Tank
§60.112b(a) §63.1100(g)(1)(ii) -After the compliance date, a storage vessel that must be controlled according to the requirements of Part 63 Subpart YY and subpart Kb or 40 CFR Part 60 is required to comply only with the storage vessel
NA
T53502 Unoxidized Spent Caustic Storage - Tank
T64207/ T64208
Light Gasoline Storage - Tank
4
Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law
Table G-1. Summary of Compliance Demonstration
Process Area Equip. ID Emissions Unit Pollutant Affected Source Regulation Compliance Requirement
Compliance Demonstration
Recordkeeping & Reporting
requirements of Part 63 Subpart YY.
T64202 Pyrolysis Tar Storage - Tank §60.112b(a)(3) §60.113b(c) §60.115b(c), §60.116b
T59708 Recovered Oil Storage - Wastewater Tank
VOC Storage Tank 25 Pa. Code Ch. 129
25 Pa. Code §129.57
T59707A/B FEOR Tank - Wastewater OWS 25 Pa. Code §129.56(a)(2) T53501 Spent Caustic Storage -
Wastewater Tank T53502 Unoxidized Spent Caustic Storage -
Tank V64205/V64206
C3+ Storage - Sphere
T64207/T64208
Light Gasoline Storage - Tank
V64201/V64202
Ethylene Storage - Sphere
V18831 DMDS Storage - Tank 25 Pa. Code §129.57 T-64201 Ethylene Refrigerated
Atmospheric Storage 25 Pa. Code §129.56(a)(2)
V-64203 Refrigerant Storage T64202 Pyrolysis Tar Storage - Tank 25 Pa. Code §129.57
Ethylene Production Unit VOC Waste gas streams 25 Pa. Code §129.65
25 Pa. Code §129.65 - No person may permit the emission into the outdoor atmosphere of a waste gas stream from an ethylene production plant or facility unless the gas stream is properly burned at no less than 1,300°F for at least .3 seconds; except that no person may permit the emission of volatile organic compounds in gaseous form into the outdoor atmosphere from a vapor blowdown system unless these
5
Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law
Table G-1. Summary of Compliance Demonstration
Process Area Equip. ID Emissions Unit Pollutant Affected Source Regulation Compliance Requirement
Compliance Demonstration
Recordkeeping & Reporting
gases are burned by smokeless flares.
GHG §98.240 Part 98 Subpart X
§§98.241-243, 245 §98.244 §§98.246, 247
Equipment Leaks VOC 25 Pa. Code §129.71(a) - This section applies to a facility with design capability to manufacture 1,000 tons per year or more of the following: (1) Synthetic organic chemicals listed in 40 CFR 60.489 (relating to list of chemicals provided by affected facilities).
25 Pa. Code §129.71
25 Pa. Code §129.71(d) 25 Pa. Code §129.71(d)
25 Pa. Code §129.71(d), (e)
§60.480a Part 60 Subpart VVa
§§60.482-1a - 60.482-11a §60.485a §60.486a, §60.487a
A5401 Spent Caustic Vent Incinerator - Closed Vent System and Control Device
NOx 25 Pa. Code §121.1 - Incinerator - A device designed to burn or oxidize solid, semisolid, liquid or gaseous wastes for the primary purpose, as determined by the Department, of volume reduction or of disposal. The term includes heat recovery systems.
25 Pa. Code Ch. 129
25 Pa. Code §129.93(c)(4), (6)
PM 25 Pa. Code Ch. 123
25 Pa. Code §123.12
HPGFLARE1/2, HPEFLARE, REFTANKFLARE
High Pressure Ground Flares, High Pressure Elevated Flare, Refrigerated Tank Flare
NOx 25 Pa. Code §121.1 - Incinerator - A device designed to burn or oxidize solid, semisolid, liquid or gaseous wastes for the primary purpose, as determined by the Department, of volume reduction or of disposal. The term includes heat recovery systems.
