One Tonne - Carbon Credit Markets

PROJECTS


HOW THEY ARE STARTED
PROJECTS START ONCE FUNDING REACHES 1 MILLION DOLLARS
EACH 1 MILLION DOLLARS IN FUNDING CREATES 200,000 TONNES of CARBON

MATH BREAKDOWN
based on 1 million dollar increments

 1 tonne = 16.6 mcf natural gas based on today price 2.01 per mcf
 1 million dollars is 200,000 tonnes @ 5.00 a tonne

 200,000 tonnes = 3,320,000 mcf = $6,673,200 gas
 so each million dollars in project creates 200,000 tonnes and saves 6.5 million plus in gas ALONE!
Pays for itself 6.5 times over  before we do the carbon benefit!

Approved baseline and monitoring methodology AM0009
 
“Recovery and utilization of gas from oil wells that would otherwise be flared or vented”
 
 
I.            SOURCE, DEFINITIONS AND APPLICABILITY
 
Sources
 
This baseline and monitoring methodology is based on elements from the following proposed methodologies:
·       NM0026 “Rang Dong Oil Field Associated Gas Recovery and Utilization Project” prepared by Japan Vietnam Petroleum Co. Ltd;
·       NM0227 “Recovery of methane from on- and off-shore oil fields that otherwise will be vented into the atmosphere” prepared by SOCAR in collaboration with ICF International.
 
This methodology also refers to the latest approved versions of the following tools:
·       “Tool to calculate project or leakage CO emissions from fossil fuel combustion”;
·       “Tool to calculate baseline, project and/or leakage emissions from electricity consumption”;
·       “Tool for the demonstration and assessment of additionality”;
·       “Assessment of the validity of the original/current baseline and to update of the baseline at the renewal of the crediting period”.
 
For more information regarding the proposed new methodologies and the tools as well as their consideration by the Executive Board please refer to <http://cdm.unfccc.int/goto/MPappmeth>.
 
Selected approach from paragraph 48 of the CDM modalities and procedures
 
“Existing actual or historical emissions, as applicable”.
and
“Emissions from a technology that represents an economically attractive course of action, taking into account barriers to investment”.
 
Definitions
 
For the purpose of this methodology, the following definitions apply:
 
Associated gas. Natural gas found in association with oil, either dissolved in the oil or as a cap of free gas above the oil.
 
Gas-lift.  An artificial lift method for oil wells exploitation in which gas is injected into the production tubing to reduce the hydrostatic pressure of the fluid column.  The resulting reduction in bottomhole pressure allows the reservoir liquids to enter the wellbore at a higher flow rate.
 
Gas-lift gas.  High-pressure gas used for gas-lift in the oil wells.
 
Recovered gas. The associated gas and/or gas-lift gas recovered from the project oil wells.
.  A facility designed to separate or process hydrocarbons through chemical, physical or physical-chemical procedures in order to produce marketable hydrocarbon and other (e.g. sulphur) products.
 
Compressed Natural Gas (CNG). The processed gas that has been compressed to high pressure (typically > 200 bar) for the purpose of storage and/or transportation.
 
Gas pipeline.  The pipeline with capacity to transport more than 1 million Nm of gas per day.
 
Applicability
 
The methodology is applicable to project activities that recover and utilise associated gas and/or gas-lift gas from oil wells.
 
The methodology is applicable under the following conditions:
·       Under the project activity the recovered gas, after the pre-treatment (compression and phase separation) in movable or stationary equipment, is:
o   Consumed on-site to meet energy demands; and/or
o   Transported to a gas pipeline without prior processing; and/or
o   Transported to a processing plant where it is processed into hydrocarbon products (e.g. dry gas, LPG and condensates).  The dry gas is either (i) transported to a gas pipeline directly, or (ii) compressed to CNG first, then transported by trailers/trucks/carriers and then decompressed and gasified again, before it finally enters the gas pipeline.
·       The project activity does not lead to changes in the process of oil production, such as an increase in the quantity or quality of oil extracted, in the oil-wells within the project boundaries;
·       The injection of any gases into the oil reservoir and its production system is allowed in the project activity only for the purpose of the gas-lift process;
·       All recovered gas comes from oil wells that are in operation and are producing oil at the time of the recovery of the associated gas and/or gas-lift gas.
 
In addition, the applicability conditions included in the tools referred to above apply.
 
Finally, the methodology is only applicable if the identified baseline scenario is:
·       The continuation of the current practice of either venting (scenario G1), flaring (scenario G2) of the associated gas and/or gas-lift gas or on-site use of the partial amount of associated gas and/or gas-lift gas to meet on-site energy demands and rest of the gas are either vented or flared (scenario G3); and
·       The continued operation of the existing oil and gas infrastructure without any other significant changes (scenario P4); and
·       In the case where gas-lift is used under the project activity: the gas-lift gas under the baseline uses the same source as under the project activity and the same quantity as under the project activity (scenario 01).
II.            BASELINE METHODOLOGY PROCEDURE
 
Project boundary
 
The project boundary encompasses:
·     The project oil reservoir and oil wells where the associated gas and/or gas-lift gas is collected;
·     The site where the associated gas and/or gas-lift gas was flared or vented in the absence of the project activity;
·     The gas recovery, pre-treatment, transportation infrastructure, including where applicable, compressors;
·     The source of gas-lift gas.
 
The greenhouse gases included in or excluded from the project boundary are shown in Table 1.
1:  Emissions sources included in or excluded from the project boundary
 
Source
Gas
Included?
Justification / Explanation
Baseline
Combustion of fossil fuels at end-users that are produced from non-associated gas or other fossil sources
CO
Yes
Main source of emissions in the baseline
CH
No
Excluded for simplification. This is conservative.
NO
No
Excluded for simplification. This is conservative.
Project Activity
Energy use for the recovery, pre-treatment, transportation, and if applicable, compression/decompression, transportation of the recovered gas
CO
Yes
Main source of emissions in the project
CH
No
Excluded for simplification. This emission source is assumed negligible
NO
No
Excluded for simplification. This emission source is assumed negligible
 
 

Figure 1:  Schematic illustration of the baseline activity
 

Figure 2:  Schematic illustration of the project activity
 
The project area may encompass several wells under a Production Sharing Contract (PSC) with a production target.
 
Identification of the baseline scenario and demonstration of additionality
 
Project participants shall apply the following procedure.
 
Step 1:     Identify plausible alternative scenarios
The project activity involves three components.  Plausible alternative scenarios should include alternatives for the following components:
 
Plausible alternative baseline scenarios for the associated gas and/or gas-lift gas from the project oil wells could include, inter alia:
G1:     Release of the associated gas and/or gas-lift gas into the atmosphere at the oil production site (venting);
G2:     Flaring of the associated gas and/or gas-lift gas at the oil production site;
G3:     On-site use of the partial amount of associated gas and/or gas-lift gas to meet on-site energy and rest of the gas are either vented (G1) or flared (G2);
G4:     Injection of the associated gas and/or gas-lift gas into an oil or gas reservoir;
G5:     The proposed project activity without being registered as a CDM project activity;
G6:     Recovery, transportation and utilization of the associated gas and/or gas-lift gas as feedstock for manufacturing of useful products.
 
Plausible alternative baseline scenarios for oil and gas infrastructure should include the proposed project activity and all relevant scenarios for any existing or new gas processing plants, pipelines, compressors, etc. They depend heavily on the context of the proposed project, but could include, inter alia:
P1:   Construction of a processing plant for the purpose of processing the recovered gas, in the same way as in the project activity, without being registered as a CDM project activity;
P2:   Construction of a processing plant of a lower capacity than under the project activity, which processes only non-associated gas and does not process recovered gas;
P3:   Supplying recovered gas to an existing gas processing plant and constructing the necessary infrastructure, without being registered as a CDM project activity;
P4:   Continuation of the operation of the existing oil and gas infrastructure without any other significant changes;
P5:   Supplying recovered gas to a gas pipeline without prior processing and without being registered as a CDM project activity.
 
