greehouse gas reporting protocol for natural gas transmission and distribution

Discussion Paper for a Natural Gas Transmission and Distribution Greenhouse Gas Reporting Protocol

Final Draft Report Prepared for: California Climate Action Registry and World Resources Institute Prepared by: URS Corporation and The LEVON Group June 6, 2007

Table of Contents

I. Introduction .........................................................................................................1

II. Brief Overview of the Natural Gas Industry ......................................................2 II.1 NG T&D Sector Definitions ..........................................................................................4

III. How Are Boundaries Defined?...........................................................................7 III.1 Geographical Boundaries...............................................................................................7 III.2 Organizational Boundaries.............................................................................................8

III.2.1 Option 2: Equity Share.....................................................................................10 III.3 Gas Transport Considerations......................................................................................11 III.4 Operational Boundaries ...............................................................................................12

III.4.1 Scope 1: Required Direct GHG Emissions......................................................12 III.4.2 Scope 2: Required Indirect GHG Emissions from Purchased and

Consumed Energy............................................................................................15 III.4.3 Scope 3: Other Indirect GHG Emissions .........................................................16

III.5 Establishing and Updating Base Year Emissions ........................................................17 III.6 Data Collection Levels.................................................................................................17

IV. What Methods Are Available for Estimating GHG Emissions?.....................20 IV.1 Methodology Review...................................................................................................21 IV.2 Emission Factors..........................................................................................................26

IV.2.1 Confidence Intervals ........................................................................................28 IV.3 Emission Factor Adjustments for Gas Composition....................................................28

V. Direct Emissions - Combustion .......................................................................30 V.1 Fuel Properties .............................................................................................................30 V.2 Energy Output to Energy Input Conversions...............................................................32 V.3 Stationary Combustion.................................................................................................32

V.3.1 Stationary Combustion – Fuel Based Material Balance ..................................35 V.3.2 Stationary Combustion – Fuel Based Emission Factors ..................................36 V.3.3 Stationary Combustion – Equipment Basis .....................................................39 V.3.4 Stationary Combustion – Manufacturer’s Data ...............................................42

V.4 Flaring..........................................................................................................................44 V.5 Recommendations and Considerations for Stationary Combustion Sources...............48 V.6 Mobile Combustion .....................................................................................................49

V.6.1 Non-road Vehicles ...........................................................................................55

VI. Direct Emissions - Process Vents ...................................................................59 VI.1 Glycol Dehydrator Vents and Pumps ..........................................................................59 VI.2 Gas Driven Pneumatic Devices ...................................................................................63 VI.3 Gas Driven Pneumatic Pumps .....................................................................................64 VI.4 Storage Tanks, Loading/Unloading, and Transit .........................................................65 VI.5 General Cold Vent .......................................................................................................67

VI.6 Non-Routine Activities ................................................................................................69 VI.6.1 Transmission/Storage.......................................................................................69 VI.6.2 Distribution ......................................................................................................71

VI.7 Fire extinguishers.........................................................................................................72 VI.8 Lost and Unaccounted for Gas.....................................................................................72

VII. Direct Emissions – Fugitives ...........................................................................73 VII.1 Methodologies for Equipment Leaks...........................................................................73 VII.2 Equipment Leaks .........................................................................................................75

VII.2.1 Facility-Level Fugitive Emission Factors........................................................75 VII.2.2 Equipment-Level Fugitive Emission Factors...................................................77 VII.2.3 Facility and Equipment Level Emission Factor Considerations......................80 VII.2.4 Average Component-Level Fugitive Emission Factors...................................81 VII.2.5 Screening-based Fugitive Emission Methodologies........................................82

VII.3 Other Fugitives.............................................................................................................85

VIII. Indirect Emissions ............................................................................................86 VIII.1 Purchased Electricity ...................................................................................................86 VIII.2 Purchased Heat/Steam .................................................................................................87 VIII.3 Purchased Cooling Water ............................................................................................87

IX. What Should Be Reported?..............................................................................88 IX.1 GHG emissions ............................................................................................................88 IX.2 CO2-equivalent emissions............................................................................................88 IX.3 De Minimis and Materiality considerations.................................................................88 IX.4 Industry specific efficiency metrics .............................................................................89 IX.5 Other Optional Reporting ............................................................................................91

X. Certification .......................................................................................................93 X.1 Documents and Information to Review .......................................................................93

X.1.1 Reviewing Documentation...............................................................................95 X.1.2 Questions to Consider in Verifying Emissions Estimates ...............................95

XI. Other Information..............................................................................................96 XI.1 Managing Inventory Quality........................................................................................96 XI.2 Key Terms....................................................................................................................98

XII. References.......................................................................................................101

Discussion Paper for Natural Gas Transmission and Distribution Greenhouse Gas Reporting Protocol

I. INTRODUCTION This Discussion Paper describes options and recommendations for accounting and reporting greenhouse gas (GHG) emissions from natural gas transmission, storage and distribution (NG T&D) facilities. Its purpose is to support the development of a protocol to establish entity-level GHG emissions inventories. The protocol and calculation tool(s), which will be developed through a stakeholder workgroup process, will supplement the California Climate Action Registry’s (Registry) General Reporting Protocol (GRP)1 and the World Resources Institute (WRI)/World Business Council for Sustainable Development (WBCSD) Greenhouse Gas Protocol Corporate Reporting and Accounting Standard (Corporate Standard)2.

The users of the resulting protocol and tool(s) will be all types of entities comprising the NG T&D sector, including private, investor owned companies as well as publicly owned public utilities that own, control and/or operate NG T&D assets. The estimation methods presented below are applicable to similar sources found in other industry sectors, such as utility companies that distribute natural gas or an integrated oil and natural gas company that owns and/or operates natural gas transmission pipelines.

Section II presents an overview of the natural gas industry and a very brief summary of some of U.S. regulations with associated reporting that could be useful when compiling a GHG inventory. Section III follows with a discussion on how are boundaries defined, and Section IV outlines tiers associated with emission estimation methods.

Sections V, VI, VII, and VIII introduce specific methods that are available for estimating GHG emissions from combustion, vented, and fugitive, and indirect emission sources, respectively. Section IX provides guidance on what should be reported. The document concludes with options for certification, other pertinent information (including key words) and references in Sections X, XI, and XII, respectively.

