Instrument Gas to Air Module

8/13/2019 Instrument Gas to Air Module

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Meta-Protocol forOil and Gas Emission Reduction Projects:

Module for Instrument Gas to Instrument AirConversion in Process Control Systems

Developed by Blue Source Canada for the Pacific Carbon TrustMarch 2011Version 1.1


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Table of Contents

1. Project Scope and Description .......................................................................... 2

2. Module Scope and Description ........................................................................ 2

2.1. Module Approach ............................................................................................. 22.2. Module Applicability ......................................................................................... 32.3. Protocol Flexibility ............................................................................................ 4

3. Project Reporting .............................................................................................. 6

4. Glossary of New Terms ..................................................................................... 8

5. Quantification Development and Justification ................................................. 95.1. Identification of the SSRs in the Project Condition .......................................... 95.2. Identification of the Baseline .......................................................................... 125.3. Identification of SSRs in the Baseline Condition ............................................. 12

5.4. Selection of Relevant Project and Baseline SSRs ............................................ 145.5. Quantification of Reductions, Removals and Reversals of Relevant SSRs ..... 175.5.1. Quantification Approaches ....................................................................... 175.5.2. Accuracy .................................................................................................... 27

List of Appendices

Appendix A: Flexibility MechanismsAppendix B: Contingent Data ApproachesAppendix C: Gas Equivalency and Leakage

List of Tables

Table 3.1: Key Data Project Reporting Table ...................................................................... 7 Table 5.1: Project SSRs ...................................................................................................... 10 Table 5.3: Baseline SSRs .................................................................................................... 13 Table 5.4: Comparison of SSRs .......................................................................................... 15 Table 5.5: Quantification Procedures ............................................................................... 18

List of Figures

Figure 2.1: Process Flow Diagram for Project Condition .................................................... 5 Figure 2.2: Process Flow Diagram for Baseline Condition 1, ................................................ 5 Figure 5.1: Project Element Lifecycle Chart ........................................................................ 9 Figure 5.2: Baseline Element Lifecycle Chart .................................................................... 13


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This module is an adaptation of the Alberta Offset System Quantification Protocol forInstrument Gas to Instrument Air Conversion in Process Control Systems. It is meant tobe used in conjunction with the Meta-Protocol Introduction and is not a standalonedocument.

1. Project Scope and DescriptionWells, oil producing facilities, gas producing facilities, and gas processing facilities oftenuse pneumatic devices for process control. Natural gas is often used to power processcontrol equipment, which includes pressure controllers, temperature controllers,transducers, liquid level controllers, and flow rate regulators. These devices have one ortwo emission rates depending on the design: continuous bleed rate and intermittentvent rate. For the purpose of this module, these two emission rates will be referred toas bleed/vent rate, which is the term commonly used in the oil and gas industry.

The opportunity to generate carbon offsets with this module arises from the direct andindirect reduction of greenhouse gas emissions from the conversion of instrument gasto instrument air in process control systems. Instrument air will be provided bycompressed air. Therefore, a complete air compressor system will be needed for thisconversion.

It is assumed that a natural gas pressure source will be converted to an air pressuresource. It should be noted that any volume of natural gas that would have been ventedwill now be avoided by this conversion. The final fate of the gas that has been conservedbecause of the instrument air conversion is assumed to be combusted by end-users,unless otherwise indicated.

2. Module Scope and Description

A process flow diagram for a typical project using compressed air to provide pressure toinstrument controllers is shown in Figure 2.1. Upon conversion, all methane that wouldhave been vented will be replaced by air.

2.1. Module Approach

The baseline condition for this module is defined as the volume of natural gas vented tothe atmosphere prior to the conversion to instrument air. In this baseline scenario,instrument gas is typically sourced from the fuel gas supply for the entire facility. Aprocess flow diagram for a typical baseline where fuel gas is used to provide pressure topneumatic controllers is shown in Figure 2.2 .

In the baseline condition, vented gas is not metered. Establishing volumes of vented gaswill be performed by converting volumes of air metered in the project condition to


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equivalent volumes of gas that would have been used in the baseline through anequivalency calculation. This module uses data from metered air to establish the volumeof natural gas that would have been vented had the project not taken place. Furtherexplanation of how to establish this equivalency is found in the Appendix C.

For facilities installing an air compressor system to power pneumatic instruments,metering of air volumes is straightforward. Metered air will provide volumes that can beused to establish the equivalent fuel gas vented. However, some facilities may use anair compressor system for other applications that do not reduce methane emissions, sometering must account for only the air used for instrumentation. Meters should beinstalled such that both the total air compressed/managed by the system and the aircompressed/managed specifically for instrumentation can both be determined. Careshould be taken to ensure that meters for instruments do not include other pneumaticequipment. However, in such cases air consumed by the pneumatic instruments can beprorated against the total metered amount of compressed air.

2.2. Module Applicability

To demonstrate that a project meets the requirements under this module, the projectdeveloper must supply sufficient evidence to demonstrate that:

1. Pneumatic instruments are designed to operate using a pressurized gas (i.e. 20or 35 psi for commercially available devices), regardless of the gas type. As aresult, the instrument air system must be designed to provide this same level ofpressure that the instrument gas system would have provided to ensure

functional equivalency as demonstrated by unit operational performance data,and/or facility process flow diagrams and/or other equipment technicalspecifications. Functional equivalence may also be demonstrated through anaffirmation by the project developer or a third party.

2. The protocol is applicable to projects that retrofit or replace existing instrumentgas systems (including end of life replacements) with instrument air systems, andto facilities that were originally constructed to use instrument air. The inclusionof end of life replacements and new facilities is appropriate provided that theproject proponent can demonstrate additionality.

3. The project proponent must inspect and repair leaks from an instrument gassystem prior to implementing an instrument air project in order to reduce andmitigate risks associated with overestimation of emissions.

Prior to the implementation of the instrument air system and metering, theproject proponent must demonstrate that the instrument ai r systems pipingnetwork has been inspected for leaks meeting or exceeding standards from the


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CAPP Best Management Practice (BMP) for Fugitive Emissions Management. ThisBMP suggests annual or quarterly leak monitoring frequencies depending on theprocess equipment device. Following these steps should guarantee that leakshave been minimized as much as practically possible. This will ensure thatmetering does not overestimate volumes of air, which in turn determines the

volumes of gas that would have been vented had the project not taken place. Ifinspection for leaks is not performed according to suggested monitoringfrequencies, metered air must be reduced using a discount factor. This factor isdeveloped in detail in Appendix A.

4. For projects installed prior to this module that are currently not metered, thesame principle applies as detailed above. Prior to the installation of a meteringsystem, leaks should be minimized as much as practically possible, otherwise adiscount factor is used.

2.3. Protocol Flexibility

Flexibility in applying the quantification protocol is provided to project developers in thefollowing ways.

1. For projects where part of the vented gas is flared or collected for combustion,the project proponent may claim credits using this pr otocols flexibilitymechanism. The total metered air is divided into two fractions; X represents thevented fraction and (1-X) represents the flared or combusted fraction. Refer toAppendix A for a detailed explanation on how these percentages are established.

2. This module has been designed for specific use in natural gas compressorstations, batteries, gathering systems, processing plants and similar facilities.However, other facilities in the oil and gas industry use instrument gas to providepressure to pneumatic devices. This protocol may be applied to projects whereexisting facilities where fuel gas provides pressure to instrumentation, chemicalinjection pumps or other types of equipment.

3. For cases in which projects were implemented but the instrument air volumeswere was not directly metered, emission reductions may be quantifiedretroactively after one year of monitoring has been completed, if additionalrecords are obtained to substantiate the inventory of pneumaticinstrumentation in operation during the baseline period at the site. Historic run-time of equipment should also be established to ensure that the one-year ofmetering is reflective of operating conditions in the baseline. More Refer toAppendix A for further details.


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Figure 2.1: Process Flow Diagram for Project Condition 1

Figure 2.2: Process Flow Diagram for Baseline Condition 1,2

1 It is assumed that only natural gas from the facility supply is used, so P/B 1 Fuel Processing andExtraction and P/B 2 Fuel Delivery are excluded from process flow diagrams.2 This process flow diagram may not represent all configurations. Flared/combusted gas is not included inthis figure, but can be quantified using the flexibility mechanism found in Appendix A.

