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NC Division of air Quality

Appendix D

Gathering, Transmission, and Distribution Phases

September 2015

Appendix D, Revised September 2015

Table of Contents

1 Overall Assumptions for Gathering, Transmission & Distribution Phases............................................4

2 Process Description.............................................................................................................................4

3 Summary of Emissions.........................................................................................................................6

4 Emissions Activities and Key Assumptions...........................................................................................8

4.1 Gathering System........................................................................................................................8

4.1.1 Potential Emission Sources..................................................................................................8

4.1.2 Gathering Compressor Engines............................................................................................8

4.1.3 Gathering System Dehydrators..........................................................................................11

4.2 Transmission System.................................................................................................................14

4.2.1 Potential Emission Sources................................................................................................15

4.2.2 Transmission Compressor Engines.....................................................................................16

4.2.3 Transmission System Glycol Dehydrators..........................................................................19

4.2.1 Dehydrator Reboiler..........................................................................................................21

4.3 Fugitive Leaks from Gathering and Transmission......................................................................21

4.3.1 Potential Emissions Sources...............................................................................................21

4.3.2 Fugitive Leaks.....................................................................................................................22

5 References.........................................................................................................................................23

List of Tables

Table D- 1. Criteria and Greenhouse Gas Emissions from Gathering and Transmission..............................6Table D-2. Hazardous Air Pollutant Emissions from Gathering and Transmission.......................................7Table D-3. Activity Data for Gathering Compressor Engines......................................................................10Table D-4. Comparison of CO and NOX Emission Factors..........................................................................11Table D- 5. Estimate of Fuel Burned by Dehydrator Reboiler at Gathering Station...................................12Table D- 6. Emission Factors for Reboilers.................................................................................................13Table D- 7. Activity Data for Glycol Dehydrator........................................................................................13Table D- 8. Vented Methane Emissions from Gathering Station Dehydrators..........................................14Table D- 9. Number of Compressor Sets Required for Each End Use Scenarios........................................15Table D- 10. Activity Data for Transmission Compressor Engines..............................................................17Table D- 11. Estimated Emissions Assuming Application of NSPS Subpart JJJJ and NESHAP Subpart ZZZZ 18Table D- 12. Methane Gas Vented from Glycol Dehydrator......................................................................19Table D- 13. Uncontrolled Methane Emissions from Glycol Dehydrator...................................................19

Appendix D, Revised September 2015

Table D- 14. VOC and HAP Emissions from Glycol Dehydration Vent Controlled by Flaring......................20Table D- 15. Emission Factors for Flare Operations Glycol Dehydrators....................................................20Table D- 16. Estimate of Reboiler Fuel Use................................................................................................21Table D- 17. Transmission Fugitives Activity Data, Emission Factor, and Methane Emissions...................22

31 Market centers provide interconnections to other pipelines and provide short-term receipt/delivery balancing needs as well as other services that assist with gas transportation. They also provide some buyer/seller matching services and limited gas trading. (Natural Gas Market Centers: A 2008 Update, EIA, 2009)

PUBLIC COMMENT DRAFT

1 Overall Assumptions for Gathering, Transmission & Distribution Phases

Overall Assumptions:

The DAQ calculated emissions using the peak production estimate of 151,605 MMcf/yr gas. The DAQ assumes that no recoverable condensate is present in the raw gas. The DAQ assumes that emissions from gathering and transmission are subject to all applicable

Federal and State rules and may require an air permit. The DAQ assumes that one transmission compressor station is located within the Sanford Sub-

basin.

2 Process Description

Natural gas produced at a given well may have to travel many miles before reaching a consumer. The natural gas transportation system primarily consists of a complex network of pipelines, compressor stations, and valves that are designed to efficiently transport the gas from the well to the end users. The system includes three main components: 1) Gathering System, 2) Transmission System, and 3) Distribution System.

The transportation system may also involve: 1) storage of natural gas in wells or tanks, 2) import and export of liquefied natural gas, and 3) market centers1. These activities require a great deal of infrastructure to support them. The DAQ does not feel these activities are feasible in North Carolina given the limited supply of natural gas in the Sanford Sub-basin. Therefore, emissions from these activities were not included.

The DAQ is also not estimating emissions from: 1) transmission of natural gas in existing large interstate pipelines, or 2) local distribution of natural gas to consumers. These are existing activities that would not be impacted by the development of natural gas wells in North Carolina. Any increase in distribution activities would be due to growth in the end use of the natural gas and not its production.

The quantity of air pollution emissions from natural gas gathering and transmission is directly proportional to the volume of gas transported through the system annually and the distance it is required to travel. The peak year development flow rate is assumed to be 151,605 MMcf2. This flow rate was used to develop emissions for natural gas gathering and transmission. The distance the gas will travel varies depending on the transportation activity and assumptions for its end use.

Transportation of gas is accomplished though pressurized pipelines. Compression requirements vary significantly with the flow requirements and the design of the piping system. The primary source of emissions is the engine used to power the compressor. The size and number of engines required will vary based on the design pressure, flow rate, and piping size.

Note that fugitive emissions from equipment leaks and purges in both the gathering and transmission systems are estimated in the last section of this appendix, Appendix D Section 4.3.