25 Pa. Code Ch. 129
25 Pa. Code §129.93(c)(4), (6)
PM 25 Pa. Code Ch. 123
25 Pa. Code §123.12
HPGFLARE1/2, HPEFLARE, REFTANKFLARE
High Pressure Ground Flares, High Pressure Elevated Flare, Refrigerated Tank Flare
VOC Part 60 Subpart A
§60.18
Process Vents VOC
§60.660, §60.667 Part 60 Subpart NNN §60.662 §60.663, §60.664 §60.665
6
Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law
Table G-1. Summary of Compliance Demonstration
Process Area Equip. ID Emissions Unit Pollutant Affected Source Regulation Compliance Requirement
Compliance Demonstration
Recordkeeping & Reporting
PM 25 Pa. Code §121.1 Process - A method, reaction or operating in which materials are handled or whereby materials undergo physical change-that is, the size shape, appearance, temperature, state or other physical property of the material is altered-or chemical change-that is, as substance with different chemical composition or properties is formed or created. The term includes all of the equipment, operations and facilities necessary for the completion of the transformation of the materials to produce a physical or chemical change. There may be several processes in series or parallel necessary to the manufacture of a product.
25 Pa. Code Ch. 123
25 Pa. Code §123.13(a), (c)(1)
Ethylene cracking furnaces and
associated decoking operations NOx 25 Pa. Code §123.51(a) - Combustion units with
a rated heat input of 250MMBtu/hr or greater and with an annual average capacity factor of greater than 30%.
25 Pa. Code Ch. 129
25 Pa. Code §129.93(c)(6)
25 Pa. Code §129.91(i), (j)
SO2 25 Pa. Code §121.1 - Combustion unit - A stationary equipment used to burn fuel primarily for the purpose of producing power or heat by indirect heat transfer.
25 Pa. Code Ch. 123
25 Pa. Code §123.22(d)(2)
NA
PM 25 Pa. Code
§123.11(a)(2) Polyethylene 1/2/3
§63.2440(a) - This subpart applies to each miscellaneous organic chemical manufacturing affected source.
§63.2440(b) - The miscellaneous organic chemical manufacturing affected source is the facilitywide collection of MCPU and heat exchange systems, wastewater, and waste management units that are associated with manufacturing materials described in §63.2435(b)(1).
Polyethylene Production Unit HAP §63.2435(a), (b)(1)(i), (b)(2); §63.2440(a), (b), (c)(1)
Part 63 Subpart A, Part 63 Subpart FFFF
§63.1, §63.2450, §63.2550
§§63.5 - 63.9, §63.11, §63.2450
§63.10, §63.2515, §63.2520, §63.2525
Equipment Leaks HAP §63.2435(b), §63.1019 Part 63 Subpart FFFF
§63.2480(a) - Table 6 - 2ai
§§63.1022 - 63.1035 §63.1038, §63.1039
Process Wastewater
HAP
§63.2440(b); §63.2485(b), (c); §63.2550(i); §63.132(b) - (e)
Part 63 Subpart FFFF
§63.2485(a) - Table 7; §63.132
§63.2485(d) - (f), (i) - (k), (m), (n); §§63.132 through 63.148 and the requirements referenced therein, except as specified in §63.2485.
§63.2485(o) if applicable.
Maintenance wastewater §63.2440(b); §63.2550(i) §63.2485(a) - Table 7 §63.105 and the requirements referenced therein, except as specified in §63.2485.
§63.105(e)
7
Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law
Table G-1. Summary of Compliance Demonstration
Process Area Equip. ID Emissions Unit Pollutant Affected Source Regulation Compliance Requirement
Compliance Demonstration
Recordkeeping & Reporting
Liquid streams in an open system within an MCPU
§63.2435(b) §63.2485(l) §63.149 and therequirements referenced therein, except as specified in §63.2485.
Stormwater from segregated sewers; Water from fire-fighting and deluge systems, including testing of such systems; Spills; Water from safety showers; Samples of a size not greater than reasonably necessary for the method of analysis that is used; Equipment leaks; Wastewater drips from procedures such as disconnecting hoses after cleaning lines; and Noncontact cooling water.
