芝加哥气候交易所资料
Chicago Climate Exchange?Agricultural Methane Collection and Combustion Offset Project Protocol
C HICAGO C LIMATE E XCHANGE O FFSET P ROJECT P ROTOCOL
Agricultural Methane Collection & Combustion
Updated as of 9/30/2009
Table of Contents
Acronyms, Terms and Definitions (4)
1.Introduction (5)
2.General Provisions (5)
3.Associated Documents (6)
4.Project Definition (6)
5.Eligibility Criteria (6)
5.1CCX Membership (6)
5.2Eligibility Governing Entities with Minor Emissions (6)
5.3Ownership and Control (7)
5.4Project Start Date (7)
5.5Project Location (7)
5.6Performance Benchmark (7)
5.6.1Regulatory Criteria (8)
5.6.2Common Practice Criteria (8)
Table 1: Anaerobic Digesters at Dairy and Swine Farms (8)
6.Project Boundary (9)
6.1Identification of GHG Sources, Sinks and Reservoirs (9)
Table 2: Relevant GHG Sources to be Included within the Project’s Boundary (9)
6.1.1Controlled GHG Sources and Sinks (10)
6.1.2Related GHG Sources and Sinks (10)
6.1.3Affected GHG Sources and Sinks (10)
6.2Determining the Baseline Scenario (10)
6.3Project Emissions (11)
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7.1Flow Monitoring (12)
7.1.1Flow Meter Performance Standard (12)
7.1.2Flow Meter Calibration (13)
7.1.3Flow Meter Location (13)
7.2Methane Content Analysis (13)
7.2.1Gas Analyzer Performance Standard (13)
7.2.2Gas Analyzer Calibration (14)
7.3Electricity Production (14)
7.4Destruction Device Operating Hours (14)
7.5Destruction Device Efficiency (15)
7.6Project-Related Emissions (15)
8.Quantifying GHG Emission Reductions (15)
8.1Calculations for Metered Methane Destruction (15)
Equation 1a: CH4 Recovered (16)
Equation 1b: Alternative CH4 Recovery Method (16)
Equation 2: CH4 Combusted (17)
8.2Calculation of Project Emissions (17)
Equation 3a: CO2 Emissions from Fossil Fuel Combustion (17)
Equation 3b: CO2 emissions from Project specific electricity consumption (18)
8.3Calculation of Project Emission Reductions (18)
Equation 4: Measured GHG Emission Reductions (18)
8.4Ex Ante Calculation for Methane Destruction Comparison (18)
8.4.1Emission Factors (18)
8.4.2Solids Separation Correction Factor (18)
8.4.3Ex-ante Calculation (19)
Equation 5: Modeled CH4 Emissions from Baseline Manure Management System (20)
Equation 6: Modeled GHG Emission Reductions (20)
9.Reporting and Recordkeeping Requirements (20)
10.Validation and Verification Requirements (21)
10.1Validation (21)
10.2Verification (21)
Appendix A: Verification Checklist (22)
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Equation 7: Emission Factor for Specific Baseline Scenario (26)
Table 3 – Methane Emission Factors (EF(T,S,St)) for Liquid/Slurry & Pit Storage Baseline Manure Management Systems (S) by Livestock Category (T) and State (St); (kg CH4 /head/day) (27)
Table 4 – Methane Emission Factors (EF(T,S,St)) for Anaerobic Lagoon Baseline Manure Management Systems (S) by Livestock Category (T) and State (St); (kg CH4/ head/day).. 28 Appendix C: Emission Factor Variables (29)
Table 5 – Livestock Categories and Waste Characteristics Included in Baseline Methane Emission Calculations and Emission Factor Derivation (29)
Table 6 – Volatile Solids Production Rates (VS(T,St)) by Livestock Category (T) and State (St) Used for Derivation of Methane Emission Factors (EF(T,S,St)); (kg VS/day/1,000 kg animal mass) (30)
Table 7 –Methane Conversion Factors (MCF(S,St)) by Baseline Manure Management System (S) and State (St)Used for Derivation of Methane Emission Factors (EF(T,S,St)); (percent) (31)
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A CRONYMS , T ERMS AND D EFINITIONS 1
ANSI American National Standards Institute CCX Chicago Climate Exchange EPA Environmental Protection Agency GCCS Gas Collection and Control System GHG Greenhouse Gas
IPCC Intergovernmental Panel on Climate Change USDA United States Department of Agriculture
WBCSD World Business Council on Sustainable Development WRI World Resources Institute
Agricultural Methane: Methane produced and emitted during the anaerobic decomposition of organic material in livestock manure.
