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Emission Reduction Protocol for
Methane Capture, Flare and Utilization
at Tyson Wastewater Treatment
Facilities
Prepared by
3165 E. Millrock Drive, Suite 340
Holladay, Utah 84121
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Table of Contents
1.0 Introduction
2.0 Proponent Identification
3.0 Project Description
3.1 Site Description
3.2 Pre-Project Conditions
3.3 Post-Project Conditions
3.3.1 Stage 1
3.3.2 Stage 2
3.4 Identification of Physical Boundaries
3.5 Identification of Relevant GHG Sources, Sinks and Reservoirs
3.5.1 Baseline SSRs
3.5.2 Project Stage 1 SSRs
3.5.3 Project Stage 2 SSRs
3.5.4 Elimination of Irrelevant SSRs
3.6 GHGs Included in this Protocol
3.7 Project Crediting Period
4.0 Baseline Assessment
4.1 Baseline Scenario Selection
5.0 Project Additionality
5.1 Common Practice
5.2 Regulatory Surplus
5.3 Least Cost Option
5.4 Supplemental Barriers Analysis
5.4.1 Investment Barriers
5.4.2 Institutional and Technological Barriers
6.0 Calculation and Reporting of Emission Reductions
6.1 Applicability Conditions
6.2 Total Emission Reductions Calculation
6.3 Baseline Emissions Calculation
6.3.1 Lagoon Baseline Calculations
6.3.2 Boiler Baseline Calculations
6.4 Project Emission Calculations
6.4.1 Physical Leakage Calculations
6.4.2 Flare Calculations
6.4.3 Electricity Calculations
6.4.4 Fossil Fuel Calculations
7.0 Monitoring Plan
7.1 Overview of Types of Data and Information
7.2 Data and Parameters Not Monitored
7.3 Data and Parameters Monitored
7.4 Differences in Parameters
7.4.1 Omitted Parameters
7.4.2 Additional or Altered Parameters
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7.5 Monitoring Methodologies
8.0 Other Environmental Impacts
8.1 Internal Impacts
8.2 External Impacts
8.3 Permanence
9.0 Estimated Emission Reductions
10.0 References
List of Figures
Figure 3-1: Pre-Project Flow of Wastewater Effluent, Biogas Emissions and Fossil Fuel
Combustion
Figure 3-2: Project Flow of Wastewater Effluent, Biogas Emissions and Fuel Combustion
after Stage 1
Figure 3-3: Project Flow of Wastewater Effluent, Biogas Emissions and Biogas
Consumption after Stage 2
Figure 4-1: Grease Cap Present in the Pre-Project State
Figure 7-1: Process flow diagram and data monitoring locations after completion of
Stage 1
Figure 7-2: Process flow diagram and data monitoring locations after completion of
Stage 2
Appendices
Appendix A: Study of Pre-Project BOD Removal Rates
Appendix B: Biogas Flaring Vs. Utilization Ratios
Appendix C: H2S Scrubbing Equipment List and Power Ratings by Facility
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1.0 Introduction
Blue Source, LLC is an active supplier of emission reduction credits sourced from
geologic sequestration, conservation, transportation, and avoidance projects and
entities. The company is also actively involved in financing and developing these types
of projects. Tyson Foods, Inc. (“Tyson”) is the world’s largest supplier of protein,
operating poultry, swine, and beef processing plants. Wastewater from Tyson’s
processing plants is treated at wastewater treatment plants owned and operated by
Tyson. Tyson’s 100 wastewater pre-treatment and full-treatment plants treat over 100
million gallons of water a day.
During primary treatment, the wastewater is traditionally held in uncovered anaerobic
lagoons. Uncovered anaerobic lagoons lead directly to the production and release of
CH4 (“biogas”) into the atmosphere as a result of the anaerobic digestion process that
takes place. Biogas production is due to the degradation of organic matter by
acidogenic and methanogenic bacteria.
Tyson first began managing the biogas emissions in December of 2000 and early 2001
with the installation and operation of covers for the anaerobic lagoons at four of its
wastewater treatment facilities throughout the Midwest. Initially, the captured biogas
was flared at all four sites, converting the methane to less harmful CO2. This covering
and flaring represents Stage 1 of the emission reductions project. In 2003, Tyson
implemented a biogas-to-boiler project at the Joslin, Illinois beef processing complex
which became operational in March, 2004. Equipment was installed to transport the
biogas from the wastewater treatment plant to the boilers for use in the production of
steam used in the beef processing facility. This addition of the energy recovery system
marked the completion of Stage 2 of the project at the first facility. Since then,
additional biogas utilization projects have been implemented at other locations.
Currently, the only site continuing to flare without utilization of the biogas is Storm
Lake, Iowa. The schedule of project implementation at each facility is shown below:
Location Stage 1 Flaring Stage 2 Biogas Utilization
Effective Date Effective Date
Joslin, Illinois 07/2001 03/2004
Lexington, Nebraska 09/2001 12/2004
Amarillo, Texas 02/2001 10/2005
Storm Lake, Iowa 12/2000 N/A
This Emission Reduction Protocol presents the details associated with the emission
reductions resulting from Tyson’s efforts to capture and subsequently flare fugitive
methane (Stage 1), as well as subsequent biogas utilization in more recent years (Stage
2). Reductions are calculated in accordance with methodology number ACM0014,
“Avoided Methane Emissions from Wastewater Treatment,” which was developed
under the UNFCCC Clean Development Mechanism (CDM) program. The report
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documents the methods used in accordance with International Standards Organization
(ISO) 14064-2 as required by the Voluntary Carbon Standard (VCS).
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2.0 Proponent Identification
The locations of the four emission reduction sources are as follows:
Amarillo Wastewater Treatment Facility
Farm Road 1912 Hwy 66 East
Amarillo, Texas 79187
Joslin Wastewater Treatment Facility
Highway 92
Geneseo, Illinois 61254
Lexington Wastewater Treatment Facility
1500 South Plum Creek Parkway
Lexington, Nebraska 68850
Storm Lake Wastewater Treatment Facility
Flindt and Richland
Storm Lake, Iowa 50588
The contact information for the emission reduction project is as follows:
Proponent Contact: J. Greg Spencer
President
Blue Source, LLC
3165 East Millrock Rd., Suite 340
Holladay, Utah 84121
Phone – (801) 322-4750
Fax – (801) 363-3248
E-mail – [email protected]
Operating Contact: John Askegaard
New Technology Manager, EHS Services
Tyson Foods, Inc.
2200 Don Tyson Parkway
Springdale, Arkansas 72762
Phone – (479) 290-1483
Fax – (479) 757-7194
E-mail – [email protected]
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3.0 Project Description
3.1 Site Description
This protocol includes four Tyson wastewater treatment facilities in the Midwestern
United States, each of which treats wastewater from Tyson’s processing plants. At each
of the four plants, the treatment occurs in two phases: Primary treatment (anaerobic)
and secondary treatment (aerobic-activated sludge)1. The waste activated sludge
effluent from the secondary treatment is treated in a storage pond. Greenhouse gases
are produced during all phases of treatment. The emission reduction project has two
stages: The first stage involves covering the primary treatment lagoons and collecting
and flaring the biogas generated by the process. The second stage involves transporting
the collected biogas to the adjacent Tyson processing facility and utilizing it in the
facility’s boilers, thereby displacing purchased natural gas.
3.2 Pre-Project Conditions
The primary phase of Tyson’s wastewater treatment involves anaerobic digestion. The
raw wastewater from the processing facilities is pumped through underground pipes
into uncovered anaerobic lagoons. The lagoons are large, earthen basins of depths
ranging from 17 to 27 feet. Process water is anaerobically treated in these primary
uncovered lagoons during a period ranging from 7 to 10 days, while organic solids are
retained in excess of 60 days. Packing plant wastewater is ideally suited for anaerobic
digestion as temperature is typically in optimum range, and it contains nutrients for
anaerobic bacterial growth. The anaerobic bacteria treat the wastewater and decrease
the organic matter content.
Anaerobic digestion consists of two steps. During the first step, the acid phase, volatile
organic acids are produced. These acids are consumed by methanogenic bacteria in the
second step, producing biogas, a mixture of CO2 and CH4 which may also contain small
amounts of hydrogen sulfide.
The anaerobic lagoon effluent then moves to the second phase of the process, aerobic
secondary treatment by activated sludge. This process takes place in aeration basins
and clarifiers. The activated-sludge process is an aerobic, continuous flow, secondary
treatment system that uses biomass containing active, complex populations of aerobic
micro-organisms to break down organic matter in wastewater. This phase of treatment
aerobically degrades the remaining organic matter into water, new cells, CO2 and other
end-products. Any (fugitive) CO2 emissions at this phase are minimal and occur pre- and
post-project.
1 As described in Figure 3-1, the Amarillo facility does not generate waste-activated sludge in its secondary
process.
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The waste activated sludge from the aerobic treatment goes to a waste activated sludge
storage lagoon, where liquid waste is stored for approximately two years. Due to the
semi-anaerobic conditions in the storage lagoon, minor greenhouse gases in the form of
CO2 and CH4 are emitted into the atmosphere. These emissions occur pre- and post-
project since the storage lagoons remain unchanged. The sludge is then used as
fertilizer in land application. Tyson’s primary lagoons are designed for BOD removal
rates in the range of 80% – 95%. A study of both pre- and post-project conditions shows
removal rates in this range, indicating that the presence of the covers neither increases
nor decreases the removal rate in the primary phase and that emissions from the
second and third phases are the same in the project case as they are in the baseline
case. Pre-project removal rate data is available in Appendix A while post-project
removal rate data is available in the emission reductions calculations spreadsheets
found in the Monitoring Report.
Figure 3-1 depicts pre-project conditions at the treatment plants. Emissions from each
phase of wastewater treatment are shown as well as emissions from the combustion of
fossil fuel in the on-site boilers.