Non-HAP 63.2550(i) - The following are not considered wastewater for the purposes of this subpart: Stormwater from segregated sewers; Water from fire-fighting and deluge systems, including testing of such systems; Spills; Water from safety showers; Samples of a size not greater than reasonably necessary for the method of analysis that is used; Equipment leaks; Wastewater drips from procedures such as disconnecting hoses after cleaning lines; and Noncontact cooling water.
NA
8
Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law
Table G-1. Summary of Compliance Demonstration
Process Area Equip. ID Emissions Unit Pollutant Affected Source Regulation Compliance Requirement
Compliance Demonstration
Recordkeeping & Reporting
Process Vents HAP §63.2450(c); §63.2550(i) - Continuous processvent means the point of discharge to the atmosphere (or the point of entry into a control device, if any) of a gas stream if the gas stream has the characteristics specified in §63.107(b) through (h), or meets the criteriaspecified in §63.107(i), except: (1) The reference in §63.107(e) to a chemical manufacturing process unit that meets the criteria of §63.100(b) means an MCPU that meets the criteria of §63.2435(b); (2) The reference in §63.107(h)(4) to §63.113 means Table 1 to this subpart; (3) The references in §63.107(h)(7) to §§63.119 and 63.126 meantables 4 and 5 to this subpart; and (4) For the purposes of §63.2455, all references to the characteristics of a process vent (e.g., flowrate, total HAP concentration, or TRE index value) mean the characteristics of the gas stream. (5) The reference to “total organic HAP” in §63.107(d) means “total HAP” for the purposesof this subpart FFFF. (6) The references to an “air oxidation reactor, distillation unit, or reactor” in §63.107 mean any continuous operation for the purposes of this subpart. (7) A separate determination is required for the emissions from each MCPU, even if emission streams from two or more MCPU are combined prior to discharge to the atmosphere or to a control device.
Part 63 Subpart FFFF
§63.2455, §63.2455 -Table1 - 1ai, §63.2455 - Table1 - 4
§63.982(b);§63.982(c)(2);§63.983; §63.993
§63.998, §63.999
S2003A/B HAP Metal Process Vent Metal HAP §63.2550(i) - HAP metals means the metal portion of antimony compounds, arsenic compounds, beryllium compounds, cadmium compounds, chromium compounds, cobalt compounds, lead compounds, manganese compounds, mercury compounds, nickel compounds, and selenium compounds.
Part 63 Subpart FFFF
§63.2465(a) - Table 3 - 2 §63.2465(d)
HPGFLARE1/2
High Pressure Header Ground Flares
HAP §63.2455 Part 63 Subpart FFFF
§63.2450(e)(2) §63.11;§63.2450(f)(1)
§63.2450(f)(2); §63.998,§63.999
LPGFLARE Low Pressure Header Ground Flare
9
Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law
Table G-1. Summary of Compliance Demonstration
Process Area Equip. ID Emissions Unit Pollutant Affected Source Regulation Compliance Requirement
Compliance Demonstration
Recordkeeping & Reporting
LPINCINERATOR
Low Pressure Header Incinerator §63.2450(e)(1) §63.2450(g), (i), (k);§63.988; §§63.996,997 as applicable.
§63.998, §63.999
T64301 Hexene Storage - Tank Non-HAP §63.2250(i) - Storage tank means a tank or other vessel that is used to store liquids that contain organic HAP and/or hydrogen halide and halogen HAP and that has been assigned to an MCPU according to the procedures in §63.2435(d).
Part 63 Subpart FFFF
NA NA
§63.2525(a)
T64302 Hexene Storage - Tank
V64301 Butene Storage - Sphere
V64302 Butene Storage - Sphere
V64401 Isopentane Storage - Bullet
V64402 Isopentane Storage - Bullet
V64501 Isobutane Storage - Bullet
V64502 Isobutane Storage - Bullet
PEHEATEXCH Heat Exchange System HAP §63.2440(b); §63.2490 - Table 10; §63.104(a)Unless one or more of the conditions specified in paragraphs (a)(1) through (a)(6) of this section are met, owners and operators of sources subject to this subpart shall monitor each heat exchange system used to cool process equipment in a chemical manufacturing process unit .