1 http://www.climateregistry.org/docs/PROTOCOLS/GRP%20V2.1.pdf 2 http://www.ghgprotocol.org/templates/GHG5/layout.asp?type=p&MenuId=ODg4&doOpen=1&ClickMenu=No

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II. BRIEF OVERVIEW OF THE NATURAL GAS INDUSTRY The natural gas industry encompasses a wide range of operations, from the exploration, production, and processing of raw natural gas to its transmission, storage and distribution to end-users. Figure II-1 shows the overall natural gas industry and depicts its different sectors based on function. Natural gas companies may be operating in more than one sector. These wide ranging modalities of operations and unique operating conditions and practices, in each of the subsectors, adds to the complexity of estimating GHG emissions associated with NG T&D operations.

Figure II-1. Diagram of the Primary Sectors in the Natural Gas Industry3

Pipeline grade natural gas is transferred downstream of gas processing plants into the natural gas transmission system via the point of “Custody Transfer”, which delineates the boundaries between exploration/ production/processing and transmission4. Natural gas transmission is affected primarily by high-pressure interstate pipelines of various diameters delivering the natural gas at 3 Figure from Report Numbers: GRI-94/0257, EPA-600/R-96-080a, “Methane Emissions from the Natural Gas Industry.” 4 This delineation is in line with the definitions provided by the U.S. EPA in their National Emissions Standards for Hazardous Air Pollutant for Oil & Natural Gas Production Facilities (codified in 40CFR63 subpart HH) and for Transmission and Storage Facilities (codified in 40CFR63 Subpart HHH).

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34% of the industrial se27% to elec to commerc The NG T& 200,000

interstat 1.4 mill

delivery 2,000 co 300 und

pressures ranging from 200 – 1,500 psi (1,380 – 10,300 KPa). Interstate pipelines transfer custody of the natural gas to local natural gas utilities at ‘transfer points’ or ‘take stations.’ In many cases in the United States, the gas utility then transports the natural gas along intrastate high-pressure transmission lines from the take station to local distribution systems in towns and cities. Natural gas utilities may direct some of this gas stream into storage facilities during off-peak seasons, and then they withdraw gas during times of peak demand (usually the winter heating season) and transport it to customers. This high pressure gas is transferred into the distribution system at the “city gate.” The local utiof the natural gas at the “city gate” to reduce the gas pressure to a rangfor delivery to end-users, which could be as low as 3 psi (20.7 KPa).

While this Discussion Paper focuses on providing GHG reporting guidtransmission, storage, and distribution sectors, guidance is also provideprocessing activities, e.g. revaporization and dehydration, which are peoperations. U.S. Regulations of Natural Gas Transportation

Natural gas transportation is highly regulated in the U.S. The regulationatural gas policy, pipeline safety, environmental protection and impacenvironment and ports. Summaries of the major regulatory regimes (ancontrol natural gas pipeline operations are provided in Table II-1. Moswell as other regulations at the local and state level) include a reportingof the data collected for these reports might serve entities in their overafor developing their emissions inventories.

Table II-1. U.S. Regulations of Natural Gas Transportat

FEDERAL AGENCY

PRIMARY RESPONSIBILITY

EXAMPLES OF RE

Pipeline and Hazardous Materials Safety Administration (PHMSA)

Primary federal agency responsible for pipeline safety, reliability, and environmental impact.

Oversees pipeline construction, maintenance and operation.

Shares responsibilities with state regulatory partners

Gas Distribution System PHMSA F 7100.1-1 (12-0

Distribution System Gas Transmission and GaPHMSA F 7100.2-1 (12/0

Transmission and Ga

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U.S. Statistics natural gas goes to the ctor, 23% to home use, tricity generation, and 15%ial markets;

D sector is comprised of, miles of high-pressure e pipeline, ion miles of low-pressure pipelines, mpressor stations, erground storage facilities.

lity steps down the pressure e that is more appropriate

ance for sources in the d for some limited gas rformed as part of NG T&D

ns stem from laws governing ts on the marine d federal agencies) that

t of these regulations (as component; some elements ll data collection activities

ion At-A-Glance

PORTING REQUIREMENT

5): Annual Report For Gas

thering Systems 5): Annual Report For Gas thering Systems

FEDERAL AGENCY

PRIMARY RESPONSIBILITY

EXAMPLES OF REPORTING REQUIREMENT

Federal Energy Regulatory Commission (FERC)

Oversees the U.S. interstate NG pipeline industry;

Regulates construction of interstate NG pipelines and its transportation;

Sets rates, terms and conditions for operation of interstate gas pipeline facilities;

Approves both the siting and abandonment of interstate natural gas pipelines, fuel storage and liquefied natural gas (LNG) facilities;

Oversees environmental matters related to natural gas projects.

Form 2—Annual Report of Major Natural Gas Companies Report submitted each year by major gas pipelines (> 50BCF). The report provides general corporate information, financial statements and related schedules and operating data. Form 2A—Annual Report Of Non-major Natural Gas Companies Report filed by interstate NG pipeline companies with annual sales or volume transactions of more than 200 MMCF but less than 50 BCF Form 8—Underground Gas Storage Report Five-page monthly report filed electronically.

U.S. Environmental Protection Agency (EPA)

Administers a wide variety of environmental laws.

Develops national ambient air quality standards

Authorizes state permit programs Develops national standards for

emissions to air and discharge to water,

State Public Utilities Commissions (PUCs)

Primary responsibility is to regulate the rates charged by natural gas utilities for transporting natural gas to end use customers.

State Environmental Agencies

Manage state implementation plans to achieve national ambient air quality standards.

Administers federal, and local permit

Annual Title V air permits certification Annual emission fee reports, including quantification of fuels

used, Reports on Leak Detection and Repair (LDAR) activities, as

appropriate.

II.1 NG T&D Sector Definitions

The operations and facilities that comprise the NG T&D sector could be defined via two options:

• Industry descriptions as portrayed in the North American Industrial Classification System (NAICS)5;

• Regulatory definitions from the National Emission Standard for Emission of Hazardous Air Pollutants (NESHAPs) promulgated by the U.S. EPA6.