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1 Market centers provide interconnections to other pipelines and provide short-term receipt/delivery balancing needs as well as other services that assist with gas transportation. They also provide some buyer/seller matching services and limited gas trading. (Natural Gas Market Centers: A 2008 Update, EIA, 2009)

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3 Summary of Emissions

Table D- 1. Criteria and Greenhouse Gas Emissions from Gathering and TransmissionCriteria GHGs

NOX VOC CO SO2 PM10 PM2.5 Methane CO2

Activity Sourceton/year ton/year ton/year ton/year ton/year ton/year ton/year ton/year

Gathering (all stations)

Compressors Engines 31.01 5.47 62.01 0.07 1.96 1.96 50.57 12,376

Dehydrators Reboiler 9.94E-06 5.47E-07 8.35E-06 5.96E-08 7.55E-07 7.55E-07 2.29E-07 1.19E-02

Still Vents 447.2

Transmission (per station)

Compressors Engines 145 51 31 0.29 0.04 0.04 624 54,925Dehydrators Reboiler 0.17 0.009 0.14 0.001 0.013 0.013

Still Vents with Flare 0.50 8.68 2.73 8.94

Fugitives (both gathering and transmission)

Leaks and Venting 13,082

Total Emissions ton/year 176.52 64.86 95.62 0.36 2.01 2.01 14,212 67,301

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Table D-2. Hazardous Air Pollutant Emissions from Gathering and TransmissionHAP

Formaldehyde Acetaldehyde AcroleinMethano

l BenzeneEthylbenzen

e Toluene Xylene Hexane Styrene

Activity Source ton/year ton/year ton/year ton/yearton/year ton/year

ton/year

ton/year

ton/year

ton/year

Gathering (all stations)Compressors Engines

2.31 0.45 0.36 0.33 0.36 0.005 0.00162 0.00005 0.00Dehydrators Reboiler

4.37E-08 1.61E-09 1.82E-09 2.19E-08 1.09E-08 1.79E-07

Still Vents

Transmission (per station)

Compressors Engines 13.2 2.1 1.3 0.62 0.11 0.020 0.204 0.092 0.554 0.012

Dehydrators Reboiler 7.4E-04 2.7E-05 3.1E-05 3.7E-04 1.8E-04 0.003

Still Vents w/Flare 2.00 0.09 1.04 3.99

Fugitives (both gathering & transmission)Leaks and Venting

Total Emissions 15.49 2.54 1.64 0.95 2.46 0.11 1.25 4.09 0.56 0.01

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4 Emissions Activities and Key Assumptions

4.1 Gathering System

The gathering system transports the raw gas from the well pad to the processing plant. Gathering lines are low pressure pipes that carry the gas from the wellheads to central point called a gathering station. At the gathering station, gas from multiple wells is consolidated into one pipeline. The pressure of the gas is then increased via a compressor in order to transport the gas to the processing plant.

Operators utilize the same type or pieces of equipment that provide the same function all along the production and gathering processes (i.e. compression, separation and dehydration). The definition of gathering activities for Federal regulatory purposes states once the gas is in single phase flow (even though it may not meet the gas quality requirements of the transmission line) the production operation is over and gathering begins3.

4.1.1 Potential Emission Sources

The potential emission sources for the gathering lines and compressors include the following;

Compressor EnginesGlycol Dehydrator & Associated Reboiler

Fugitive Leaks Storage Tanks

The DAQ assumed that the raw gas does not contain any condensate (see Section 3.1.5 Chemical Composition of NC Shale Gas of the main document). Therefore, emissions from separators were not estimated for gathering stations.

Storage tanks are maintained at gathering stations for storing wastewater, oil, glycol, hydraulic fluid, and other materials. Under 40 CFR 60 Subpart OOOO, new tanks with VOC emissions of 6 tons per year or greater are required to be equipped with a 95% efficient vapor control system4. Since throughput data is not available for storage tanks, the DAQ did not estimate emissions from storage tanks.

Therefore, the DAQ estimated gathering system emissions from compressor engines, glycol dehydrators, and fugitive emissions. Fugitive emissions, however, are estimated for both gathering and transmission activities in the last section of this appendix, Appendix D Section 4.3.

4.1.2 Gathering Compressor Engines

Compressors at gathering stations are generally powered by reciprocating internal combustion engines (RICE) using raw natural gas. The number of engines, the engine size or horsepower (hp) and other operating characteristics of the engines are determined by the compressor requirements. The required line pressure, pipe size and distance traveled by the gas will also impact the sizing of engines and the resulting emissions.

The engines are grouped into two categories based on their combustion design: “rich-burn” and “lean-burn”. The primary distinction between the two is the amount of excess air used for combustion. Rich-burn engines operate with a minimum amount of air required for combustion and lean-burn engines use 50% to 100% more air than is necessary for combustion5.

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The actual engine emissions may vary considerably from AP-42 published emission factors due to variations in the engine operating conditions. These operating conditions include the following; air-to-fuel ratio, ignition timing, torque, speed, ambient temperature, humidity, as well as other factors5. In addition, most natural gas production emission inventories published by other states use engine surveys to obtain engine model specific emissions factors to estimate emissions from this sector.