Figure 3-1: Pre-Project Flow of Wastewater Effluent, Biogas Emissions and Fossil Fuel Combustion2
2 At the Amarillo facility, after the aeration basin, wastewater is directed to a storage lagoon for irrigation.
No waste-activated sludge is produced. Pretreatment for removal of calcium and suspended solids as
shown in the diagram occurs at Amarillo and Joslin.
WAS
WW
Land
Application
CH4 + CO2 CO2
CH4 + CO2
Boiler
Processing
Facility
Anaerobic
Lagoons
Aeration
Basins/
Clarifiers
Storage
Lagoon
Fuel
CO2
Receiving
Stream
Legend
WAS: Waste-Activated Sludge
WW: Wastewater
Pretreatment
Plant
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3.3 Post-Project Conditions
3.3.1 Stage 1
Tyson first began managing the biogas emissions in December of 2000 and early 2001,
with the installation and operation of covers for the anaerobic lagoons at four of its
wastewater treatment facilities throughout the Midwest. Initially, the captured biogas
was flared at all four sites, converting the methane to less harmful CO2. This covering
and flaring represents Stage 1 of the emission reductions project. At each of the four
wastewater treatment facilities, the existing anaerobic lagoons were covered with a gas-
tight high density polyethylene (HDPE) material. At the Joslin facility, Tyson constructed
one additional covered lagoon for primary anaerobic digestion because the plant was
experiencing capacity constraints, and a new, uncovered lagoon would’ve been built in
the absence of the project. Centrifugal, low-pressure biogas blowers were installed to
move the biogas through the gas processing system for eventual flaring. Each facility
was equipped with a Varec 244W waste gas burner, an open flare capable of achieving
99% combustion efficiency; however, actual permitted efficiencies for each facility are
used in the reductions calculations for conservativeness.
Stage 1 results in significant reductions of anthropogenic GHG emissions. As a result of
Tyson’s capture and flare of fugitive gas (methane) at its wastewater treatment
facilities, direct emission reductions have been achieved. All wastewater treatment now
occurs primarily in covered anaerobic lagoons. Gas collected from the anaerobic
lagoons is captured and flared. This reduces the GHG impact of the facility, by means of
the destruction of CH4. Per CDM Methodology ACM0014, the CO2 released by the flare,
as a component of the emissions from the decomposition of organic waste, is
considered to be part of the natural carbon cycle and is therefore carbon neutral3.
Figure 3-2 shows the new emissions from the process flow of Stage 1.
3 UNFCCC CDM Methodology ACM0014 Version 01, page 4
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Figure 3-2: Project Flow of Wastewater Effluent, Biogas Emissions and Fuel Combustion after Stage 1
The number of anaerobic lagoons varies by site and is shown in the below table:
Location Number of Anaerobic Lagoons
Joslin, Illinois 3
Lexington, Nebraska 2
Amarillo, Texas 6
Storm Lake, Iowa 2
3.3.2 Stage 2
In 2003, Tyson implemented a biogas-to-boiler project at the Joslin, Illinois beef
processing complex which became operational in March, 2004. Equipment was installed
to transport the biogas from the wastewater treatment plant to the boilers for use in
the production of steam used in the beef processing facility. This addition of the energy
recovery system marked the completion of Stage 2 of the project at the first facility.
Since then, additional biogas utilization projects have been implemented at other
locations. Stage 2 of Tyson’s emission reduction project involves tying in the onsite
boilers to the biogas collection system, which involves the installation of more powerful
centrifugal blowers to move the biogas to the packing plant. Whenever possible, the
biogas is utilized in the boilers, displacing the fossil fuels that would be consumed in its
place, thus reducing the CO2 emissions from fossil fuel combustion. For various reasons,
it is not always possible to utilize the biogas at all times. Because of this, the flares from
Stage 1 remain an integral part of the system, continuing to destroy the CH4 that would
Lagoon Cover - Gas
Capture, Measurement &
Gas Scrubbing System
Flare
Boiler
CO2
Fuel
Legend
WAS: Waste-Activated Sludge
WW: Wastewater
Pretreatment
Plant
Pilot
Fuel
CO2,Pilot
WAS
WW
Land
Application
CH4 + CO2
Storage
Lagoon
Receiving
Stream
CO2
Processing
Facility
Anaerobic
Lagoons
Aeration
Basins/
Clarifiers
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otherwise be vented during these downtimes. Figure 3-3 shows the process flow and
emissions after Stage 1 and 2 have been implemented.
Figure 3-3: Project Flow of Wastewater Effluent, Biogas Emissions and Biogas Consumption after Stage 2
The schedule of project implementation (Stage 1 and 2) is shown below:
Location Stage 1 Flaring Stage 2 Biogas Utilization
Effective Date Effective Date
Joslin, Illinois 07/2001 03/2004
Lexington, Nebraska 09/2001 12/2004
Amarillo, Texas 02/2001 10/2005
Storm Lake, Iowa 12/2000 N/A
3.4 Identification of Physical Boundaries
The physical boundary of the project must be separated into Stage 1 and Stage 2
boundaries. Each boundary consists of the following components of the wastewater
treatment operation:
Stage 1 – Biogas Flaring
- Primary anaerobic lagoons, including the cover and gas collection system
and any electricity or fuel used in the collection of biogas
- Gas flaring system, including any electricity or fuel consumed as well as
methane emissions due to flare efficiency
- Second Phase (activated sludge) storage lagoons and clarifiers
CH4 + CO2
CO2
WW
WAS
Lagoon Cover - Gas
Capture, Measurement &
Gas Scrubbing System
Flare
Boiler
Processing
Facility
Anaerobic
Lagoons
Aeration
Basins/
Clarifiers
Storage
Lagoon
Receiving
Stream
Land
Application
Pilot
Fuel
CO2,Pilot
Pretreatment
Plant
Legend
WAS: Waste-Activated Sludge
WW: Wastewater
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- Final storage lagoons prior to land application.
Stage 2 – Biogas Utilization / Energy Recovery
- Primary anaerobic lagoons, including the cover and gas collection system
and any electricity or fuel used in the collection of biogas
- Gas transport system, including any electricity or fuel used to transport
the gas, as well as any leakage that occurs within piping systems.
- Boiler combustion system, including fossil fuel displaced by project.
- Gas flaring system, in the event that not all biogas is utilized in the boiler
system.
- Second Phase (activated sludge) storage lagoons and clarifiers
- Final storage lagoons prior to land application.
3.5 Identification of Relevant GHG Sources, Sinks and Reservoirs (SSRs)
3.5.1 Baseline SSRs
Within the baseline scenario, GHG sources include the primary anaerobic lagoons,
secondary aeration basins, waste-activated sludge storage lagoons and facility boilers
combusting fossil fuels. There are no significant sinks or reservoirs.
3.5.2 Project Stage 1 SSRs
Within Stage 1 of the project, GHG sources are the same as the baseline, with the
addition of indirect emissions from electricity used in the gas collection and transport
system as well as the H2S scrubbing system. GHG Sinks are added in the form of
anaerobic lagoon covers and biogas flares which reduce CH4’s Global Warming Potential
(GWP) of 21 to carbon-neutral CO2. Boiler emissions from the project remain
unaffected and are equal to those in the baseline. There are no significant reservoirs.
3.5.3 Project Stage 2 SSRs
Within Stage 2 of the project, all SSRs from Stage 1 apply, with the following additions:
A sink is added in the form of fossil fuel displaced by combusting biogas in the on-site
boilers.
3.5.4 Elimination of Irrelevant SSRs
As previously described in Section 3.2 – Pre-Project Conditions, it has been determined
from pre- and post-project data that the biogas production associated with the
secondary clarifiers, tertiary storage lagoons and sludge application are equal in both
the baseline and the project scenarios (Stages 1 and 2). This is indicated by studies of
BOD removal rates in the pre- and post-project cases. Having determined these rates to
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be equal, these sources are excluded from the emission reduction calculations as they
negate one another.
3.6 GHGs Included in This Protocol
This report documents GHG emissions and reductions for Carbon Dioxide (CO2) and
Methane (CH4). In accordance with CDM ACM0014, emissions of other GHGs from
wastewater treatment processes, such as Nitrous Oxide (N2O), have been determined to
be negligible and are excluded4.
3.7 Project Crediting Period
The project crediting period lasts 10 years, beginning on January 1, 2004 and ending on
December 31, 2013.
4.0 Baseline Assessment
Baseline emissions for Tyson’s activities are the actual CO2e emissions that would have
been released to the atmosphere in the absence of Tyson’s capture, flare and utilization
operations. Before Tyson implemented this project, the biogas generated by the
degradation of organic material in the wastewater during all phases of treatment was
freely released into the atmosphere.
Stage 1 baseline emissions can be summarized as the CH4 emissions from the uncovered
lagoon wastewater treatment systems before the covers were installed.
Stage 2 baseline emissions are equal to those of Stage 1, with the addition of the CO2
emissions associated with fossil fuel combustion in the facilities’ process heating
equipment.
Under CDM Methodology ACM0014, baseline emissions from the lagoon are estimated
based on the chemical oxygen demand (COD) of the effluent that would be degraded
anaerobically in the lagoon in the absence of the project activity and the maximum
methane producing capacity (Bo) of the COD. These CH4 emissions are calculated
according to CDM Methodology ACM0014, which also references IPCC guidelines for
anaerobic wastewater treatment.
Industrial wastewater treatment in the meatpacking industry is unique in that the
effluent results in the formation of a grease cap on top of the lagoons in the pre-project
state. These grease caps are usually 3 to 5 feet thick and are very firm. A photograph of
a grease cap at an uncovered Tyson facility is shown below in Figure 4-1.
4 UNFCCC CDM Methodology ACM0014 Version 01, page 4
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Figure 4-1: Grease Cap Present in the Pre-Project State
Once the project has been implemented, the cover provides the right conditions for the
grease cap to be dissolved in the wastewater, where it nearly completely diminishes.