P4 AirManagement

System

P5Air Compression

P6Raw Gas

Production

P9 ProcessedGas Distribution

and Sale

P8Raw Gas

Processing

P7Raw Gas

Transportation

B6Raw Gas

Production

B9 ProcessedGas Distribution

and Sale

B8Raw Gas

Processing

B7Raw Gas

Transportation

B10Fuel Gas for

Facility

P10Fuel Gas forFacility

B5Vented Fuel

Gas

P3b GridTransmission

Losses

P3a GridElectricity

Generation

B3bTransmission

Losses

B3a GridElectricity

Generation

P11 ElectricityGeneration

(On-Site)

P1 FuelExtraction/Processing

P2Fuel

Delivery

B11 ElectricityGeneration

(On-Site)

B1 FuelExtraction/Processing

B2Fuel

Delivery

B4Instrument

Control Process


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3. Project Reporting

The project reporting table provided below is meant to assist validators and verifiers inidentifying key project data monitoring requirements. These are the minimummonitoring requirements necessary to quantify emissions. The information in Table 3.1is not intended to provide a complete summary of monitoring requirements. It is theresponsibility of project proponents to correctly quantify emissions reductions usingthe methods set out in this module.

In addition, the following checklist serves as a summary of module applicabilityrequirements that may be reviewed to ensure that each project meets the requirementsof this module. It is the responsibility of project proponents to correctly assessapplicability requirements as laid out in this module.

Applicability Checklist

The compressed air system in project condition and the compressed gas systemin baseline condition operate at the same pressure. An inventory of pneumatic devices is documented at the start of the project and

updated annually. A leak management system is in place, based on the CAPP Best Management

Practices or equivalent.


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Table 3.1: Key Data Project Reporting TableInstrument Air to Instrument Gas Reporting Table

Retrofit ID: Yearly Monitoring Requirements

Date of Fuel GasAnalysis

Basin/Site Location ofFuel Gas Analysis

CH4 Contentof Gas

CO2 Contentof Gas

EquipmentRuntime (Project)

EquipmentRuntime (Baseline)

Emission Factor(Off-Grid Generation)

- - % % hours hours kg CO 2e /kWh

Monthly Monitoring Requirements 3 Month Volume of Air Compressed

for PneumaticInstrumentation

Total Volume ofCompressed Air

Air Managed for PneumaticInstrumentation

Total Volume of AirManaged

EmissionReductions

- m 3 m 3 m 3 m 3 t CO2eJanuary

FebruaryMarchAprilMayJuneJuly

AugustSeptember

OctoberNovemberDecember

3Monthly totals should be provided where continuous monitoring is required.


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4. Glossary of New Terms

Instrument Air Any instrument that uses pressurized compressed air to

function and provides the necessary level of controlrequired for its intended use.

Bleed Rate Rate at which a device uses air or natural gas continuouslydue to design requirements. Rates may vary in the fielddue to changing conditions.

Fuel Gas Portion of the sales gas used for facility operations such asfuel for engines and compressors, pressure supply forpneumatic devices, etc.

Instrument Gas Any instrument that uses pressurized natural gas tofunction and provided the necessary level of controlrequired for its intended use.

Leak Unintentional emissions from worn seals, gaskets, anddiaphragms, nozzle corrosion or wear from poor qualitygas leading to increased flow, and loose control tubefittings in a pneumatic instrument.

Vent Rate Rate at which a device uses air or natural gasintermittently due to design requirements. Rates mayvary in the field due to changing conditions. In thisprotocol, vent rate is use dot describe the sum of bothbleed and vent rates.


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5. Quantification Development and Justification

5.1. Identification of the SSRs in the Project Condition

Based on the process diagrams provided in Figure 2.1 , the projects SSRs were organized

into lifecycle categories in Figure 5.1. A description of each of the SSRs and theirclassification as controlled, related or affected are provided in Table 5.1. Note that SSRspreviously defined in the Meta-Protocol Introduction are excluded from Figure 2.1 andTable 5.1 for brevity.

Figure 5.1: Project Element Lifecycle ChartUpstream SSRs During Project

Upstream SSRsBefore Project

On Site SSRs During Project Downstream SSRs After Project

Downstream SSRs During Project

P5Air Compression

P4 AirManagement

System

P11 ElectricityGeneration

(On-Site)

P6Raw Gas

Production

P7Raw Gas

Transportation

P8Raw Gas

Processing

P10 Fuel Gasfor Facility

Processes

P9 ProcessedGas Distribution

and Sale


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Table 5.1: Project SSRs1. SSR 2. Description 3.Controlled,

Related, orAffected

Upstream SSRs During Project OperationP6 Raw Gas

Production

The raw gas is collected from a group of adjacent wells where

moisture content is reduced by removing water and condensate.Condensate is transported to other facilities for further processingand wastewater is disposed of. The quantity of methane and CO 2 inthe raw gas would need to be tracked. The types and quantities offuels used in extraction equipment would also need to be tracked.Leaks may also be present in the production facility and should betracked too.

Related

P7 Raw GasTransportation

The raw gas is piped to a natural gas processing plant. The typesand quantities of fuels used in transportation would need to betracked. Leaks may also be present in the pipeline and should betracked also.

Related

P8 Raw Gas

Processing

Processing of raw gas is required to remove hydrogen sulphide,

carbon dioxide, water vapour, and heavier hydrocarbons. Clean gasis ready to be distributed and sold. Heavier hydrocarbons are alsoremoved and transported to oil refineries. The quantity ofgreenhouse gas in the processed gas would need to be tracked.Leaks may also be present in the production facility and should betracked too. Possibility of venting gas must also be considered andtracked.

Related

P10 Fuel GasFor FacilityProcesses

Many processes in the facility require clean gas to function. Thisclean gas, also referred to as fuel gas, is drawn from the processedgas that will be sold. Equipment in the processes includescompressors, boilers, heaters, engines, glycol dehydrators,refrigerators, and chemical injection pumps (CIP). The types andquantities of fuels used in processing would need to be tracked.Leaks may also be present in the production facility and should betracked too.

Related

P11 ElectricityGeneration(On-Site)

Electricity may be required for operating the compressors or airmanagement system. This power is sourced from internalgeneration. Quantity and source of the power are the importantcharacteristics to be tracked as they directly relate to the quantityof greenhouse gas emissions.

Controlled

Onsite SSRs During Project Operation

P4 AirManagementSystem

Compressed air will pass from the air compressor to the volumetanks and then through the control instrumentation whenactivated. This air may require conditioning such as drying byspecialized equipment prior to distribution in the air instrument

network. Equipment for the air management system may consumeenergy and needs to be tracked.

Controlled

P5 AirCompression

Air will be used to supply pressure to the pneumatic controlinstruments. The energy required for the compressors to functionwill come from various sources. Quantity and source of theelectricity source are the important characteristics to be tracked asthey directly relate to the quantity of greenhouse gas emissions.

Controlled


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Downstream SSRs During Project OperationP9 ProcessedGasDistributionand Sale

Natural gas and other commercially viable NGL products may besent to a pipeline system or transported by rail or truck tocustomers at another point. Greenhouse gas emissions are avoidedfrom the conservation of fuel gas that was supplied to the controlinstrumentation in the baseline. It is assumed that the mostly likely

use of avoided fuel gas consumption would be controlledcombustion to produce carbon dioxide.

Related

OtherN/A


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5.2. Identification of the Baseline

The selected baseline scenario is a projection based approach. In this method ofquantification, the total volume of compressed air in the project condition represents an

equivalent amount of compressed gas in the baseline condition after an equivalencyfactor has been applied, thus establishing functional equivalence between the baselineand the project condition.

Baseline emissions are determined from the metered quantity of compressed air andthrough the use of a gas equivalence factor as described in Appendix C. Once the air hasbeen metered, the gas equivalency is applied. This will yield the amount of fuel gas thatwould have been vented. Note that this equivalency is in terms of pure methane (100%in gas composition). The equivalent volume is then adjusted to take into account thepercent of methane and carbon dioxide present in this fuel gas based on an annual gasanalysis.

Pneumatic devices are designed to run at specific supply pressures, regardless of thepressure source. In the gas equivalency formula presented in Appendix C, pressure isassumed to be equal in the instrument gas and instrument air condition. Therefore, theenergy losses in both the fuel gas system and air management system are equal. As aresult, this baseline methodology ensures functional equivalence because pressures andlosses in the baseline and project conditions are assumed to be equal. This is anindustry-accepted methodology to compare air usage and fuel gas usage in processcontrol systems.

5.3. Identification of SSRs in the Baseline Condition

The baseline condition is defined, including the relevant SSRs and processes, as shown inTable 5.2 provides descriptions of each SSR. Again, SSRs previously defined are excludedfrom Figure 2.2 and Table 5.2.