The classification that is based on the U.S. Bureau of Census 2002 North American Industrial Classification System (NAICS) is shown in Table II-2. It is important to note that the NAICS does not account separately for Natural Gas Storage operations. 5 http://www.census.gov/epcd/naics02/naicod02.htm6 http://www.epa.gov/ttn/atw/natgas/natgaspg.html

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Table II-2. 2002 NAICS Codes and Titles for Applicable Sectors

2002 NAICS SECTOR TITLE SECTOR DESCRIPTION 221210 Natural Gas Distribution This industry comprises:

1) Establishments primarily engaged in operating gas distribution systems (e.g., mains, meters);

2) Establishments known as gas marketers that buy gas from the well and sell it to a distribution system;

3) Establishments known as gas brokers or agents that arrange the sale of gas over gas distribution systems operated by others; and

4) Establishments primarily engaged in transmitting and distributing gas to final consumers.

486210 Pipeline Transportation of Natural Gas

This industry comprises establishments primarily engaged in the pipeline transportation of natural gas from processing plants to local distribution systems

The second options for defining the NG T&D sector could be based on the NESHAPs promulgated by the U.S. EPA in title 40, chapter I, part 63 subpart HHH to the Code of Federal Regulations. Table II-3 provides some key definitions from that standard that could be used, with appropriate modifications for the purpose of the NG T&D Protocol, for delineating the applicability of this guidance to the NG T&D sector.

Table II-3. Approaches to Sector Definition based on U.S. EPA Rule

TERMS DEFINED U.S. EPA DESIGNATION FOR NG TRANSMISSION & STORAGE (1)

Applicability Owners and operators of natural gas transmission and storage facilities that transport or store natural gas prior to entering the pipeline to a local distribution company or to a final end user (if there is no local distribution company) (2)

Custody Transfer The transfer of natural gas after processing and/or treatment in the production operations to pipelines or any other forms of transportation.

Facility (3) Facility means natural gas transmission and storage equipment that is located inside the boundaries of an individual surface site and is connected by ancillary equipment, such as gas flow lines or power lines. Equipment that is part of a facility will typically be located within close proximity to other equipment located at the same facility. Natural gas transmission and storage equipment or groupings of equipment located on different gas leases, mineral fee tracts, lease tracts, subsurface unit areas, surface fee tracts, or surface lease tracts shall not be considered part of the same facility.

(1) Rule promulgated by the U.S. EPA to control air toxics emissions from the NG Transmission and Storage (See footnote 6 above); these definitions are provided as an example and are not the final definitions recommended for the NG T&D protocol. (2) For the protocol, it is recommended that the phrase “local distribution system” replace the phrase “local distribution company” (3) The U.S. EPA has long-standing definitions of “facility” for purposes of determining applicability of the new source review (NSR) and prevention of significant deterioration (PSD) program that are different that those stated here. Under the NSR/PSD program, EPA does not consider long line sources such as pipelines to be a single source, “despite

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connection between them.” It is recommended that underground pipelines should not be considered as the same ‘source’ or ‘facility’ as above ground compressor stations.

For the purpose of the U.S. EPA NESHAPS definitions from Table II-3 above, the “custody transfer” point is the demarcation between the “Upstream” exploration/production/processing industry sectors and the entry point into natural gas transmission, storage and distribution sectors that are the topic of this Discussion Paper. However, for purposes of this Discussion Paper, a more accurate demarcation between high pressure transmission and low pressure distribution is the “city gate”, as discussed below.

The U.S. EPA defines the boundaries of the sector subject to the cited regulation as “owners and operators of natural gas transmission and storage facilities that transport or store natural gas prior to entering the pipeline to a local distribution company (or to a final end user (if there is no local distribution company)”. As stated in the footnote to Table II-3 above, for the protocol that will be developed by WRI and the Registry, it is recommended that the phrase “local distribution system” replace the phrase “local distribution company”.

It is also important to recognize that natural gas utility companies often operate intra-state high pressure transmission and storage facilities, and that the real delineation between high pressure “transmission and storage” on the one hand and low pressure “distribution” on the other hand is the “city gate” where natural gas enters a local distribution system.

Consequently, it is recommended to adopt a combined approach and designate the operations that are covered by this Discussion Paper as those that operate under NAICS 221210 and/or 486210, and their boundaries would consist of activities that are downstream of the “custody transfer” points at the exit from the gas processing plant and/or the “city gate” facility.

Finally, it is important to recognize that pipelines that cross continents could be subject to multiple regulatory regimes governing their operation and therefore, the NG T&D protocol ought to allow several options of reporting detail and flexibility depending on the regulatory context and availability of data for estimating GHG emissions.

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III. HOW ARE BOUNDARIES DEFINED? This section of the discussion paper aims to supplement the boundaries chapters in the Registry’s GRP and WRI’s Corporate Standard with relevant, sector-specific guidance for NG T&D companies. The objective is to provide additional information to help define geographical boundaries (if necessary), organizational boundaries, and operational boundaries.

The approach presented here is relevant both for companies that operate exclusively within the NG T&D industry sector or for other entities where one or more of their subsidiaries, joint-venture partnerships, or operating divisions are engaged in natural gas transmission and/or distribution activities.

For the purpose of reporting to WRI and the Registry, the reporting unit is the applicable corporate or organizational entity in accordance with existing protocols. Entities are expected to report GHG emissions from all of their operations, using general guidance or sector specific tools and protocols that cover their operations. Entities are expected to document the approach used to establish their organizational boundaries, which should be consistent with existing guidelines and further include special considerations for NG T&D operations, as discussed below.

III.1 Geographical Boundaries

Establishing geographical boundaries for reporting will depend on the program. For the purposes of reporting to the California Registry, the geographic boundaries only apply to the Registry and the options are limited to:

• U.S. GHG emissions as a whole, or • California emissions only.

The Registry does accept international GHG emissions data but does not certify it.

WRI does not collect data from companies and sets no geographic boundaries.

Boundaries are set for emission sources based on where the natural gas is transported, stored or distributed. Some difficulties may be encountered when pipelines cross jurisdictional lines such as national, provincial or state boundaries, in which case there might be several options on how to report the GHG emissions associated with the run of the pipeline by itself. Several options might be considered when providing guidance to reporting entities:

1) Developing an average emission factor for that specific type of pipeline (pressure, diameter, type of fluid) and devising an allocation scheme that relies on the length of pipeline segments within a certain jurisdiction; or

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2) Adopting a convention where the GHG emissions from each pipeline segment are lumped together (and reported) with those of the geographically nearest compressor or pumping station.