One of the most important impacts of the grease cap on the baseline scenario is that it
insulates and maintains warmer temperatures within the lagoon even more so than a
cover system. Furthermore, it creates an oxygen-tight barrier over the entire lagoon
surface.
4.1 Baseline Scenario Selection
All plausible baseline scenarios for the treatment of wastewater prior to project
implementation are listed below:
W1: The use of open lagoons for the treatment of wastewater;
W2: Direct release of wastewater to a nearby body of water;
W3: Aerobic treatment of wastewater;
W4: Filter-bed treatment of wastewater;
W5: Chemical treatment of wastewater;
W6: Anaerobic digester with methane recovery and flaring.
Regulatory requirements eliminate Scenario W2 from consideration because the
strength of the wastewater produced by Tyson’s operations is too high for legal
discharge into local bodies of water and would be in violation of federally enforceable
permits.
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Prohibitive barriers are evident in Scenarios W3, W4, W5 and W6.
Scenario W3 results in too high of a sludge output, drastically increased
electricity consumption, and capital costs estimated to be three times that of
anaerobic treatment.
Scenario W4 is unsuitable due to the high suspended solids content and fat
content in the Tyson wastewater.
Scenario W5 results in large quantities of DAF sludge, which is troublesome for
land application and not sustainable. Attempts are being made to eliminate this
form of wastewater treatment from other similar industrial sectors.
Scenario W6 is eliminated because it provides the same level of service as
scenario W1, but with dramatically higher investment and operating costs.
Scenario W1 is the only remaining plausible scenario and is therefore selected as the
appropriate baseline case. Further discussion on baseline selection in accordance with
The Voluntary Carbon Standard is shown below in Section 5.0 – Project Additionality.
To meet the thermal energy demands of the adjacent Tyson meat-packing plants, the
plausible baseline scenarios prior to project implementation are as follows:
H1: Heat generation using fossil fuels in the boilers
H2: Heat generation using tire scraps
H3: Fossil fuel-based cogeneration of heat from captive power plant
H4: Heat generation by burning animal fats
None of the above options face regulatory barriers. Prohibitive barriers are evident in
Scenarios H2 through H4.
Scenario H2 is eliminated due to high capital cost of equipment at the time of
project implementation. Additionally, emissions from such an activity would
likely be high.
Scenario H3 is eliminated because the project activity does not involve the
generation of electricity.
Scenario H4 is a potential option for Tyson in the future, but the price of animal
fats has historically warranted their sale as a product rather than their use as a
fuel. Furthermore, additional boiler modifications would have to be made to
accommodate this scenario.
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Historically Tyson has purchased natural gas for use in boilers (Scenario H1) to meet the
thermal energy demands of the rendering plants throughout the life of each plant. To
this day, Tyson is only able to use biogas from the project activity to meet a fraction of
the energy demand, which has resulted in the continued utilization of Scenario H1 for
the balance of the energy requirements. Tyson also has back-up fuel supplies of #2 fuel
oil and propane at some of the sites. Emissions from the combustion of these fuels are
higher than those from natural gas consumption, further ensuring that the selection of
natural gas as the baseline is conservative.
5.0 Project Additionality
The project activity meets the additionality criteria requirements of The Voluntary
Carbon Standard (VCS), Version 1, Part A, which establishes clear evidence that the
project is additional because it is not common practice, it is not required by regulation
and it is not the least cost option for providing the underlying product or service.
5.1 Common Practice
The covering of anaerobic lagoons and the subsequent capture, flare or utilization of
methane at wastewater treatment facilities is not common practice. In its 2003 report,
Wastewater Technology Fact Sheet – Anaerobic Lagoons, The U.S. Environmental
Protection Agency (EPA) states that, “A cover can be provided to trap and collect the
methane gas produced in the process for use elsewhere, but this is not a common
practice.”5 Additionally, Tyson’s own operations exemplify the unique character of
these projects. At the time these projects were implemented, Tyson operated
uncovered lagoons at 14 of its Fresh Meats facilities. The projects discussed in this
protocol represent four out of five sites in this group that have been able to implement
ghg reduction projects. Tyson was actually among the first in the meatpacking industry
to take such action and has been instrumental in leading the industry and setting design
standards.
5.2 Regulatory Surplus
An emission reduction project is considered to be surplus in nature if it is not mandated
by any enforced law, statute or other regulatory framework. The surplus nature of
these emission reductions is demonstrated by a review of applicable state and federal
regulations associated with wastewater treatment facilities servicing Tyson’s processing
facilities. None of these apply to methane or other greenhouse gases. Since the project
is not mandated by law and is not required to control GHG emissions, the project is
purely voluntary and associated emission reductions generated by the project are
deemed to be surplus in nature.
5 United States Environmental Protection Agency, Wastewater Technology Fact Sheet – Anaerobic
Lagoons, page 1
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5.3 Least Cost Option
The least cost option for providing the same underlying product and service (anaerobic
wastewater treatment) is to operate uncovered lagoons in the traditional, pre-project
manner, as evidenced by the historical experience at these specific sites as well as the
continued uncovered operation of anaerobic lagoons at other Tyson meat-packing
facilities. Uncovered anaerobic wastewater treatment, when compared to covered
treatment, provides the same level of service, but avoids the following capital costs:
Purchase and installation of the lagoon covers, flare, biogas scrubbing system, piping
and blowers. It also avoids the continuing operating expenses of personnel, electricity
and propane consumption.
5.4 Supplemental Barriers Analysis
In addition to meeting the criteria of VCS Version 1, more stringent additionality tests
have been applied to the project activity to further prove that the reductions are real,
voluntary and surplus in nature. In addition to the common practice and regulatory
surplus criteria described in Sections 5.1 and 5.2, respectively, the “Project Test of
Additionality”6 includes an assessment of implementation barriers that further
demonstrate the additional nature of the project. In order to develop this emission
reductions project, Tyson faced multiple investment, institutional and technological
barriers.
5.4.1 Investment Barriers
When Tyson implemented Stage 1 of the project activity, there were no revenue
streams to recoup the costs of the investment other than the marketing of Verified
Emission Reductions. While the implementation of Stage 2 does provide revenues due
to energy savings from the displacement of natural gas, the various sites took between 3
and 4-1/2 years to implement Stage 2 (Storm Lake still has only implemented Stage 1).
This multi-year lag between Stages 1 and 2 demonstrates that Stage 2 energy revenues
were not part of an investment repayment strategy for Tyson. The least-cost option for
Tyson to carry on its business activities would be to keep the lagoons uncovered since
the project activity does not enhance the wastewater treatment in any way, but rather
adds substantial operating expenses to the process (described in greater detail in
Section 5.3). All financing for Stage 1 and Stage 2 project activities was provided
internally by Tyson.
5.4.2 Institutional and Technological Barriers
Many institutional and technological barriers relating to operating in an area outside of
Tyson’s core business were prevalent in the project activity and had to be overcome.
6 The Voluntary Carbon Standard 2007, page 14.
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The implementation and operation of gas collection and energy recovery systems is not
a core competency at Tyson’s wastewater treatment facilities. As such, challenges
relating to personnel and operating efficiency had to be overcome. Tyson did not have
human resources skilled in the project field and had to overcome this institutional
barrier by developing or hiring personnel to run the operation. Additionally, Tyson
implemented gas scrubbing equipment, adding another cost, level of training, personnel
and data monitoring.
Even with skilled personnel in place, Tyson faced the difficult challenge of integrating
the new equipment efficiently into the existing process. This was not an easy task, and
one of the many technology implementation barriers is exemplified in the biogas
utilization vs. flaring ratios found in Appendix B. It can be seen from the massive
fluctuations in flaring vs. utilization that Tyson struggled to make the process efficient in
the first year after start-up at each location. In 2005, the first year after all three
utilization projects were implemented, the flaring vs. utilization ratio had reached 29%
to 71%. Even today, though it is most profitable to utilize all of the biogas, the average
utilization is still only 75% of the total biogas generated.
6.0 Calculation and Reporting of Emission Reductions
6.1 Applicability Conditions
The project meets all of the applicability criteria specified by CDM ACM0014 as
described below:
- Scenario 1 applies: Historically, untreated wastewater enters uncovered
lagoons that have clearly anaerobic conditions. The project activity
involves constructing covers and gas collection systems to flare and/or
utilize the biogas to generate heat. The residual COD load from the
anaerobic digester is then directed to open lagoons.
- The depth of the Tyson lagoons ranges from 17 to 27 feet.
- Energy requirements per unit of wastewater input remain largely
unchanged before and after the project.
- All data requirements of the methodology are fulfilled.
- The residence time of organic matter in the uncovered lagoon system is
at least 60 days.
- Local regulations do not prevent discharge of wastewater in uncovered
lagoons.
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6.2 Total Emission Reductions Calculation
The net emission reductions are calculated using the following equations:
��� ��� � � �� (6-1)
Where:
Net ERC = Net Emission Reduction Credit (expressed as metric tonnes CO2e)
BE = Baseline Emissions
PE = Project Emissions
6.3 Baseline Emissions Calculation
� � �� � � � � (6-2)
Where:
BECH4 = CH4 emissions generated by the uncovered anaerobic lagoons (mtCO2e)
BEHG = CO2 emissions associated with fossil fuel combustion in the boilers that
is displaced by the project (mtCO2e)
NOTE: Before Stage 2 of the project is implemented, baseline boiler
emissions, BEHG, are equal to the Project Emissions for the boiler, PEHG.
These values, therefore, negate one another and are not accounted for
until Stage 2 is implemented.
6.3.1 Lagoon Baseline (BECH4) Calculations
Baseline emissions from anaerobic treatment, BECH4, are calculated using the organic
removal ratio method, which expresses the fraction of COD degraded anaerobically in
the uncovered lagoons less that which is decomposed aerobically, oxidatively or lost due
to sedimentation within the lagoon.