The DAQ used U.S. average data provided in US EPA’s Nonpoint Oil and Gas Emission Estimation Tool (the Tool) to estimate activity data for compressor engines at gathering stations6. The DAQ calculated the number of gathering lines required for the Sanford Sub-basin using the average number of wells per gathering line reported in the Tool. This value was then increased by two additional gathering lines to be conservative.

Assumptions for Number of Gathering Lines and Engine Activity

Compressor Engine Type: 4-cycle internal combustion enginesCompressor Engine Size: mid-sized (200 to 600 hp)

Fuel: raw natural gasAverage number of wells per gathering line: 35

Estimated number of gathering lines for 368 wells: 11DAQ assumed number of gathering lines: 15

As discussed above, there are rich burn and lean burn engines. The report which accompanies EPA’s 2011 Nonpoint Oil and Gas Emission Estimation Tool includes data on the number of each engine type operated in the basins. The DAQ used this data to calculate the fraction of engines that are rich burn (0.8) and lean burn (0.2). These fractions were then applied to the estimated number of engines required to transport gas in the Sanford Sub-basin to give the number of engines which would be rich burn. See Table D-3 on the following page for the fraction of rich to lean burn engines and the estimated number of each engine type assumed to operate in the Sanford Sub-basin.

The DAQ also used the average horsepower and the average load factor for gathering engines that was reported in the Tool. The engines were assumed to operate continuously, 8760 hours per year. This data was used to calculate the total horse-power hours required for the gathering activity for each engine type, rich burn and lean burn. The general equation for horsepower-hour activity is given below. Table 6.3

Horsepower−hour type=Horsepower type× Load Factortype×Hours

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Table D-3. Activity Data for Gathering Compressor Engines

Engine Type

Parameter4-cycle

Rich Burn4-cycle

Lean Burn

Average fraction of rich/lean engines 0.8 0.2Number of engines by type 12 3

Average horsepower 280 235Average load factor 75% 98%Hours of Operation 8760 8760

Total Annual hp-hours 22,075,200 6,052,284

Federal Rules for Compressor Engines

Since the RICE engines used to power compressors for production, gathering, and transmissions would be a new air pollution source, the engines would have to comply with the following rules:

40 CFR Part 60 Subpart JJJJ - Standards of Performance for Stationary Spark Ignition Internal Combustion Engines (NSPS Subpart JJJJ)7, and

40 CFR Part 63 Subpart ZZZZ - National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines (NESHAP Subpart ZZZZ)8.

The rules divide the engines into several classes based on size and emissions potential.

Since the potential HAP emissions estimated from compressor engines are less than 10 tpy of formaldehyde and less than 25 tpy for total HAP, the compressors are considered an Area Source under Subpart ZZZZ. For area sources, owners/operators that demonstrate compliance with NSPS Subpart JJJJ will also be in compliance with NESHAP Subpart ZZZZ.

Emission Factors for Gathering Engines

The DAQ examined emission factors for gathering station engines obtained from the Tool6. The source of the emission factors in the Tool is US EPA’s AP-42. Both criteria and HAP emissions are reported in the Tool. For NOX, CO and VOC, the Tool reported emission factors assuming 90% control efficiency. These emission factors were compared to emission limits required under NSPS Subpart JJJJ. The comparison between the Tool’s emission factors and NSPS limits are given in Table D-4 on the following page. It shows that emissions calculated using NSPS JJJJ limits are expected to be lower than emissions calculated using the Tool average emission factor. Therefore, the emission limits for NOX and CO under NSPS JJJJ were used to calculate compressor engine emissions.

Emissions from all other pollutants were calculated using the Tool average emissions factor for gathering engines. There is expected to be some control of formaldehyde and other HAP emissions for engines complying with NSPS Subpart JJJJ. However, formaldehyde control efficiency for this size engine meeting NSPS JJJJ could not be obtained. Therefore, the DAQ did not assume any control efficiency for HAPs. Assuming uncontrolled HAP emissions does not appear to impact the permitting status of the gathering compressor stations as shown in Table D-2 at the beginning of this appendix.

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Table D-4. Comparison of CO and NOX Emission Factors for Compressor Engines at Gathering Stations

Pollutant

Engine Type 4 Cycle Lean Burn 4 Cycle Rich Burn

CenSARA Average

NSPS Subpart JJJJ

CenSARA

Average

NSPS Subpart

JJJJg/hp-hr g/hp-hr g/hp-hr g/hp-hr

NOX 3.074 1.000 8.237 1.000

CO 2.021 2.000 12.737 2.000

VOC 0.428 0.700 0.107 0.700

Emissions from Gathering Compressor Engines

The emission factor and activity data for engines in horsepower-hour for both rich burn and lean burn engine types were used to calculate emissions due to gathering compressor engines. The equation for calculating emissions is given below.

Emissionsn=EF× AvgCapacity×Load Factor× Hours× Number of engines

907,185

Where:EF = Emission Factor

Avg Capacity = Average capacity of the engine in horsepower (hp)Load Factor = operating load on engine, ratio of actual hp to capacity hp

Hours = annual operating hours of engine907,185 = conversion factor from grams to tons

Total emissions from compressor engines for each pollutant are presented in Table D-1 and Table D-2 given at the beginning of this appendix.