§63.104(a) (5) The recirculating heat exchangesystem is used to cool process fluids that contain less than 5 percent by weight of total hazardous air pollutants listed in table 4 of this subpart.
Part 63 Subpart FFFF
NA NA
§63.2525(a)
LPGFLARE Low Pressure Header Ground Flare VOC Part 60 Subpart A
§60.18
PE1/2/3 Polyethylene Production Unit VOC §60.560(a) Part 60 Subpart DDD
§60.560(c) §60.564 §60.565
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Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law
Table G-1. Summary of Compliance Demonstration
Process Area Equip. ID Emissions Unit Pollutant Affected Source Regulation Compliance Requirement
Compliance Demonstration
Recordkeeping & Reporting
Emergency vent streams VOC §60.561 - Emergency vent stream means anintermittent emission that results from a decomposition, attempts to prevent decompositions, power failure, equipment failure or other unexpected cause that requires immediate venting of gases from process equipment in order to avoid safety hazards or equipment damage. This includes intermittent vents that occur from process equipment where normal operating parameters (e.g., pressure or temperature) are exceeded such that the process equipment cannot be returned to normal operating conditions using the design features of the system and venting must occur to avoid equipment failure or adverse safety personnel consequences and to minimize adverse effects of the runaway reaction. This does not include intermittent vents that are designed into the process to maintain normal operating conditions of process vessels including those vents that regulate normal process vessel pressure.
Part 60 Subpart DDD
§60.560(h) - Emergencyvent streams from a new, modified or reconstructed polyethylene affected facility are exempt from the requirements of §60.562-1(a)(2).§60.562-1(a)(2) - Thisparagraph does not apply to emergency vent streams exempted by §60.560(h) and as defined in §60.561.
NA NA
Equipment Leaks VOC §60.560(a)(4) - For VOC emissions fromequipment leaks from polypropylene, polyethylene, and polystyrene (including expandable polystyrene) manufacturing processes, the affected facilities are each group of fugitive emissions equipment (as defined in §60.561) within any process unit (as defined in§60.561). This subpart does not apply to VOCemissions from equipment leaks from poly(ethylene terephthalate) manufacturing processes.
Part 60 Subpart DDD
§60.562-2 §60.485 §60.486, §60.487
PE1BLENDA/B/C/D/E, PE2BLENDA/B/C/D/E
PE Process Vents VOC
§60.561 - Vent stream means any gas streamreleased to the atmosphere directly from an emission source or indirectly either through another piece of process equipment or a material recovery device that constitutes part of the normal recovery operations in a polymer process line where potential emissions are recovered for recycle or resale, and any gas stream directed to an air pollution control device. The emissions released from an air pollution control device are not considered a vent stream unless, as noted above, the control
Part 60 Subpart DDD
§60.562-1(a)(2) §60.560(g) toexempt this intermittent vent; §60.563(e) torequest compliance "by any other means", specifically residual VOC content in the granular resin below a level of 50 ppmw of resin.
§60.565(a)(10),§60.565(h)
11
Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law
Table G-1. Summary of Compliance Demonstration
Process Area Equip. ID Emissions Unit Pollutant Affected Source Regulation Compliance Requirement
Compliance Demonstration
Recordkeeping & Reporting
device is part of the normal material recovery operations in a polymer process line where potential emissions are recovered for recycle or resale. Continuous emissions means any gas stream containing VOC that is generated essentially continuously when the process line or any piece of equipment in the process line is operating. Intermittent emissions means those gas streams containing VOC that are generated at intervals during process line operation and includes both planned and emergency releases.
§60.562-1(a)(1)(i),§60.560(g) - Individualvent streams that emit continuous emissions with uncontrolled annual emissions of less than 1.6 Mg/yr (1.76 ton/yr) or with a weight percent TOC of less than 0.10 percent from a new, modified, or reconstructed polypropylene or polyethylene affected facility are exempt from the requirements of §60.562-1(a)(1).
§60.564(d), ResidualVOC content in the granular resin below a level of 50 ppmw of resin.