�� � � �������,� ������,� �����,� ������ �,�! " �#$
�%#" 21
2204.62
(6-3)
Where:
CODBL,m = Monthly Chemical Oxygen Demand that would be treated in the
uncovered lagoons in the absence of the project activity (lbs COD/month)
CODAer,m = Monthly Chemical Oxygen Demand that would degrade aerobically in
the lagoon (lbs COD/month)
CODOX,m = Monthly Chemical Oxygen Demand that would be chemically oxidized
through sulfate in the wastewater (lbs COD/month)
____________________________________________________________________________________________________________
Page 19
CODSedim,m = Monthly Chemical Oxygen Demand lost through sedimentation in the
lagoon (lbs COD.month)
BO = Maximum methane producing capacity. The IPCC default value for BO is
0.21 (lbs CH4/lbs COD)
NOTE: Despite IPCC recommendations of 0.25, the default value chosen
by CDM ACM0014 is 0.21 (lbs CH4/lbs COD)7. Additionally, Tyson’s
standard operating procedure samples and reports BOD concentration
instead of COD. Per the same IPCC recommendations, COD is calculated
to be 2.4 times BOD. 8
21 = Global Warming Potential of Methane9
2204.62 = lbs/mton
�����,� � ���,-,� � ���./,� ����01,� (6-4)
Where:
CODPJ.m = Monthly Chemical Oxygen Demand treated in the covered anaerobic
lagoon (lbs COD/month)
NOTE: The project activity does not change the wastewater volume or
COD loading directed toward the anaerobic lagoons. The baseline COD
corresponds to the COD that is treated under the project activity.
CODIn.m = Chemical Oxygen Demand entering the anaerobic lagoon (lbs
COD/month)
CODOut,m = Chemical Oxygen Demand leaving the lagoon and entering secondary
and tertiary processes (lbs COD/month)
������,� � 2 " 3��4,5�� (6-5)
Where:
A = Surface area of the uncovered lagoon (ft2)
fCOD,aer = Quantity of Chemical Oxygen Demand degraded under aerobic
conditions due to surface oxygenation (lbs COD/ft2/month)
�����,� � 6,-,� " 78 " �8 " 2.4 (6-6)
Where:
FPJ,m = Monthly quantity of wastewater treated in the digester (mgal)
ws = Average concentration of chemically oxidative substance (Sulfate)
present in the treated wastewater (mg/l). Sulfate is primarily sourced
from deep freshwater wells. Sulfate values typically range from 250 mg/l
to 375 mg/l as Sulfate (SO4) (83 mg/l to 125 mg/l as Sulfur) in the influent
7 UNFCCC CDM Methodology ACM0014 Version 01, page 22
8 2006 IPCC Guidelines for National Greenhouse Gas Inventories, Volume 5 – Waste, Chapter 6 –
Wastewater Treatment and Discharge, Page 6.12 9 IPCC, Climate Change 1995: The Science of Climate Change, 1996
____________________________________________________________________________________________________________
Page 20
to the anaerobic lagoons. An analysis of Sulfur mass balances at Tyson’s
lagoons indicates the average concentration of Sulfate in the influent to
be 329 mg/l, with an average effluent concentration of 144 mg/l. This
data yields an average Sulfate concentration available to reduce COD of
185 mg/l; however, for conservativeness, the highest average value
reported of 231 mg/l SO4 is used in the calculations.
Rs = Specific reduction in Chemical Oxygen Demand by Sulfate (lbs COD / lbs
Sulfate). Engineering design information for calculations associated with
loadings to activated sludge facilities that have relatively high soluble
sulfide values use a factor of 2 lbs Oxygen for 1 pound of soluble Sulfide
to convert to Sulfate. Engineering factors for oxidizing BOD are 1.5
pounds of oxygen to 1 pound of BOD. The reduction factor, Rs, is then
given by 2/1.5 = 1.3333 for oxidation of BOD by Sulfur-reducing bacteria
in an anaerobic lagoon. It is then necessary to convert BOD to COD as
described for Equation 6-3.
CODSedim,m Determination
In accordance with Appendix II of CDM Methodology ACM001410
, the first step in
characterizing CODSedim,m is to determine the likelihood of any sedimentation actually
taking place. Tyson’s lagoons are highly anaerobically active, keeping all material that
would sediment in a permanent state of suspension. This material is then anaerobically
degraded. The lost COD due to sedimentation, if any, can then be determined by any
change of lagoon depth over time. Tyson’s lagoons are designed not to have any
accumulation of organic matter sedimentation, and as such, periodic depth
measurements made by accessing the lagoons from various hatch points have not
shown any change in depth of the lagoons over time. This is further verified by
observations made during Tyson’s periodic purging of the pipes and pumps at the
bottom of the lagoons. The only accumulated material observed by Tyson has been
sand, silt and other inorganic materials. Therefore, COD lost due to sedimentation,
CODSedim,m, is determined to be zero.
6.3.2 Boiler Baseline (BEHG) Calculations
� � � � 9:,-,� " �6��$,;;,<= >��?<= >��
#$
�%#
(6-7)
Where:
HGPJ.m = Monthly thermal energy generated with biogas from the covered
lagoon that displaces fossil fuel combustion (MMBtu)
10
UNFCCC CDM Methodology ACM0014 Version 01, page 34
____________________________________________________________________________________________________________
Page 21
EFCO2,FF,boiler = CO2 emission factor for fossil fuel used in boiler = 0.05919
mtCO2/MMBtu11
ηboiler = Efficiency of the boiler that would be used for heat generation in the
absence of the project activity. While U.S. EPA and IPCC guidelines
suggest values of 98%12
and 99.5%13
respectively, a value of 100% is
conservative and is therefore used.
9:,-,� � 6@A�<,� " 3B� � " ��@� � C 1,000,000 (6-8)
Where:
FVRGb,m = Gross monthly volume of biogas combusted in the boiler (ft3)
fvCH4 = Volumetric fraction of methane in the biogas (%)
NCVCH4 = Net Caloric Value of Methane = 922.45 Btu/ft3 14
1,000,000 = Btu/MMBtu
6.4 Project Emissions Calculations
Project emissions occur from lagoon cover leakage, flaring, electricity consumption in
the gas collection and scrubbing systems and fossil fuel combustion. As described in
Section 3.2 - Pre-Project Conditions, the project implementation has not resulted in any
change in organic material loading or wastewater quantity directed to secondary and
tertiary processes. Thus, project emissions from effluent entering these processes are
identical to the equivalent baseline emissions. Project emissions are characterized by
the following equation:
�� � ��� �,� D�81 � ��;>5�� � ��E� � ��;� (6-9)
Where:
PECH4,digest = Physical biogas leakage from the lagoons’ cover systems (mtCO2e)
PEFlare = Emissions from flaring biogas generated in the lagoon (mtCO22e)
PEEC = Indirect emissions associated with electricity consumption from the
project activity (mtCO2e)
PEFC = Emissions from fossil fuel combustion (mtCO2e)
11
2006 IPCC Guidelines for National Greenhouse Gas Inventories, Volume 2 – Energy, Chapter 1 –
Introduction, Table 1.4. 56,100 kgCO2/TJ factor converted to mtCO2/MMBtu. 12
United States Environmental Protection Agency, AP 42, Table 2.4-3 13
Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories, Module 1 Energy, Table 1-4 14
2006 IPCC Guidelines for National Greenhouse Gas Inventories, Volume 2 – Energy, Chapter 1 –
Introduction, Page 1.2. 48.0 TJ/Gg factor converted to Btu/ft3.
____________________________________________________________________________________________________________
Page 22
6.4.1 Physical leakage Calculations
Tyson employs rigorous inspection protocols to ensure that biogas leakage from the
lagoon cover and piping systems is minimized. All facilities inspect the covers and
above-ground pipes daily (Joslin, IL, the one exception, inspects two to four times per
week). Since Tyson uses both 80 and 100 mil thickness HDPE in its covers, it is very rare
that leaks occur. Additionally, when biogas is transported to the flare or boiler, the vast
majority of the piping is under vacuum, minimizing leakage that can occur from such
system components. Most facilities report only several leaks per year, with one facility
even reporting no leaks in a 2-1/2 year time span. When leaks do occur, they are
repaired immediately using special tape, which stops the leak until the cover contractor
arrives to do a more permanent repair. Most leaks are reported as being slits less than
1 inch in length, but some facilities have reported slits up to 2 inches long.
In order to calculate a worst-case physical leakage scenario, Bernoulli’s equation is used
to estimate flow velocity across a rectangular tear measuring 0.25” x 2” (much larger
than actual worst case tear sizing). The mass of leaking CH4 is then calculated using the
maximum volumetric fraction of methane in the biogas combined with the longest time
a leak could go undetected. Bernoulli’s equation states the following:
B � F G,HIJK (6-10)
Where:
v = Flow velocity (cm/sec)
∆P = Change in pressure (kgf/cm2). Pressure monitoring indicates that the
maximum pressure under the covers rarely exceeds 0.1” H2O. For
conservativeness and uncertainty management, a value of 2” H2O =
0.00508 kgf/cm2 is used.
ρCH4 = Density of methane at ambient conditions = 6.8 x 10-7
kg/cm3
L � B " M " N� � " 3B� � (6-11)
Where:
M = Mass flow rate of Methane (kg/sec)
a = Cross-sectional area of worst-case tear = 3.23 cm2
fvCH4 = Volumetric fraction of methane in the biogas (%)
��� �,� D�81 � L " ���1�O1 " P� " 0.001 " 21 � ��QE (6-12)
Where:
tdetect = Maximum time that a leak would go undetected based on frequency of
inspection at each site (sec). 1 day used for all sites except Joslin, which
is 3.5 days.
____________________________________________________________________________________________________________
Page 23
nL = Maximum number of leaks reported in a given year = 5 leaks per year is
used for conservativeness.