Anaerobic Lagoons:
A waste management system found in various agricultural applications that is designed and operated to combine waste stabilization and storage. Anaerobic lagoons create an environment necessary for anaerobic digestion (breakdown of organic matter by microorganisms in the absence of oxygen). Anaerobic lagoons result in the creation of biogas.
Biogas:
A mixture of gas, primarily made up of methane, produced by the anaerobic breakdown of organic matter. Gas Collection and Control System (GCCS):
A network of wells and/or piping to create a pathway for gas migration towards a combustion or non-combustion technology to mitigate emissions, pollutants and/or odor. Liquid/Slurry: A manure management system where manure is stored as excreted or
with some minimal addition of water to facilitate handling and is stored in either tanks or earthen ponds, usually for periods of less than one year. Pit Storage Below Animal Confinement:
Collection and storage of manure usually with little or no added water typically below a slatted floor in an enclosed animal confinement facility. Typical storage periods range from 5 to 12 months, but must exceed one month.
Solid
Separation:
Removal of water from manure, resulting in a liquid and manure solids.
1 Please refer to CCX General Offsets Program Provisions for additional “Acronyms, Terms and Definitions”
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1. I NTRODUCTION
Chicago Climate Exchange (CCX) is the world’s first and North America’s only active voluntary, legally binding integrated trading system to reduce emissions of all six major greenhouse gases (GHGs), with Offset Projects worldwide. CCX Members with significant GHG emissions voluntarily enter into a legally binding agreement to reach CCX GHG Emission Reduction Commitment 2. Upon enrollment with CCX, Exchange Allowances are issued to Members in amounts equal to their emission reduction targets. CCX Exchange Offsets are issued to Owners or Aggregators of registered Projects on the basis of verified sequestration, destruction or reduction of GHG emissions not included under the CCX Emission Reduction Commitment. Members are required to turn in the amount of Exchange Allowances and/or Exchange Offsets equal their actual GHG emissions annually.
CCX strives to promote transparency and integrity in the carbon market. In accordance with this goal, in developing this document, CCX was guided by the fundamental principles of Project GHG accounting outlined in ISO 14064-2: Specification with guidance at the Project level for quantification, monitoring and reporting of greenhouse gas emission reductions or removal enhanceme
nts, Version 1. These principles include:
Relevance
Completeness
Consistency
Accuracy
Transparency
Conservativeness
The following sections of this Protocol discuss the Project criteria, boundaries, monitoring requirements, emissions reduction calculations and other guidelines that each Project Proponent must adhere to in order to generate Exchange Offsets from agricultural methane collection and combustion Projects.
2. G ENERAL P ROVISIONS
Offset Project eligibility is subject to the CCX General Offset Program Provisions and CCX Offset Project Protocol for Agricultural Methane Collection and Combustion Offset Projects, and the determinations of the CCX Committee on Offsets. Project Proponents should review CCX General Offset Program Provisions and CCX Offset Project Protocol for Agricultural Methane Collection and Combustion Offset Projects.