PE1RAILSILOA/B/C/D, PE2RAILSILOA/B/C/D
Process Vent - Railcar Storage Silos
PE1RAILDEDUSTA/B, PE2RAILDEDUSTA/B
Process Vent - Rail Car DeDuster Vents
PE1RAILLOAD A/B, PE2RAILLOAD A/B
Process Vent – Rail Car Loading
PE1TRUCKSILOA/B/C/D/E/F/G/H/I/J, PE2TRUCKSILOA/B/C/D/E/F/G/H/I/J
Process Vent - Truck Storage Silos
PE1TRUCKDEDUSTA/B/C/D/E, PE2TRUCKDEDUSTA/B/C/D/E
Process Vent - Truck DeDuster Vents
12
Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law
Table G-1. Summary of Compliance Demonstration
Process Area Equip. ID Emissions Unit Pollutant Affected Source Regulation Compliance Requirement
Compliance Demonstration
Recordkeeping & Reporting
PE1TRUCKLOAD A-E, PE2TRUCKLOAD A-E
Process Vent – Truck Loading
SANDPIT
PE Process Vents
§60.564(d)S2003A/B C6004
§60.564(d), ResidualVOC content in the granular resin below a level of 50 ppmw of resin.
C6003 V6007 V7001A/B/C/D PE3RAILSILOA/B/C/D
Process Vent - Railcar Storage Silos
PE3RAILDEDUSTA/B
Process Vent - Rail Car DeDuster Vents
PE3RAILLOAD A/B
Process Vent – Railcar Loading
PE3TRUCKSILO A/B/C/D/E/F/G/H/I/J/K/L /M/N/O/P/Q/R
Process Vent - Truck Storage Silos
PE3TRUCKDEDUST A/B/C/D/E/F/G/H/I
Process Vent - Truck DeDuster Vents
PE3TRUCKLOAD A-I
Process Vent – Truck Loading
T64301 Hexene Storage - Tank VOC §60.110b(a) Part 60 Subpart Kb
§60.112b(a)(3) §60.113b(c) or (d) asapplicable
§60.115b(c) or (d) asapplicable, §60.116b
T64302 Hexene Storage - Tank
V64301 Butene Storage - Sphere §60.112b(d)(2) - Thissubpart does not apply to the following: Pressure vessels designed to operate in excess of 204.9 kPa and without emissions to the atmosphere.
NA
§60.116bV64302 Butene Storage - Sphere V64401 Isopentane Storage - Bullet V64402 Isopentane Storage - Bullet V64501 Isobutane Storage - Bullet V64502 Isobutane Storage - Bullet
13
Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law
Table G-1. Summary of Compliance Demonstration
Process Area Equip. ID Emissions Unit Pollutant Affected Source Regulation Compliance Requirement
Compliance Demonstration
Recordkeeping & Reporting
HPGFLARE High Pressure Header Ground Flare: Process Vent -
S3004
VOC
§60.561 - Control device means an enclosedcombustion device, vapor recovery system, or flare.
Part 60 Subpart DDD
§60.562-1(a)(1)(i)(C),§60.562-1(d), §60.562-1(e)
§60.18, §60.562-1(a)(2)(i), §60.563(a)(2),§60.563(a)(3),§60.563(c),§60.563(d),§60.564(e), (f)
§60.565(a)(3), (5);§60.565(e),§60.565(b)(1),§60.565(a)(3)(i),§60.565(a)(5)(i)LPGFLARE Low Pressure Header Ground
Flare: Process Vent -
V5005, T5004, R5002, R5003A/B, R5004, E5011, S4005A/B, E4001
LPINCIN Low Pressure Header Incinerator: Process Vent -
V5005, T5004, R5002, R5003A/B, R5004, E5011, S4005A/B, E4001
§60.562-1(a)(1)(i)(A),§60.562-1(d), §60.562-1(e), §60.562-1(a)(2)(ii)
§60.562-1(a)(2)(ii),§60.563(a)(1),§60.563(a)(3),§60.563(b)(1)(i),§60.563(b)(2),§60.563(c),§60.563(d),§60.564(b),§60.564(c)
§60.565(a)(4),§60.565(c),§60.565(b)(1),§60.565(a)(1),§60.565(a)(4)
PE Process Vents
PM
25 Pa. Code §121.1 Process - A method, reaction or operating in which materials are handled or whereby materials undergo physical change-that is, the size shape, appearance, temperature, state or other physical property of the material is altered-or chemical change-that is, as substance with different chemical composition or properties is formed or created. The term includes all of the equipment, operations and facilities necessary for the completion of the transformation of the materials to produce a physical or chemical change. There may be several processes in series or parallel necessary to the manufacture of a product.