PEME = Project emissions associated with cover leakage due to major events
(mtCO2e). Occasionally, Tyson’s facilities experience major events that
result in additional leakage from the cover systems. Such events might
include large tears, de-anchoring of the covers due to extreme winds, or
a partial cover removal to unclog pipes. These major events typically only
occur once every four to five years or less for any given site. When such
an event does occur, wastewater flow to the digester is typically shut off
immediately and the repair is made within a few days or less. For
conservativeness, when such an event occurs, if the lagoon loses the
ability to retain biogas, the methane production associated with one
period of lagoon residence time is added to the project emissions for that
month.
6.4.2 Flare Calculations
Project emissions due to flaring are calculated according to the CDM “Tool to Determine
Project Emissions from Flaring Gases Containing Methane.”15
��;>5�� � � RLA�S,� " T1 ?;>5��U " 212204.62
#$
�%#
(6-13)
Where:
TMRGf,m = Monthly total mass of methane in the residual gas from the anaerobic
lagoons combusted in the flare (lbs)
ηFlare = Methane destruction efficiency of the flare
At each facility, Tyson operates Varec 244W waste gas burners able to
achieve 99% combustion efficiency. Each site’s minimum allowable flare
efficiency was calculated for its respective air permit for the purposes of
ensuring the destruction of any H2S that might be present in the biogas.
H2S combustion efficiency is a requirement under the permits and cannot
be obtained without first achieving the same destruction efficiency of
CH4, thereby guaranteeing equal or greater methane destruction
efficiency.
Additionally, under permit, Tyson flares or utilizes 100% of the biogas
collected, meaning there is no uncombusted gas vented at any time.
15
Equations 6-13 and 6-14 reference UNFCCC CDM Tool to Determine Project Emissions from Flaring
Gases Containing Methane, pages 9 and 11
____________________________________________________________________________________________________________
Page 24
Whenever there is downtime due to maintenance or other issues, biogas
accumulates in the collection system until it can be flared or utilized once
more. The flares come complete with an electronic sensor and controls
package that verifies pilot operation and subsequent flare operation. The
controls are electronically interlocked with the biogas blowers to ensure
the blowers will automatically shut down in the event the sensors
indicate the flare or pilot flame is not operating properly. There is also an
alarm system linked with the flare that will contact facility operators in
the event of system failure.
All flares are operated in accordance with the manufacturer’s guidelines
for maximum efficiency and meet the requirements of 40 CFR 60.18 and
AP-42 2.4-3. These standards specify requirements for Btu content and
exit velocity that must be met in order to achieve 99% flare efficiency.
The minimum Btu content specified is 300 Btu/ft3 with a maximum exit
velocity of 60 ft/sec. The minimum Btu content achieved by the Tyson
biogas is 679 Btu/ft3, while the typical exit velocities average 47 ft/sec
and never exceed 60 ft/sec. Although 99% flare efficiency is likely
achieved at all sites as a result of the flare selection and operating
procedures, the permitted efficiency values, which are checked and
reported to regulatory bodies on a regular basis, have been used for
conservativeness. The permitted flare efficiency for each site is shown in
Section 7.2.
RLA�S,� � 6@A�S,� " 3B� � " N� � (6-14)
Where:
FVRGf,m = Gross monthly volume of biogas flared (ft3)
fvCH4 = Volumetric fraction of methane in the biogas (%)
ρCH4 = Density of methane at normal conditions = 0.0447 (lbs/ft3)
6.4.3 Electricity Calculations
Electricity consumption from the project activity includes electricity used by the blowers
in the transport of gas to the flare and boiler as well as the H2S scrubbing system.
Project emissions associated with this consumption are calculated in accordance with
the CDM “Tool to Calculate Project Emissions from Electricity Consumption – Case A.”16
16
Equation 6-15 references UNFCCC CDM Tool to Calculate Project Emissions from Electricity
Consumption, page 2
____________________________________________________________________________________________________________
Page 25
��E� � � ��,-,� " �6D� � " T1 � R�VU#$
�%#C 2204.62
(6-15)
Where:
ECPJ,m = Monthly electricity consumed by the project activity (MWh)
EFgrid = Grid CO2 emissions factor for electricity consumed at the project site
(lbsCO2/MWh)
TDL = Average transmission and distribution losses in the grid = 7.2%17
��,-,� � VS " �S,� � V< " �<,� � V $� " � $�,� (6-16)
Where:
Lf = Load rating of the centrifugal blowers used to transport biogas to the
flare (MW)
tf,m = Hours of operation of the blowers transporting biogas to the flare in
month m
Lb = Load rating of the centrifugal blowers used to transport biogas to the
boiler (MW)
tb,m = Hours of operation of the blowers transporting biogas to the boiler in
month m.
NOTE: In some data sets, hours of boiler utilization (tb,m) and flare time
(tf,m) are combined. In such cases, the load rating of the boiler blowers
(Lb) is used for the entire time for conservativeness.
LH2S = Load rating of the H2S scrubber system (MW). Each site employs
different types of H2S scrubbing systems. A breakdown of equipment for
each site can be found in Appendix C.
tH2S,m = Hours of operation of the H2S scrubber system in month m
Load ratings are calculated based on the nameplate horsepower for each blower. Even
though the blowers typically operate at approximately half load, electricity consumption
is calculated based on full load for conservativeness. An example calculation for MW
conversion for a 15 hp blower is shown below:
V � 15 XY " Z0.746 \]XY ^ " Z 1 L]
1000 \]^ � 0.01119 L]
(6-17)
17
United States Climate Change Technology Program, Technology Options for the Near and Long Term,
Page 34
____________________________________________________________________________________________________________
Page 26
6.4.4 Fossil Fuel Calculations
Pilot fuel used in the flares represents the sole fossil fuel emission from the project
activity. In order to ensure safe and proper startup and operation of the flare, propane
is used as a pilot fuel in the flares. Project emissions are calculated according to the
CDM “Tool to Calculate Project or Leakage CO2 Emissions from Fossil Fuel Combustion –
Option B.”
��;� � 6�,�=`5/� " �6,�=`5/� " 3, (6-18)
Where:
FCPropane = Annual quantity of propane used in the flares as pilot fuel (gal)
EFPropane = Emission factor of propane = 0.00574 mtCO2e/gal
NOTE: The CDM “Tool to Calculate Project or Leakage CO2 Emissions
from Fossil Fuel Combustion” recommends calculating emission
coefficients based on IPCC factors; however, no such IPCC factors exist for
Propane. As such, U.S. EPA factors are used instead.18
It is possible to
use the IPCC factors for Liquefied Petroleum Gas, a mixture of Propane
and Butane, but the EPA factor used is higher and therefore more
conservative.
fP = Uncertainty factor = 2. Propane usage data is only available for 2007.
Since Tyson operates its flares in the same manner every year, it is
reasonable to assume that propane usage will be consistent year to year,
but due to this uncertainty, a conservative factor of 2 is used for all years
prior to 2007. As part of the monitoring plan, Tyson will record Propane
usage monthly in the future.
�6,�=`5/� � 7�,,�=`5/� " ��,�=`5/� " 44/12 C 42 C 1000 (6-19)
Where:
wC,Propane = Carbon content of Propane per unit energy = 17.20 kgC/MMBtu
ECPropane = Energy Content of Propane per volume = 3.824 MMBtu/Barrel
44/12 = Molar mass ratio of Carbon Dioxide, CO2, to Carbon, C.
42 = Gallons/Barrel
1000 = kg/mt
18
U.S. EPA, Inventory of Greenhouse Gas Emissions and Sinks: 1990 – 2005 (2007), Annex 2.1, Table A-
40
____________________________________________________________________________________________________________
Page 27
7.0 Monitoring Plan
7.1 Overview of Types of Data and Information
The BOD5 test is a method of approximating the amount of dissolved oxygen utilized by
microorganisms in the biochemical oxidation of organic matter. Biological oxidation is a
slow process and theoretically takes an infinite amount of time to go to completion.
The oxidation of carbonaceous organic matter is approximately 95 to 99 percent
complete in 20 days. Wastewater treatment operations typically cannot wait 20 days
for results of the BOD test, so a shorter test is used. The BOD5 test is used instead to
receive results in a more timely fashion. The oxidation of organic matter is
approximately 60 to 70 percent complete at the end of 5 days. The anaerobic
biodegradation of organic matter does not utilize oxygen; however, approximations are
made between the biogas generated and the value of the BOD5 analysis. Historically,
Tyson experiences carbonaceous BOD removal rates in the primary anaerobic lagoons in
excess of 85%.
The estimation of greenhouse gas emission reductions from Tyson’s fugitive gas
(methane) capture and flare claimed in this protocol relies heavily on data provided by
Tyson. Tyson provided schematic diagrams of the wastewater treatment facilities pre-
and post-project. Tyson also provided spreadsheets containing the flow rates and BOD
concentrations of wastewater treated, volumes of biogas captured, flared and utilized,
and hours of operation for all components requiring electricity consumption. This data
is monitored in accordance with the parameters defined in Section 7.3 and is totalized in
daily, weekly and monthly values. All data is stored on Continuous Emissions
Monitoring System (CEMS) data collection systems at each location except for Amarillo,
where totalized data is entered into collection spreadsheets manually.
Data is initially gathered by the wastewater treatment operators, who are trained and
supervised by the wastewater superintendent. The data is then aggregated by the
superintendent, where it is then formalized and forwarded to the Secretary of the
Director of Fresh Meats EHS Operations. An inclusive report for all facilities is then
distributed to operations management personnel within the Fresh Meats group.
Included in this distribution group is Tyson Foods’ New Technology Manager for the EHS
Group, who then submits the data to Blue Source for integration into the emission
reductions calculations.
All flowmeters (both wastewater and biogas) are calibrated and/or verified by certified
third parties on a quarterly or annual basis. The CEMS systems self-calibrate daily and
also undergo annual third party calibration by certified parties. At the Amarillo facility,
Tyson monitors gas composition of the biogas treated and flared with a Daniel
“Danalyzer” BTU Chromatograph. Readings on gas composition and heating value are
generated continuously on the Intellution software and can be checked at any time
____________________________________________________________________________________________________________
Page 28
during operation. Mostardi-Platt and other third-party gas analysis firms perform tests
at the other facilities to determine the gas composition of the biogas being flared.