4.1.3 Gathering System Dehydrators

Additional water may need to be removed from the raw gas at the gathering stations prior to entering the gathering station compressors. The most common form of dehydration at these stations is a glycol dehydrator. Other methods of dehydration exist, including a desiccant dehydrator, which uses a water adsorbing tablets made of calcium chloride or lithium chloride. The DAQ assumed that the gathering stations used glycol dehydrators due to their low operational cost. Glycol dehydrators were discussed previously in Section 4.4 of Appendix B Production Phase; therefore, a detailed discussion on glycol dehydrators is not included in this appendix.

The DAQ estimated both reboiler emissions and vented emissions for the glycol dehydrators at the gathering stations. Note that the amount of water contained in the gas at the gathering station varies depending on the temperature, humidity and pressure of both ambient air and the pipeline gas.

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a. Gathering System Dehydrator Reboiler

Reboiler emissions were estimated using the Tool and the methodology discussed under Appendix B Production Phase, Section 4.4 Glycol Dehydrators.

Assumptions

15 gathering stations with one dehydrator located at each station

Flow rate per station = 27.7 MMcf/day for year 6, the peak development year (151,605 MMcfg/year)

Activity Data

After reviewing air quality permits for various compressor stations in Pennsylvania, a slightly larger reboiler heat input was assumed for the gathering station than the heat input for the reboiler at the wellhead (1.0 Btu/hr vs 0.6 Btu/hr) since the volume of gas passing through the dehydrator is larger at the gathering stations. The DAQ estimated natural gas fuel burned annually by the reboiler for dehydration at gathering stations using the data in Table D-5 given below.

Table D- 5. Estimate of Fuel Burned by Dehydrator Reboiler at Gathering StationData Parameter Units1.0 reboiler heater size Btu/hr591 LHV of natural gas in basin Btu/scf

7831 Operating time hours1.0 fraction of operating time heater is on

1.3E-05 Volume of Gas Burned per reboiler MMscf/year15 Total number dehydrators

0.0002 Total Gas Burned MMscf/year

Emission Factors

Emission factors for reboiler were obtained from the Tool in pound per million cubic feet of gas (lb/MMscf). The emission factors are given on the following page.

Emissions

The volume of gas burned from Table D-5 is multiplied by the emission factors from Table D-6, given below, to calculate the emissions from the reboiler. Total emissions for each pollutant from dehydrator reboilers are presented in Table D-1 and Table D-2 given at the beginning of this appendix.

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Table D- 6. Emission Factors for Reboilers

Pollutant UnitsEmission Factor Pollutant Units

Emission Factor

Carbon Monoxide lb/MMscf 84.0 Formaldehyde lb/MMscf 0.440Oxides of Nitrogen lb/MMscf 100.0 Acetaldehyde lb/MMscf 0.016PM10 Primary (Filt + Cond) lb/MMscf 7.6 Acrolein lb/MMscf 0.018PM2.5 Primary (Filt + Cond) lb/MMscf 7.6 Benzene lb/MMscf 0.220Sulfur Dioxide lb/MMscf 0.6 Toluene lb/MMscf 0.110Volatile Organic Compounds lb/MMscf 5.5 Hexane, n- lb/MMscf 1.800Carbon Dioxide lb/MMscf 120,000Methane lb/MMscf 2.30Nitrous Oxide lb/MMscf 2.20

Dehydrator Vented Emissions

Emissions of methane and other volatile organics vented from dehydrators are a function of the following parameters:

Flow rate, temperature and pressure of the gas, Water content of the gas, Glycol to water ratio, Glycol circulation rate, and Methane entrainment.

Assumptions and Activity Data

US EPA Gas Star Program provided a method and for estimating methane emissions from venting of dehydrators. Emissions were calculated using the formulas given below9.

Methane Emissions from Dehydrator Venting = (F×W ×R×OC×G×365days / year )1,000 cf /Mcf

Estimates of all parameters were obtained from US EPA Gas Star Program except for water content. The water content of pipeline gas is generally between 4 to 7 pounds per MMcf at standard conditions10. The activity data for estimating methane emissions from dehydrators is given below in Table D-7.

Table D- 7. Activity Data for Glycol DehydratorParameter Symbol Units Value

Total flow rate of gas MMcf/year 151,605Flow rate of gas per station F MMcf/day 27.7Water Content W lb H2O/MMcfg 7Glycol to Water Ratio R gallons/lb 3Overcirculation Rate Oc percent 150%Methane entrainment G cf/gallon 3

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EmissionsThe estimated methane emissions due to venting of the dehydrators from this methodology are presented below and converted from cubic feet to tons. Actual emissions from a dehydrator are highly dependent on the design parameters for the dehydrator such as glycol to water ratio and circulation rate.

Table D- 8. Vented Methane Emissions from Gathering Station Dehydrators

The DAQ did not estimate emissions of hazardous air pollutants from gathering stations since the only available emissions factor was for methane.

Rules for Dehydrators

The NESHAP for Oil & Natural Gas Production Subpart HH and HHH applies to “large” and “small” glycol dehydrators at compressor stations. Large dehydrators are defined as those with a flow rate greater than or equal to 283,000 standard cubic meters per day or 10 MMscf/day. Since the estimated flow rate data during the peak year is 27.7 MMcf/day for each gathering station, the dehydrator at the gathering station may be considered a “large” dehydrator under the rule.