25 Pa. Code §123.13
25 Pa. Code §123.13(a), (c)(1)
PE1BLENDA/B/C/D/E, PE2BLENDA/B/C/D/E
14
Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law
Table G-1. Summary of Compliance Demonstration
Process Area Equip. ID Emissions Unit Pollutant Affected Source Regulation Compliance Requirement
Compliance Demonstration
Recordkeeping & Reporting
PE1RAILSILOA/B/C/D, PE2RAILSILOA/B/C/D
Process Vent - Railcar Loading Silos
PE1RAILDEDUSTA/B, PE2RAILDEDUSTA/B
Process Vent - Rail Car DeDuster Vents
PE1TRUCKSILOA/B/C/D/E/F/G/H/I/J, PE2TRUCKSILOA/B/C/D/E/F/G/H/I/J
Process Vent - Truck Loading Silos
PE1TRUCKDEDUSTA/B/C/D/E, PE2TRUCKDEDUSTA/B/C/D/E
Process Vent - Truck DeDuster Vents
C6005
PE Process Vents
Q6002A/B/C/D C6004 C6003 V6007 V7001A/B/C/D PE3RAILSILO A/B/C/D
Process Vent - Railcar Loading Silos
PE3RAILDEDUSTA/B
Process Vent - Rail Car DeDuster Vents
PE3TRUCKSILO A/B/C/D/E/F/G/H/I /J/K/L/M/N/O/P/Q/R
Process Vent - Truck Loading Silos
PE3TRUCKDEDUST A/B/C/D/E/F/G/H/I
Process Vent - Truck DeDuster Vents
S2003A/B Process Vent - R2001A, R2001B
15
Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law
Table G-1. Summary of Compliance Demonstration
Process Area Equip. ID Emissions Unit Pollutant Affected Source Regulation Compliance Requirement
Compliance Demonstration
Recordkeeping & Reporting
T64301 Hexene Storage - Tank VOC Storage Tank 25 Pa. Code §129.56
25 Pa. Code §129.56(a)(2)T64302 Hexene Storage - Tank
V64301 Butene Storage - Sphere V64302 Butene Storage - Sphere V64401 Isopentane Storage - Bullet V64402 Isopentane Storage - Bullet V64501 Isobutane Storage - Bullet V64502 Isobutane Storage - Bullet LPGFLARE Low Pressure Header Ground Flare NOx 25 Pa. Code §121.1 - Incinerator - A device
designed to burn or oxidize solid, semisolid, liquid or gaseous wastes for the primary purpose, as determined by the Department, of volume reduction or of disposal. The term includes heat recovery systems.
25 Pa. Code Ch. 129
25 Pa. Code §129.93(c)(4), (6)
PM 25 Pa. Code Ch. 123
25 Pa. Code §123.12
LPINCIN Low Pressure Header Incinerator: Process Vent -
R5003A/B, R5004, E5011, S4005A/B, E4001
NOx 25 Pa. Code §121.1 - Incinerator - A device designed to burn or oxidize solid, semisolid, liquid or gaseous wastes for the primary purpose, as determined by the Department, of volume reduction or of disposal. The term includes heat recovery systems.