For both options there will be a need to have some average emission factor that could be used to quantify emissions from various types of pipelines. If option (2) is adopted, reporting entities should be able to assess whether the emissions from the pipeline segment are significant in the context of the overall emissions from the compressor or pump station. They might be able to demonstrate that these emissions are insignificant (under normal operating conditions) and would not require detailed GHG reporting. As noted above in the discussion of “Facility” definition., the U.S. EPA has long-standing definitions of “facility” for purposes of determining applicability of the new source review (NSR) and prevention of significant deterioration (PSD) program. Under the NSR/PSD program, EPA does not consider long line sources such as pipelines to be a single source, “despite connection between them.” In accordance with these practices, it is recommended that underground pipelines should not be considered as the same ‘source’ or ‘facility’ as above ground compressor stations, and Option (1) above be adopted for reporting emissions from the “run of the pipeline”.

It should be emphasized yet again that geographic boundaries are not the same as organizational boundaries. Geographic boundaries reflect the physical location of the reporting sectors’ facilities and operations, while organizational boundaries reflect financial, legal and operational relationships that are discussed in further detail below.

III.2 Organizational Boundaries

Corporate organization of the natural gas transport sector varies around the world in accordance with the structure of local natural gas markets, regulatory regimes and corporate policies. They could be owned and operated by either utility companies, as divisions of integrated oil and natural gas companies, or as stand alone pipeline transportation companies, or a mixture of joint-ventures and other legal entities as applicable. This could include various legal agreements with state or publicly owned companies.

In some cases the structure is simple: exploration and production companies explore and drill for natural gas, selling their product to large transportation pipeline companies, which transport the natural gas, selling it to local distribution utilities, which in turn distribute and sell the gas to its customers. In other cases, natural gas marketing divisions, joint-ventures or stand alone companies facilitate the movement of the natural gas from the producer to the end user and they, the marketer, can also contract for transportation and storage. Essentially, a myriad of different ownership pathways exist for natural gas to proceed from producer to end user.

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As with other sectors, there are several options for establishing organizational boundaries and consolidating into one report the various components of the entity and therefore the GHG emissions that will be reported. WRI and the Registry provide three possible approaches: operational control, financial control, equity share. In addition there may be other contractual arrangements that detail specifically who will report the emissions, which are also allowed, and should be noted in the description of the consolidation approach chosen by the entity. Once the geographical boundaries for reporting have been established the entity is expected to evaluate all operations, facilities, and sources within the appropriate geographical setting and establish a consistent approach for reporting GHG emissions from operations within those boundaries.

Accounting for GHG emissions is complicated by the wide array of organizational relationships that are common in this industry sector. This is an on-going process as energy markets get more deregulated around the world. Typically, NG T&D operations are undertaken by different types of business organizations and legal agreements. The most common ones are:

• Subsidiary – A parent company either wholly owns the subsidiary or has enough voting stock to have full control;

• Joint Venture – Several corporations either work together or form a new company that manages and operates certain joint assets and capital. If a new company is created then the joint venture partners are its sole shareholders. If no independent company is created one of the joint-venture partners serves as the operator.

• Joint-Venture with a publicly owned company – Several corporations join-in with a national, state or local public owned company for the purpose of developing the infrastructure and/or operating facilities on behalf of the public entity. They could form a new company or operate as independent companies under a contractual agreement.

• Limited Partnership – A limited partnership is a form of partnership similar to a general partnership, except that in addition to one or more general partners there are one or more limited partners. The general partners have similar roles and responsibilities as partners in a conventional firm, Like shareholders in a corporation, the limited partners limited liability and no management authority. Limited partnerships are distinct from limited liability partnerships, in which all partners have limited liability.

• Stock ownership – Ownership of stock in publicly traded corporations. Accounting standards define that an ownership of 20% or more of company stock results in significant influence.

Detailed guidance on the subject is available from several general reporting protocols (WRI/WBCSD, 2004 and CCAR, 2006), and from the Petroleum Industry Guidelines (IPIECA, 2003). In short, for those operations and facilities that are wholly owned, all associated emissions

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are typically reported. For those operations or facilities in which a company has a partial ownership share (working interest), holds an operating license, or operates as a joint venture, or under a limited partnership, there are several options for determining how the GHG emissions will be reported. Option 1: Control Approach

This option consists primarily of reporting 100% of the GHG emissions from operations, facilities, and sources over which the organization has control. The exact interpretation of what it means to “have control” is based on both financial accounting standards and common practices. This could be summarized as follows:

1) Financial Control – a company has financial control over an operation if it has the ability to direct both the financial and operating policies of the operations with a view to gaining economic benefits from such activities;

2) Operational Control – a company has operational control over an operation if it has the full authority to introduce and implement its operating policies and practices at the operation.

If a “control” approach is used, companies would report 100% of the emissions from those operations where they exercise “control”. However, this approach could result in situations where they would not be reporting GHG emissions from potentially significant parts of their overall business – for those operations where they have neither financial nor operational control, although they have a material stake.

It should be noted that reporting based on operational control is the common practice for natural gas systems, thus the resultant protocol should consider designating it as the primary approach for reporting for the NG T&D sector. Equity-based reporting, as discussed below, would also be included as an optional approach to be used at the discretion of the system owner/operator.

III.2.1 Option 2: Equity Share

This option consists of reporting the percentage of GHG emissions, based on the entity’s share of financial ownership of an operation, facility, or source. The equity concept relies on economic interest that is linked to the financial gain or loss from an operation.

The equity share approach could also extend to situations where companies (or their major subsidiaries) are involved in joint ventures where the participants have contracts or legal agreements that assign GHG emission ownership rights.

Particular types of contractual agreements are Production Sharing Agreements that address the ownership of gas produced in association with oil or from coal-beds. If the gas is collected, processed and transferred into a pipeline system for transmission and distribution then the

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emissions associated with this gas should be treated the same as with any natural gas that enters the system.