Plausible alternative baseline scenarios for the use of gas-lift could include, inter alia:
O1:   Gas from the same source as under the project activity and in the same quantity as under the project activity is used for the gas-lift system;
O2:    Gas from a different source than under the project activity but using the same quantity of gas-lift gas as under the project activity is used for the gas-lift system;
O3:   Gas from the same source as under the project activity, but using a different quantity of gas-lift gas, is used for the gas-lift system;
O4:   Gas from a different source than under the project activity and in a different quantity than under the project activity, is used for the gas-lift system;
O5:   No gas-lift system is utilized.
 
Realistic combinations of these three components should be identified and considered as possible alternative scenarios to the proposed project activity.  The identified combinations should be transparently described and be illustrated in schematic diagrams in the CDM-PDD.
 
Step 2:     Evaluate legal aspects
In evaluating legal aspects, the following issues should be addressed:
·     Are the alternatives permitted by law or other (industrial) agreements and standards?
·     Are there laws or other regulations (e.g. environmental regulations) which implicitly restrict certain alternatives?
All baseline alternatives shall be in compliance with all applicable legal and regulatory requirements, even if these laws have objectives other than GHG reductions.  If an alternative does not comply with all applicable legislation and regulations, such an alternative should be eliminated unless it is demonstrated, based on an examination of current practice in the country or region in which the law or regulation applies, that applicable legal or regulatory requirements are systematically not enforced and that non-compliance is widespread.
 
Step 3:     Evaluate the economic attractiveness of alternatives
 
The economic attractiveness is assessed for those alternative scenarios that are feasible in technical terms and that are identified as permitted by law or other (industrial) agreements and standards in Step 2. The economic attractiveness is assessed by determining an expected Internal Rate of Return (IRR) of each alternative scenario, following the guidance for the investment analysis in the latest approved version of the “Tool for the demonstration and assessment of additionality”.  The IRR should be determined using, inter alia, the following parameters as applicable to the relevant scenario:
·     Overall projected production of associated gas and/or gas-lift gas;
·     The projected quantity of gas recovered, gas flared, vented, consumed on-site, processed in a gas processing plant and/or compressed into a pipeline;
·     The agreed price for the delivery of recovered gas (e.g. from a Production Sharing Contract) to the gas pipeline or gas processing plant (if operated by a third party);
·     The net calorific value of the recovered gas;
·     Capital expenditure for all oil and gas infrastructure needed in the relevant scenario, such as gas recovery facilities, pipelines, and gas processing plant (if applicable) etc. (CAPEX);
·     All operational expenditure associated with the respective scenario (OPEX);
·     All revenues from the operation of the alternative scenario, such as revenues from selling processed gas or other products of the gas processing plant or electricity;
·     Any profit sharing agreements and cost recovery, such as cost savings through the substitution of products by the recovered gas, if applicable.
 
If venting or flaring of the associated gas at a given location is not outright banned, but instead is subject to taxes or fines, the impact of these taxes and fines should be considered in the IRR calculation.
 
The alternative scenario that is economically the most attractive course of action is considered as the baseline scenario.  Proceed to the next step if the IRR of the project activity is lower than the hurdle rate of the project participants (typically about 10%) and if the most plausible baseline scenario is not the project activity without being registered as a CDM project activity; otherwise, the project activity is not additional.
 
The DOE should verify what value for the IRR is typical for this type of investment in the respective Host country.  The calculations should be described and documented transparently.
 
Step 4:     Common practice analysis
 
Apply the “common practice analysis”, following the guidance for the common practice analysis in the latest approved version of the “Tool for the demonstration and assessment of additionality”.
 
Baseline emissions
 
Project activities under this methodology reduce emissions by recovering associated gas and/or gas-lift gas and utilizing the recovered gas.  The utilization of the recovered gas displaces the use of other fossil fuel sources.  For example:
  • The use of recovered gas in a processing plant can displace the use of non-associated gas in that processing plant;
  • In another situation, the recovered gas may be compressed into a natural gas pipeline, thereby displacing the processing of non-associated gas in a gas processing plant at another site. 
 
The exact emission effects are difficult to determine and would require an analysis of the whole fuel supply chain up to the end-users for both the project activity and the baseline scenario.  This methodology provides a simplified and conservative calculation of emission reductions, assuming that the use of recovered gas displaces the use of methane – the fossil fuel with the lowest direct CO emissions. Emissions from processing and transportation of fuels to end-users are neglected for both the project activity and the baseline scenario, as it is assumed that these emissions are similar in their magnitude and level out.
 
Baseline emissions are calculated as follows:
           
            (1)
 
Where:
BE
=
Baseline emissions in year y, (tCOe)
V
=
Volume of total recovered gas measured at point F in Figure 2 in year y (Nm³)
NCV
=
Average net calorific value of recovered gas at point F in Figure 2 in year y (TJ/Nm)
EF
=
CO emission factor for methane (tCO/TJ)
Project emissions
The following sources[1] of project emissions are accounted in this methodology:
·     CO emissions due to consumption of fossil fuels for the recovery, pre-treatment, transportation, and, if applicable, compression of the recovered gas up to the point F in Figure 2;
·     CO emissions due to the use of electricity for the recovery, pre-treatment, transportation, and, if applicable, compression of the recovered gas up to the point F in Figure 2.
Project emissions are calculated as follows:
           
(2)
 
Where:
PE
=
Project emissions in year y, (tCOe)
PE
=
CO emissions due to consumption of fossil fuels for the recovery, pre-treatment, transportation, and, if applicable, compression of the recovered gas up to the point F in Figure 2 in year y (tCOe)
PE
=
CO emissions due to the use of electricity for recovery, pre-treatment, transportation and, if applicable, compression of the recovered gas up to the point F in Figure 2 in year y, (tCOe)
 
Project emissions from the consumption of fossil fuels
 
Project emissions PE due to the consumption of fossil fuels, including the recovered gas, if applicable for the recovery, pre-treatment, transportation and, if applicable, compression of the recovered gas are calculated applying the latest approved version of the “Tool to calculate project or leakage CO emissions from fossil fuel combustion” where PEcorresponds to PEFC,j,y in the tool and process j corresponds to all sources of fuel combustion (e.g. a compressor, etc) up to point F in Figure 2.  All applicable emission sources should be documented transparently in the CDM-PDD and in monitoring reports.
 
Project emissions from consumption of electricity
 
Project emissions PE due to the use of electricity for the recovery, pre-treatment, transportation, and, if applicable, compression of the recovered gas are calculated applying the latest approved version of the “Tool to calculate baseline, project and/or leakage emissions from electricity consumption” where PEcorresponds to PE in the tool and the electricity consumption sources j in the tool corresponds to all sources of electricity consumption (e.g. a compressor, etc) up to point F in Figure 2.  All applicable sources of electricity consumption should be documented transparently in the CDM-PDD and in monitoring reports.
 
Leakage
 
Leakage emission is calculated as follows:
            (3)
 
Where:
LE
=
Leakage emissions in year y (tCOe)
LE
=
Leakage emissions due to fossil fuel consumption after point F in Figure 2 in year y (tCOe)
LE
=
Leakage emissions due to electricity consumption after point F in Figure 2 in year y (tCOe)
 
Leakage emissions due to fossil fuel consumption
 
Leakage emissions due to fossil fuel consumption in year y (LE) is calculated applying the latest approved version of the “Tool to calculate project or leakage CO emissions from fossil fuel combustion” where LEcorresponds to PEFC,j,y in the tool and process j corresponds to all sources of fuel combustion (e.g. compressor, decompressor or trailers/trucks/carriers etc) after point F in Figure 2.  All emission sources of fuel consumptions should be documented transparently in the CDM-PDD and in monitoring reports.
 
Leakage emissions due to electricity consumption
 
Leakage emissions due to electricity consumption in year y (LE) is calculated applying the latest approved version of the “Tool to calculate baseline, project and/or leakage emissions from electricity consumption” where LEcorresponds to PE in the tool and the electricity consumption sources j in the tool corresponds to all sources of electricity consumption (e.g. compressor, decompressor or trailers/trucks/carriers etc) after point F in Figure 2. All emission sources of electricity consumption should be documented transparently in the CDM-PDD and in monitoring reports.
 