2 https://www.wendangku.net/doc/df4995050.html,/content.jsf?id=72
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3. A SSOCIATED D OCUMENTS
This Protocol references the use of several associated documents. These documents include:
CCX General Offset Program Provisions
CCX General Verification Guidance Document
CCX Project Implementation Document
CCX Project Specific Conflict of Interest Form
CCX Greenhouse Gas Emission Factors Document
CCX Project Owner Attestation
These documents are available on the Offsets section of the CCX website: https://www.wendangku.net/doc/df4995050.html,
4. P ROJECT D EFINITION
An Agricultural Methane Collection and Combustion Offset Project consists of the installation and operation of a new agricultural methane gas collection 3 and control system (GCCS) that meets the eligibility criteria and other requirements outlined in these guidelines.
5. E LIGIBILITY C RITERIA
Several factors determine a Project’s eligibility for generating Exchange Offsets including Proponent’s membership status, ownership status, Project start date, location and whether the Project meets the CCX performance benchmark. Project Proponents should submit the CCX Project Information Document (PID) to CCX for review and determination of eligibility.
5.1 CCX Membership
The Project Proponent must be a Member or Participant Member (Offset Provider or Aggregator) of CCX. Project Proponents should contact CCX directly for membership rules and information.
5.2 Eligibility Governing Entities with Minor Emissions
Entities with an entity-wide emissions profile greater than 10,000 metric tons CO 2 equivalent for the most recent calendar year may register and trade CCX Exchange Offsets only if the entity is a Member of CCX and undertakes the CCX Emission Reduction Commitment. For specific guidance on this provision, Project Proponents should review CCX General Offset Program Provisions.
3 Agricultural methane collection systems include various anaerobic digester systems such as complete mix, plug
flow, and covered lagoons.
Entities who are unsure of their emissions profile should estimate their direct CO2 emission using well accepted methodologies such as those available at the World Resources Institute (WRI)/World Business Council on Sustainable Development (WBCSD). CCX requires that all entities that are not Members, including producers enrolled with Aggregators, provide an attestation relating to their direct emissions in a form provided by CCX.
Project Emissions shall be calculated in accordance with the CCX Project Emissions Guidance Document. Fossil fuel emissions factors are available at https://www.wendangku.net/doc/df4995050.html,/docs/misc/GHG_Emission_Factors.pdf.
For specific guidance on this provision, Project Proponents should review the CCX General Offset Program Provisions.
5.3Ownership and Control
The Project Owner must demonstrate clear ownership of the GHG mitigation rights associated with the Project in order to register the Offsets with CCX.
CCX Offset Aggregators must have acquired appropriate control of the GHG mitigation rights from the Project Owner in order to execute its responsibilities on CCX pursuant to CCX General Offset Program Provisions. Aggregators must demonstrate to the Project CCX-Approved Verifier contracted to perform verification services for the Project and to CCX that they have acquired appropriate control for trading of Exchange Offsets associated with the Project activity. This may be demonstrated through a mandate from the Project Owner providing the Aggregator the rights to register and trade Exchange Offsets on behalf of the Project Owner.
5.4Project Start Date
Projects must start on or after January 1, 2003, which corresponds with the beginning of the CCX cap and trade program.
5.5Project Location
Agricultural methane Projects shall be located either in the United States or in a country designated as a non-Annex I country under the Kyoto Protocol.
5.6Performance Benchmark
Agricultural methane Projects are not eligible to generate Exchange Offsets in instances where the collection and destruction of agricultural methane gas can be considered a standard business practice (i.e. business as usual) or is required by law or other legally binding framework. CCX has identified two performance criteria that Projects must meet to be considered for Exchange Offset issuance.
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5.6.1 Regulatory Criteria
In order to be eligible to receive Exchange Offsets under these guidelines, the Project shall not be required to collect and destroy agricultural methane gas under any federal, state or local regulations or other legally binding framework. The regulatory criteria must be applied to both U.S. and non-U.S.-based Projects (approved Projects originating in non-Annex I Kyoto Protocol countries).