When voluntarily reporting emissions, entities ought to follow arrangements described in their contracts irrespective of whether they report on an equity share or operational control basis. However, when reporting under particular reporting initiatives (schemes), entities should follow the reporting requirements that are specified for those reporting systems, such as those for WRI and the Registry.

III.3 Gas Transport Considerations

Natural Gas transportation via pipelines could be undertaken under various scenarios; companies can either operate as if they were “common carriers”, where they provide the pipelines and their facilities for hire but do not own the natural gas transmitted. Or they can enter directly into contracts with distribution companies and purchase agreements with natural gas providers, as discussed above.

Prior to the passage of FERC Order 636 in 1985 in the U.S., local distribution companies purchased wholesale natural gas from the interstate natural gas pipelines, which in turn purchased and amalgamated the needed supply from available producers. In general, under this mode of operation gas quality specifications in purchase contracts allow the acceptance of a wide variation of gas supply, with small quantities of “out of spec” gas being averaged out in the blended delivered gas stream. This is still the operating practice in many parts of the world.

In the U.S., FERC Order 636 separated the gas transportation and ownership responsibilities, canceling those contracts, which then allowed suppliers, marketers and end users to purchase and ship their own gas on those pipelines. Although gas pipelines by definition are not “common carriers” but “contract carriers”, the restructured business systems that resulted have incorporated the quality specifications for the natural gas transported into the tariffs, and the transmission companies have to handle varying specifications for natural gas in almost every dispatch delivered to end customers. However, the varying compositions are within the tariff specifications unless the pipeline decides to waive the requirements. This could add to the complexity of defining an average heat content and trace compounds speciation for the gas transported. The distribution companies on the other hand have a much better handle on natural gas quality specifications based on their supply contracts.

In considering the emissions from all the sources within the operational boundaries of the NG T&D sector, it is important to note that entities that comprise this sector, and which might be using this guidance, vary greatly in size, scope and complexity. Some are multinational organizations where NG T&D operations are just a small part of overall activities (and consequently GHG

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emissions). Others might be companies that specialize in NG T&D where the emissions covered by this protocol will represent most – if not all – of their GHG emissions. Hence, the emission estimation methods used will have to meet the needed level of detail for specific situations, while allowing for a tiered approach in method rigor to fit the need. This will ensure that methods utilized are most appropriate for particular operations and do not impose undue burden for operations where these emission are not significant (or, material).

III.4 Operational Boundaries

Natural gas transmission and distribution systems consist of both large diameter high pressure pipelines and smaller diameter low pressure lines, and a number of support facilities and equipment that include metering stations, compressor stations, scraper (pig) launching/receiving stations, relief valves, maintenance facilities, office buildings and vehicles. Glycol dehydrators may be associated with deep reservoir storage systems within a transmission system and filter/separators can be found anywhere within the marketing system where condensable hydrocarbons may be present.

Storage facilities are used to store natural gas produced during off-peak times (usually summer) so that gas can be delivered during peak demand. Storage facilities can be below or above ground. Aboveground facilities liquefy the gas by super-cooling and then storing the liquefied natural gas (LNG) in heavily insulated tanks. Below-ground facilities compress and store natural gas in the vapor phase in one of several formations: 1) spent gas production fields, 2) aquifers, or 3) salt caverns.

III.4.1 Scope 1: Required Direct GHG Emissions Direct GHG emissions occur from sources that are owned or controlled by the company. Within the natural gas pipeline sector, direct emissions result from:

• Stationary combustion of fossil fuels to operate compressors, engines, pumps, and other equipment, to dispose of waste gas or emergency releases through flares or incinerators, and for the generation of electricity, steam, heating or cooling for facility needs;

• Mobil combustion sources (cars, trucks, construction equipment, etc.) owned for pipeline system operations;

• Process vents from equipment that vent natural gas as part of their operation, as well from maintenance activities, or from emergency releases; and

• Fugitive emissions from pressurized equipment handling natural gas or from non-point evaporative sources.

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The following tables outline the potential emission sources that may contribute to direct emissions.7 Sources are presented relative to the sub-sector of the natural gas pipeline industry in which they apply (e.g., transmission, storage, LNG, distribution) and the type of GHG emissions that result (CO2, CH4, N2O, HFCs, PFCs, SF6). References are provided for available calculation methodologies presented in Sections V, VI, VII, and VIII of this Discussion Paper. Emission sources that were considered but determined to be outside the scope of the NG T&D Protocol are noted.

Table III-1. Potential Direct Emission Sources – Stationary Combustion

Methodology Reference

Likely Pipeline Industry Sector(s) Potential Emission Sources

GHG Emissions of

Interest Transmissions, Storage, LNG

Reciprocating engine compressor drivers Turbine/centrifugal compressor drivers IC engine generators Turbine generators

Transmission, Storage

Dehydrator reboilers

All Facility boilers or process heaters Space heaters, water heaters Line heaters Chillers

V.1 V.2 V.3 V.5

LNG Heat exchangers for vaporization V.4 V.5

Transmission, Storage, LNG

Flares Catalytic and thermal oxidizers Incinerators

All Diesel, gasoline, propane and natural gas fired backup, full-time, or portable generators Diesel and gasoline powered small engines for line and facility maintenance Other miscellaneous fossil fuel fired equipment

All Fire pumps

V.1 V.2 V.3 V.5

LNG LNG booster pumps Sea water pumps Boiler off gas compressors Liquefaction compressors

Primarily CO2, formed through the oxidation of fuel carbon. To a lesser extent, CH4 and N2O.

Table III-2. Potential Direct Emission Sources – Mobile Combustion


Pipeline Industry Sector Source Types

GHG Emissions

All Company vehicles (passenger cars, vans, light duty service trucks, heavy duty service trucks)

V.3.1 V.3.2 V.6 All Off road construction and/or excavation

equipment (backhoes, loaders, dump trucks, water trucks)

Primarily CO2, formed through the oxidation of fuel carbon.

7Note: NG T&D may include atypical equipment associated with upstream operations.

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Pipeline Industry Sector Source Types

GHG Emissions

LNG Road tanker trailers Railroad tankers

LNG Marine tankers Barges Tug boats

V.3.1 V.3.2 V.6

All Planes/helicopters

To a lesser extent, CH4 and N2O.