Emission reductions
 
Emission reductions are calculated as follows:
 
            (4)
 
Where:
ER
=
Emission reductions in year y (tCOe)
BE
=
Baseline emissions in year y (tCOe)
PE
=
Project emissions in year y (tCOe)
LE
=
Leakage emissions in year y (tCOe)
 
Changes required for methodology implementation in 2nd and 3rd crediting periods

Refer to the tool “Assessment of the validity of the original/current baseline and to update of the baseline at the renewal of the crediting period”.
 
Data and parameters not monitored
 
In addition to the parameters listed in the tables below, the provisions on data and parameters not monitored in the tools referred to in this methodology apply.
 
Data / parameter:
EF
Data unit:
tCO2/TJ
Description:
CO emission factor for methane
Source of data:
Calculated in line with procedures and data presented in ISO 6976:
Unit
Value
Source
Carbon Content of Methane
12,011 kg/kmol
ISO 6976: Table 1
CO Emission Factor for Methane
44.01 kg/kmol
ISO 6976: Table 1
NCV of Methane (at 25C)
802.60 kJ/mol
ISO 6976: Table 3

Value to be applied:
54.834 tCO2/TJ
Any comment:
---
III.            MONITORING METHODOLOGY
 
All data collected as part of monitoring should be archived electronically and be kept at least for 2 years after the end of the last crediting period.  100% of the data should be monitored if not indicated otherwise in the tables below.  All measurements should be conducted with calibrated measurement equipment according to relevant industry standards.
 
The CDM-PDD will have to include minimal procedures to ensure that the data collection and retention will be made properly.
 
In addition, the monitoring provisions in the tools referred to in this methodology apply.
 
Projection and adjustment of project and baseline emissions on the basis of oil production
 
Project as well as baseline emissions depend on the quantity of associated gas and gas-lift gas recovered, which is linked to the oil production.  Oil production may be projected with the help of a reservoir simulator, reflecting the rock and fluid properties in the oil reservoir.  As projections of the oil production, the methane content of the gas and other parameters involve a considerable degree of uncertainty, the quantity and composition of the recovered gas are monitored ex post and baseline and project emissions are adjusted respectively during monitoring.
 
The validating DOE shall confirm that estimated emission reductions reported in the CDM-PDD are based on estimates provided in the survey used for defining the terms of the underlying oil production project as per the production sharing contract.
At verification the verifying DOE shall check the production data for oil and associated gas and gas-lift gas and compare them with the initial production target as per the information provided in survey used for defining the terms of the underlying oil production project.  If the oil production differs significantly from the initial production target, then it should be checked that this is not intentional, and that such a scenario is properly addressed by the production sharing contract between the contracted party(ies).
Data and parameters monitored
 
Data / Parameter:
V
Data unit:
Nm³
Description:
Volume of the total recovered gas measured at point F in Figure 2 in year y
Source of data:
Flow meter (e.g., diaphragm gouge)
Measurement
procedures (if any):
Data should be measured using calibrated flow meters. 
Measurements should be taken at the point(s) where recovered gas exits the pre-treatment plant
Monitoring frequency:
Continuously
QA/QC procedures:
Volume of gas should be completely metered with regular calibration of metering equipment.  The measured volume should be converted to the volume at normal temperature and pressure using the temperature and pressure at the time to measurement
Any comment:
---
 
Data / Parameter:
NCV
Data unit:
TJ/Nm
Description:
Average net calorific value of recovered gas at point F in Figure 2 in year y
Source of data:
On site measurement (Chemical analysis of gas samples taken at point F in Figure 2)
Measurement
procedures (if any):
Measurements should be undertaken in line with national or international fuel standards
Gas samples should regularly be taken at point F in Figure 2 and  the  molar composition of each gas sample should be determined through chemical analysis following the procedures for QA/QC. Based on the molar composition, the Net Calorific Value on a volumetric basis  should be determined  for each sample in line with ISO 6976 or an equivalent standard for a combustion reference temperature of 25C  and  the same  metering reference condition used for parameter VF,y. The average NCV during the period y is defined as the arithmetic average of NCVs for the samples taken during the same period
Monitoring frequency:
Sampling and compositional analysis and calculation of net calorific value at least monthly
QA/QC procedures:
Sampling in accordance with ISO 10715 or equivalent standard. Compositional analysis in accordance with ISO 6974 or equivalent standard. Routine maintenance and calibration in accordance with ISO 10723 or equivalent standard. GC calibration gases certified  to ISO 6141 or equivalent standard. Annual manufacturer servicing and calibration to ISO17025 or equivalent standard.  In case third party  laboratories  are used, these should as a minimum have ISO17025 accreditation or justify that they can comply with similar quality standards
Any comment:
For the purpose of this methodology, the qualifier “net” is synonymous with “lower” and “inferior”, and the term “calorific value” is synonymous with “heating value”

 
- - - - -
 
History of the document
Version 
Date
Nature of revision(s)
05.0.1
EB 66, Annex 41
2 March 2012
Editorial amendment to:
·     Correct the reference of common practice analysis;
·     Correct the description of V and description of point F in Figure 2 throughout the methodology; and
·     Update the title of the methodological tool “Assessment of the validity of the original/current baseline and to update of the baseline at the renewal of the crediting period”.
05.0.0
EB 65, Annex 11
25 November 2011
Revision to expand the applicability of the methodology to situations where:
·     The associated gas and/or gas-lift gas is partially recovered and utilized on-site before the implementation of the project activity;
·     Pre-treatment is done by movable or stationary equipments;
·     Recovered gas is first compressed to Compressed Natural Gas (CNG), then transported via trailers or carriers, and later decompressed and gasified before it finally enters the gas pipelines to end-users;
Additionally, revision to:
·     Provide definition of CNG and gas pipeline;
·     Include leakage emissions due to the use of fossil fuels and/or electricity due to the compression, transportation and decompression of CNG;
·     Update the schematic illustration of baseline and project activity to reflect above changes;
·     Update the monitoring tables by revising (i) the CO emission factor for methane, and (ii) the measurement procedures and QA/QC procedures for net calorific value of recovered gas; and
·     Remove reference to the “Combined tool to identify the baseline scenario and demonstrate additionality”;
·     Add reference to the tool “Validity of the original/current baseline and to update the baseline at the renewal of a crediting period”.
04
EB 46, Annex 5
25 March 2009
Revision to:
·     Expand the scope of the methodology by allowing the use of gas coming to the surface from gas-lift systems;
·     Modify the project activity diagram;
·     Adjust the table for emission sources in the project boundary section;
·     Include provisions to identify plausible alternative baseline scenarios for a gas processing facility and gas-lift gas;
·     Simplify the procedure to calculate baseline emissions;
·     Neglect project emissions related to gas leaks, venting and flaring during the recovery, transport and processing of the recovered gas;
·     Eliminate the leakage emissions section; and
·     Eliminate the uncertainty assessment section.
03.3
EB 44, Annex 6
28 November 2008
Editorial revision to delete the term ‘transportation’ from the section “CH project emissions from venting, leak or flaring of the associated gas”.
03.2
EB 42, Annex 4
26 September 2008
Editorial revision to correct equation 3 under project emissions.
03.1
EB 39, Paragraph 22
16 May 2008
“Tool to calculate baseline, project and/or leakage emissions from electricity consumption” replaces the withdrawn “Tool to calculate project emissions from electricity consumption”.
03
EB 36, Annex 6
30 November 2007
Revision to:
·     Expand the applicability of the methodology by introducing a new baseline scenario where the associated gas is vented in the absence of the project activity;
·     Introduce an option of supplying part of the captured gas directly to the existing natural gas grid without processing;
·     Introduce project emissions from the use of electricity and fossil fuels for project activities where electricity and fossil fuels are used for capture, transportation and processing of the associated gas;
·     Incorporate “Tool to calculate project or leakage CO emissions from fossil fuel combustion”, “Tool to calculate project emissions from electricity consumption” and “Combined tool to identify the baseline scenario and demonstrate additionality”.
02.1
22 June 2007
The methodology was editorially revised to add the guidance provided by the Board at its thirty-second meeting (paragraph 23 of thirty-second meeting report) in the following sections:
(i) Projection and adjustment of project and baseline emissions; and
(ii) Note below the QA/QC table (on Page 15).
Guidance by the Board:
“The Board clarified that the validating DOE shall confirm that estimated flare reduction in the CDM-PDD for project activities using approved methodology AM0009 are based on estimates provided in the survey used for defining the terms of the underlying oil production project. At verification the DOE shall check the production data for oil and associate gas and compare it with initial production target. If the oil production differs significantly from initial production target, then it should be checked upon verification that this is not intentional, and that such a scenario is properly addressed by the contract between the contracted party(ies).”
02
EB 19, Annex 5
13 May 2005
Revision to introduce project emissions from the transportation of the associated gas and project emissions from accidents.
01
EB 13, Annex 3
26 March 2004
Initial adoption.
Decision Class
: Regulatory
Document Type
: Standard
Business Function
: Methodology

 
 
 
 

[1] Other sources of project emissions such as emissions from leaks, venting and flaring during the recovery, transportation and processing of recovered gas are assumed to be of similar magnitude in the baseline scenario.