During the course of verification, the Project Proponent shall provide to the Verifier reasonable assurances necessary to demonstrate that the Project is not required under any federal, state or local regulation or other legally binding framework and shall sign an attestation stating that the Project is not required under any federal, state, or local regulation or other legally binding framework.
5.6.2 Common Practice Criteria
According to the GHG Protocol for Project Accounting, “Common practice refers to the predominant technologies or practices in a given market, as determined by the degree to which those technologies or practices have penetrated the market (defined by a specified geographic area).”4 CCX reviewed information regarding the prevalence of anaerobic digesters at dairy and swine farms in the United States. The United States Environmental Protection Agency (US EPA) AgStar Program gathers information on farms in the US and their manure management systems. Based on EPA AgStar and US Department of Agriculture (USDA) data, only 0.06% of dairy and swine farms in the United States have anaerobic digesters currently in operation. This information is summarized in the table below.
Given the common practice definition above, installation of anaerobic digesters at
unregulated farms in the United States is clearly not common practice. Therefore, a Project that meets the regulatory criteria above and installs an anaerobic digester or similar GCCS can be considered beyond business as usual. For Projects in non-Annex 1 countries under the Kyoto Protocol, the Project Proponent must similarly demonstrate that the Project activity is
4 World Resources Institute and World Business Council for Sustainable Development. 2005. The Greenhouse Gas
Protocol for Project Accounting. WRI/WBCSD, Washington, D.C. 5 USDA, 2002, Census of Agriculture
6 EPA AgStar Program. Guide to Anaerobic Digesters. December 2008. Accessed online at https://www.wendangku.net/doc/df4995050.html,/agstar/operational.html on January 9, 2009.
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beyond business as usual. CCX will periodically review this data to assess whether the performance benchmark has changed and may implement modifications in the future based on the review. Once a Project is registered with CCX, it is not affected by changes to the common practice criteria for the market period in which it registers. The current market period is from January 1, 2003 through December 31, 2010.
6. P ROJECT B OUNDARY
A clearly defined boundary is vital to accurately assessing emission reductions due to the installation of a GCCS. Although the destruction method may vary, the Project Boundary for agricultural methane Projects will include the agricultural methane collection system, equipment used for upgrading the collected gas, monitoring and recording equipment and destruction device(s).
6.1 Identification of GHG Sources, Sinks and Reservoirs
The following table identifies relevant GHG Sources and whether each is to be included within the Project’s Boundary.
7 Based on emissions factors found in Volume 2, Table 2.2 of the 2006 IPCC Guidelines for National Greenhouse Gas
Inventories, all CH 4 and N 2O emissions are excluded (with the exception of CH 4 emissions from agricultural methane gas destruction), as emissions will be small in comparison to CO 2 emissions.
8 See Project Emissions discussion in this section for exceptions of the inclusion of indirect emission sources.
The GHG Sink(s) will be the combustion process and associated destruction device(s) used by the Project. No Reservoirs are anticipated in agricultural methane Projects and therefore are not discussed at greater length below.
ISO 14064-2 requires that the Project’s GHG Sources and Sinks be categorized as controlled by the Project Proponent, related to the Project, or affected by the Project. These are discussed below.
6.1.1Controlled GHG Sources and Sinks
Controlled GHG Sources and Sinks for agricultural methane Projects are those that occur on-site. Therefore, Controlled GHG Sources and Sinks for agricultural methane Projects refer to those that are part of the agricultural methane collection and upgrading systems and the agricultural methane destruction device.
6.1.2Related GHG Sources and Sinks
Related GHG Sources and Sinks for agricultural methane Projects refer to those that have material or energy flows into or out of the Project. Therefore, Related GHG Sources and Sinks are the electricity grid that supplies electricity to the Project (if applicable) and the natural gas pipeline that conveys upgraded agricultural methane gas to an end user’s destruction device (if applicable).