The rule requires one of the control options for large dehydrators:

Reduce HAP emissions by 95%, or Reduce benzene emissions to 1 ton/day

Small glycol dehydrators also have benzene emissions limits. These limits are determined based on the gas throughput and gas composition using an equation.

In general, the gathering stations are complying with the rule by flaring. There are other control options which do not involve combusting the emissions such as a flash tank separator-condenser.

As stated above, the DAQ did not estimate HAP emissions from dehydrators since emission factors of sufficient quality were not available.

4.2 Transmission System

The transmission system transports the processed natural gas from the processing plant to one of the following; 1) an interstate transmission system, 2) a local distribution system, or 3) an industrial user.

Transmission systems consist of high pressure pipelines that carry the gas long distances with compressor stations located along the pipelines to periodically increase the gas pressure as it flows.

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Source Pollutant Units EmissionsTotal Vents for Gathering Methane Cubic feet 14,326,673Total Vents for Gathering Methane ton/year 447.2One Dehydrator Vent Methane ton/year 29.8


Multiple compressor stations are generally required to transport the gas along a given pipeline. In addition to the compressor stations, there is a set of compressors located at the processing plant which provides the initial pressure for gas flow from the plant.

The natural gas stream entering the compressor station is generally passed through scrubbers and filters to extract any liquids that may have condensed out of the natural gas stream as line pressure decreased and to remove any particulate matter that may have formed during contact with the materials that coat the inside of the natural gas pipeline.

End Use Scenarios

There are 3 scenarios for the use of the natural gas which would affect the number of compressor stations along a given pipeline. The DAQ assumed all the gas is piped to one location for end use. In addition, the DAQ assumed one compressor station is required approximately every 50 miles11. The end use scenarios and the compression requirements are summarized below.

Table D- 9. Number of Compressor Sets Required for Each End Use Scenarios

Scenario Use of Processed Natural Gas DistanceNo of Processing

Plant Compressor Sets

No of Transmission Compressor

Stations

1 Gas piped to TRANSCO Pipeline ≥ 100 miles 1 2

2 Gas piped to utility or industrial facility≥ 50 miles and

≤ 100 miles 1 1

3 Gas piped to local distribution company < 50 miles 1 0

As shown above, the first set of compressors is located at the processing plant and their emissions are permitted as part of the plant. There may be additional sets of compressors located at compressor stations in North Carolina required for transmission activities depending on how far the gas must travel prior to its entering the distribution system or end use facility. For this study, the DAQ assumed one compressor station would be located in the Sanford Sub-basin. Since the emissions from any other required compressor stations occur outside of Chatham, Lee and Moore counties at an unknown location, the DAQ did not include them in its air quality impacts modelling activity.

4.2.1 Potential Emission Sources

The potential emission sources for the transmission system include the following;

Compressor Station EnginesStorage Tanks & HeatersGlycol Dehydrator & Associated Reboiler

FlaresFugitive Leaks

Storage tanks are maintained at compressor stations for storing wastewater, oil, hydraulic fluid, and other materials. The size of the tanks can be obtained through permits but the throughput of the tanks is not generally available. New tanks with VOC emissions of 6 tons per year or more are required to be equipped with a 95% efficient vapor control system4. Since throughput data is not available for storage tanks, the DAQ did not estimate emissions from storage tanks.

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Fugitive leaks for transmission compressor stations and pipelines are included in the estimates presented in Section 4.3 at the end of this appendix.

4.2.2 Transmission Compressor Engines

This section only discusses estimating emissions from the main compressor engines. Emissions from auxiliary and emergency engines located at compressor stations were not estimated for this activity. These types of engines are only used periodically and the hours of operations in a given year will vary.

The DAQ estimated the number and size of compressors required to transmit the North Carolina shale gas by sizing the system as a percentage of existing permitted compressor sets operated by TRANSCO. TRANSO operates a large interstate natural gas pipeline that goes through North Carolina with multiple compressor stations to pressurize the gas.

Assumptions

Total volume of gas leaving the processing plant would be piped to one location One compressor is located in the Sanford Sub-basin area Emissions were estimated for one compressor station TRANSCO Pipeline transmits approximately 1.1 Bcfg/day across North Carolina12

Sanford Sub-Basin would transmit approximately 0.4 Bcfg/day2

Assume size of compressor station is 38% of TRANSCO capacity

Activity Data

TRANSCO’s average total horsepower for Station 150 and Station 160 is 54,830 hp

Estimated total horsepower required for Sanford Sub-Basin gas flow is 20,621 hp (38% of TRANSCO)

The vast majority of compressor stations reviewed maintained 4-stroke lean burn engines. For this compressor power, most stations maintained 8 to 10 engines plus auxiliary and emergency engines. Therefore, the DAQ assumed eight 4-stroke lean burn main engines at the model compressor station. The average compressor power is estimated to be 2,500 hp per engine. The DAQ did not estimate emissions from auxiliary or emergency engines since the operational hours vary from year to year.

The following table calculates the estimated total horsepower-hours and heat input in MMBtu required for gas transmission using the same equation presented in Section 4.1.2. Note that total engine heat input in MMBtu’s is required to calculate HAP emissions while total engine horsepower hours are required to calculate criteria pollutants.