Table III-3. Potential Direct Emission Sources – Process Vents



GHG Emissions of

Interest VI.1 Storage Dehydrator process vent

Dehydrator Kimray pump VI.2 VI.3

Transmission, Storage

Pneumatic controllers/ actuators Pneumatic pumps (other than Kimray)

VI.4 LNG Loading/unloading/transit Transit emissions LNG storage tanks LNG off-loading LNG cold box LNG re-vaporization Vapor handling system

Primarily CH4, though there may be some small amount of CO2 in the gas.

Transmission and Distribution

Pipeline venting Pipeline dig-ins Internal inspection and cleaning (other than pigging)

All Gas sampling/analysis Transmission Pigging Distribution Drips

Odorizer injection Transmission, Storage, LNG

Compressor blowdowns Compressor starts Compressor station venting


Metering and Regulating (M&R) station venting

All Vessel blowdowns Storage Storage tanks

Storage station venting

VI.5 VI.6

All Pressure Relief Valves (PRVs) Emergency vents

Outside NG T&D Boundaries

Liquid pipelines Surge tanks

Outside NG T&D Boundaries

Unique operation. Generally this gas is used for electric generation at or near the collection facility.

Landfill gas collection systems Anaerobic digested gas collection systems


VI.7 All Fire extinguishers HFCs, PFCs

14

Table III-4. Potential Direct Emission Sources – Fugitive



GHG Emissions of

Interest Transmission, Distribution, Storage

Buried pipelines Primarily CH4, though there may be some small amount of CO2 in the gas. SF6 may be used as a tracer.

Transmission, Distribution, LNG

Compressor seals Compressor components Compressor station components

All M&R station components Meters

Storage Wellhead – active storage field Wellhead – abandoned storage field

LNG Vapor handling system LNG booster pumps Boiler off gas compressor

Potentially All Anaerobic water/waste water treatment



Organic liquid storage tank components Potentially small amount of CH4

VII

All Chillers Mobile air conditioning units Stationary refrigeration/AC units

HFCs, PFCs

III.4.2 Scope 2: Required Indirect GHG Emissions from Purchased and Consumed Energy

Indirect GHG emissions are those that are a consequence of a pipeline company’s activities, but occur from sources owned or controlled by other(s). Indirect emissions should be accounted for separate from direct emissions to avoid double counting.

Within the natural gas pipeline sector, indirect emissions result from:

• Purchased electricity; • Purchased heat/steam; and • Purchased cooling water.

Emissions of CO2, CH4, or N2O are associated with indirect emissions, as these GHGs are released from fossil fuel combustion in the generation of energy. Refer to Section VIII indirect electricity emission calculation methodologies.

15

Table III-5. Indirect Emissions

Methodology Reference Potential Emission Sources

Likely Pipeline Industry Sector(s)

GHG Emissions of

Interest VIII.1 Electricity

VIII.2 Heat/Steam

VIII.3 Cooling Water

All Primarily CO2, formed through the oxidation of fuel carbon. To a lesser extent, CH4 and N2O.

III.4.3 Scope 3: Other Indirect GHG Emissions

Scope 3 emissions relate to emission sources that are not owned or operated by the pipeline company but are related to their operations. Reporting Scope 3 emissions is optional; however, companies may choose to report emissions associated with operations that are important to their business and goals. For natural gas pipeline companies, many of these include GHG emissions that are attributed to third parties whose operations on behalf of the entity are instrumental to carrying out the organization’s business. Potential Scope 3 emissions might include:

• Emissions associated with 3rd party transport of a natural gas owned by the reporting company;

• Third party regasification of LNG; • Third party operation of natural gas storage sites; • Contracted natural gas dehydration operations; • Contracted pipeline inspection and maintenance activities; • Emissions from leased equipment used for maintenance or construction activities; • Leased facilities; • Emissions associated with other contracted activities; • Emissions associated with upstream landfills, coal bed methane operations, etc.

supplying natural gas to the pipeline system; • Transportation of employees or contractors to remote areas for operation, inspection

and maintenance; • Waste disposal; and • Wastewater treatment located onsite, but owned and operated by another entity. • When companies choose to report these types of emissions, they should be reported

separately from direct emissions (Scope 1) or indirect emissions from the consumption of energy (Scope 2) to avoid “double counting”.

16

III.5 Establishing and Updating Base Year8 Emissions

Due to the dynamic nature of pipeline companies and their changing business environment, some level of effort will be required for pipeline companies to maintain an accurate base year inventory that permits meaningful comparison of year-to-year inventory changes. Selecting a baseline year may also warrant some consideration, particularly related to the availability of data to support a reliable baseline inventory. However, there are no unique baseline considerations for natural gas pipelines. Pipeline companies can refer to the Registry’s GRP or the Corporate Standard for further guidance on conditions and thresholds for updating the baseline.

III.6 Data Collection Levels

Examples of ‘Facility’ Definitions ISO GHG Standards Facility means a single installation, set of installations or production processes (stationary or mobile), which can be defined within a single geographical boundary, organizational unit or production process. [ISO 14064.1, final international standard, 2005] EU-ETS Installation means a stationary technical unit where one or more activities listed in Annex I to the Directive are carried out and any other directly associated activities which have a technical connection with the activities carried out on that site and which could have an effect on emissions and pollution, as defined by the Directive. [Guidelines for the monitoring and reporting of GHG emissions pursuant to Directive 2003/87/EC of the European Parliament and of the Council, 29 January 2004] U.S. EPA NESHAPS for Natural Gas Distribution & Storage Facility means natural gas transmission and storage equipment that is located inside the boundaries of an individual surface site. Equipment that is part of a facility will typically be located within close proximity to other equipment located at the same facility. Natural gas transmission and storage equipment or groupings of equipment located on different gas leases, mineral fee tracts, lease tracts, subsurface unit areas, surface fee tracts, or surface lease tracts shall not be considered part of the same facility. [U.S. EPA, Code of Federal Regulations, Title 40, chapter I, part 63 subpart HHH]

Based on current WRI and Registry protocols, companies can report corporate level data subdivided into major categories by types of sources (stationary or mobile) or operation (direct or indirect). This top down approach for collecting and reporting data may not satisfy emerging programs where the emphasis is moving toward collecting facility level data (or even unit level data) and rolling it up to the corporate (or entity) level. These programs might have different data collection and information requirements and could lead to inconsistencies in the resultant entity emissions inventory in the aggregation and roll-up process.