TOP 50 PROJECTS
1. NIGERIA
2. UKRAINE
3. CALIFORNIA
4. MEXICO
5. CANADA
6. TEXAS
7. TRANS BORDER
8. COAL MINES
9. FLARE
10. ISOLATION
11. LEAK COMPLIANCE
Updated frequently, we are currently accepting proposals

Approved baseline and monitoring methodology AM0023
 
“Leak detection and repair in gas production, processing, transmission, storage and distribution systems and in refinery facilities”
 
I.
SOURCE, DEFINITIONS AND APPLICABILITY
 
Source
 
This baseline and monitoring methodology is based on the following proposed methodology:
·       NM00091:  “Leak reduction from natural gas pipeline compressor or gate stations”, whose baseline study, monitoring and verification plan and project design document, were prepared by QualityTonnes on behalf of MoldovaGas. 
 
This methodology also refers to the latest approved version of the:
·       “Combined tool to identify the baseline scenario and demonstrate additionality”.
 
For more information regarding the proposed new methodologies and these tools, as well as their consideration by the Executive Board, please refer to <http://cdm.unfccc.int/goto/MPappmeth.>.
 
Selected approach from paragraph 48 of the CDM modalities and procedures
 
“Existing actual or historical emissions”.
 
Definitions
For the purpose of this methodology, the following definitions apply:
 
ComponentAbove-ground process equipment in natural gas production, processing, transmission, storage, distribution systems and in refinery facilities, including the following:
·       Valves;
·       Flanges and other connectors;
·       Pump seals;
·       Compressor seals;
·       Pressure relief valves. Pressure relief valves are only accountable under this methodology when the gas pressure is less than the set point to open the valve (i.e. when the relief valve is closed);
·       Open-ended lines, and sampling connections. Leaks from open-ended lines and sampling connections occur at the point of the line open to the atmosphere and are usually controlled by using caps, plugs, and flanges. Leaks can also be caused by the incorrect implementation of the block and bleed procedure.
·       Others: Diaphragms, drains, dump arms, hatches, instruments, meters, polished rods, and vents.
 
Refinery gas.  Also known as still gas, can be defined as: “Any form or mixture of gases produced in refineries by distillation, cracking, reforming and other processes.  The principal constituents are methane, ethane, ethylene, normal butane, butylene, propane, propylene, etc. Still gas is used as a refinery fuel and a petrochemical feedstock”[1][2][3][4] and is generally produced from light ends distillation units of refinery facilities, where it has a pressure that allows its immediate use.
Physical leakThe unintentional and continuous loss of natural gas or refinery gas from a component. The leaking may occur past a seal, mechanical connection or minor flaw on the component at a rate that is in excess of normal tolerances allowed by the manufacturer. Leaks may occur due to normal wear and tear, improper or incomplete assembly of components, inadequate material specification, manufacturing defects, damage during installation or use, corrosion, fouling and demanding service conditions (e.g. vibrations and thermal cycling).
Leak detection and repair (LDAR) program. A structured program to detect and repair physical leaks from components. If a component is determined to have a physical leak, then the component is tagged and the physical leak repaired within a specified time. In the context of this methodology the following types of LDAR programs are defined:

  • Conventional LDAR program.  This comprises (where applicable) physical leaks detected by worker audio, visual and olfactory responses, area and building monitoring for flammable or toxic gases, worker personal monitors and leak checks performed as part of normal inspection and maintenance activities. The conventional LDAR program shall also comprise any additional leak detection and repair measures required and enforced by local regulations. The physical leaks that are detected and repaired within the framework of conventional LDAR cannot be included in the project activity;    
  • Advanced LDAR program.  A program that is in addition to the conventional LDAR program.

 
Repair of physical leaks. A repair of a physical leak occurs when the natural gas or refinery gas losses from a physical leak at a component are reduced to within normal manufacturer’s tolerances for periods during which the component is in pressurized natural gas or refinery gas service. The repair may be achieved by tightening or adjusting the component, applying sealants, replacing packing materials or seals, repairing or replacing the component. Conversion to better performing components, packing materials, and seals, conversion to sealless technologies can help to reduce the project emissions.
 
Process venting. Engineered or intentional releases of natural gas or refinery gas to the atmosphere, such as the venting of natural gas or refinery gas by pneumatic devices, equipment and pipeline depressurization events, disposal of processing waste or by-product streams (e.g. dehydrator and storage tank vents), and discharges from emergency pressure relief events.
 
Maintenance.  It is a set of activities that are performed on components in accordance to international standards[5] in order to correct or to prevent any degradation in their operating conditions. The maintenance carried out at predetermined intervals or according to prescribed criteria and intended to reduce the probability of failure or the degradation of the functioning and the effects limited.
 
Applicability
 
This methodology is applicable to project activities that reduce physical leaks in components through the introduction of an advanced LDAR program.
The methodology is applicable under the following conditions:
·       During the last three years prior to the implementation of the project activity, no advanced LDAR program was in place to address physical leakage from components that are included in the project boundary;
·       New physical leaks that are detected at components during the crediting period (e.g. not at the time the project starts) are accountable only if the components were included in the project boundary at the validation of the project activity;
·       Physical leaks that need to be repaired due to current regulations and legislation are accountable only if it can be demonstrated that relevant regulations and legislation are not enforced in the country.
 
Note that this methodology is not applicable to:
·       Physical leaks that are detected and repaired under a conventional LDAR program;
·       Physical leaks that can be repaired by tightening/re-greasing or by similar measures;
·       Physical leaks that are identified on components where the latest scheduled maintenance or replacement was not done before the starting date of a project activity as documented through maintenance logs, maintenance schedules, maintenance guidelines, worker logbooks, or other similar sources;   
·       Reductions in process venting;
·       Reductions in natural gas or refinery gas combustion by process heaters or boilers, engines and thermal oxidizers.
In addition, the applicability conditions of the tools referred to above apply.
Finally, the methodology is only applicable if the most likely baseline scenario is the continuation of the current practice.
 
II.
BASELINE METHODOLOGY
PROCEDURE
Project boundary
 
The spatial extent of the project boundary includes the components where the project activity is being implemented.  The spatial extent of the project boundary should be clearly illustrated in the CDM-PDD.
Moreover, only methane (CH) emissions from physical leaks that were detected through the introduction of the advanced LDAR program should be included in the project boundary. The project boundary should be defined by clear definition of all components that are, or could be, sources of physical leakage.
For the purpose of defining the project boundary a database should be used, which is further described in Step 2 of the Baseline emissions section of this methodology.
The emission sources included in or excluded from the project boundary are shown in Table 1.
 
Table 1:  Emissions sources included in or excluded from the project boundary
Source
Gas
Included?
Justification / Explanation
Baseline
Physical leaks from the components included in the project boundary
CO
No
The CO content in natural gas/refinery gas is very low. Exclusion is conservative
CH
Yes
Main source of emissions
NO
No
The NO content in natural gas/refinery gas is negligible
Project Activity
Physical leaks from the components included in the project boundary
CO
No
The CO content in natural gas/refinery gas is very low. Exclusion is conservative
CH
Yes
Main source of emissions
NO
No
The NO content in natural gas/refinery gas is negligible
 
Procedure for the selection of the baseline scenario and the demonstration of additionality
 
The selection of the baseline scenario and the demonstration of additionality should be conducted using the “Combined tool to identify the baseline scenario and demonstrate additionality”.
 