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Figure 5.2: Baseline Element Lifecycle ChartUpstream SSRs During Project

Upstream SSRsBefore Project

On Site SSRs During Project Downstream SSRs After Project

Downstream SSRs During Project

Table 5.2: Baseline SSRs1. SSR 2. Description 3.Controlled,

Related, or AffectedUpstream SSRs During Project OperationB6 Raw Gas

Production

The raw gas is collected from a group of adjacent wells where

moisture content is reduced by removing water and condensate.Condensate is transported to oil refineries for further processingand wastewater is disposed. The quantity of greenhouse gas inthe raw gas would need to be tracked. The types and quantitiesof fuels used in extraction equipment would also need to betracked. Leaks may also be present in the production facility andshould be tracked too.

Related

B7 Raw GasTransportation

The raw gas is piped to a natural gas processing plant. The typesand quantities of fuels used in transportation would need to betracked. Leaks may also be present in the pipeline and should betracked also.

Related

B8 Raw GasProcessing

Processing of raw gas is required to remove hydrogen sulphur,carbon dioxide, water vapour, and heavier hydrocarbons. Cleangas is ready to be distributed and sold. Heavier hydrocarbonsare also removed and transported to oil refineries. The quantityof greenhouse gas in the processed gas would need to betracked. Leaks may also be present in the production facility andshould be tracked too. Possibility of venting gas must also beconsidered and tracked.

Related

B10 Fuel GasFor Facility

Many processes in the facility require clean gas to function. Thisclean gas, also referred to as fuel gas, is drawn from the

Related

B5Vented

Fuel Gas

B4Instrument

Process Control

B11 ElectricityGeneration

(On-Site)

B6Raw Gas

Production

B7Raw Gas

Transportation

B8Raw Gas

Processing

B10 Fuel Gasfor FacilityProcesses

B9 ProcessedGas Distribution

and Sale


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processed. Equipment in the processes include compressors,boilers, heaters, engines, glycol dehydrators, refrigerators, andchemical injection pumps (CIP), The types and quantities of fuelsused in processing would need to be tracked. Leaks may also bepresent in the production facility and should be tracked too.

B11 ElectricityGeneration(On-Site)

Electricity may be required for operating the compressors or air

management system. This power is sourced from internalgeneration. Quantity and source of the power are the importantcharacteristics to be tracked as they directly relate to thequantity of greenhouse gas emissions.

Controlled

Onsite SSRs During Project Operation

B4 InstrumentControlProcess

Pressurized gas will pass from the fuel gas supply and thenthrough the control instruments when activated. The pressureof the gas is equivalent to the pressure that the project willprovide to the instruments once the conversion has taken place.

Controlled

B5 Vented FuelGas

Quantity of gas will need to be tracked because it represents theamount of fuel gas that is vented to the atmosphere once it hasbeen used by pneumatic instruments. The quantity can becalculated or estimated.

Controlled

Downstream SSRs During Project OperationB9 ProcessedGasDistributionand Sale

Natural gas and other commercially viable NGL products may besent to a pipeline system or transported by rail or truck tocustomers at another point. The mostly likely use would becontrolled combustion to produce carbon dioxide.

Related

OtherN/A

5.4. Selection of Relevant Project and Baseline SSRs

Each of the SSRs from the project and baseline condition were compared and evaluatedas to their relevancy in quantification of GHG emissions and reductions usingISO 14064-2. SSRs were identified as controlled, related or affected and included orexcluded for quantification. The justification for the exclusion or conditions upon whichSSRs may be excluded is provided in Table 5.3, below.


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Table 5.3: Comparison of SSRs

1. Identified SSR2. Baseline(C, R, A)

3. Project(C, R, A)

4. Include or Excludefrom Quantification

5. Justification for Exclusion

Upstream SSRsP6 Raw Gas Production N/A Related Excluded Excluded as the production of raw gas is not impacted by the

implementation of the project and as such the baseline and the projectconditions will be functionally equivalent.

B6 Raw Gas Production Related N/A Excluded

P7 Raw Gas

TransportationN/A Related Excluded Excluded as the transportation of raw gas is not impacted by the

implementation of the project and as such the baseline and the projectconditions will be functionally equivalent.B7 Raw Gas

TransportationRelated N/A Excluded

P8 Raw Gas Processing N/A Related Excluded Excluded as the processing of raw gas is not impacted by the implementationof the project and as such the baseline and the project conditions will befunctionally equivalent.B8 Raw Gas Processing Related N/A Excluded

P10 Fuel Gas For Facility N/A Related Excluded Excluded as the fuel gas for facility is not impacted by the implementation ofthe project and as such the baseline and the project conditions will befunctionally equivalent.

B10 Fuel Gas For Facility Related N/A Excluded

B4 Instrument ControlProcess Related N/A Excluded

Excluded as instrument control processes are not impacted by the projectand as such the baseline and the project conditions will be functionallyequivalent.

P11 Electricity Generation N/A Controlled Excluded Accounted for under P5 Air Compression and P4 Air Management System

B11 Electricity Generation(On-Site)

Controlled N/A Excluded No electricity is consumed in the baseline condition

Onsite SSRsP5 Air Compression N/A Controlled IncludedGrid electricity consumed by these SSRs is negligible and therefore excluded.P4 Air Management

SystemN/A Controlled Included

B5 Vented Fuel Gas Controlled N/A Included N/AB6 Flared / CombustedFuel Gas

Controlled N/A Included N/A

Downstream SSRsP9 Processed GasDistribution and Sale

N/A Related ExcludedExcluded as the emissions from the distribution and sale of avoided ventedgas is the sole responsibility of the end user. It is assumed the final use of


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this gas will be controlled combustion to produce carbon dioxide.Accountability of this gas is in the hands of end users.

B9 Processed GasDistribution and Sale Related N/A Excluded

Excluded as the emissions from the distribution and sale of gas is the soleresponsibility of the end user and it is assumed the final use of this gas willbe controlled combustion to produce carbon dioxide.

OtherN/A


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5.5. Quantification of Reductions, Removals and Reversals of RelevantSSRs

5.5.1. Quantification Approaches

Quantification of the reductions, removals and reversals of relevant SSRs for each of thegreenhouse gases will be completed using the methodologies outlined in Table 5.4below. These calculation methodologies serve to complete the following threeequations for calculating the emission reductions from the comparison of the baselineand project conditions.

Baseline emissions were estimated using a projection based approach to quantify thedynamic and site-specific volume of natural gas vented to the atmosphere in thebaseline using measured air flow volumes in the project condition. Project emissionswere quantified by the direct monitoring of the volume of fuel or electricity consumed

by the compression and air management system.

where:

Emissions Baseline = sum of the emissions under the baseline condition.Emissions Vented Fuel Gas = emissions under SSR B5 Vented Fuel Gas

Emissions Project = sum of the emissions under the project condition.Emissions Air Compression = emissions under SSR P5 Air CompressionEmissions Air Management System = emissions under SSR P4 Air Management System

Emissions Project = Emissions Air Compression + Emissions Air Management System

Emissions Baseline = Emissions Vented Fuel Gas

Emission Reduction = Emissions Baseline Emissions Project


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Table 5.4: Quantification Procedures

1. Project /Baseline SSR

2. Parameter /Variable 3. Unit

4. Measured/ Estimated 5. Method 6. Frequency

7. Justify measurementor estimation andfrequency

Project SSRs

P5 AirCompression

The following equation (1) should be used to calculate emissions from Air Compression for projects that use on-site electricity generated from fossil fuels.

1. Emissions Air Compression = (Vol. Fuel i EF Fuel i CO2 Site Compressed Air Control Instruments i ) / (Total Produced Air i); (Vol. Fuel i EF Fuel i CH4 Compressed Air Control Instruments i ) / (Total Produced Air i); (Vol. Fuel i EF Fuel i N2O Compressed Air Control Instruments i ) / (Total Produced Air i)

The following equation (2) should be used when it is not possible to meter the volume of fuel consumed from on-site generation.

2. Emissions Air Compression = (ECI EF Electricity CO2e Compressed Air Control Instruments i ) / (Total Produced Air i);

Emissions AirCompression

kg of CO2e N/A N/A N/AQuantity being calculatedin aggregate form as fueluse on site is likelyaggregate for each ofthese SSRs.

Compressed AirUsed forPneumatic

Instrument /Compressed AirControl Instruments i

m 3 Measured

Direct monitoring of massflow rate (flow meter) orcumulative volume(totalizer) of aircompressed and sent tocontrol instrument pipenetwork

Flow meter: minimumhourly measurements

Totalizer: continuousmetering withminimum monthlyrecording of values

Both methods arestandard practice.Frequency of metering

accurately captures flowrate or volume of air sentto instrumentation

Total Air Producedin Air CompressorSystem byCompressor i /Produced Air i

m 3 Measured

Direct monitoring of massflow rate (flow meter) orvolume (totalizer) of totalair compressed


Totalizer: continuousmetering with

minimum monthlyrecording of values

Both methods arestandard practice.Frequency of meteringaccurately captures flowrate or volume of aircompressed.