25 Pa. Code Ch. 129
25 Pa. Code §129.93(c)(4), (6)
PM 25 Pa. Code Ch. 123
25 Pa. Code §123.12
Equipment Leaks VOC 25 Pa. Code §129.71(a) - This section applies to a facility with design capability to manufacture 1,000 tons per year or more of the following: (3) Polyethylene
25 Pa. Code Ch. 129.71
25 Pa. Code §129.71(b), (d)
25 Pa. Code §129.71(d)
25 Pa. Code §129.71(d), (e)
Cogen Equipment Leaks VOC §60.480a Part 60 Subpart
VVa §§60.482-1a - 60.482-11a §60.485a §60.486a, §60.487a
CT1/2/3 Combustion Turbines NOx and SO2
§60.4305(a) Part 60 Subpart KKKK
§60.4320(a) - Table 1,§60.4330(a), §60.4333,§60.4360, §60.4405
§60.4340(b)(1),§60.4345, §60.4350,§60.4365(a),§60.4400,§60.4415(a)(2)
§60.4375, §60.4380,§60.4395
HAP §63.6090(a)(2), §63.6092 Part 63 Subpart YYYY
§63.6095(d) §63.6145(c)
16
Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law
V5005, T5004, R5002,
Table G-1. Summary of Compliance Demonstration
Process Area Equip. ID Emissions Unit Pollutant Affected Source Regulation Compliance Requirement
Compliance Demonstration
Recordkeeping & Reporting
NOx 25 Pa. Code §§145.4(a)(1)(iii), 145.203 25 Pa. Code Ch. 145
25 Pa. Code §145.8(c); 25 Pa. Code §145.10-14; 25 Pa. Code §145.213(a); 25 Pa.Code §145.223(a)
25 Pa. Code §§145.54, 145.71(b), 145.72
25 Pa. Code §§145.30; 145.52; 145.60; 145.70; 145.71(d); 145.73; 145.74; 145.76; §145.213(a), (c)-(e);§145.223(a), (c)-(e)
PM 25 Pa. Code §121.1 - Combustion unit - A stationary equipment used to burn fuel primarily for the purpose of producing power or heat by indirect heat transfer.
25 Pa. Code Ch. 123
25 Pa. Code §123.11(a)(2)
SO2 25 Pa. Code §123.22(d)(2)
SO2 and CO2
§72.6(a)(3)(i) Part 72 Parts 72, 73 §75.10(a)(3)(ii),§75.11(d)(2),§75.13(b), §75.14(c),§75.20(g);§75.59(b), (e)
§75.53(a); (e); (f)(1), (6);(g); (h); §75.57; §75.58(c)(4), (8);§75.60-64;
GHG §98.40 Part 98 Subpart D
§§98.41-43, 45 §98.44 §§98.46, 47
§60.5509(a) Part 60 Subpart TTTT - Proposal expected 6/2014
§§60.5515, 5520, 5525, 5530
§§60.5535, 5540 §§60.5550, 5555, 5560, 5565
COGENCWT Cooling Water Tower PM 25 Pa. Code Ch. 123
25 Pa. Code §123.13(c)(1)
Shared Units T59708 Recovered Oil Storage -
Wastewater Tank VOC §60.110b(a) Part 60 Subpart
Kb §60.112b(a) §63.1100(g)(1)(ii) -
After the compliance date, a storage vessel that must be controlled according to the requirements of Part 63 Subpart YY and subpart Kb or 40 CFR Part 60 is required to comply only with the storage vessel requirements of Part 63 Subpart YY.