In order to lay the foundation, and to try to reconcile these differing approaches, it is important to clarify how a “facility” might be defined and how it could be incorporated within the entity realm. Selected examples of such definitions are provided in the text box to the right. The basic difference between the various approaches is whether a facility is

8 Baseline is sometimes used to refer to the base year in the California Registry. The base year is the year against which future inventories will be compared in order to identify reductions over time that the company may be seeking to achieve, either to meet a voluntary target or for other performance initiatives.

17

comprised of a physical structure that can be bound by a real or imaginary fence line, or whether it refers to an assembly of similar operational activities that are more amenable to be functionally controlled. The choice of a specific definition would have an impact on data collection needs for constructing an emissions inventory. The ultimate decision on how a “facility” and/or an “entity” is to be defined should be left to the framers of individual reporting programs and GHG tracking schemes.

The ISO international standard9 allows for flexibility in defining a ‘facility’ by recognizing that it can either be a physical location or a functional grouping. It goes on to state that “an organization’s GHG emissions and removals are aggregated from facility-level quantification of GHG sources and sinks” (see footnote 8). In contrast, the “regulatory” approaches focus on a physical location and its associated equipment. These approaches will differ in the granularity of the reported GHG emission and would entail different levels of data collection and data quality.

A top down approach, which is also compatible with functional definitions of “facilities” is usually less resource intensive. It relies on higher level estimates of emissions that could be applied in a consistent manner over a wide array of operations. When moving to a bottoms-up approach, at the physical site level, a higher level of detail will be required for each facility including information about specific activity levels , fuels consumed and other factors that impact emission calculations for that specific physical site.

As a consequence, these differing approaches could lead to differences in the overall GHG reported. In a top-down approach, entities have a better chance of accounting for all of their activities in a similar manner to their fiscal accounting practices. Namely, the inventory could address partial ownership of a myriad of operations and energy imports that are used to run their administrative offices, along with other optional reporting elements. Alternatively, when reporting on a bottoms up basis at the physical facility level, there is a chance of obtaining more GHG emissions details from given sites by reporting emissions from unique operations and processes that would otherwise be immaterial at the entity level. However, there is also a potential of creating inconsistencies if information in not available at the same level of detail for all facilities. It could also blur the corporate responsibility aspect of reporting if one or more of the sites encompass operations that are owned (or operated) by several entities.

Therefore, careful attention ought to be paid to the ramification of “facility” definition and the associated requirements on how to aggregate and report GHG emissions. Ultimately, the choice should aim to achieve the highest level of data accuracy balanced against resource burden and availability of site-specific data and emission estimation methodologies.

9 ISO TC207, Greenhouse Gases Part 1 – Specification with guidance at the organization level for quantification and reporting of greenhouse gas emissions and removals, ISO 14064-1, April 2006

18

These could be reconciled by adopting a flexible approach where “facilities” could either be defined as equipment that is located inside the boundaries of an individual surface site, or as a collection of such installations that are operated by a common organizational entity using common operating practices and processes. For example, for the NG T&D sector that would mean that a “facility” could be either physical sites, such as individual compressor stations, where one would collect site specific information like the amount of fuels consumed and its carbon content; or it could be a functional ”facility”, such as miles of interstate pipeline within a given pressure range, where an average factor (such as emissions/pipeline-miles) could be used to calculate GHG emissions. The entity GHG inventory will then include the aggregation of these “facilities” to the reporting entity level.

19

IV. WHAT METHODS ARE AVAILABLE FOR ESTIMATING GHG EMISSIONS?

Emissions are generally calculated by multiplying an annual emission factor, which represents an average emission rate per source, by a corresponding measure of the emission source activity (activity value), such as the number of equipment units or the frequency of an emission generating event. This is illustrated by the following equation:

⎟⎟⎠

⎞⎜⎜⎝

⎛=⎟⎟

⎠

⎞⎜⎜⎝

⎛×⎟⎟⎠

⎞⎜⎜⎝

⎛Rate

EmissionValue

ActivityFactor

Emission Equation 1

For many emission sources within the NG T&D sector, a variety of emission estimation approaches exist. In addition, the GHG estimation methodologies are continuing to evolve, particularly for the natural gas systems. Figure IV-1 illustrates the hierarchy associated with the range of available options for estimating emissions.

Types of Approaches Hierarchy

Published emission factors

Equipment manufacturer emission factors

Engineering calculations

Monitoring over a range of conditions and deriving emission factors

Periodic monitoring of emissions or parameters for calculating emissions

Continuous emissions* or parameters monitoring

Improved accuracy Additional data requirements

Higher cost

*Continuous emissions monitoring applies broadly to most types of air emissions, but may not be directly applicable nor highly reliable for greenhouse gas emissions associated with natural gas transmission and distribution.

Figure IV-1. Estimation Approaches

Even within this hierarchy, there may be multiple levels of detail and accuracy associated with a particular approach. For example, published emission factors can range from very broad, national level factors to emission factors specific to a type of equipment or equipment component.

20

Sections V, VI, VII, and VIII present the emission estimation approaches for NG T&D operations. Where, possible, an indication of accuracy and level of effort in gathering data for different approaches is provided. The primary GHG types addressed in this analysis are carbon dioxide (CO2), methane (CH4), and nitrous oxide (N2O). The emissions are organized in the following sections according to the following major categories: combustion (including stationary and mobile sources), vented, fugitive, and indirect (e.g., electricity usage) emissions.

IV.1 Methodology Review

In addition to the protocols and tools available through the Registry and WRI/WBCSD, methodologies examined in this Discussion Paper primarily rely on work conducted in developing the API Compendium (API, 2004) and the INGAA Guidelines (INGAA, 2005).

In 2000, API initiated a project to develop an industry-wide protocol for quantifying GHG emissions based on a compilation of recognized emission factors and emission estimation techniques applicable to world-wide oil and natural gas industry operations. The early stages of the API Compendium development project included the review and comparison of the following GHG emissions estimation protocols and inventory reports:

1. American Petroleum Institute (API). Methane and Carbon Dioxide Emission Estimates from U.S. Petroleum Sources, January 1997.