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Volume of FossilFuel i Combustedfor P 5 to ProduceElectricity for theAir CompressionSystem/ Vol. Fuel i

m 3 Measured Reconciliation of volumes Monthly

Frequency ofreconciliation accuratelycaptures fuelconsumption

CO2 Site SpecificEmissions Factorfor Combustion ofFuel Gas/ EF Fuel iCO2 Site

kg CO2e / m3 Measured

Using gas compositionanalysis, a site specific

emission factor can bedeveloped using theequation presented inAppendix A, Section A1 ofthe Meta-ProtocolIntroduction. Where gascomposition is notavailable, the emissionfactor for producerconsumption of naturalgas may be used which canbe found in Table A1 ofthe Meta-ProtocolIntroduction.

Annual

The use of site specificfuel gas analyses todetermine the carboncontent of the fuel gasrepresents best practice.This approach accountsfor variability in naturalgas composition from siteto site. Reference valuesadjusted annually as partof Environment Canadareporting on Canada'semissions inventory.

CH4 EmissionsFactor for EachType of Fuel i / EFFuel CH4

kg CH4 per m3 Estimated

From Environment Canadareference documents

Annual

Reference values adjustedannually as part of

Environment Canadareporting on Canadasemissions inventory. Ifequipment specific CH 4 emission factors areavailable from US EPA AP-42 or the equipmentmanufacturer, then thedefault EC values may besubstituted.


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N2O EmissionsFactor for EachType of Fuel i / EFFuel N2O

kg N2O per m3 Estimated


Annual

Reference values adjustedannually as part ofEnvironment Canadareporting on Canadasemissions inventory. Ifequipment specific N 2Oemission factors areavailable from US EPA AP-

42 or the equipmentmanufacturer, then thedefault EC values may besubstituted.

ElectricityConsumed by AirCompressor i /EC i

kWh Measured Direct metering

Continuous meteringusing a standard

electricity meter orreconciliation of

equipment ratings andoperating hours

Continuous meteringprovides accurate, directmeasurement ofelectricity consumed byproject. Reconciliation isadequate given the smallsize of the electric motors

Emission Factorfor Grid Electricity/ EF Electricity tCO2e /kWh Estimated

The emission factor shouldbe determined usingEquation A3 from theMeta-ProtocolIntroduction.

Once

This method ofcalculation provides areasonable andconservative estimate ofthe parameter.


The following equation (1) should be used to calculate emissions from Air Management System for projects that use on-site electricitygenerated from fossil fuels.

1. Emissions Air Management System = (Vol. Fuel i EF Fuel i CO2 Site Managed Air Control Instruments i ) / (Total Managed Air i); (Vol. Fuel i EF Fuel i CH4 Managed Air Control Instruments i ) / (Total Managed Air i); (Vol. Fuel i EF Fuel i N2O Managed Air Control Instruments i ) / (Total Managed Air i).

The following equation (2) should be used when it is not possible to meter the volume of fuel consumed from on-site generation.

2. Emissions Air Management System = (ECI EF Electricity Managed Air Control Instruments i ) / (Total Managed Air i);


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Emissions AirManagement System

kg of CO2e N/A N/A N/A

Quantity being calculatedin aggregate form as fueluse on site is likelyaggregate for each ofthese SSRs.

Managed Air byAir ManagementSystem i /Managed Air ControlInstruments i

m 3 Measured

Direct monitoring of massflow rate (flow meter) orvolume (totalizer) of airmanaged and sent tocontrol instrument pipenetwork and volumes ofair being managed andused for engine starters




Both methods arestandard practice.Frequency of meteringaccurately captures flowrate or volume of air sentto instrumentation

Total Air Managedby AirManagementSystem i/ TotalManaged Air i

m 3 Measured

Direct monitoring of massflow rate (flow meter) orvolume (totalizer) of airbeing managed




Both methods arestandard practice.Frequency of meteringaccurately captures flowrate or volume of beingmanaged.

Volume of FossilFuel i Combustedfor P 4 to ProduceElectricity for theAir ManagementSystem/ Vol. Fuel i

m 3 Measured Reconciliation of volumes Monthly

Frequency ofreconciliation accuratelycaptures fuelconsumption


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N2O EmissionsFactor for EachType of Fuel i / EFFuel N2O

kg N2O per m3 Estimated


Annual

Reference values adjustedannually as part ofEnvironment Canadareporting on Canadasemissions inventory. Ifequipment specific N 2Oemission factors areavailable from US EPA AP-

42 or the equipmentmanufacturer, then thedefault EC values may besubstituted.

ElectricityConsumed by AirManagementSystem i /EC i

kWh Measured Direct metering

Continuous meteringusing a standard

electricity meter orreconciliation of

equipment ratings andoperating hours

Continuous meteringprovides accurate, directmeasurement ofelectricity consumed byproject. Reconciliation isadequate given the smallsize of the electric motors

Emission Factorfor Grid Electricity/ EF Electricity

tCO2e /kWh Estimated

The emission factor shouldbe determined usingEquation A3 from theMeta-ProtocolIntroduction.

Once

This method ofcalculation provides areasonable andconservative estimate ofthe parameter.

Baseline SSRs


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B5 Vented FuelGas

The following equations 4 are used to establish baseline emissions based on metered compressed air powering the pneumatic instrumentsonce the air conversion has taken place. Equation (1) is for the vented CH 4 and will always be used. Typically, the percentage of CH 4 in fuelgas is in excess of 85% and can be as much as 99%. Equation (2) is used to establish baseline emission for vented CO 2.

Emissions Fuel Gas for Control Instruments =

1. Compressed Air Control Instruments i GWP CH

F

F

G

G DR CH

AIR

k

CH

AIR **%*

*311

*31

1

**)1(* 444

;

2. Compressed Air Control Instruments i 1644

*%%

**%*

*31

1

*31

1

**)1(*4

244

4 CH CO

CH

F

F

GG

DR CH

AIR

k

CH

AIR

;

where

4.1k

F

Emissions Fuel Gas ForControl Instruments

kg of CO2e N/A N/A N/A

Quantity being calculatedin aggregate form as fueluse on site is likelyaggregate for each of

these SSRs.

4 These equations are derived using methods outlined in Appendix A of the Alberta Offset Systems Quantification Methodology fo r Instrument Gas toInstrument Air Conversion in Process Control Systems, Version 1.0, October 2009.


26/55

Page 25 |

Compressed AirUsed forPneumaticInstruments i/Compressed AirControl Instruments i

m 3 Measured

Direct monitoring of massflow rate (flow meter) orvolume (totalizer) of aircompressed and sent tocontrol instrument pipenetwork as determined inP6




Both methods arestandard practice.Frequency of meteringaccurately captures flowrate or volume of air sentto instrumentation.Values must be adjustedto 15C and 101.3 kPa. 5

Discount Rate dueto Leaks / DR

% Estimated

1. DR(%)=0 if inspectionoccurred < 1 year2. DR(%)= 2.5 %*minimumyear intervalfor 1< year < 103. DR(%)= 25% foryear > 10

N/A

Leaks are taken intoaccount when air ismetered to adjust thebaseline. The year of lastdocumented inspectionand maintenance is takeninto account in parameterminimum year interval.A 2.5% per annumincrease due to leaks isassumed.

Specific Gravity ofAir /G AIR

- Estimated 1.00 at NTP N/A Accepted value.

Specific Gravity ofMethane / G CH4


Density ofMethane / CH4 kg / m

3 Estimated0.678 kg/m 3 at 15C and101.325 kPa N/A

All volumes must be

adjusted to 15C and101.325 kPa.

5 The pressure at which the instrument air system operates under steady state conditions is constant and is found in the design considerations of thecompressed air system.


27/55

Page 26 |

Global WarmingPotential ofMethane/ GWP CH4

kg CO2e/kg CO2

Estimated From IPCC Annual

The GWP of CH 4 is 21, asper IntergovernmentalPanel on Climate Change(IPCC) and InternationalStandards Organization(ISO).

Specific Heat Ratiofor CH4 / k

- Assumed 1.31 at STP N/A Accepted value.

Specific Heat Ratiofor air / k

- Assumed 1.40 at STP N/A Accepted value.

MethaneComposition inFuel Gas / % CH 4

% Measured Direct measurement Annual

Fuel gas compositionshould remain relativelystable during steady-stateoperation.

Carbon DioxideComposition inFuel Gas / % CO 2

% Measured Direct measurement Annual

Fuel gas compositionshould remain relativelystable during steady-stateoperation.


28/55

Page 27 |

5.5.2. Accuracy

Most parameters, such as compressed air and volume of fuel used for compression, canbe accurately monitored. The direct metering of air volumes accounts for variations in

instrument gas demand due to operational factors.

