Emission Reduction Protocol for Methane Capture, Flare …€¦ · Emission Reduction Protocol for Methane Capture, Flare and Utilization at Tyson Wastewater Treatment Facilities

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


3.5.4 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


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



Flare

Boiler

Processing

Facility

Anaerobic

Lagoons

Aeration

Basins/

Clarifiers

Storage

Lagoon

Receiving

Stream

Land

Application

Pilot

Fuel

CO2,Pilot

Pretreatment

Plant

Legend


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.


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.


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.


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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


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


�� ,� 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)


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


Value to be Applied 0.05919

Any Comment

Parameter NCVCH4

Data Unit Btu/ft3

Description Net Caloric Value of Methane



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



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


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


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


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


Any Comment Calculated from carbon content and energy content of Propane

Parameter wC,Propane

Data Unit kg C / MMBtu

Description Carbon content of Propane



Any Comment IPCC values not available for Propane

Parameter ECPropane

Data Unit MMBtu / Barrel

Description Energy Content of Propane



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


Value to be Applied

Amarillo, TX 125 (0.09325)

Joslin, IL 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


Value to be Applied

Amarillo, TX 150 (0.1119)

Joslin, IL 127 (0.0947)


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.

____________________________________________________________________________________________________________

Page 34

Parameter EFGrid

Data Unit mtCO2 / MWh

Description Grid emission factor

Source of Data CDM “Tool to calculate project emissions from electricity

consumption” Version 01.


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


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


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)


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)



basis.

Any Comment

Parameter FVRGf,m

Data Unit ft3

Description Monthly gross volume of biogas flared


Measurement

Procedures (if any) Biogas flow is monitored continuously by an inline thermal mass flowmeter.



basis.

Any Comment

Parameter FVRGb,m

Data Unit ft3

Description Monthly gross volume of biogas utilized in on-site boilers


Measurement

Procedures (if any) Biogas flow is monitored continuously by an inline thermal mass flowmeter.



basis.

Any Comment

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Page 38

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)



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


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.



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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Parameter tb,m

Data Unit hours

Description Monthly hours of operation of the blowers transporting biogas to the

boilers


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.



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


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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Page 40

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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Page 41

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



Flare

Legend


WW: Wastewater

Pretreatment

Plant

Pilot

Fuel

CO2,Pilot

CH4 + CO2

Receiving

Stream

Storage

Lagoon

Land

Application

____________________________________________________________________________________________________________

Page 42

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



Flare

Boiler

6

7

Legend


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.

____________________________________________________________________________________________________________


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

____________________________________________________________________________________________________________



For years 2004 through 2008, existing data was analyzed, with emission


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 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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Page 44


was analyzed, with emission


years 2005 through 2008 were

This average

(6-20)


The resultant estimated volumes for the project life can be viewed below in Figure 9-1.

____________________________________________________________________________________________________________

Page 45

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


Mechanism (CDM), Tool to determine project emissions from flaring gases containing

methane.

http://cdm.unfccc.int/methodologies/PAmethodologies/approved.html


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


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

____________________________________________________________________________________________________________

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

____________________________________________________________________________________________________________

Page 47

Appendix A

Study of Pre-Project BOD Removal Rates

____________________________________________________________________________________________________________

Page 48

____________________________________________________________________________________________________________

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

____________________________________________________________________________________________________________

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


Total hp 127

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Page 56

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


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


Total hp 140

Emission Reduction Protocol for Methane Capture, Flare …€¦ · Emission Reduction Protocol for Methane Capture, Flare and Utilization at Tyson Wastewater Treatment Facilities

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