6.1.3Affected GHG Sources and Sinks
Affected GHG Sources and Sinks are those that are influenced by the agricultural methane Project and result in new or changed activities outside the Project Boundary that actually increase GHG emissions. This concept is commonly referred to as leakage. CCX does not expect agricultural methane Projects to result in new or changed activities that increase GHG emissions outside of the Project Boundary and, therefore, no Project specific leakage assessment is required.
6.2Determining the Baseline Scenario
In accordance with the process outlined in ISO 14064-Part 2, possible baseline scenarios were evaluated for agricultural methane Projects. CCX identified two plausible baselines for new agricultural methane Projects:
1.The unmitigated release of methane to the atmosphere.
2.The voluntary installation of a GCCS without the generation of revenue from Offsets.
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Based on the information presented in Section 5, the most likely baseline scenario in the absence of regulation or other requirement mandating installation is the unmitigated release of methane to the atmosphere.
The unmitigated release of methane to the atmosphere results from manure management practices (as defined in the Intergovernmental Panel on Climate Change (IPCC) 2000 Good Practice Guidance document, the IPCC 2006 Guidelines, and as further clarified below) where manure is handled as a liquid and with significant methane emitting potential.
Therefore, Projects must have one of the following baseline manure management practices:
Liquid Slurry;
Pit storage below animal confinement; or
Anaerobic lagoon.
Manure management systems that utilize flush technologies to handle manure, or that combine scraped (or vacuumed) manure with more than minimal quantities of water in storage (for example, by mixing dairy parlor waste water with manure for handling or storage), and that have liquid manure storage systems with hydraulic retention times of greater than 90 days, may be categorized as “anaerobic lagoon” systems for baseline determination.
Eligible Projects with baseline manure management systems other than those listed above may include only that portion of the manure handled by eligible systems in any baseline emission and Exchange Offset calculation.
The GHG Sources, Sinks and Reservoirs identified in this baseline are limited to the GHG emissions from the pre-Project manure management system. For Projects developed on recently established farms, baseline manure management systems should represent the prevailing regional manure management systems for similar farm types.
6.3 Project Emissions
In cases where Project emissions are not included in a legally binding emission reduction program (such as an electric utility cap and trade scheme), they shall be included as Project emissions and subtracted from Project emission reductions as provided in section 8 below. Where Project emissions are included within a legally binding emissions reduction program, they may be omitted from the Project emissions calculation. Only those specific sources included under the capped portion of an emissions reduction program may be omitted. All other sources must be included.
Project emissions sources include, but are not limited to, the use of electricity from the grid, the consumption of purchased steam or heat, and the combustion of fossil fuel by the collection equipment or destruction device. Emissions associated with the preparation of agricultural methane gas for injection to a natural gas pipeline are included within the Project Boundary and shall be counted as a Project emissions source. Since carbon dioxide emissions from these sources are of much greater magnitude than emissions of other GHGs, only carbon dioxide emissions shall be included as Project emissions.
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7. M ONITORING R EQUIREMENTS
The Project Proponent shall develop and maintain a monitoring plan with procedures for obtaining, recording, compiling and analyzing data and information required for quantifying and reporting GHG emission reductions.
Agricultural methane Project monitoring includes the following parameters:
Daily totals of continuous biogas flow with monthly temperature and pressure monitoring to each combustion device.9
Methane content analysis using a continuous gas analyzer or a portable gas analyzer, or gas sampling for independent laboratory analysis according to ASTM D-1946 or
other appropriate standard.
Electricity production (if applicable).
Destruction device operating hours.
Project-related emissions.
Section 8 presents two alternatives for calculating the GHG emission reductions for an agricultural methane Project. In the first alternative, biogas flow and methane content data are used while in the second, electricity production data is used to calculate the amount of methane destroyed.10 Monitoring data shall be maintained to support the calculation to be used by the Project.