To ensure the baseline condition is not overestimated, a leak repair program must beused or else baseline emissions are conservatively discounted by a larger percentageeach year without the program. Additionally, some uncertainty exists in the moduleassociated with the commissioning and decommissioning of devices, but this can bemitigated through the development and regular update of an inventory of pneumaticdevices.


29/55

APPENDIX A: FLEXIBILITY MECHANSIMQUANTIFICATION


30/55

A-I

A.I Retroactive Credits

To facilitate verification of retroactive credits, the project proponent should identify therun time of principle equipment such as compressors, dehydrators, or other equipmentwithin the facility, or provide other facility-specific supporting documentation to

demonstrate continuity of operations. In the event that instrument counts cannot bedeveloped for a facility in the past, the proponent can use the aforementioned evidenceto demonstrate that a significant change to the facility had (or had not) occurred.

The project developer will estimate emission reductions from the unmetered periodusing average emission reductions created by the project. This estimate will be basedon at least one year of project metering and account for any differences in operationtime. This average reduction will be discounted based on instrument counts and ventrates from the manufacturer s technical specifications . For conservativeness,adjustments are only to be made for equipment which was commissioned beforemetering.

Due to the level of uncertainty associated with manufacturers technical specifications,the sum of the volume of air commissioned must not exceed 10% of the total volume ofair used for pneumatic instrumentation. If this is the case, proponents are not eligibleto claim retroactive credits.

The following equation shows how adjusted emission reductions are quantified.

Where:

ER = estimated emission reductions for unmetered period (tCO 2e);ER = average emission reductions from project (tCO 2e);VRi = vent rate of commissioned instrument i using manufactures technical

specifications (m 3/h);t i = time from installation of instrument to time when project was metered,

conservatively assuming complete hours of operation (8760 hours/year)

DR = leak discount rate (%);%CH4 = % methane, by volume, as shown by historical recordsGWPCH4 = global warming potential of methane (21)CH4 = density of methane%CO2 = % carbon dioxide, by volume, as shown by historical records


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A-II

As an example, a project was implemented 4 years ago but was not metered. Noinspection for leaks or repairs occurred. One instrument (6 scmh emission rate) wascommissioned three years ago. The estimated emission reductions for the unmeteredperiod would be:

Table A1: Bleed Rates for Pneumatic Devices Used in Oil and Gas Industry 6

Controller Model Signal Pressure (Psi)Manufacturer Data

(scfh)Pressure Controller

Ametek Series 4020 635 6

Bristol Babcock Series 5453-Model 10F20 335 3

Bristol Babcock Series 5455-Model 624-III 20 235 3

Bristol Babcock Series 502 A/D (recording controller)20


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A-III


(scfh)Level Controllers

Fisher 2900

20 2320 2335 23

35 23

Fisher 250020 4235 42

Fisher 2660 Series20 135 1

Fisher 2100 Series20


33/55

A-IV


(scfh)35 24 - 50

Moore Products Model 750P2035 42

Moore Products 73 B PtoP

20 36

35

PMV D5 Digital20


34/55

A-V

Device TypeEmission Factor (Original

Units)Precision

(+%)CH4 Emissions Factor *

(Converted to Tonnes Basis)Turbine valve operator 67,599 scf gas/device-yr 276 1.211 tonnes/device-yr

Transmission or storage average 162,197 scfy gas CH 4/device 44 3.111 tonnes/device-yrDistribution

Pneumatic isolation valvesbased on 93.4 mole% CH 4

0.366 tonnes CH 4/device -yrPrecision not

specified0.366 tonnes /device -yr

Pneumatic control loopsbased on 93.4 mole% CH 4

3.465 tonnes CH 4/device -yrPrecision not

specified3.465 tonnes /device -yr

Distribution average(if device is unknown)

based on 93.4 mole% CH 4 2.941 tonnes/device-yr

Precision notspecified

2.941 tonnes/device-yr

* CH4 emission factors converted from scf and m 3 are based on 60F and 14.7 psia.

Table A3: Gas Consumption Rates (m 3/h) for Standard (High Bleed) Pneumatic Instruments 8 Instrument Operating Pressure (140 kpag) Operating Pressure (240 kpag)Transmitter 0.12 0.2Controller 0.6 0.8

I/P Transducer 0.6 0.8P/P Positioner 0.32 .05I/P 0.4 0.6Chem. injection pumps(diaphragm)

0.4 0.6

Chem. injection pumps (piston) 0.04 0.06

A.2 Fraction of Vented and Combusted Emissions

Vent and bleed natural gas may be collected and sent to a flare or other combustion

device for various reasons. Therefore, this methodology allows the project developer toclaim credits from combusted and vented gas. The vent or bleed gas fraction X isestimated as follows based on vendors technical specifications:

m

j j j

n

iii

n

iii

mVRnVR

nVR X

11

1

**

*

Where

VRi = vent rate for device i from manufacturers technical specifications that ventgas to the atmosphere;

n i = number of type i devicesVR j = vent rate for device j from manufacturers technical specifications for gas that

is combusted

8 Source: CAPP (2003). Guide to Calculating Greenhouse Gas Emissions. Table 1-12.


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A-VI

m j = number of type j devices

The denominator is simply the addition of all devices at the facility. The combustedemissions are the remaining fraction and are calculated as:

m

j j j

n

iii

n

iii

mVRnVR

nVR X

11

1

**

*11

Care must be taken to use bleed rates that are either expressed in terms of air ornatural gas as well as the same units.


36/55

A-VII

1. Project/Baseline SSR

2. Parameter/variable

3. Unit

4.Measured/estimated

5. Contingency Method 4. Frequency 5. Justify measurement or estimationand frequency

Flexibility Mechanism

B5 Vented FuelGas

The following equations are used to establish baseline emissions based on metered compressed air powering the pneumatic instruments once the airconversion has taken place. Equations 1 and 2 are for vented fuel gas. Equations (3) and (4) are used to establish CO 2e emissions from flared fuel gas

(1) Emissions Vented Fuel Gas CH4 = Compressed Air Control Instruments i 444

*%*

*31

1

*31

1

**)1(** CH

AIR

k

CH

AIR CH

F

F

GG

DR X

;

(2) Emissions Vented Fuel Gas CO2 = Compressed Air Control Instruments i 1644

*%%

**%*

*31

1

*31

1

**)1(**4

244

4 CH CO

CH

F

F

GG

DR X CH

AIR

k

CH

AIR

;

where

4.1k

F k ; in this case k is taken as k GASor K CH4, which is 1.31.

(3) Emissions Flared/Combusted Fuel Gas = Compressed Air Control Instruments i DE EF

F

F

GG

DR X SiteiCO

AIR

k

GAS

AIR %**

*31

1

*311

**)1(*)1(*2

;

(4)Emissions Flared/Combusted Fuel Gas = Compressed Air Control Instruments i )%1(**%*

*31

1

*31

1

**)1(*)1(* 4 DE CH CH

F

F

G

G DR X

AIR

k

GAS

AIR


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A-VIII

(5) Emissions Flared/Combusted Fuel Gas = Compressed Air Control InstrumentsO N

AIR

k

GAS

AIR EF

F

F

G

G DR X

2*

*31

1

*31

1

**)1(*)1(*

Emissions Vented Fuel Gas

kg of

CH4 ;CO2

N/A N/A N/A

Quantity being calculated in

aggregate form as fuel use on siteis likely aggregate for each ofthese SSRs.

EmissionsFlared/Combusted FuelGas

kg ofCH4 ;CO2

N/A N/A N/A

Quantity being calculated inaggregate form as fuel use on siteis likely aggregate for each ofthese SSRs.

Compressed AirUsed forPneumaticInstruments i/Compressed AirControl Instruments i

m 3 Measured

Direct monitoring of mass flow rate (flowmeter) or volume (totalizer) of aircompressed and sent to controlinstrument pipe network


Totalizer: continuousmetering withminimum monthlyrecording of values

Both methods are standardpractice. Frequency ofmetering accurately capturesflow rate or volume of air sentto instrumentation

Fraction ofvented

emissions/ X

- Estimated

Estimated using

m

j j j

n

iii

n

iii

mVRnVR

nVR X

11

1

**

* N/A

This represents the fraction ofvented emissions from control

devices

Discount Ratedue to Leaks /DR

% Estimated

1. DR(%)=0 if inspection occurred < 1 year2. DR(%)= 2.5 %*minimum year intervalfor 1< year < 103. DR(%)= 25% for year > 10

N/A

Leaks are taken into accountwhen air is metered to adjust thebaseline. The year of lastdocumented inspection andmaintenance is taken intoaccount in parameter year.