Emission reductions
Emission reductions are calculated as follows:
 

(1)
Where:
ER
=
Emission reductions for crediting year y (tCOe)
BE
=
Baseline emissions for crediting year y (tCOe)
PE
=
Project emissions for crediting year y (tCOe)
 
Baseline emissions
 
Baseline emissions are determined based on the quantity of CH emitted through physical leaks that are detected and repaired as part of the project activity (i.e., by the advanced LDAR program).
 
Baseline emissions are calculated in these four steps:
Step 1:  Establishment of criteria to identify which types of physical leaks are eligible for crediting.
Step 2:  Establishment of a database to manage all information related to the project activity.
Step 3:  Documentation of the schedules for the maintenance and replacement of components.
Step 4:  Calculation of baseline emissions.
 
Step 1:  Establishment of criteria to identify which types of physical leaks are eligible for crediting
 
For this purpose, project participants should first describe and assess in the CDM-PDD the current leak detection and repair practices applied by the operating company as well as the relevant local industry and regulatory standards. Based on this information, the project participants should classify different types of physical leaks.  The following criteria may, inter alia, be taken into account in the classification of physical leaks:
·      Safety aspects.  Some physical leaks need to be repaired for safety reasons.  An assessment of the safety regulations, local industry safety standards and their implementation may help in identifying what types of physical leaks are detected and repaired under the current safety regulations or other legislation of the country and local industry safety practices.  In some case there may be a separate emergency repair apparatus specially dedicated to repair leaks that are considered safety risks;
·      Accessibility. Some physical leaks may not get detected by a conventional LDAR program because they are inaccessible (e.g. they occur in crowded areas, are unsafe to access due to hot surfaces, or they are elevated and require ladders with fall-protection or lifts to access);
·      Visibility, audibility and/or smell.  Some companies may detect and repair physical leaks only if staff see, smell or hear the physical leak;
·      Practicability of repairs.  Some physical leaks may only get repaired where they are deemed economical to fix or if spare parts or industry standard repair materials are available;
·      Leak detection technologies.  The types of physical leaks that are identified may depend on the technology used to detect physical leaks.  The introduction of new advanced technologies as part of the project activity may help to identify physical leaks that would otherwise not be detected.  It has to be defined which types of physical leaks are usually detected using the current technological means and measurement instruments.
 
In undertaking the assessment, the following type of information shall be used:
·       Written protocols and all physical leak repair records available from the previous years;
·       Equipment component specifications and design standards;
·       Written internal procedures which instruct staff how to identify and repair physical leaks;
·       Interviews with key staff of the company, in particular managers responsible for physical leak detection and repair, e.g. on practices undertaken that are not part of documented protocols;
·       Documentation on the technologies and measurement instruments used to detect physical leaks and repair materials available to undertake repairs.
 
Using this type of information, clear criteria should be established to identify whether the detection and repair of a physical leak during project implementation would also have occurred under conventional LDAR.  These criteria should be documented in the CDM-PDD and be validated by the DOE.
 
To facilitate the decision making process when classifying detected physical leaks as part of either a conventional or advanced LDAR program during the project, a flowchart could be used like the example shown in Figure 1 below.
 
 
 
 

Figure 1:  Criteria for inclusion/exclusion leak in/from project activities
 
Step 2:  Establishment of a database to manage all information related to the project activity
As part of an advanced LDAR program, a database shall be established to manage all relevant information related to the detection and repair of physical leaks. All data collected during project implementation should be entered into this database. The database should, inter alia, include the following information on each physical leak:
(1)  Data to clearly identify the component: ID number, type of component, size of component, service, process unit or area, location of the component, type of the facility, digital photo number, etc;
(2)  Relevant information on the detection of the physical leak: date of detection, detection method applied, who detected the leak, detection reading if applicable e.g. screening value or leak image, etc;
(3)  In case measurements of the flow from the physical leak are undertaken, relevant information on the measurement: date of measurement, the measurement method applied, the measured leak rate F and the uncertainty of the measurement;
(4)  Hours during which the component is in pressurized natural gas or refinery gas service since the last leak survey or facility turnaround;
(5)  Information regarding the eligibility of the physical leak to be included in the project activity (information that is required to distinguish between leaks detected by the conventional LDAR program and the advanced LDAR program);
(6)  Information regarding the time in which the physical leak is eligible for crediting year y
(7)  Relevant information on the repair of the detected physical leak: date of physical leak repair attempts and final successful physical leak repair.
In addition to the information that is required to be entered in the database, all of the following three ways of tagging leak locations and tracking leak measurements must be applied to clearly identify a leak location:
(1)  A digital photo of the leak itself is taken and this photograph is then documented together with the actual leakage rate and measurement date;
(2)  The leak itself is physically tagged on-site and the leak rate and measurement date are written on the tag; and
(3)  The location of the leak is documented on a drawing of the facility itself, when the leak measurement and date are entered into the database.
The database should be continuously updated during the crediting period with information on the physical leaks repaired during the crediting period.  The data in the database should also be included in each monitoring report.
 
Step 3:  Documentation of the schedules for replacement of components
 
In the absence of an advanced LDAR, the physical leak would often cease to leak when the equipment would be replaced.
 
In calculating baseline emissions, it is assumed that a physical leak would have continued to emit gas until the component concerned would have been either maintained or replaced.  In all cases the maximum period for which baseline emissions from a leak are accountable is:
(a)   Seven years in the case that a renewable crediting period is chosen;
(b)   The end of the crediting period in the case that a non-renewable crediting period is chosen.  
 
The expected time schedules for the replacement of components that may be subject to leaks shall be identified in cases where such time schedules exist.  For this purpose, it should be identified when a single component or the entire facility would be subject to replacement in the baseline scenario.
 
In order to identify the schedules of replacements that would take place in the baseline scenario, project participants should use written documentation by the company and interviews with managers on performed and planned replacements.  The expected schedule of replacements should be documented in the CDM-PDD and be validated by the DOE.
 
Step 4:  Calculation of baseline emissions
 
There are two options for the calculation of baseline emissions. The choice taken by project participants should be documented in the CDM-PDD and cannot be changed during the crediting period.  In addition baseline emissions are capped to the baseline emission level of the first crediting year.
Option 1. Use any tool listed in the monitoring equipment section to detect (but not to quantify) the physical leaks and apply default emission factors developed by the American Petroleum Institute (API).  Emissions should be calculated by multiplying the CH fraction in the natural gas or refinery gas with the appropriate emission factors and then summing up all components that are accountable for the baseline emissions in a crediting year y, as follows:
 
 (2)
With
   (3)
 
Where:
BE
=
Baseline emissions for the first crediting year of the crediting period (t COe)
BE
=
Baseline emissions for crediting year y (t COe)
GWP
=
Global warming potential of methane valid for the commitment period (t COe / t CH)
w
=
Average mass fraction of methane in the natural gas/refinery gas for crediting year y (kg CH / kg gas)
EF
=
Emission factor for the component type i (kg/hour/component type)
T
=
The time the component r of component type i would leak in the baseline scenario and would be eligible for crediting during the crediting year y (hours)
i
=
Component types as classified by the API Compendium (“API Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Natural Gas Industry” 2009, tables 6-17, 18, 19, 21)
r
=
Components of component type i for which physical leaks were detected during initial survey and repaired and which would leak in the baseline scenario during the crediting year y
 
Option 2: Measure the flow rates of the physical leaks through the use of a Hi-Flow Samplers, calibrated bag or other suitable flowmeasurements technology as described in the monitoring equipment section below.  
 
Baseline emissions are calculated as follows:
(4)
With
 (5)
 
Where:
BE
=
Baseline emissions for the first crediting year of the crediting period (t COe)
BE
=
Baseline emissions for crediting year y (t COe)
ConvFactor
=
Conversion factor to convert Nm³ CH into t CH
j
=
All physical leaks that are included in the project activity for which physical leaks were detected and repaired and which would leak in the baseline scenario during the crediting year y
F
=
Measured flow rate of methane for the physical leak j from the leaking component (m³ CH / h)
UR
=
Uncertainty range for the flow rate measurement method applied to physical leak j
T
=
occurred, would leak in the baseline scenario and would be eligible for crediting during the crediting year y (hours)
GWP
=
The global warming potential of methane valid for the commitment period (t COe / t CH)
The uncertainty of the measurement is taken into account conservatively by using the flow rate at the lower end of the uncertainty range of the measurement at a 95% confidence interval for baseline emissions from leaks.  For example, if the measured flow rate is 1 m³/h and the uncertainty range of the measurement method is ±10%, emissions reductions shall be calculated based on a flow rate of 0.9 m³/h. Given the large quantity of measurements potentially involved in the baseline study, calculation methods provided in the 2006 IPCC Guidelines to calculate UR using the combined uncertainties of all measurements can be used.
 