Tyson follows preventative maintenance procedures as recommended by equipment
manufacturers for all monitoring equipment. During the quarterly calibration checks, in
the event that a flowmeter were to be found to be out of spec, it would be repaired or
replaced immediately. To date, no flowmeters have been found to be out of spec or
have required service or replacement other than the routinely scheduled preventative
maintenance.
7.2 Data and Parameters Not Monitored
All constants and emission factors used are in accordance with CDM ACM0014, the
“Tool to determine project emissions from flaring gases containing methane,” the “Tool
to calculate project emissions from fossil fuel combustion” and the “Tool to calculate
project emissions from electricity consumption.”
Parameter B0
Data Unit mtCH4 / mtCOD
Description
Maximum methane producing capacity, expressing the maximum amount
of CH4 that can be produced from a given quantity of chemical oxygen
demand (COD)
Source of Data 2006 IPCC Guidelines
Value to be Applied Despite IPCC recommendations of 0.25, the default value chosen by CDM
ACM0014 is 0.21 (lbs CH4 / lbs COD) due to the uncertainty of the value.
Any Comment
Parameter A
Data Unit ft2
Description Surface area of the uncovered lagoons
Source of Data Engineering blue prints of the lagoons
Value to be Applied
Amarillo, TX 538,078
Joslin, IL 190,962
Lexington, NE 204,800
Storm Lake, IA 171,000
Any Comment Parameter represents total open surface area at each site. Accounts for
multiple lagoons of varying sizes where applicable.
____________________________________________________________________________________________________________
Page 29
Parameter fCOD, aer
Data Unit mtCOD / ha month
Description Quantity of COD degraded to CO2 under aerobic conditions per surface area
of the lagoon
Source of Data Expert engineering opinions from both internal and third party assessment
Value to be Applied 0.1582 lbs COD / ft2 / month = 92.7 mtCOD / ha / yr
Any Comment
The grease cap present in the pre-project case, as described in Section 4.0 –
Baseline Assessment, forms a completely oxygen-tight barrier over the
entire lagoon surface, which eliminates all COD removal due to aerobic
activity at the lagoon surface. However, since no experiments have been
conducted to date, the default values described above are used in
accordance with the CDM methodology. Experiments may be conducted in
the future to determine if different values are more accurate.
Parameter D
Data Unit ft
Description Depth of the lagoon
Source of Data Engineering blue prints of the lagoons
Value to be Applied
Amarillo, TX 19
Joslin, IL 17
Lexington, NE 27
Storm Lake, IA 17
Any Comment
Parameter EFCO2,FF,Boiler
Data Unit mtCO2 / MMBtu
Description CO2 emission factor of the fossil fuel type used in the boiler (natural gas) for
heat generation in the absence of the project activity
Source of Data 2006 IPCC Guidelines
Value to be Applied 0.05919
Any Comment
Parameter NCVCH4
Data Unit Btu/ft3
Description Net Caloric Value of Methane
Source of Data 2006 IPCC Guidelines
Value to be Applied 922.45
Any Comment
____________________________________________________________________________________________________________
Page 30
Parameter ηBoiler
Data Unit %
Description Efficiency of the boiler that would be used for heat generation in the
absence of the project activity
Source of Data
Value to be Applied 100%
Any Comment U.S. EPA and IPCC guidelines suggest values of 98% and 99.5% respectively;
however, a value of 100% is conservative and is therefore used.
Parameter GWPCH4
Data Unit mtCO2e / mtCH4
Description Global warming potential for CH4
Source of Data IPCC
Value to be Applied 21
Any Comment
Parameter COD/BOD
Data Unit lbs COD / lbs BOD
Description BOD to COD Conversion Factor
Source of Data 2006 IPCC Guidelines
Value to be Applied 2.4
Any Comment
Parameter wS
Data Unit mg/L
Description Average Concentration of Chemically Oxidative Substance (Sulfate) present
in the treated wastewater
Source of Data On-site measurements
Value to be Applied 231
Any Comment Most conservative value chosen from available data
Parameter RS
Data Unit lbs COD / lbs Sulfate
Description Specific Reduction of Chemical Oxygen Demand by Sulfate
Source of Data Engineering factors for oxidizing BOD
Value to be Applied 1.3333
Any Comment
____________________________________________________________________________________________________________
Page 31
Parameter tdetect
Data Unit seconds (days)
Description Maximum time that a leak would go undetected based on frequency of
inspection at each site
Source of Data Standard Tyson Operating Procedures for lagoon cover monitoring
Value to be Applied
Amarillo, TX 86,400 (1)
Joslin, IL 302,400 (3.5)
Lexington, NE 86,400 (1)
Storm Lake, IA 86,400 (1)
Any Comment
Parameter nL
Data Unit -
Description Maximum number of leaks reported in a given year
Source of Data Reports from wastewater superintendants
Value to be Applied 5
Any Comment Most conservative value chosen from all site reports
Parameter EFPropane
Data Unit mtCO2e/gallon
Description Emission factor of Propane
Source of Data U.S. EPA Guidelines
Value to be Applied 0.00574
Any Comment Calculated from carbon content and energy content of Propane
Parameter wC,Propane
Data Unit kg C / MMBtu
Description Carbon content of Propane
Source of Data U.S. EPA Guidelines
Value to be Applied 17.20
Any Comment IPCC values not available for Propane
Parameter ECPropane
Data Unit MMBtu / Barrel
Description Energy Content of Propane
Source of Data U.S. EPA Guidelines
Value to be Applied 3.824
Any Comment IPCC values not available for Propane
____________________________________________________________________________________________________________
Page 32
Parameter fP
Data Unit -
Description Uncertainty Factor for Propane Usage
Source of Data
Value to be Applied 2, for 2007 and preceding years. 1, for 2008 and forward where current
data is available.
Any Comment Used for years preceding 2007 in which actual Propane usage data is not
available
Parameter ρCH4
Data Unit lbs/ft3 (kg/cm
3)
Description Density of Methane at Ambient Conditions
Source of Data
Value to be Applied 0.0447 (6.8 x 10-7
)
Any Comment
Parameter ηFlare
Data Unit %
Description Permitted Flare Efficiency
Source of Data State Air permits for each facility
Value to be Applied
Amarillo, TX 98.0%
Joslin, IL 96.3%
Lexington, NE 98.0%
Storm Lake, IA 98.0%
Any Comment
Parameter Lf
Data Unit hp (MW)
Description Load Rating of the Centrifugal Blowers used to transport biogas to the flare
Source of Data Equipment nameplates
Value to be Applied
Amarillo, TX 125 (0.09325)
Joslin, IL 10 (0.00746)
Lexington, NE 15 (0.01119)
Storm Lake, IA 7.5 (0.00559)
Any Comment
Blowers typically operated near half load. Full load used in calculations for
conservativeness. Verifier to verify equipment configurations and power
ratings to ensure any future changes are accounted for.
____________________________________________________________________________________________________________
Page 33
Parameter Lb
Data Unit hp (MW)
Description Load Rating of the Centrifugal Blowers used to transport biogas to the boiler
Source of Data Equipment nameplates
Value to be Applied
Amarillo, TX 125 (0.09325)
Joslin, IL 75 (0.05595)
Lexington, NE 75 (0.05595)
Storm Lake, IA N/A
Any Comment
Blowers typically operated near half load. Full load used in calculations for
conservativeness. Verifier to verify equipment configurations and power
ratings to ensure any future changes are accounted for.
Parameter LH2S
Data Unit hp (MW)
Description Load Rating of the H2S Scrubbing System
Source of Data Equipment nameplates
Value to be Applied
Amarillo, TX 150 (0.1119)
Joslin, IL 127 (0.0947)
Lexington, NE 123 (0.0918)
Storm Lake, IA 140 (0.1044)
Any Comment
Equipment breakdown shown in Appendix C. Full load used in calculations
for conservativeness. Some equipment only runs very rarely, but all loads
are accounted for full time for conservativeness. Verifier to verify
equipment configurations and power ratings to ensure any future changes
are accounted for.
Parameter tH2S,m
Data Unit hours
Description Hours of operation of the H2S scrubbing system in month, m.
Source of Data Tyson Standard Operating Procedures
Value to be Applied
Amarillo, TX 730
Joslin, IL 730
Lexington, NE 730
Storm Lake, IA 730
Any Comment H2S system runs 24 hours per day, 7 days per week (728 hours per month)
at all sites.
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Parameter EFGrid
Data Unit mtCO2 / MWh
Description Grid emission factor
Source of Data CDM “Tool to calculate project emissions from electricity
consumption” Version 01.
Value to be Applied 1.3
Any Comment
Parameter TDL
Data Unit %
Description Average Transmission and Distribution Losses in the Grid
Source of Data U.S. Climate Change Technology Program
Value to be Applied 7.2%
Any Comment
7.3 Data and Parameters Monitored
Parameter
CODBL,m
CODPJ,m
CODIn,m
CODOut,m
Data Unit lbs COD / month
Description
- Monthly Chemical Oxygen Demand that would be treated in the
uncovered lagoons in the absence of the project activity
- Monthly Chemical Oxygen Demand treated in the covered lagoons
- Chemical Oxygen Demand entering the anaerobic lagoon
- Chemical Oxygen Demand leaving the anaerobic lagoon and entering
secondary and tertiary processes
Source of Data Measured
Measurement
Procedures (if any)
Concentration is measured daily at the inlet to the anaerobic lagoons and 3
times per week at the outlet of the lagoons. Flow is monitored
continuously by a totalizing magnetic flowmeter. All sampling is carried out
by on-site, state-certified laboratories adhering to recognized procedures.
Monitoring frequency Weekly
QA/QC Procedures Flowmeters are calibrated by certified third parties on a quarterly basis.
Any Comment BOD is measured and converted to COD per IPCC guidelines. Per ACM0014,
CODBL,m = CODPJ,m.