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Table D- 10. Activity Data for Transmission Compressor EnginesParameter DAQ AssumptionAverage Engine Size (hp) 2500Average Heat Input Rate (MMBtu/hr) 19Engine Type 4-stroke leanFuel Type pipeline natural gasNumber of engines 8Operating Hours 8760Average Load 75%

Total horsepower-hours per year 131,400,000Total MMBtu per year 998,640

Emissions from Transmission Compressor Engines

The emission factor and activity data for lean burn engines in horsepower-hour were used to calculate emissions due to gathering compressor engines. The equation for calculating emissions is given below.

Emissionsn=EF× AvgCapacity×Load Factor× Hours× Number of engines

907,185

Where:EF = Emission Factor

Avg Capacity = Average capacity of the engine in horsepower (hp)Load Factor = operating load on engine, ratio of actual hp to capacity hp

Hours = annual operating hours of engine907,185 = conversion factor from grams to tons

Total emissions from compressor engines for each pollutant are presented in Table D-1 and Table D-2 given at the beginning of this appendix.

Federal Rules for Compressor Engines Since the RICE engines used to power compressors transmissions would be a new air pollution source, the engines would have to comply with the following rules:

40 CFR Part 60 Subpart JJJJ - Standards of Performance for Stationary Spark Ignition Internal Combustion Engines (NSPS Subpart JJJJ), and

40 CFR Part 63 Subpart ZZZZ - National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines (NESHAP Subpart ZZZZ).

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For HAP Major Sources

Owners/operators of new RICE > 500 hp are required to comply with both NSPS JJJJ for NOX, and VOC emission standards and NESHAP Subpart ZZZZ for CO and HAPs. The Subpart ZZZZ limits are given below for rich and lean burn engines.

For lean burn engines - reduce CO by 93% or limit formaldehyde to ≥ 14 ppm at 15% O2

For rich burn engines - reduce CO by 76% or limit formaldehyde to ≥ 350 ppb at 15% O2

Sources that are complying with 40 CFR 63 Subpart ZZZZ do not have to meet emission limits under NSPS Subpart JJJJ.

The NESHAP Subpart ZZZZ uses CO emissions as a surrogate for formaldehyde emissions from these engines. The oxidation catalyst required to control CO emissions under NSPS JJJJ also control formaldehyde emissions from these engines (and vice versa). In addition the oxidation catalyst would also limit emissions of other organic HAPs.

Emission Factors and Emissions

Emission factors were taken from Tables 3.2-2 and 3.2-3 of US EPA AP-42 except for NOX, CO and VOC5. Since these engines would be a new air pollution source, the emission factors for these pollutants were lowered to reflect the emission limits of NSPS Subpart. All other emissions were assumed to be uncontrolled. The emissions using these assumptions are presented below in column two of the table given below. Note the estimated emissions of formaldehyde are 26.4 tons per year (tpy).

Table D- 11. Estimated Emissions Assuming Application of NSPS Subpart JJJJ and NESHAP Subpart ZZZZ

Pollutant

NSPS Emissions

(tpy)

Uncontrolled

Emissions(tpy)

Control Efficiency

Controlled Emissions

(tpy)

NOX 144.8 144.8

CO 289.7 439.1 93% 30.7VOC 101.4 50% 50.7

Formaldehyde 26.4 50% 13.2

* Assuming 50% control of organics and 93% control of CO with use of an oxidation catalyst

Since the uncontrolled formaldehyde emissions are over the 10 tons per year threshold, the engines are also subject to NESHAP Subpart ZZZZ. Under this rule, CO is a surrogate for organic HAP. The rule requires 93% control of CO in order to control organic HAP emissions. Therefore, the uncontrolled emissions for CO were first calculated and then a control factor of 93% was applied to CO. This reduced emissions of CO to 30.7 tons per year. A conservative control factor of 50% was applied to the VOC and HAP organics based on controlling CO with an oxidation catalyst which reduced VOC emissions to 50.7 tpy and formaldehyde emissions to 13.2 tpy.

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4.2.3 Transmission System Glycol Dehydrators

As stated previously, glycol dehydrators are described in detail in Appendix B. The glycol dehydrators located at the transmission station are larger than those located at the well pad or gathering station, and are assumed to process 151,605 MMcf/year or 415 MMcf/day of natural gas. Emission sources from these units are still vents, and reboilers.

Emissions from glycol dehydrators operated at natural gas transmissions stations were estimated using the same procedures, emissions factors, and activity data used in estimating emissions from dehydrators at natural gas processing plants. Therefore, the data and emissions are summarized here.

As stated previously, the DAQ used methods provided by the US EPA Gas Star Program to calculate emissions from dehydrators at compressor stations. For this activity, the default data provided by the US EPA Gas Star was used except for water content. The water content of pipeline gas is generally between 4 to 7 pounds at standard conditions. All other parameters were assigned same as the US EPA default values as shown below in Table D-11.

Table D- 12. Methane Gas Vented from Glycol Dehydrator

Variables Parameter ValueF Gas flow rate 151,605W Water Content 7R Glycol to Water Ratio 3

OC Circulation Rate 150%G Methane entrainment 3

GV cf/yr 14,326,673

Table D- 13. Uncontrolled Methane Emissions from Glycol DehydratorMethane

Emissions Units 894,385 lb/year 447.2 ton/year

Rules for Dehydrators

The NESHAP for Oil & Natural Gas Production Subpart HH and HHH that applies to “large” and “small” glycol dehydrators at compressor stations 13,14. Large dehydrators are defined as those with a flow rate greater than or equal to 283,000 standard cubic meters per day or 10 MMscf/day. Since the estimated flow rate data during the peak development year is 400 MMcf/day for each gathering station, this rule may apply to dehydrators at the gathering stations in North Carolina.