7.1 Flow Monitoring
Biogas flow shall be continuously read by an acceptable flow meter and should be tabulated daily. The flow meter shall be installed along the header pipe at a location that provides a straight section of pipe sufficient to establish laminar gas flow.
7.1.1 Flow Meter Performance Standard
The following information regarding flow meter performance shall be maintained:
Manufacturer specifications of flow meter accuracy should be +/- 5% of reading.
Proof of initial calibration.
Capability to read flow every 15 minutes. Means to correct for temperature and pressure.
9 Separate monitoring of temperature and pressure is not required when using flow meters that standardize based
on temperature and pressure and present flow rate in standard cubic feet per minute (SCFM).
10 This methodology is employed by the USEPA in the Inventory of U.S. Greenhouse Gas Emissions and Sinks (1990-2007) to estimate methane emissions avoided through landfill gas-to-energy Projects.
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It is essential that flow meters operate properly in order to accurately quantify GHG emission reductions. To ensure proper flow meter function, annual calibration of the flow meter shall be performed unless otherwise specified by the manufacturer. Flow meter
calibrations must meet the following conditions:
Calibrations must be performed in accordance with manufacturer’s specifications and
methodologies.
Calibrations must be performed by the manufacturer, an ISO 17025 certified
calibration and testing organization, or other appropriately trained personnel.
All records of calibration reports and methodologies must be documented and made available for review during the verification process.
If manufacturer specifications state that the flow meter must be calibrated more often than annually, then the calibration schedule as recommended by the manufacturer shall be followed and the above conditions applied.
7.1.3 Flow Meter Location
The flow meter shall be installed at a location that provides a straight section of pipe sufficient to establish laminar gas flow as turbulent flow resulting from bends, obstructions, or constrictions in the pipe can cause interference with flow measurements that rely on differential pressure. Alternatively, a flow meter may be installed where there is not laminar flow, provided the technology is proven to be accurate under such conditions and the location of the installation has been specifically approved by a professional engineer to provide accurate flow meter readings. Flow meters shall be located such that the quantity of agricultural methane gas being consumed by each destruction device can be continuously and accurately measured.
7.2 Methane Content Analysis
Methane content measurements shall be taken and recorded on at least a quarterly basis using a portable gas analyzer or by laboratory analysis of sampled gas.
7.2.1 Gas Analyzer Performance Standard
The gas analyzer used shall meet the following performance standards:
Precision: Methane measurements are to be to the nearest 0.1 percent.
Accuracy: Methane measurement accuracy decreases with increasing methane concentration but should be within +/- 10% of reading, as specified by the manufacturer.
Alternate instruments, including gas chromatographs or thermal conductivity detectors shall meet similar standards.
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Continuous gas analyzers shall be calibrated according to manufacturer specifications. Records of these calibrations shall be maintained.
For quarterly measurements, portable gas analyzers shall be calibrated against a gas sample with a known methane concentration prior to each use. Records of these calibrations shall be maintained according to the Project’s monitoring plan and shall be conducted by appropriately trained personnel.
7.3 Electricity Production
Where an engine is serving as a destruction device, the following information shall be
maintained regarding the measurement of methane combustion:
Type, make, and model number of combustion unit(s).
Number of combustion units that exclusively use agricultural methane gas as fuel.
Copy of the summary table from the most recent source test (source test shall be taken within 3 years of enrollment in the CCX Offsets Program) showing the
measured heat rate of combustion device(s).
Summary tables showing kWh of electricity produced from biogas per month over the
relevant period.
Type of electrical metering device.
Accuracy, precision, and proof of calibration of the electrical metering device per manufacturer specifications (this parameter is only required if the purchasing utility’s sales meter is not used as these meters must already meet stringent requirements).