The following assumption should be made in the calculation of baseline emissions:
·       For components where no physical leak were detected at the initial survey and where physical leak(s) were detected during a subsequent survey, baseline emissions shall be accounted from the moment when the leak was detected;
·       Baseline emissions from a specific leak j or a specific component r are included in the calculations until whichever of the following occurs first:
(a)            The equipment concerned is replaced for a non-leak related reason (i.e. it breaks down); or
(b)            The end of the last crediting period of the overall project activity; or
(c)            The maximum period for which a specific leak is can be accounted towards emission reductions is over. This maximum period is seven years (in the case that a renewable crediting period is chosen) or the end of the crediting period (in the case that a non-renewable crediting period is chosen).
 
Project emissions
 
Project emissions include emissions from physical leaks that take place on components included in the project boundaries in the following cases:
·       If a repair of a physical leak ceases to function, for as long as it is not repaired again; or
·       If a new physical leak is detected in a component which was part of the initial survey and for which no physical leak was detected during that survey, as long as that physical leak is not repaired.
 
Project emissions are calculated as follows:
 
In case of Option 1:
 
 (6)
 
Where:
PE
=
Project emissions for crediting year y (t COe)
GWP
=
Global warming potential of methane valid for the commitment period (t COe / t CH)
i
=
Component types as classified by the API Compendium (“API Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Natural Gas Industry” 2009, tables 6-17, 18, 19, 21)
w
=
Average mass fraction of methane in the natural gas/refinery gas  for crediting
year y (kg CH / kg gas)
EF
=
Emission factor for the component type i (kg/hour/component type)
 
T
=
The time the component x of component type i was leaking during the crediting year y (hours)
x
=
All components of component type i that are accounted for as project emissions during the crediting year y
 
In case of Option 2:
 
(7)
 
Where:
PE
=
Project emissions in crediting year y (tCOe)
ConvFactor
=
Conversion factor to convert Nm³ CH into t CH
z
=
All leaks that are accounted for as project emissions during the crediting year y
F
=
The leak flow rate of methane for the physical leak z from the leaking component (Nm³CH/h)
UR
=
The uncertainty range for the measurement method applied to leak z
T
=
The time the relevant component has been leaking during the crediting year y (hours)
GWP
=
Global warming potential of methane valid for the commitment period (t COe / t CH)
 
The uncertainty of the measurement is taken into account conservatively by using the flow rate at the upper end of the uncertainty range of the measurement at a 95% confidence interval for project emissions from leaks.  For example, if the measured flow rate is 1 m³/h and the uncertainty range of a measurement is ±10% , emissions reductions will be calculated at an effective flow rate of 1.1 m³/h.  Given the large quantity of measurements potentially involved, calculation methods provided in the 2006 IPCC Guidelines to calculate UR using the combined uncertainties of all measurements can be used.
 
The following assumptions should be made in the calculation of project emissions:
·       If a repair of a physical leak ceases to function, it is conservatively assumed that the leak resumed either:
(a)    At the same flow rate that was measured prior to its repair when using only leak detection equipment;
(b)    At the newly measured leak rate if the leak is re-measured using leak measurement equipment at the time of monitoring (in case of Option 2);
(c)    At the flow rate specified by the API Compendium (in case of Option 1).
It is further assumed that the leak resumed at the day when the leak was last checked and confirmed not to leak and that it continued to leak for the entire time since that date.  Thus, leaks where the repair failed should be included in the project emissions;
·       For components where no physical leak was detected at the initial survey and where physical leak(s) were detected during subsequent survey, project emissions from these components shall be accounted since the moment when the leak was detected;
·       Project emissions from a specific physical leak are included in the calculations until whichever of the following are earlier:
(a)    The date of any repair of the physical leak, as long as the repair does not cease to function; or
(b)    The equipment concerned is replaced (i.e. it breaks down).
Crediting period
 
The crediting period of the project activity should start at the date of first successful repair of a physical leak as part of the project activity. 
Leakage
 
No significant leakage is expected to occur in these types of projects.
 
Data and parameters not monitored
In addition to the parameters listed in the tables below, the provisions on data and parameters not monitored in the tools referred to in this methodology apply. 
 
Data / Parameter:
GWP
Data unit:
t CO / t CH
Description:
Global warming potential of CHvalid for the commitment period
Source of data:
IPCC
Value to be applied:
Project participants shall update GWPs according to any decisions by the CMP.
GWP=21 for the first commitment period
Any comment:
This value applies for the calculation of the baseline and project emissions
 
Data / Parameter:
ConvFactor
Data unit:
t CH / Nm CH
Description:
The factor to convert Nm³ CH into t CH
Source of data:
-
Value to be applied:
-
Any comment:
The leak flow rate (F) and conversion factor (ConvFactor) should be reduced to the same reference conditions. For example, if local industry’s “normal conditions” defined as 20 degree Celsius and 101.3 kPa, a value of 0.00067 (IPCC 2006 Vol.2, p. 4.12) is used to convert from Nm³ CH into t CH, and the flow rate should be determined for reference conditions of 20 degree Celsius and 101.3 kPa
 
Data / Parameter:
EF
Data unit:
kg/hour/component type
Description:
The emission factor for the relevant component type
Source of data:
API Compendium 2009. Tables 6-17, 18, 19, 21
Value to be applied:
 
 
 
 
 
 
 
 
 
 
 
Natural Gas Transmission Compressor Station
Component Emission Factors
Component
ON COMPRESSOR
OFF COMPRESSOR
Emission Factor, kg/hr/component
MAIN LINE PRESSURE (3447.4 to 6894.8 kPa)
Ball/Plug Valves
1.31E-03
1.09E-02
Blowdown Valves
--
4.24E-01
Compressor Cylinder Joints
2.02E-02
--
Packing Seals - Running
1.77
--
Packing Seals -Idle
2.59
--
Compressor Valves
8.39E-03
--
Control Valves
--
8.71E-03
Flanges
1.66E-03
6.54E-04
Gate Valves
--
1.25E-03
Loader Valves
3.52E-02
--
Open-Ended Lines (OEL)
--
1.67E-01
Pressure Relief Valves (PRV)
--
1.18E-01
Regulators
--
4.09E-04
Starter Gas Vents
--
8.34E-02
Threaded Connectors
1.51E-03
1.23E-03
Centrifugal Seals - Dry
--
1.28E-01
Centrifugal Seals - Wet
--
5.69E-01
Unit Valves
--
7.29E-03
FUEL GAS PRESSURE (482.6 to 689.5 kPa)
Ball/Plug Valves
2.05E-04
1.04E-03
Control Valves
--
5.03E-03
Flanges
--
4.09E-04
Fuel Valves
5.64E-02
--
Gate Valves
--
8.79E-04
Open-Ended Lines (OEL)
--
5.17E-03
Pneumatic Vents
--
1.57E-01
Regulators
--
8.24E-03
Threaded Connectors
2.47E-03
6.54E-04
 