The rule requires one of the control options for large dehydrators:

Reduce HAP emissions by 95%, or Reduce benzene emissions to 1 ton/day

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In general, the compressor stations are complying with the rule by flaring. There are other control options which do not involve combusting the emissions such as a flash tank separator-condenser. For this study, the DAQ assumed flaring at the transmission compressor stations.

The DAQ estimated VOC and HAP emissions using the ratio of CH4 to VOC and HAPs given in the Tool. The DAQ also estimated controlled emissions given that emissions from this source will be subject to federal regulations.13, 14 A control efficiency of 98% was assumed for the flare based on data in the Tool. The ratios and uncontrolled and controlled emissions are given below. In addition, the NOX, CO and CO2 emissions that result from flaring were estimated using emission factors reported in AP-42.5

Table D- 14. VOC and HAP Emissions from Glycol Dehydration Vent Controlled by Flaring

Pollutant % of CH4

Uncontrolled Emissions

(tpy)

Flare Control

Efficiency

Controlled Emissions

(tpy)Methane 447.2 98% 8.9VOC 97% 434.2 98% 8.6Benzene 22% 99.9 98% 2.0Ethylbenzene 1% 4.3 98% 0.1Toluene 12% 52.1 98% 1.0Xylene 45% 199.7 98% 4.0

Emissions from the Flare

The DAQ estimated criteria emissions due to the flaring of emissions from the glycol dehydrator. The amount of gas flared is assumed to be equal to the amount of methane emitted from the glycol dehydrators, 14,326,673 cubic feet per year. This value was converted to heat input using the heating value of natural gas, 1030 Btu/scf, to give a flare throughput in Year 6 of 14,756 MMBtu/yr.

Emissions factors for natural gas flares were obtained from the US EPA’s AP-42 Chapter 13: Miscellaneous Sources, Table 13.5-1 Emission Factors for Flare Operations. The emissions factors and calculated emissions are presented in Table D-15.

Table D- 15. Emission Factors for Flare Operations Glycol DehydratorsEmission

FactorFlare

Throughput EmissionsPollutant (lb/MMBtu) (MMBtu/yr) (ton/year)CO 0.37 14,756 2.73NOX 0.068 0.50

4.2.1 Dehydrator Reboiler

To calculate emissions from the glycol dehydrator reboiler the following equation was used by the DAQ:

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Fuel=F ×W ×HR×R×365day / yrH×1,000,000 scf /MMcf

Where:Fuel = Fuel for glycol reboiler (MMcf/yr)F = Gas flow rate (MMcf/day)W = Inlet-outlet H2O content (lb/MMcf) HR = Heat rate for reboiler (Btu/gal)R = Glycol/water ratio = 3 gal/lbH = Heat content of natural gas = 1,030 Btu/scf

The activity data and estimate of the reboiler fuel use calculated by the DAQ are given in the following table. The reboiler uses approximately 3.36 MMcf per year of natural gas.

Table D- 16. Estimate of Reboiler Fuel Use

Variable Parameter Units ActualF Gas flow rate MMcf/day 415W Water removed lb/MMcf 7HR Heat rate Btu/gal 1,124R Glycol/water ratio gal/lb 3H Heat content Btu/scf 1,030

Reboiler Fuel cf/yr 3,362,296Fuel Reboiler Fuel MMcf/yr 3.36

Reboiler emissions were calculated using the fuel estimate in Table 8 and AP-42 emission factors for natural gas combustion in small boilers given in pound per MMcf. These emission factors are given above in Section 4.2.3 Gathering System Dehydrators. Emissions from reboilers are presented in Table D-1 and Table D-2 given at the beginning of this appendix.

4.3 Fugitive Leaks from Gathering and Transmission

This activity includes the transportation of natural gas from the wells to processing plants, and the processing plants to compressor stations. It does not include the following: 1) transmission of the gas in large interstate pipelines, 2) flow past primary metering stations, which lower the gas pressure prior to entering a distribution line, or 3) flow through local distribution lines.

4.3.1 Potential Emissions Sources

Fugitive emissions result from gas leaks in a variety of equipment used for transmission of gas through gathering and transmission lines and at compressor stations. This equipment includes:

pipeline network - leaks from microscopic holes, corrosion, welds and other connections compressor intake and outlet seals, compressor rod packing, blow and purge operations, pipeline pigging, and

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pneumatic devices on the pipeline network.

Fugitive emissions are the largest contributor to methane emissions from natural gas processing, transmission, and storage. Nearly 90% of these emissions result from leaks on compressor components such as the suction, discharge, blowdown, and pressure regulator valves and compressor seals15.

4.3.2 Fugitive Leaks

Assumptions

Total volume of gas being transmitted is 151,605 MMcfg2.

Activity Data and Emission Factors

Fugitive emissions factors for individual pieces of equipment are available. However, using equipment-level emissions factors would require estimating the total number of each equipment type in the gathering and transmission system.