NA T59707A/B FEOR Tank - Wastewater OWS
Synthetic Organic Chemical Manufacturing Industry Wastewater
VOC §60.770 Part 60 Subpart YYY - Proposed but never published in FR
§§60.773-780, 786 §60.781-783 §§60.785, 786
17
Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law
Table G-1. Summary of Compliance Demonstration
Process Area Equip. ID Emissions Unit Pollutant Affected Source Regulation Compliance Requirement
Compliance Demonstration
Recordkeeping & Reporting
T4000 Locomotive Diesel Storage - Tank SO2 25 Pa. Code Ch. 123
25 Pa. Code §123.22(d)(2)(i)
25 Pa. Code §123.22(g)(1)
25 Pa. Code §123.22(g)(4), (5)T58901
A/B/C/D Generator Diesel Storage - Tank T59101 A/B/C Fire Pump Diesel Storage - Tank T4000 Locomotive Diesel Storage - Tank VOC Storage Tank <40,000 25 Pa. Code
Ch. 129 25 Pa. Code §129.57
T58901 A/B/C/D Generator Diesel Storage - Tank T59101 A/B/C Fire Pump Diesel Storage - Tank PROCESSCWT Process Cooling Water Tower
PM 25 Pa. Code Ch. 123
25 Pa. Code §123.13(c)(1)
EGEN1/2/3/4 Emergency Generators
NOx Internal Combustion Engine 25 Pa. Code Ch. 129
25 Pa. Code §129.93(c)(5), (6)
25 Pa. Code §129.95(a)-(d)
FWP1/2/3 Fire Pump Engines
EGEN1/2/3/4
Emergency Generators HAP, VOC §60.4200(a), §63.6585, §63.6590(a)(2)(i), §63.6590(b)(1)(i)
Part 63 Subpart ZZZZ, Part 60 Subpart IIII
§60.4205(b), §60.4206,§60.4211(a)(1),§60.4211(a)(2),§60.4211(a)(3),§60.4209(a),§60.4211(f),§60.4207(b),
§60.4211(c) §60.4214, §63.6645(f)
FWP1/2/3
Fire Pump Engines §60.4200(a), §63.6585, §63.6590(a)(2)(i),§63.6590(b)(1)(i)]
§60.4205(c) – Table 4,§60.4206,§60.4211(a)(1),§60.4211(a)(2),§60.4211(a)(3),§60.4209(a),§60.4211(f),§60.4207(b),
§60.4211(c) §60.4214, §63.6645(f)
Sitewide Part 68
GHG §98.2(a)(1) - Table A-3, §98.2(a)(2) Part 98 Subpart A
§98.3 §98.7, §98.8 §98.4, §98.5
§98.30 Part 98 Subpart C
§§98.31-33, 35 §98.34 §98.36, §98.37
§60.1(a) Part 60 Subpart A
§60.11, §60.13, §60.18 §60.7, §60.8 §60.19
HAP 25 Pa. Code §124.3 NESHAP promulgated in 40 CFR Part 61 by the EPA under section 112(d) of the CAA are hereby adopted in their entirety by the Department and incorporated herein by reference.
25 Pa. Code Ch. 124
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Table G-1. Summary of Compliance Demonstration
Process Area Equip. ID Emissions Unit Pollutant Affected Source Regulation Compliance Requirement
Compliance Demonstration
Recordkeeping & Reporting
VOC Sources Subject to NSPS 25 Pa. Code §129.51
25 Pa. Code §129.51(b) - New source performance standards. Sources covered by new source performance standards which are more stringent than those contained in this chapter shall comply with those standards in lieu of the standards found in this chapter. 25 Pa. Code §129.51(a) as applicable
25 Pa. Code §129.51(c) -Demonstration of compliance. Test methods and procedures used to monitor compliance with the emission requirements of this section are those specified in Chapter 139 (relating to sampling and testing).
25 Pa. Code §129.51(d) - Records. The owner or operator of a facility or source subject to the VOC emission limitations and control requirements in this chapter shall keep records to demonstrate compliance with the applicable limitation or control requirement.
NOx and VOC
25 Pa. Code §129.91(a) - Major NOx or major VOC emitting facility for which no RACT requirement has been established in §§129.51, 129.52, 129.54-129.72, 129.81 and 129.82
25 Pa. Code Ch. 129
25 Pa. Code §129.91(g); §129.92(a)(1)-(4), (7),(8), (10); §129.92(c)
25 Pa. Code §129.93(a)
25 Pa. Code §129.95(a)-(d)
SO2 25 Pa. Code Ch. 123
25 Pa. Code §123.21(b)
25 Pa. Code §§123.31, 127, 128, 131, 135, 137, 139 as applicable
25 Pa. Code §§123.31, 127, 128, 131, 137 as applicable
25 Pa. Code Ch. 139 as applicable
25 Pa. Code Ch. 135
Visible Emissions
25 Pa. Code Ch. 123
25 Pa. Code §§123.41, 123.42
25 Pa. Code §123.43
Fugitive air contaminants
Use of roads and streets 25 Pa. Code Ch. 123
25 Pa. Code §123.1(a)(3)
25 Pa. Code §§123.1(c)(3), 123.2
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