Specific Gravityof Air /G AIR


Specific Gravityof Methane /



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A-IX

G CH4

Density ofMethane / CH4

kg /m 3

Estimated 0.717kg/m 3 at STP N/AIf this value is used all valuesmust be adjusted for standardtemperature and pressure.

Specific HeatRatio formethane / k CH4

- Assumed 1.31 at STP N/A Accepted value

Specific HeatRatio for air /k

- Assumed 1.40 at STP N/A Accepted value

MethaneComposition inGas / % CH 4

% Measured Direct measurement AnnualFuel gas composition shouldremain relatively stable duringsteady-state operation

Carbon DioxideComposition inGas / % CO 2

% Measured Direct measurement AnnualFuel gas composition shouldremain relatively stable duringsteady-state operation

Site SpecificEmission Factorfor CO 2 for gascomposition i/EFCO2 Site

kgCO2e /

m 3 Measured

Using gas composition analysis, a site specificemission factor can be developed using theequation presented in Appendix A, Section A1of the Meta-Protocol Introduction. Wherevented gas composition is not available, theemission factor for producer consumptionmay be used which can be found in Table A1of the Meta-Protocol Introduction.

Annual

The use of site specific fuel gasanalyses to determine the carboncontent of the fuel gas representsbest practice. This approachaccounts for variability in naturalgas composition from site to site.Reference values adjustedannually as part of EnvironmentCanada reporting on Canada'semissions inventory.

N2O EmissionsFactor for Flaringof ProcessEmissions / EF N2O

kgN2Operm 3

Estimated

Emission factor for natural gas used torepresent N 2O emissions from flaring ofprocess emissions. From Environment Canadareference documents. Reference value forproducer consumption of natural gas to beused if flared gas stream source is not pipelinegrade (sales) natural gas.

AnnualReference values adjustedannually as part of EnvironmentCanada reporting on Canada'semissions inventory.

Specific Gravityof Fuel GasSupply / G GAS

- Measured Direct measurement and corrected to NTP AnnualFuel gas composition shouldremain relatively stable duringsteady-state operation

Flare DestructionEfficiency/ %DE

%98.5% forflares and99.5% for

The methane emission factor was calculatedbased on the assumed destruction efficiencyof the flare. The destruction efficiency was

N/ARepresents the mostcomprehensive research on flaredestruction efficiency in Canada


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A-X

incinerators assumed to be 98.5% for flares and 99.5% forincinerators based on studies conducted bythe University of Alberta, US EPA and theERCB Directive 60 flare operatingrequirements. Specifically ERCB D60 requiresflares to have liquid separators and ensurethat the flare gas net heating value be at least20 MJ/m 3. Further details are provided at thebeginning of Appendix A on the parameters

that impact flare destruction efficiency.

based on over 8 years ofresearch, modelling and fieldtesting. The ERCB Directiverequirements are intended toensure destruction efficiencies of98% or greater.


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A-I

A.3 Discount FactorThe discount factors presented here are based on rates from the EPAs Natural Gas STAR Program Lessons Learned-Convert Gas Pneumatic Controls to Instrument Air . Instrumentcontrol devices in service and that have not been repaired will leak as time passes. A2.5% yearly linear increase in leaks is assumed. For devices that have been inspectedand repaired within the last year, the discount rate is assumed to be zero. For devices orpipe networks that have not been inspected and repaired in the last 10 years, thediscount rate increases linearly until reaching 25%. The maximum discount rate is 25%for devices with more than 10 years without inspection and repairs. The equations usedto calculate the discount rate are as follows:

DR (%) = 2.5 %* (minimum year interval) for 0< year < 10

DR (%) = 25% for year > 10

This relationship is assumed linear and is illustrated in Figure A.1. As an example, if thelast inspection and repair took place 5.5 years ago, then the minimum of that yearinterval is 5.5 times 2.5 % yearly increase due to leaks yields a 12.5 % leak rate. The DR istherefore 12.5%.

This discount rate is used to adjust the baseline and maintain a conservative approach.The equation below shows the use of coefficients as illustrated in the followingequations:

444

4 *%*

*31

1

*31

1

***)1( CH

AIR

k

CH

AIR AIRCH CH

F

F

GG

Q DRm


41/55


42/55

B-I

Contingent means for calculating or estimating the required data for the equations outlined in 5.5.1 are summarized in Table B1below.

Table B1: Contingent Data Approaches1. Project /Baseline SSR

2. Parameter /Variable 3. Unit

4. Measured/ Estimated 5. Method

6.Frequency

7. Justify measurement orestimation and frequency

Project SSRs

P5 AirCompression

Volume of FossilFuel i Combustedfor P5 to ProduceElectricity for theAir CompressionSystem/ Vol. Fuel i

L / m 3 / other Estimated Reconciliation of volumeof fuel purchased withingiven time period

Monthly

Provides reasonableestimate of the parameter,when the more accurate andprecise method cannot beused.

Compressed AirUsed for PneumaticInstruments /Compressed AirControl Instruments i

m 3 Estimated

Reconciliation ofcompressed air used in aircompression systemwithin given time periodbased on equipmentefficiency specificationsand average flow rates

Monthly


Total Air Producedin Air CompressorSystem byCompressor i /Produced Air i

m 3 Estimated

Reconciliation of total airproduced in aircompression systemwithin given time periodbased on equipmentefficiency specificationsand average flow rates

Monthly


ElectricityConsumed by AirCompressor i /

kWh Estimated Reconciliation ofelectricity consumed bythe air compression

Monthly Provides reasonableestimate of the parameter,when the more accurate and


43/55

B-II

EC i system based onequipment ratings andoperating hours

precise method cannot beused.


Volume of FossilFuel i Combustedfor P4 to ProduceElectricity for the

Air ManagementSystem/ Vol. Fuel i

L / m 3 / other Estimated

Reconciliation of volumeof fuel purchased withingiven time period Monthly

Provides reasonableestimate of the parameter,when the more accurate andprecise method cannot be

used.

Managed Air by AirManagementsystem i / ManagedAir ControlInstruments i

m3 Estimated

Reconciliation of managedair used in airmanagement systemwithin given time periodbased on equipmentefficiency specificationsand average flow rates

Monthly


Total Air Managedby AirManagementSystem i/ TotalManaged Air i

m3 Estimated

Reconciliation of managedair used in airmanagement systemwithin given time periodbased on equipmentefficiency specifications

and average flow rates

Monthly


ElectricityConsumed by AirManagementSystem i /EC i

kWh Estimated

Reconciliation ofelectricity consumed bythe air managementsystem based onequipment ratings andoperating hours

Monthly


Baseline SSRs


44/55

B-III

B5 VentedFuel Gas

Compressed AirUsed for PneumaticInstruments /Compressed AirControlInstruments i

m3 Estimated

Reconciliation ofcompressed air used in aircompression systemwithin given time periodbased on equipmentefficiency specificationsand average flow rates

Monthly


MethaneComposition inFuel Gas / % CH4

% Estimated

Interpolation of previousand followingmeasurements taken, orfrom fuel analysis of gascomposition within thesame basin.

Annually


Carbon dioxideComposition inFuel Gas / % CO2

% Estimated

Interpolation of previousand followingmeasurements taken, orfrom fuel analysis of gascomposition within thesame basin.

Annually



45/55


46/55

C-I

C.1 Gas Equivalence

The capacity of a device to flow air or gas is expressed in terms of C V, or flow coefficient.The CV measures the impact on flow from diverse factors to a device such as:

Orifice size (diameter of the piping or opening through the valve); Length of piping or opening through the valve; Turbulence caused by bends or turns in the piping; Restrictions, or anything that reduces the orifice size or the flow path; and Shape of the orifice.

For this methodology, the formula employed by the Instrument Society of America (ISA)based on L.R. Driskells work will be used to develop equivalence between airconsumption and natural gas that would have been consumed. This formula may befound in ANSI/ISA-75.02-1996 Control Valve Capacity Test Procedures and is anestablished method used by industry to calculate the C V for pneumatic devices.Expanded formula can be found in L.R. Driskells New Approach to Control Valve Sizing .

Gas and air are considered compressible fluids. In pneumatic devices, flow can bechoked or non-choked. Flow in a duct or passage such that the flow upstream of acertain critical section cannot be increased by a reduction of downstream pressure isdefined as choked. For the purpose of this methodology, choked conditions will be usedbecause these conditions represent a conservative approach in estimating air volumes,explained in detail in this section.