Natural Gas Transmission and Storage Average Emission
Factors
Component
Emission Factor, kg/hr/component
Block valves
0.002140
Control valves
0.01969
Connectors
0.0002732
Compressor seals – reciprocating
0.6616
Compressor seals – centrifugal
0.8139
Pressure relief valves
0.2795
Open-ended lines (OEL)
0.08355
OEL - station or pressurized compressor blowdown system
0.9369
OEL – depressurized reciprocating (comp. blowdown system)
2.347
OEL – depressurized centrifugal (comp. blowdown system)
0.7334
OEL – overall pressurized/ depressurized reciprocating (comp. blowdown system)
1.232
OEL – overall pressurized/ depressurized centrifugal (comp. blowdown system)
0.7945
Orifice meter
0.003333
Other gas meter
0.000009060
Natural Gas Distribution Meter/Regulator Stations Average
Emission Factors
Component
Emission Factor, kg/hr/component
Valves
0.00111
Control valves
0.01969
Connectors
0.00011
Pressure relief valves
0.01665
Open-ended lines (OEL)
0.08355
OEL – station blowdown
0.9369
Orifice meter
0.00333
Other gas meter
0.00001
Other systems (refinery, etc.)
Component – Service
Emission Factor, kg/hr/component
Valves
2.81E-03
Connectors
8.18E-04
Control valves
1.62E-02
Pressure relief valves
1.70E-02
Pressure regulators
8.11E-03
Open ended lines
4.67E-01
Chemical injection pumps
1.62E-01
Compressor seals
7.13E-01
Compressor starts
6.34E-03
Controllers
2.38E-01

Any comment:
-
 
III. MONITORING METHODOLOGY
Monitoring procedures
 
1.  Establishment of a database
Please refer to Step 2 of the Baseline emissions section.
 
2.  Data collection during project implementation
The implementation of the project involves an initial survey and regular subsequent surveys of each component within the project boundary. Increasing the frequency at which physical leak surveys are conducted will tend to increase the level of physical leak control achieved.
Monitoring equipment
 
Project participants may use the following tools to detect, but not to quantify, physical leaks in components:
·    Electronic gas detectors using small hand-held gas detectors or "sniffing" devices to detect accessible physical leaks.  Electronic gas detectors are equipped with catalytic oxidation and thermal conductivity sensors designed to detect the presence of specific gases.  Electronic gas detectors can be used on larger openings that cannot be screened by soaping;
·    Organic Vapor Analyzers (OVAs) and Toxic Vapor Analyzers (TVAs) are portable hydrocarbon detectors that can also be used to identifyphysical leaks.  An OVA is a flame ionization detector (FID), which measures theconcentration of organic vapors over a range of 0.5 to 50,000 parts permillion (ppm).  TVAs and OVAs measure the concentration ofmethane in the area around a physical leak;
·    Acoustic leak detection using portable acoustic screening devices designed to detect the acoustic signal that results when pressurized gas escapes through an orifice.  As gas moves from a high-pressure to a low-pressure environment across a physical leak opening, the turbulent flow produces an acoustic signal, which is detected by a hand-held sensor or probe, and read as intensity increments on a meter.  Although acoustic detectors do not measure physical leak rates, they provide a relative indication of leak size – a high intensity or "loud” signal corresponds to a greater leak rate.
·    Optical Gas Imaging Instruments.  There are twogeneral classes of such instruments, active and passive instruments. The active type uses a laser beam that is reflected by the background. The attenuation of the beam passing through a hydrocarbon cloud provides the optical image. The passive type uses ambient illumination to detect the difference in heat radiance of the hydrocarbon cloud. Optical gas imaging instruments do not measure leak rates, but allows faster screening of components than FID detectors.
 
One of the following technologies shall be used to measure leak flow rates:
·    Bagging techniques are commonly used to measure flow rates of physical leaks.  The leaking component or leak opening is enclosed in a "bag" or tent.  An inert carrier gas such as nitrogen is conveyed through the bag at a known flow rate.  Once the carrier gas attains equilibrium, a gas sample is collected from the bag and the methane concentration of the sample is measured.  The flow rate of the physical leak from the component is calculated from the purge flow rate through the enclosure and the concentration of methane in the outlet stream as follows:
 
F=  F x w (8)
Where:
F
=
The leak flow rate of methane for leak i from the leaking component (m³CH/h)
F
=
The purge flow rate of the clean air or nitrogen at leak i (m³/h)
w
=
The measured mass fraction of methane in the natural or refinery gas during the crediting year y (kg CH / kg gas)
 
·    High volume or Hi-Flow Samplers capture all emissions from a leaking component to quantify leak flow rates.  Leak emissions, plus a large volume sample of the air around the leaking component, are pulled into the instrument through a vacuum sampling hose.  High volume samplers are equipped with dual hydrocarbon detectors that measure the concentration of hydrocarbon gas in the captured sample, as well as the ambient hydrocarbon gas concentration.  Sample measurements are corrected for the ambient hydrocarbon concentration, and the leak rate is calculated by multiplying the flow rate of the measured sample by the difference between the ambient gas concentration and the gas concentration in the measured sample.  Methane emissions are obtained by calibrating the hydrocarbon detectors to a range of concentrations of methane-in-air.  High volume samplers are equipped with special attachments designed to promote complete emissions capture and to prevent interference from other nearby emissions sources.[6]  The hydrocarbon sensors are used to measure the exit concentration in the air stream of the system.  The sampler essentially makes rapid vacuum enclosure measurements; 
·    Calibrated bag measurements use anti-static bags of known volume (e.g. 0.085 mor 0.227 m) with a neck shaped for easy sealing around the vent.  Measurement is made by timing the bag expansion to full capacity while also employing a technique to completely capture the leak while the inflation is being timed.  The measurement is repeated on the same leak source numerous times (at least 7, typically 7 to 10 times) to ensure a representative average for the fill times (outliers or problem times should be omitted and the tests rerun until a representative average rate is established).  The temperature of the gas is measured to allow correction of volume to standard conditions.  Additionally, the gas composition is measured to verify the proportion of methane in the vented gas, since in some cases air may also be vented, resulting in a mixture of natural gas and air.  Calibrated bags allow for reliable measurement of leak flow rates of more than 250m/h.  The leak flow rate of methane is calculated as follows:
 
F = V x w x 3600 / t (9)
 
Where:
F
=
The leak flow rate of methane for leak i from the leaking component (m³/h)
V
=
Volume of calibrated bag used for measurement (m³)
w
=
The concentration of methane in the sample flow from leak i (volume percent)
t
=
Average bag fill time for leak i (seconds)
 
5.  Monitoring requirements
 
For each component where a physical leak has occurred, the following information should be collected during regular monitoring checks:
·       Date of monitoring;
·       An assessment whether the relevant component has been replaced after the repair of the leak;
·       The number of hours during which the component is in pressurized natural gas or refinery gas service;
·       An assessment whether the repair of the leak functions appropriately.
 
All information should be added to the database and be included in monitoring reports.
Data and parameters monitored
In some cases particular measuring tools may also automatically account for certain parameters that do not need to be separately measured.
 
Data / Parameter:
     
Data unit:
Hours
Description
The time the component x of component type i was leaking during the crediting year y (hours)
Source of data used:
Plant records
Measurement procedures (if any)
Any outages will be recorded
Recording frequency
Constant
Proportion of data to be monitored
100%
QA/QC procedures to be applied
Any outages resulting from system repairs will be documented and logged in the project database in the form of a reduction in the time of operation. To be clear, if an unrelated activity requires the shut-down of an already repaired piece of equipment, the hours of operation for every piece of affected equipment with be reduced in the database for the entire duration of the shut-down. Any other unscheduled shutdown will also be timed and accounted for through a reduction of operating hours
Any comment:
-
 
Data / Parameter:
T       
Data unit:
Hours
Description
The time (in hours) the relevant component has been leaking during the crediting year y
Source of data used:
Plant records
Measurement procedures (if any)
Any outages will be recorded
Recording frequency
Constant
Proportion of data to be monitored
100%
QA/QC procedures to be applied
Any outages resulting from system repairs will be documented and logged in the project database in the form of a reduction in the time of operation. To be clear, if an unrelated activity requires the shut-down of an already repaired piece of equipment, the hours of operation for every piece of affected equipment with be reduced in the database for the entire duration of the shut-down. Any other unscheduled shutdown will also be timed and accounted for through a reduction of operating hours
Any comment:
-
 
 
Data / Parameter:
Temperature and pressure of natural gas
Data Unit
ºC and bar
Source of data used:
Conditions observed at the point and time of the leak rate measurement
Measurement procedures (if any)
-
Recording frequency
At the time of each leak measurement
Proportion of data to be monitored
100%
QA/QC procedures to be applied
Data measurement equipment will be calibrated and double checked on a regular basis. The manufacturer’s recommended calibration procedures shall be applied
Any comment:
Applicable only in the case that option 2 for the calculation of baseline and project emissions is selected
 