7.4 Destruction Device Operating Hours
The operating hours of each destruction device must be monitored to ensure that methane destruction is claimed for methane used only during periods when the destruction device(s) was operational. Operating hours must be continuously monitored and recorded. In general, operating hours for a flare are tracked through the use of a thermocouple which monitors the presence and temperature of the flame. Operating hours for other destruction devices such as engines should be tracked through operator logs.
Projects shall provide evidence of alarms, valves or other methods (a GCCS often incorporates one or more of these methods so that the system can be shut down when it is not functioning properly) that ensure that the destruction device does not simply vent agricultural methane gas to the atmosphere. Projects that treat agricultural methane gas and inject it into a natural gas pipeline shall only provide evidence of the quantity of gas delivered to the pipeline and are not required to provide evidence of agricultural methane gas destruction.
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Exchange Offsets will not be issued for time periods where the destruction device(s) is not operating.
7.5 Destruction Device Efficiency
CCX reviewed available literature on destruction efficiency values from a variety of sources. Based on this review, CCX determined that 98% default destruction efficiency is conservative and shall be applied where Project Proponents have not conducted source tests or do not have manufacturer data. In situations where a source test has been conducted, the destruction efficiency value obtained during this source test shall be utilized rather than the default destruction efficiency value provided herein.11
7.6 Project-Related Emissions
Project-related emissions may result from the importation of electricity or from the use of fossil fuels. Information related to electricity usage and relevant fossil fuel consumption may be obtained from sources such as on-site electricity meters, utility invoices, and fuel purchase records. Project emissions may be omitted if the source is included in a legally binding emission reduction program for the period in question.
8. Q UANTIFYING GHG E MISSION R EDUCTIONS
Emission reductions are assumed to be the amount of methane that would be emitted during the crediting period in the absence of the agricultural methane Project (minus Project emissions). For each year during the crediting period, Project Proponents shall compare the actual metered methane destruction values and ex-ante modeled estimates of methane destruction. Project Proponents shall claim emission reductions only for the lesser of the two values.
8.1 Calculations for Metered Methane Destruction
Tabulated records of total daily agricultural methane gas flows (in standard cubic feet per day) shall be matched with either the continuous methane content data or with the associated periodic reading to methane recovery rates, using Equation 1:
11 Seebold et al. (2003) Reaction Efficiency of Industrial Flares: The Perspective of the Past.
11The Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories gives a standard value for the
fraction of carbon oxidized for gas combustion of 99.5% (Reference Manual, Table 1.6, page 1.29). It also gives a value for emissions from processing, transmission and distribution of gas which would be a very conservative
estimate for losses in the pipeline and for leakage at the end user (Reference Manual, Table 1.58, page 1.121). These emissions are given as 118,000kgCH4/PJ on the basis of gas consumption, which is 0.6%. Leakage in the residential and commercial sectors is stated to be 0 to 87,000kgCH4/PJ, which equates to 0.4%, and in industrial plants and power station the losses are 0 to 175,000kg/CH4/PJ, which is 0.8%. These leakage estimates are compounded and multiplied. The methane destruction efficiency for landfill gas injected into the natural gas transmission and
distribution system can now be calculated as the product of these three efficiency factors, giving a total efficiency of (99.5% * 99.4% * 99.6%) 98.5% for residential and commercial sector users, and (99.5% * 99.4% * 99.2%) 98.1% for industrial plants and power stations.
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Equation 1a: CH 4 Recovered
CH 4recovered = BG recovered x %CH 4
Where:
readings for flow and the appropriate methane content readings.
Equation 1b: Alternative CH4 Recovery Method
Energy generation facilities that use agricultural methane as a fuel to generate electricity typically have detailed records of electrical generation rates in kilowatt-hours (kWhr) that can be used to calculate methane recovery. Information on the heat rate of the combustion unit in Btu per kilowatt hour (Btu/kWhr) can be used to calculate amount of methane combusted. The calculation is summarized in Equation 3:
CH 4recovered =
(kWhr x [Btu/kWhr]) / 1012
Where:
generated over a one-year period in the equation above. The heat rate used in the calculation shall be from the most recent source test for the combustion device or the manufacturer specified heat rate.13
12 Where the engine heat rate is specified in lower heating value, the Project Proponent shall make the appropriate
adjustment.