For compressible fluid flow in non-choked conditions, the flow rate can be expressed as

R g psiaV SCFH T G

xY P C Q

****17.4 1 (1)

where

T k X F

xY

**31 (Limits 1.0 > Y > 0.667 for air) (2)

Q SCMH = fluid volumetric flow rate (m3/h);

CV = flow coefficient;P1kPa = inlet pressure;Y = expansion factor;x = pressure drop ratio to absolute inlet pressure;Gg = gas specific gravity (this is the density of the gas divided by the density of air

at the same conditions);TK = temperature in degrees Kelvin;


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C-II

Fk = ratio of specific heats (equal to the specific heat ratio of the gas divided bythe specific heat ratio of air); and

XT = maximum pressure ratio before choking.

When choking occurs, (1) and (2) are still valid with the exception that x=X T. Equation (2)

becomes

k F

Y *31

1 (3)

where

4.1k

F k

k is the ratio of specific heats for a given gas (1.4 is the ratio specific heat for air, 1.3 formethane). The heat capacity ratio or adiabatic index or ratio of specific heats , is theratio of the heat capacity at constant pressure (C P) to heat capacity at constant volume(CV). It is the ratio of specific heats between 2 gases; in the case of the methodology, theratio between air and air (used as reference), and the ratio between methane and air,the gas of interest.

Approach

In order to establish the equivalence of how much natural gas would have been ventedif the air system had not been installed, the assumption of equal C V for both gas and airpowered devices must be established. Therefore (1) for CH 4 can be expressed as

K CH CH kPaV CH T G

xY P C Q

*****17.4

4414 (4)

where

Q CH4 = CH4 volumetric fluid flow rate

Similarly, (1) for air can be expressed as

K AIR AIRkPaV AIR T G

xY P C Q*

****17.4 1 (5)

where

Q AIR = air volumetric flow rate


48/55

C-III

It should be noted that a specific pneumatic instrument has a unique C v, regardless ofthe liquid or gas being consumed by the instrument. By substituting (5) into (4) as afunction of C Vand eliminating common terms,

444

1**

1*

1

1*

CH CH

AIR

AIR

AIRCH GY

Y G

QQ (6)

The fuel gas supply and compressed air will travel along the same pipe network.Pressures cancel each other out since they are assumed equal as per the considerationof functional equivalence (P 1kPa AIR= P1kPa CH4 ).

Because the pipeline is thin and not insulated, the temperature of the gas (either fuelsupply gas or air) will reach approximate ambient temperature just before being ventedby the pneumatic device after having travelled through the pipe network (T AIR=TCH4). For

this reason, the temperatures of either fuel gas or compressed air were consideredcomparable and cancel each other out in equation (6).

Finally, x was taken as x T or the limiting condition when choking occurs. If YC v is plottedagainst x, there is a linear relationship with a negative slope as x increase. Chokedcondition will occur when Y*C v=0.667*C v for air and Y*C v=.0644*C v for methane. Notethat the corresponding values of x T AIR when Y*C v=0.667*C v is slightly less than thecorresponding value of x T CH4 when Y*Cv=0.644*C v for a given device. When dividing x TCH4 by xT AIR and square-rooting, this value is slightly greater than 1. For simplicity andconservativeness in calculations, the value was equal to 1 in equations (6).

Rearranging terms and assuming choked conditions in (3)

AIR

CH

CH

AIR AIRCH

F

F GG

QQ

*31

1

*31

1** 4

44 (7)

The following are the assumptions used to state conservativeness in the approach.

a) Equation (2) is used to show all the possible pressure drops that can be experienced

by the device before it reaches the critical pressure and then asymptotes under chokedconditions.

b) Under choked conditions, x=X T. Choked flow is a limiting condition which occurswhen the mass flow rate will not increase with a further decrease in the downstreampressure environment while upstream pressure is fixed. Using equation (3), for airY=0.667 and natural gas Y=0.643, so Y CH4/YAIR = .965 in equations (6) and consequently(7). Under unchoked conditions and the extreme right-hand side of Figure C.1 (for


49/55

C-IV

Fk=1.00 and x vc=0.0), F CH4 =.935 and F AIR = 1, so it follows that Y CH4/YAIR = 1. Note that Y AIR and YCH4 have been normalized with respect to Y AIR. As can be seen, Y CH4/YAIR drops from1 in unchoked conditions to .965 in choked conditions. So by assuming chokedconditions, the quantities are discounted at .965 and not 1. The approach loses 0.035(1-.965) of the possible credits claimable, so it underestimates the quantities by 3.5%

and provides a conservative approach. Table A.1 summarizes the calculations for Y CH4, YAIR and x/x T using equations in the ISA standard. The yellow row indicates chokedconditions. Note that x T is the terminal or limiting pressure where choking begins.

TABLE C.1 Evolution of Y CH4/Y AIR from unchoked to choked conditionsYCH4 YAIR YCH4/

YAIR

FIGURE A.1 Y for Air and CH4 (Normalized with respectto air)

x/x T k=1.31 k=1.40 1 1 1

0.1 0.964 0.967 0.998

0.2 0.929 0.933 0.9950.3 0.893 0.9 0.9920.4 0.858 0.867 0.9890.5 0.822 0.833 0.9860.6 0.786 0.8 0.9830.7 0.751 0.767 0.9800.8 0.715 0.733 0.9750.9 0.679 0.7 0.971

1 0.644 0.667 0.966

c) From the figure in TABLE C.1, it is clear that by dividing methane as it asymptotes bythe reference gas (with a value of Y AIR/Y AIR = 1), the minimum value will occur whenchoked conditions occur, or when F CH4 asymptotes at .965.

Specific gas gravities for greenhouse gases present in fuel supply gas at NTP 9 aresummarized below.

TABLE C.2 Specific gravity of gases present in fuel gasGas S.G.Air 1.000Carbon dioxide 1.519

Methane 0.5537Natural Gas 0.60 - 0.70Source: http://www.engineeringtoolbox.com/specific-gravities-gases-d_334.html

Using GCH4= 0.5537, G AIR=1, and k=1.31 for pure methane, (7) becomes

9 Normal Temperature and Pressure is defined as air at 20 oC (293.15 K, 68 oF) and 1 atm ( 101.325 kN/m2,101.325 kPa, 14.7 psia, 0 psig, 30 in Hg, 760 torr)

Y for Air and CH4

0.950

0.9600.970

0.980

0.9901.000

1.010

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

x/xT

Y

k=1.31 k=1.4
http://www.engineeringtoolbox.com/specific-gravities-gases-d_334.htmlhttp://www.engineeringtoolbox.com/stp-standard-ntp-normal-air-d_772.htmlhttp://www.engineeringtoolbox.com/stp-standard-ntp-normal-air-d_772.htmlhttp://www.engineeringtoolbox.com/specific-gravities-gases-d_334.html


50/55

C-V

AIRCH QQ *2977.14

This represents the volumes of pure methane that would have been vented instead ofair. In general terms, pure methane is not vented. Instead, vented gas composed mainlyof methane and to a lesser extent carbon dioxide is vented. Consequently, the amount

of greenhouse gases that would have been emitted in the absence of air is adjusted asfollows in terms of mass flow rate:

444

4 *%*

*31

1

*31

1

** CH

AIR

k

CH

AIR AIRCH CH

F

F

GG

Qm

(8)

Where

4CH m = CH4 mass fluid flow rate;%CH4 = volume fraction of CH 4 in fuel supply gas; andCH4 = methane density;

and

1644

*%%

**%*

*31

1

*31

1

**4

244

42 CH

COCH

F

F

GG

Qm CH

AIR

k

CH

AIR AIRCO

(9)

Where

2COm = CO2 mass fluid flow rate;

%CH4 = volume fraction of CH 4 in fuel supply gas;%CO2 = volume fraction of CO 2 in fuel supply gas;44 = molecular weight of CO 2; and16 = molecular weight of CH 4.

Conservativeness of Approach

ISO 10464-2:2006(E) Section 3.7 introduces the principle of conservativeness andguidance is given on its application:

Use conservative assumptions, values and procedures to ensure that GHG [greenhousegas] emission reductions or removal enhancements are not over-estimated.


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As stated previously, the parameter that has the most effect on flow in pneumaticdevices is Y, the expansion factor. The ISA standard (sections 8.3.4 to 8.3.7) states thatfor the evaluation of C v for a pneumatic device, at least two points are needed thatcomply with the following conditions

1. (Y*Cv)1 > 0.97(YCv)0 where (Y*C v)0 corresponds to x 0; and2. (Y*Cv)n < 0.87(Y*Cv)0

3. The test points are plotted on linear coordinates as (Y*C v) vs. x and a linear curvefitted to the data The value of C v for the specimen (device) shall be taken from the curveat x=0, Y=1. The value of x T for the specimen shall be taken from the curve atY*Cv=0.667*C v.