Data / Parameter:
T      
Data unit:
Hours
Description
The time the component r of component type i would leak in the baseline scenario and would be eligible for crediting during the crediting year y (hours)
Source of data used:
Plant records
Measurement procedures (if any)
Any outages will be recorded
Recording frequency
Constant
Proportion of data to be monitored
100%
QA/QC procedures to be applied
Any outages resulting from system repairs will be documented and logged in the project database in the form of a reduction in the time of operation. To be clear, if an unrelated activity requires the shut-down of an already repaired piece of equipment, the hours of operation for every piece of affected equipment with be reduced in the database for the entire duration of the shut-down. Any other unscheduled shutdown will also be timed and accounted for through a reduction of operating hours
Any comment:
-
 
Data / Parameter:
T      
Data unit:
Hours
Description
The time the relevant component, in which physical leak j, occurred, would leak in the baseline scenario and would be eligible for crediting during the crediting year y (hours)
Source of data used:
Plant records
Measurement procedures (if any)
Any outages will be recorded
Recording frequency
Constant
Proportion of data to be monitored
100%
QA/QC procedures to be applied
Any outages resulting from system repairs will be documented and logged in the project database in the form of a reduction in the time of operation. To be clear, if an unrelated activity requires the shut-down of an already repaired piece of equipment, the hours of operation for every piece of affected equipment with be reduced in the database for the entire duration of the shut-down. Any other unscheduled shutdown will also be timed and accounted for through a reduction of operating hours
Any comment:
-
 
Data / Parameter:
UR
Data Unit
Fraction
Description:
The uncertainty range for the measurement method applied to leak j
Source of data used:
Manufacturer data and/or IPCC GPG
Measurement procedures (if any)
Estimated, where possible, at a 95% confidence interval, consulting the guidance provided in Chapter 6 of the 2000 IPCC Good Practice Guidance. If leak measurement equipment manufacturers report an uncertainty range without specifying a confidence interval, a confidence interval of 95% may be assumed
Recording frequency
Periodically
Proportion of data to be monitored
100%
QA/QC procedures to be applied
-
Any comment:
Applicable only in the case that option 2 for the calculation of baseline and project emissions is selected
 
Data / Parameter:
UR
Data Unit
Fraction
Description:
The uncertainty range for the measurement method applied to leak z
Source of data used:
Manufacturer data and/or IPCC GPG
Measurement procedures (if any)
Estimated, where possible, at a 95% confidence interval, consulting the guidance provided in Chapter 6 of the 2000 IPCC Good Practice Guidance. If leak measurement equipment manufacturers report an uncertainty range without specifying a confidence interval, a confidence interval of 95% may be assumed
Recording frequency
Periodically
Proportion of data to be monitored
100%
 
QA/QC procedures to be applied
-
Any comment:
Applicable only in the case that option 2 for the calculation of baseline and project emissions is selected
 
Data / Parameter:
w
Data Unit
kg CH/kg gas
Description:
Average mass fraction of methane in the natural gas/refinery gas  for crediting year y
Source of data used:
Direct measurement
Measurement procedures (if any)
 
Recording frequency
Periodically
Proportion of data to be monitored
100%
QA/QC procedures to be applied
For the purpose of determining average mass fraction of methane, a natural gas or refinery gas sample should be collected and chemical analysis should be made in the laboratory
Any comment:
-
 
Data / Parameter:
w
Data Unit
volume percent
Description:
The concentration of methane in the sample flow from leak i
Source of data used:
Direct measurement
Measurement procedures (if any)
 
Recording frequency
Periodically
Proportion of data to be monitored
100%
QA/QC procedures to be applied
-
Any comment:
Applicable only in the case that option 2 for the calculation of baseline and project emissions is selected
 
Data / Parameter:
F/F/
Data unit:
m³CH/h
Description
The leak flow rate of methane for leak (i, z) from the leaking component
Source of data used:
On-site measurements
Measurement procedures (if any)
Procedures requires by manufactures of the equipment used to measure leak flow rates should be followed
Recording frequency
Annual
Proportion of data to be monitored
100%
QA/QC procedures to be applied
-
Any comment:
Applicable only in the case that option 2 for the calculation of baseline and project emissions is selected. The leak flow rate (F) and conversion factor (ConvFactor) should be corrected to the same reference temperature and pressure conditions. For example if value of 0.00067 (IPCC 2006 Vol.2, p. 4.12) is used to convert from m³ CH into t CH, then the flow rate should corrected to reference conditions of 20 degree Celsius and 101.3 kPa
 
Data / Parameter:
F
Data unit:
m³/h
Description
The purge flow rate of the clean air or nitrogen at leak i
Source of data used:
On-site measurements
Measurement procedures (if any)
Procedures requires by manufactures of the equipment used to measure leak flow rates should be followed
Recording frequency
Annual
Proportion of data to be monitored
100%
QA/QC procedures to be applied
-
Any comment:
Applicable only in the case that option 2 for the calculation of baseline and project emissions is selected. The purge flow rate and leak flow rate should be corrected to the same reference temperature and pressure conditions
 
Data / Parameter:
t
Data unit:
sec
Description
Average bag fill time for leak i
Source of data used:
On-site measurements
Measurement procedures (if any)
Procedures requires by manufactures of the equipment used to measure leak flow rates should be followed
Recording frequency
Annual
Proportion of data to be monitored
100%
QA/QC procedures to be applied
-
Any comment:
Applicable only in the case that option 2 for the calculation of baseline and project emissions is selected
 
Data / Parameter:
BE
Data unit:
t COe
Description:
Capped quantity of the baseline emissions, defined as the baseline emissions for the first year of the crediting period
Source of data:
Monitored baselines emissions during the first year of the first crediting period
Value to be applied:
-
Any comment:
-
 
History of the document
Version 
Date
Nature of revision(s)
04.0.0
EB 63, Annex 14
29 September 2011
 
Revision to:
·      Expand the applicability of the methodology to more installations;
·      Introduce an option to use default values;
·      Improve the monitoring section;
·      Improve the clarity of the language;
·      Assess the internal consistency of the methodology;
The revision includes change of title in the methodology from “Leak reduction from natural gas pipeline compressor or gate stations to “Leak detection and repair in gas production, processing, transmission, storage and distribution systems and in refinery facilities”.
Due to the overall modification of the document, no highlights of the changes are provided.
03
EB 50, Annex 4
16 October 2009
The methodology was revised in response to AM_REV_0161, to expand scope of the applicable leak flow rate measurement techniques to include calibrated bags and ultrasonic meters.
02.1
EB 45, Annex 7
13 February 2009
Editorial revision to adjust the text in the Project Boundary section to be consistent with the Applicability Conditions section as modified from version 01 to version 02 of this methodology.
02
EB 31, Annex 10
4 May 2007
Revision to expand the applicability of the approved methodology to project activities that reduce leakage in distribution systems above ground.
01
EB 20, Annex 13
8 July 2005
Initial adoption.
Decision Class
: Regulatory
Document Type
: Standard
Business Function
: Methodology

 
 

[1] <http://www.energy.ca.gov/oil/refinery_output/definitions.html>. updated 2002. [2] <http://www.ipcc-nggip.iges.or.jp/public/gl/guidelin/glosri.pdf> IPCC. [3] <http://unfccc.int/resource/cd_roms/na1/ghg_inventories/english/8_glossary/Glossary.htm>. [4] <http://stats.oecd.org/glossary/detail.asp?ID=4621> based on Energy Statistics of OECD Countries: 1999-2000, 2002 Edition, International Energy Agency, Paris, Part 2 – Notes on Energy Sources. Created 2002. [5] See, for example: <http://www.iso.org/iso/iso_catalogue/catalogue_tc/catalogue_detail.htm?csnumber=29242> and <http://www.iso.org/iso/iso_catalogue/catalogue_tc/catalogue_detail.htm?csnumber=31170>. [6]  The background concentration must be subtracted from the main sample concentration because it may be elevated due to other leaks in the vicinity of the leak being measured.  Variables such as wind speed and wind direction may cause the background concentration to fluctuate, so the background is measured simultaneously with the sample concentration.



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