13 Source test, if used, shall be taken within 3 years of enrollment in the CCX Offsets program.
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Equation 2: CH 4 Combusted
In order to estimate the amount of methane combusted in metric tons per year (Mg/yr), the annual methane recovery rate in cubic feet per year needs to be converted to weight using Equation 2:
CH 4combusted =
(CH 4recovered x 16.04 x [1/106 ] * [1/24.04] x 28.32) * DE
Where:
8.2 Calculation of Project Emissions
Depending on Project-specific circumstances, certain emissions sources may need to be subtracted from total Project emission reductions using the equations below.
Equation 3a: CO 2 Emissions from Fossil Fuel Combustion
Dest CO2 = ∑y (FF y *EF y )
Where:
14 The appropriate adjustment factor should be applied if the Project flow meter(s) apply a different standard
temperature and/or pressure.
15 Relevant GHG emission factors can be found here: https://www.wendangku.net/doc/df4995050.html,/docs/misc/GHG_Emission_Factors.pdf
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Equation 3b: CO 2 emissions from Project specific electricity consumption
Elec CO2 =
(EL total * EF EL )/2204.62
Where:
8.3
Calculation of Project Emission Reductions
Equation 4: Measured GHG Emission Reductions
ER=
(CH 4combusted * 21) – PE
Where: 8.4 Ex Ante Calculation for Methane Destruction Comparison
CCX requires that all Projects compare the actual metered amount of methane that is destroyed in the biogas control system with modeled methane emission reductions for each year during the crediting period. The lesser of the two values will be used for determining emission reductions.
8.4.1 Emission Factors
State-specific methane emission factors (EF(T,S,St)) for each livestock category (T) and baseline manure management system (S) included in this method are listed in Appendix B, Tables 3 and 4.
8.4.2 Solids Separation Correction Factor
For baseline liquid slurry storage or anaerobic lagoon manure management systems that separate manure solids prior to the input of liquid manure, a default solids separation correction factor (SSCF) of 0.8 must be used to calculate baseline emissions. Project specific
correction factors may be used if supported by manufacturer’s specifications or oth er acceptable data. For those systems that do not separate solids, or that utilize simple gravity separation of sand and other non-manure solids, the SSCF is equal to 1.
For Projects which did not use solids separation in the baseline case, but subsequently utilize solids separation prior to the input of liquid manure to the digester, the separated solids must be handled in a manner that ensures negligible production of methane (e.g., aerobic composting, use as animal bedding, or daily spread), otherwise, the appropriate solids separation correction factor must be used to calculate baseline emissions.
8.4.3Ex-ante Calculation
The following procedure for ex-ante calculation of baseline methane emissions from manure digester Projects in the U.S. follows the IPCC Tier 2 approach and emission factors used in the most recent U.S. Greenhouse Gas Inventory Report. Projects located in non-Annex I countries must use country appropriate factors.
The procedure includes the following general steps for each reporting period (annual reporting is recommended to account for seasonal variability in animal populations and baseline emissions):
1.Characterize the average livestock populations included in the anaerobic digester
Project for the reporting period;
2.Characterize the baseline manure management system(s) for the Project;
3.For each livestock population category and baseline manure management system,
multiply the number of animals by the appropriate emission factor for that state (from Tables 3 and 4), by the appropriate solids separation correction factor, by the proportion of manure from those animals used in the digester, by the number of days in the period (Equation 5);
4.Sum the estimates for all population categories and baseline manure management
systems (Equation 5);
5.Multiply the total estimate of methane emissions by the appropriate methane GWP
for the reporting period and subtract metered Project emissions if appropriate (Equation 6).
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