Y*Cv=0.667*C v corresponds to the critical ratio of air, which is the medium (type of gas)most commonly used for compressible fluid testing. The equations in the ISA standardare all corrected with respect to air which allows for testing with different types of

gases, not just air. The other value of interest with respect to this methodology isYCv=0.644*C v, or the corresponding x T for methane.

FIGURE C.2 (with values in TABLE C.3) is an example of this plotting procedure toevaluate C v and x T

10 . Cv was taken as 35.52 as an example. Note that x T CH4 (blue line) isslightly higher than x T AIR (red line) at all times, regardless of the C v value because theslope (m) of the linear curve (line) is always negative thus guaranteeing that x T CH4 willalways be greater than x T AIR.

TABLE C.3 Illustrative Example of Y*C V vs. x

Y*Cv

FIGURE A.2 Example of fitted data to linear curve

x Y 35.200

0.000 1.000 35.200

0.021 0.970 34.144

0.092 0.870 30.624

0.236 0.667 23.467

0.252 0.644 22.661

The value of x T CH4 (=0.252) is slightly higher than x T AIR (=0.225) in this example. It is truethat x T CH4 xT AIR at all times because x T CH4 will always be greater than x T AIR. If this isassumed, then data can be generated for the expansion factors Y as summarized inTABLE C.4 and shown in FIGURE C.3. x/x T CH4 and x/x T AIR are evaluated individually (i.e x T

10 Example values taken from Stubbs, W.L. (1998). Establishing a new method for determining valve flowcoefficient. Micro Magazine, May, p. 39-51.Retrieved from http://www.micromagazine.com/archive/98/05/stubbs.html on 2008-08-06.

YCv vs. x

202224262830323436

0.000 0.050 0.100 0.150 0.200 0.250 0.300

Pressure Drop, x (dimensionless)

Y C v

( d i m e n s i o n

l e s s

)
http://www.micromagazine.com/archive/98/05/stubbs.htmlhttp://www.micromagazine.com/archive/98/05/stubbs.htmlhttp://www.micromagazine.com/archive/98/05/stubbs.htmlhttp://www.micromagazine.com/archive/98/05/stubbs.html


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CH4 xT AIR is assumed). Note that if the pneumatic device runs on air, the maximumpressure drop it experiences is 0.225, which corresponds to Y AIR= 0.667. The pressuredrop if the device runs on CH 4 would be the same, which corresponds to Y CH4= 0.682. YCH4/Y AIR would be 0.682/ 0.667 or 1.022. It should be noted that air is flowing chokedand CH 4 is flowing unchoked if the same pressure drop ratio is assumed. Therefore, air

flow will enter choked conditions before CH 4 does at all times because x T CH4 > xT AIR,regardless of C V. If unchoked conditions are assumed also, this approach will increasethe value of Y CH4/Y AIR from 1 to an asymptote of roughly 1.022.

1.022 is higher than the one calculated assuming x T CH4= xT AIR, which corresponds to YCH4/Y AIR= 0.644/ 0.6667 or .966. The value of .966 is conservative because itunderestimates the actual value of quantifiable emissions (which would use 1.022 if x TCH4 xT AIR). Conclusively, assuming x T CH4 = xT AIR both under choked conditions simplifiesand reduces calculations, and further metering requirements while assuringconservativeness as per ISO guidance.

Note on Pressure Drop, x

Typically, pneumatic devices are designed to operate at 20 PSI (~138 kPa) or 35 PSI(~241 kPa). The pressure drop, x (dimensionless), defined by the ISA standard is the ratioof pressure drop to absolute inlet pressure (p/p 1). p is the differential pressure, p 1-p 2.p1 is the upstream absolute static pressure, measured two nominal pipe diametersupstream of the valve-fitting equipment. p 2 is the downstream absolute static pressure,measured six nominal pipe diameters upstream of the valve-fitting equipment. Toapproximate x in a field setting, p 1 can be assumed to be the design pressure and p 2 theatmospheric pressure at sufficient distance downstream. Therefore, x can be calculated

as

581.241

101241

;275.138

101138

240

138

kPa

kPa

x

x

These are typical x values to be found in the field. These can be normalized with respectto x T CH4 or xT AIR if the values are known from the manufacture. However, this may beimpractical and tedious to accomplish. The proposed approach simplifies and keeps aconservative approach, in line with the ISO principle.


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TABLE C.4 Y with the conditions x T CH4 = xT AIR and x T CH4 xT AIR xT CH4=0.252 AIR=0.225 YCH4/Y AIR

(x TCH4=xT AIR) YAIR/

YAIR YCH4/Y AIR

(x TCH4xT AIR)x x x/xT YCH4 x x/x T YAIR x x/x T YCH4 0.0 0.000 0.0 1.000 0.000 0.0 1.000 1.000 1.000 0.000 0.000 1.000 1.0000.1 0.025 0.1 0.964 0.023 0.1 0.967 0.998 1.000 0.023 0.089 0.968 1.0020.2 0.050 0.2 0.929 0.045 0.2 0.933 0.995 1.000 0.045 0.179 0.936 1.003

0.3 0.076 0.3 0.893 0.068 0.3 0.900 0.992 1.000 0.068 0.268 0.905 1.0050.4 0.101 0.4 0.858 0.090 0.4 0.867 0.989 1.000 0.090 0.357 0.873 1.0070.5 0.126 0.5 0.822 0.113 0.5 0.833 0.986 1.000 0.113 0.446 0.841 1.0090.6 0.151 0.6 0.786 0.135 0.6 0.800 0.983 1.000 0.135 0.536 0.809 1.0110.7 0.176 0.7 0.751 0.158 0.7 0.767 0.979 1.000 0.158 0.625 0.777 1.0140.8 0.202 0.8 0.715 0.180 0.8 0.733 0.975 1.000 0.180 0.714 0.746 1.0170.9 0.227 0.9 0.679 0.203 0.9 0.700 0.971 1.000 0.203 0.804 0.714 1.0201.0 0.252 1.0 0.644 0.225 1.0 0.667 0.966 1.000 0.225 0.893 0.682 1.023

FIGURE C.3 Expansion Curves for Y CH4/YAIRxT CH4 = xT AIR and x T CH4 xT AIR

Y for Air and CH4

0.9500.9600.9700.9800.9901.0001.0101.0201.030

0.000 0.100 0.200x (Dimensionless)

Y ( D i m e n s i o n

l e s s

Y AIR/Y AIR Y CH4/Y AIR (x TCH4=xT AIR)

Y CH4/Y AIR (x TCH4xT AIR)


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A.2 Leaks

Minimizing leaks by making use of a regular inspection and maintenance programensures that metered air volumes are not overestimated, and hence gas that wouldhave been vented had the instrument air conversion not taken place. At times a regular

inspection and maintenance program is not practical or programmed at different timeperiods that do not coincide with the implementation of the instrument air conversionproject. Estimates based on best practices and emission factors from creditedreferences are used to discount metered air volumes to safeguard conservativeness inthese estimations.

The discount factors presented here are based on rates from the EPAs Natural Gas STAR Program Lessons Learned-Convert Gas Pneumatic Controls to Instrument Air . Instrumentcontrol devices in service and that have not been repaired will leak as time passes. A 2.5% yearly linear increase in leaks is assumed. For devices that have been recentlyinspected and repaired, the discount rate is assumed to be zero. For devices or pipenetworks that have not been inspected and repaired in the last 10 years, the discountrate increases linearly until reaching 25%. The maximum discount rate is 25% for deviceswith more than 10 years without inspection and repairs. The equations used to calculatethe discount rate are as follows:

DR (%) = 2.5 %* (minimum year interval) for 0< year < 10 (10)

DR (%) = 25% for year > 10 (11)

This relationship is assumed linear and is illustrated in Figure C.1. As an example, if thelast inspection and repair took place 5.5 years ago, then the minimum of that yearinterval is 5.5 times 2.5 % yearly increase due to leaks yields a 12.5 % leak rate. The DR istherefore 12.5%.

Figure C.4 Linear relationship between elapsed time and discount factor.

This discount rate is used to adjust the baseline and maintain a conservative approach.Equations (10) and (11) are incorporated into equations (8) and (9) as coefficients asillustrated in the following equations:

Emission discount factor

0%

5%

10%

15%

20%

25%

30%

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16

Year

D i s c o u n

t P e r c e n

t a g e


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444

4 *%*

*31

1

*31

1

***)1( CH

AIR

k

CH

AIR AIRCH CH

F

F

GG

Q DRm

(12)

1644

*%%

**%*

*31

1

*31

1

***)1(4

244

42 CH

COCH

F

F

GG

Q DRm CH

AIR

k

CH

AIR AIRCO

(13)

Documents

Instrument Gas to Air Module