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Parameter FPJ,m
Data Unit mgal / day
Description Monthly quantity of wastewater treated in the anaerobic lagoons in the
project activity
Source of Data Measured
Measurement
Procedures (if any) Flow is monitored continuously by a totalizing magnetic flowmeter.
Monitoring frequency Continuously monitored. Data aggregated into weekly and monthly totals.
QA/QC Procedures Flowmeters are verified by certified third parties on an annual basis.
Any Comment
Parameter CODSedim,m
Data Unit lbs COD
Description Monthly quantity of Chemical Oxygen Demand accumulated as
sedimentation
Source of Data Measured
Measurement
Procedures (if any) Depth measurements from cover hatches
Monitoring frequency Annually
QA/QC Procedures
Any Comment
In over 7 years of operation, Tyson has not observed any sedimentation;
however, this will be monitored annually to verify that this remains
unchanged year over year. If any accumulation is observed, core samples
will be taken and analyzed for COD content.
Parameter HGPJ,m
Data Unit MMBtu
Description Monthly thermal energy generated with biogas from the covered
lagoons that displaces fossil fuel combustion
Source of Data Calculated based on gross volume of biogas used for heat generation, the
methane content of the gas and the NCV of methane as per equation 6-8
Measurement
Procedures (if any)
Monitoring frequency Continuously monitored. Data aggregated into weekly and monthly totals.
QA/QC Procedures Biogas flowmeters are calibrated by certified third parties on a quarterly
basis.
Any Comment
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Parameter fvCH4
Data Unit %
Description Volumetric Fraction of CH4 in Biogas
Source of Data Gas Chromatography Samples
Measurement
Procedures (if any)
Monitoring frequency
Historically, Tyson used a single third-party measured reference point.
Future monitoring periods following the issuance of this PDD will have
quarterly measurements, except at sites where online continuous monitors
are active, in which case the volumetric fraction will be monitored
continuously.
QA/QC Procedures Quarterly measurements are to be performed by certified third parties.
Any Comment
Initial third party reference data points preceding quarterly measurements
are as follows:
Amarillo, TX 73.7%
Joslin, IL 75.5%
Lexington, NE 76.6%
Storm Lake, IA 76.5%
Parameter PEME
Data Unit mtCO2e
Description Project Emissions associated with cover leakage due to major events
Source of Data Tyson standard operating procedures for lagoon inspection and repair
records
Measurement
Procedures (if any)
Monitoring frequency Monitored as major events occur.
QA/QC Procedures Records are kept in biogas logbooks.
Any Comment
Records contain the following: Description of the event including size of
tear or other feature, whether the cover maintained or lost its ability to
retain biogas, whether the gas was drawn down completely before the
event (only applicable to planned events), whether the wastewater flow
was shut off to the lagoon, and how long the repair took.
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Parameter FVRG,m , Fbiogas
Data Unit ft3
Description Monthly gross volume of biogas collected in the outlet of the covered
lagoons
Source of Data Calculated based on the sum of the biogas flared and the biogas sent to the
boilers.
Measurement
Procedures (if any)
Monitoring frequency Continuously monitored. Data aggregated into weekly and monthly totals.
QA/QC Procedures Biogas flowmeters are calibrated by certified third parties on a quarterly
basis.
Any Comment
Parameter FVRGf,m
Data Unit ft3
Description Monthly gross volume of biogas flared
Source of Data Measured
Measurement
Procedures (if any) Biogas flow is monitored continuously by an inline thermal mass flowmeter.
Monitoring frequency Continuously monitored. Data aggregated into weekly and monthly totals.
QA/QC Procedures Biogas flowmeters are calibrated by certified third parties on a quarterly
basis.
Any Comment
Parameter FVRGb,m
Data Unit ft3
Description Monthly gross volume of biogas utilized in on-site boilers
Source of Data Measured
Measurement
Procedures (if any) Biogas flow is monitored continuously by an inline thermal mass flowmeter.
Monitoring frequency Continuously monitored. Data aggregated into weekly and monthly totals.
QA/QC Procedures Biogas flowmeters are calibrated by certified third parties on a quarterly
basis.
Any Comment
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Parameter TMRGf,m
Data Unit lbs CH4
Description Monthly total mass of methane combusted in the flare
Source of Data
Calculated based on gross monthly volume of biogas flared, olumetric
fraction of methane in the biogas and the density of methane per equation
6-14.
Measurement
Procedures (if any)
Monitoring frequency Continuously monitored. Data aggregated into weekly and monthly totals.
QA/QC Procedures Biogas flowmeters are calibrated by certified third parties on a quarterly
basis.
Any Comment
Parameter ECPJ,m
Data Unit MWh
Description Monthly electricity consumed by the project activity
Source of Data Calculated based on load ratings for biogas blowers and H2S scrubbing
equipment and hours of operation for each
Measurement
Procedures (if any)
Monitoring frequency Hours of operation continuously monitored on CEMS systems
QA/QC Procedures CEMS systems self-calibrate daily and also receive annual calibration by
certified third party.
Any Comment Project activity not metered separately
Parameter tf,m
Data Unit hours
Description Monthly hours of operation of the blowers transporting biogas to the
flare
Source of Data Measured
Measurement
Procedures (if any) Measured by CEMS system
Monitoring frequency Hours of operation continuously monitored on CEMS system. Data
aggregated into weekly and monthly totals.
QA/QC Procedures CEMS systems self-calibrate daily and also receive annual calibration by
certified third party.
Any Comment
In some data sets, hours of boiler utilization (tb,m) and flare time (tf,m)
are combined. In such cases, the load rating of the boiler blowers (Lb)
is used for the entire time for conservativeness.
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Page 39
Parameter tb,m
Data Unit hours
Description Monthly hours of operation of the blowers transporting biogas to the
boilers
Source of Data Measured
Measurement
Procedures (if any) Measured by CEMS system
Monitoring frequency Hours of operation continuously monitored on CEMS system. Data
aggregated into weekly and monthly totals.
QA/QC Procedures CEMS systems self-calibrate daily and also receive annual calibration by
certified third party.
Any Comment
In some data sets, hours of boiler utilization (tb,m) and flare time (tf,m)
are combined. In such cases, the load rating of the boiler blowers (Lb)
is used for the entire time for conservativeness.
Parameter FCPropane
Data Unit Gallons
Description Annual quantity of propane used in the flares as pilot fuel
Source of Data Measured
Measurement
Procedures (if any) Purchase records by volume
Monitoring frequency Monthly
QA/QC Procedures
Any Comment Propane usage data only available for 2007 and forward. Uncertainty
factor, fP, applied to previous years for conservativeness.
7.4 Differences in Parameters
Depending on how CDM ACM0014 is applied, not all parameters listed in the
methodology are required. For example, if Step 1a (Methane Conversion Factor
Method) is used, a set of parameters would be chosen that would differ from those
selected if Step 1b (Organic Removal Ratio Method) were to be used. The latter method
has been chosen for this project, as described previously in Section 6.3.1 – Lagoon
Baseline (BECH4) Calculations. Additionally, for reasons of applicability to Tyson’s
operations, certain parameters included in CDM ACM0014 have not been included in
this methodology, and likewise, new parameters have been added where necessary. A
discussion of all such differences follows.
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7.4.1 Omitted Parameters
Parameter Justification
fd
T2,m
Tlag
Not applicable to Step 1b: Organic Removal Ratio Method.
ECBL
EGPJ,y Not applicable since the project activity does not generate electricity.
EFCH4,digest,y
PCH4,bio
Inspection procedures at Tyson warrant physical leakage calculations per
Section 6.4.1.
wCOD,dig,m
wS,y
wCOD,effl,dig,m
wCOD,effl,lag,m
Data provided by Tyson converts concentrations into mass by correlating
with wastewater flow.
EFN2O,LA,sludge
MCFla
CODPJ,effl,dig,y
CODPJ,effl,lag,y
CODsludge,LA,y
FPJ,effl,dig,m
SLA,y
WS,eff,y
wN,sludge,y
Emissions from secondary treatment processes are unaffected by the
project activity as described in Sections 3.2 and 3.5.4.
7.4.2 Additional or Altered Parameters
The only parameter added to the methodology is the conversion factor between
BOD and COD. As described in Section 6.3.1 Lagoon Baseline (BECH4) Calculations,
Tyson’s standard operating procedure samples and reports BOD concentration instead
of COD. Per IPCC recommendations, COD is calculated to be 2.4 times BOD. 19
It is also
noted that the monitoring frequency of parameter fvCH4 has been modified to represent
Tyson’s historic measurement procedures and equipment availability as described in
Section 7.3.
7.5 Monitoring Methodologies
Tyson gathers several different types of data from multiple locations throughout the
wastewater and biogas streams to ensure accurate and measurable emission
reductions. Specific locations, data types and units are identified for Project Stages 1
and 2 in Figures 7-1 and 7-2, respectively.