Therefore, a more simplified approach was taken from a report developed by the Gas Research Institute (GRI) and the US EPA which estimated total transmission fugitives as a function of total gas production16.

The DAQ reviewed the fugitive methane data reported by the GRI and the US EPA for each activity listed for each potential emission source given above. The DAQ assumed no gas storage activity would occur during production, processing, or transmission of gas. All other activities from the GRI & US EPA report were included in the fugitive emissions estimate. The DAQ calculated fugitive emissions would be approximately 0.39% of total gas production, rather than 0.47% when including fugitive emissions from storage.

Table D- 17. Transmission Fugitives Activity Data, Emission Factor, and Methane EmissionsParameter Value UnitsFlow rate 151.6 BcfgFugitive Emissions Ratio 0.0039Fugitive Emissions 0.591 BcfgConversion for Methane 0.04425 lb/cfMethane Fugitive Emissions 13,082 tons

Emission factors for VOC emissions from fugitive leaks were not readily available. Since the pipeline quality gas is approximately 95% methane, worst-case VOC emissions could be estimated as 5% of total annual methane fugitive emissions in billion cubic feet.

Federal Rules for Fugitive Emissions

New rules limiting fugitive emissions are expected to decrease the estimated emissions. The estimated control efficiency of the rules on total transmission fugitives is not known. Therefore, no control efficiency was applied to the estimated fugitive methane emissions given above.

NSPS Subpart OOOO requires the following;

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a. gas gathering and booster station centrifugal compressors with wet seals to be connected to a 95% efficient control system,

b. reciprocation compressors to change the rod packing after operating 26,000 hours (36 months of continuous operation), and

c. requires natural gas-driven pneumatic controllers between wellhead and natural gas processing plant have a bleed rate less than or equal to 6 standard cubic feet per hour.

NSPS Subpart OOOO lowered the allowable leak detection for valves from 10,000 ppm to 500 ppm, and require the monitoring of connectors. Pumps, pressure relief devices and open-ended valves or lines must also be monitored.

5 References

1. Natural Gas Market Centers: A 2008 Update, EIA, 2009

2. North Carolina Oil and Gas Study under Session Law 2011276, Prepared by the North Carolina Department of Environment and Natural Resources and the North Carolina Department of Commerce, April 30, 2012.

3. “Onshore Gas Gathering FAQs”, Pipeline and Hazardous Materials Safety, Department of Transportation, http://www.phmsa.dot.gov/

4. 40 CFR 60 Subpart OOOO Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution

5. AP-42, Fifth Edition, Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area Sources, Chapter 3 Stationary Internal Combustion Sources, Section 3.2 Natural Gas-fired Reciprocating Engines ,US EPA, August 2000.

6. 2011 Nonpoint Oil and Gas Emission Estimation Tool, U.S. EPA, November 21, 2014.

7. 40 CFR Part 60, Subpart JJJJ Standards of Performance for Stationary Spark Ignition Internal Combustion Engines.

8. NESHAP Subpart ZZZZ National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines.

9. “Natural Gas Dehydration: Lessons Learned from the Natural Gas STAR Program”, Anadarko Petroleum Corporation and the Domestic Petroleum Council, Producers Technology Transfer Workshop College Station, Texas, May 17, 2007.

10. (http://www.mckenziecorp.com/how_it_works.htm)

11. Natural Gas Compressor Stations on the Interstate Pipeline Network: Developments since 1996, Energy Information Administration, Office of Oil and Gas, November 2007.

12. Report of the Public Staff North Carolina Utilities Commission to the Joint Legislative Commission on Governmental Operations Analysis and Summary of Expansion Plans of North Carolina Natural Gas Utilities and the Status of Natural Gas Service in North Carolina, Submitted April 24, 2012 Pursuant To G.S. 62-36a(C)

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http://www.mckenziecorp.com/how_it_works.htm


13. 40 CFR Part 63 subpart HH - National Emission Standards for Hazardous Air Pollutants from Oil and Natural Gas Production Facilities.

14. 40 CFR Part 63 subpart HHH - National Emission Standards for Hazardous Air Pollutants from Natural Gas Transmission and Storage Facilities.

15. Emissions from Natural Gas Production in the Barnett Shale Area and Opportunities for Cost-Effective Improvements, Al Armendariz, Ph.D., Southern Methodist University, Report for Ramon Alvarez, Ph.D., Environmental Defense Fund, Version 1.1, January 26, 2009

16. US Environmental Protection Agency and the Gas Research Institute, "Methane Emissions from the Natural Gas Industry." EPA/600/SR-96/080, GRI-94/0257. June 1996. on-line documents:

http://www.epa.gov/gasstar/documents/emissions_report/1_executiveummary.pdf http://www.p2pays.org/ref%5C07/06348.pdf

17. Natural Gas Compressor Engine Survey for Gas Production and Processing Facilities H68 FINAL REPORT Prepared for Houston Advanced Research Center, Prepared by: Clinton E. Burklin and Michael Heaney, Eastern Research Group, Inc., Morrisville, North Carolina, October 5, 2006.

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http://www.p2pays.org/ref%5C07/06348.pdf

http://www.epa.gov/gasstar/documents/emissions_report/1_executiveummary.pdf

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