19
2006 IPCC Guidelines for National Greenhouse Gas Inventories, Volume 5 – Waste, Chapter 6 –
Wastewater Treatment and Discharge, Page 6.12
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Figure 7-1: Process flow diagram and data monitoring locations after completion of Stage 1
The measured values and instrumentation shown in Figure 7-1 are as follows:
1. Wastewater effluent flow into the anaerobic lagoon (Mgal/d)
2. BOD concentration at inlet to the anaerobic lagoon (mg/l)
3. Wastewater effluent flow out of the anaerobic lagoon (Mgal/d)
4. BOD concentration at outlet of the anaerobic lagoon (mg/l)
5. Biogas CH4 content (volumetric fraction)
6. Biogas flow rate to the flare (ft3/min)
WAS
WW
Processing
Facility
Anaerobic
Lagoons
Aeration
Basins/
Clarifiers
CO2
1,2 3,4
5,6
Lagoon Cover - Gas
Capture, Measurement &
Gas Scrubbing System
Flare
Legend
WAS: Waste-Activated Sludge
WW: Wastewater
Pretreatment
Plant
Pilot
Fuel
CO2,Pilot
CH4 + CO2
Receiving
Stream
Storage
Lagoon
Land
Application
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Figure 7-2: Process flow diagram and data monitoring locations after completion of Stage 2
The measured values shown in Figure 7-2 are as follows:
1. Wastewater effluent flow into the anaerobic lagoon (Mgal/d)
2. BOD concentration at inlet to the anaerobic lagoon (mg/l)
3. Wastewater effluent flow out of the anaerobic lagoon (Mgal/d)
4. BOD concentration at outlet of the anaerobic lagoon (mg/l)
5. Biogas CH4 content (volumetric fraction)
6. Biogas flow rate to the flare (ft3/min)
7. Biogas flow rate to the boiler (ft3/min)
WAS
WW
Storage
Lagoon
Processing
Facility
Anaerobic
Lagoons
Aeration
Basins/
Clarifiers
CO2
1,2 3,4
5
Lagoon Cover - Gas
Capture, Measurement &
Gas Scrubbing System
Flare
Boiler
6
7
Legend
WAS: Waste-Activated Sludge
WW: Wastewater
Pretreatment
Plant
Pilot
Fuel
CO2,Pilot
CH4 + CO2
Receiving
Stream
Land
Application
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8.0 Other Environmental Impacts
8.1 Internal Impacts
Tyson’s capture, flare and utilization of fugitive gas (methane) has no known adverse
environmental effects.
8.2 External Impacts
There are no known external impacts due to the capture, flare and utilization of fugitive
gas (methane). The water quality leaving the wastewater treatment facilities remains
the same as does the solid waste used as fertilizer.
8.3 Permanence
The project’s conversion of methane to carbon dioxide [and other byproducts] is not
reversible, therefore the reductions associated with this process are considered
permanent. As for the project’s permanence, all system components are permanently
installed and Tyson fully intends to continue operation and maintenance of the flaring
and utilization equipment.
____________________________________________________________________________________________________________
9.0 Estimated Emission Reductions
Emission reduction projections over the crediting period have been determined as
follows:
For years 2004 through 2008
reductions generated as a function of the methodology contained herein.
For years 2009 through 2013
averaged and projected by Tyson
annual projection is shown in the below calculation:
The estimated total volume of emission reductions over the life of the project is
2,788,438 mtCO2e.
The resultant estimated volumes for the project life can be viewed below in Figure
Figure 9-1: Estimated annual emission reductions over the crediting period
____________________________________________________________________________________________________________
9.0 Estimated Emission Reductions
Emission reduction projections over the crediting period have been determined as
For years 2004 through 2008, existing data was analyzed, with emission
reductions generated as a function of the methodology contained herein.
2009 through 2013, volumes from years 2005 through 2008
averaged and projected by Tyson to be flat for future operations. This average
is shown in the below calculation:
The estimated total volume of emission reductions over the life of the project is
The resultant estimated volumes for the project life can be viewed below in Figure
Estimated annual emission reductions over the crediting period
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Emission reduction projections over the crediting period have been determined as
was analyzed, with emission
reductions generated as a function of the methodology contained herein.
years 2005 through 2008 were
This average
(6-20)
The estimated total volume of emission reductions over the life of the project is
The resultant estimated volumes for the project life can be viewed below in Figure 9-1.
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10.0 References
Intergovernmental Panel on Climate Change (IPCC), 2006 IPCC Guidelines for National
Greenhouse Gas Inventories, Volume 2 – Energy, Chapter 1 – Introduction, 2006.
http://www.ipcc-nggip.iges.or.jp/public/2006gl/vol2.htm
Intergovernmental Panel on Climate Change (IPCC), 2006 IPCC Guidelines for National
Greenhouse Gas Inventories, Volume 5 – Waste, Chapter 6 – Wastewater Treatment and
Discharge, 2006.
http://www.ipcc-nggip.iges.or.jp/public/2006gl/vol5.htm
Intergovernmental Panel on Climate Change (IPCC). Revised Guidelines for National
Greenhouse Gas Inventories: Workbook, Volume 2, Module 1 – Energy, 1997.
http://www.ipcc-nggip.iges.or.jp/public/gl/guidelin/ch1wb1.pdf
Intergovernmental Panel on Climate Change (IPCC). Climate Change 1995: The Science
of Climate Change, 1996.
http://www.ipcc.ch/pub/reports.htm
United Nations Framework Convention on Climate Change (UNFCC), Clean Development
Mechanism (CDM), ACM0014 - Avoided methane emissions from wastewater treatment
– Version 01, 2008.
http://cdm.unfccc.int/UserManagement/FileStorage/CDM_ACMT8RW5N83C6BMN848I
MYMCNFJ808SC2
United Nations Framework Convention on Climate Change (UNFCC), Clean Development
Mechanism (CDM), Tool to determine project emissions from flaring gases containing
methane.
http://cdm.unfccc.int/methodologies/PAmethodologies/approved.html
United Nations Framework Convention on Climate Change (UNFCC), Clean Development
Mechanism (CDM), Tool to calculate project emissions from electricity consumption,
Version 01.
http://cdm.unfccc.int/Reference/Guidclarif/EB32_repan10_Tool_electricity_comsuption
_ver01.pdf
United Nations Framework Convention on Climate Change (UNFCC), Clean Development
Mechanism (CDM), Tool to calculate project or leakage CO2 emissions from fossil fuel
combustion, Version 01.
http://cdm.unfccc.int/Reference/Guidclarif/EB32_repan09_Tool_proj_emiss.pdf
U.S. Climate Change Technology Program, Technology Options for the Near and Long
Term, Section 1.3.2 – Transmission and Distribution Technologies, 2003.
http://www.climatetechnology.gov/library/2005/tech-options/index.htm
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Page 46
U.S. Environmental Protection Agency (EPA), Inventory of Greenhouse Gas Emissions
and Sinks: 1990 – 2005, Annex 2.1, 2007.
http://www.epa.gov/climatechange/emissions/downloads06/07CR.pdf
http://www.epa.gov/climatechange/emissions/downloads/08_Annex_2.pdf
U.S. Environmental Protection Agency (EPA), eGRID2006 Version 2.1 - eGRID Subregion
Emissions, 2004 Data.
http://www.epa.gov/cleanenergy/egrid/index.htm
U.S. Environmental Protection Agency (EPA), Wastewater Technology Fact Sheet-
Anaerobic Lagoons, 2003.
http://www.epa.gov/owm/mtb/mtbfact.htm
U.S. Environmental Protection Agency (EPA), AP 42, Volume I, Fifth Edition, Chapter 2.4,
1998.
http://www.epa.gov/ttn/chief/ap42/ch02/final/c02s04.pdf
The Voluntary Carbon Standard, The Voluntary Carbon Standard 2007, 2007.
http://www.v-c-s.org/docs/VCS%202007.pdf
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Page 47
Appendix A
Study of Pre-Project BOD Removal Rates
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Page 49
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Page 50
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Page 51
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Page 52
Appendix B
Biogas Flaring Vs. Utilization Ratios
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Page 53
Flared (ft3) Utilized (ft3) Ratio Flared Ratio Utilized
Lexington, NE 78,746,781 90,764,849 46% 54%
Amarillo, TX 89,251,344 280,159,186 24% 76%
Joslin, IL 37,298,020 129,639,053 22% 78%
Flared (ft3) Utilized (ft3) Ratio Flared Ratio Utilized Sites
2004 36,319,598 108,792,987 25% 75% Joslin Only (start date)
2005 111,464,206 277,699,981 29% 71% All sites subsequent to start date
2006 181,430,703 583,111,411 24% 76% All sites
2007 246,220,437 594,745,782 29% 71% All sites
2008 238,496,077 730,326,659 25% 75% All sites
1st Year of Utilization
Flaring vs Utilzation Ratios
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Page 54
Appendix C
H2S Scrubbing Equipment List and Power
Ratings by Facility
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Page 55
H2S Scrubbing System Electricity Loads
Amarillo H2S Scrubbing System Components
Load Rating
(hp)
# of Units in
Operation
Press Wash Pump 7.5 1
Scrubber Feed Pump 15 1
Air Blower 25 2
Regen Feed Pump 15 1
Air Compressor 20 1
Condensate Pump 3 1
Larox press 20 1
Water pump on Larox 7.5 1
Outside sump 7.5 1
Roof exhaust 1.5 1
Air handling Unit 3 1
Total hp 150
Joslin H2S Scrubbing System Components
Load Rating
(hp)
# of Units in
Operation
Regen feed pump 10 1
Filter Feed pump 15 1
Scrubber feed pump 10 1
Air Compressor 20 1
Make-up air unit 1.5 2
Blower room ex fan 0.75 1
Regenerated air blower 30 1
Electric Unit heaters 0.25 6
Water booster pump 7.5 1
Larox press Hyd pump 20 1
Larox press H2O pump 5 1
Roof exhaust 1.5 1
Air handling Unit 3 1
Total hp 127
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Lexington H2S Scrubbing System Components
Load Rating
(hp)
# of Units in
Operation
Scrubber Feed Pump 15 1
Reactor Feed Pump 15 1
PD Aeration Blower 30 2
Air Compressor 20 1
Water pump 7.5 1
Roof exhaust 1.5 1
Air handling Unit 3 1
Fuelgas Chiller Refrigeration Unit 1 1
Total hp 123
Storm Lake H2S Scrubbing System Components
Load Rating
(hp)
# of Units in
Operation
Bio-Gas blowers 7 1/2 1
Reactor feed pumps 15 1
scrubber feed pumps 15 1
condensate pumps 0.25 2
PD blowers 20 1
air compressor 20 1
recycle pumps 15 1
filtrate pumps 10 1
Pressure pumps 7.5 1
press( bio-gas larox) 20 1
press( bio-gas larox) 5 1
Roof exhaust 1.5 1
Air handling Unit 3 1
Total hp 140