2. Canadian Association of Petroleum Producers (CAPP). Global Climate Change Voluntary Challenge Guide, June 2000.

3. E&P Forum [more recently named the Offshore Gas Producers (OGP)]. Methods for Estimating Atmospheric Emissions from E&P Operations, September 1994.

4. Emission Inventory Improvement Program (EIIP). Guidance for Emissions Inventory Development, 1999.

5. US Environmental Protection Agency (EPA). Methane Emissions from the U.S. Petroleum Industry, Volumes 1-15, February 1999.

6. Gas Research Institute (GRI) and EPA. Methane Emissions from the Natural Gas Industry, June 1996.

7. Intergovernmental Panel on Climate Change (IPCC). Greenhouse Gas Inventory Reference Manual: IPCC Guidelines for National Greenhouse Gas Inventories, Volume 3, 1997.

8. Canadian Petroleum Association (CPA). A Detailed Inventory of CH4 and VOC Emissions from Upstream Oil and Gas Operations in Alberta, Volumes I-III, March 1992.

9. US Department of Energy (DOE). Instructions for Form EIA 1605 Voluntary Reporting of Greenhouse Gases, 1997.

21

On completion, the pilot API Compendium underwent industry and NGO review and was updated in early 2004. Part of this review process included a qualitative and quantitative benchmark of the Compendium to the most current GHG protocols available from the oil and gas industry, governmental, and non-governmental organizations. Differences revealed from the study formed the foundation for continued discussion with other GHG protocol and policy development groups, and the 2004 update to the API Compendium.

In updating the API Compendium, a more detailed comparison study was conducted to identify and understand differences among various existing and newly developed emission estimation guidance documents. The following documents were reviewed on a qualitative basis to examine differences between their emission estimation approaches and those provided in the API Compendium.

• Australian Greenhouse Office (AGO), Workbook for Fuel Combustion Activities (AGO a, 1999) and Workbook for Fugitive Fuel Emissions (Fuel Production, Transmission, Storage, and Distribution) (AGO b, 1999);

• Australian Petroleum Production and Exploration Association (APPEA), Greenhouse Challenge Report (APPEA, 2000);

• Canadian Association of Petroleum Producers (CAPP), Calculating Greenhouse Gas Emissions (CAPP a, 2003);

• Canadian Association of Petroleum Producers (CAPP), Estimation of Flaring and Venting Volumes from Upstream Oil and Gas Facilities (CAPP b, 2003);

• Canadian Industrial Energy End-Use Data and Analysis Centre (CIEEDAC) memorandum on “Guide for the Consumption of Energy Survey” (CIEEDAC, 2000);

• Environmental Protection Agency (EPA), Emission Inventory Improvement Program (EIIP, 1999);

• European Environment Agency (EEA), EMEP/CORINAIR Emission Inventory Guidebook (EEA, 2002);

• Exploration and Production Forum (E&P Forum) Methods for Estimating Atmospheric Emissions from E&P Operations (E&P Forum, 1994);

• Intergovernmental Panel on Climate Change (IPCC), Guidelines for National Greenhouse Gas Inventories (IPCC, 1997; UNECE/EMEP, 1999; IPCC, 2001);

• Regional Association of Oil and Natural Gas Companies in Latin America and the Caribbean (ARPEL), Atmospheric Emissions Inventories Methodologies in the Petroleum Industry (ARPEL, 1998);

• UK Emissions Trading Scheme (DEFRA, 2003);

22

• UK Offshore Operators Association Limited, Guidelines for the Compilation of an Atmospheric Emissions Inventory (UKOOA, 2002); and

• World Resources Institute and World Business Council for Sustainable Development, The Greenhouse Gas Protocol (WRI/WBCSD, 2001) and calculation tools for Stationary and Mobile Combustion Sources (WRI/WBCSD, 2003).

Similarly, the INGAA GHG Emissions Estimation Guidelines for Natural Gas Transmission and Storage Document presents a compilation of estimation methods for assessing GHG emissions from combustion and non-combustion sources at natural gas transmission and storage facilities. Additional resources reviewed in developing the INGAA Guidelines include the following:

• GRI Canada. Handbook for Estimating Methane Emissions From Canadian Natural Gas Systems. Prepared by Clearstone Engineering Ltd., Enerco Engineering Ltd., and Radian International for Gas Technology Canada. Guelph, ON, 1998

• GHGCalc™, Gas Research Institute software Version 1.0, GRI-99/0086 December 1999 and GRI-GHGCalc™, Version 1.0 Emission Factor Documentation, July 2001

• AEA Technology Environment, R Stewart, A Survey of Gaseous Emissions to Atmosphere from UK Gas Turbines (1998)

• AEUB, Alberta Energy and Utilities Board, “Guide 60: Upstream Petroleum Industry Flaring Guide” (February 2001)

• AGO – 2004 - "Australian Methodology for the Estimation of Greenhouse Gas Emissions and Sinks (2002), Energy (Stationary Sources)" National Greenhouse Gas Inventory Committee, Australian Greenhouse Office (May 2004).

• CORINAIR 94 (Core Inventory Air), European Topic Centre on Air Emissions, CORINAIR 1994 Inventory, European Environment Agency (1998)

• CORINAIR 90, European Topic Centre on Air Emissions, CORINAIR 90 Summary Report.

• Edison Mission Energy “Greenhouse Gas Emission Factor Review - Final Technical Memorandum” (February, 2003)

• Environment Canada, Canada's Greenhouse Gas Inventory 1990-2001, Greenhouse Gas Division (August 2003)

• European Environment Agency “Annual European Community Greenhouse Gas Inventory 1990 – 2002 and Inventory Report 2004” (July 2004)

23

• International Association of Oil & Gas Producers “Environmental Performance in the Exploration and Production Industry, 2003 Data” (December 2004)

• Interstate Natural Gas Association of America (INGAA) White Paper “Greenhouse Gas Emissions Inventory for Natural Gas Transmission and Storage: Status of Emission Estimation Methods and Issues for Development of a Sector-Specific Report” (September 2004)

• IPCC Emission Factor Database (EFDB) – National Greenhouse Gas Inventories, website (3/31/05); http://www.ipcc-nggip.iges.or.jp/EFDB/find_ef_main.php

• United States Department of Energy (US DOE) Office of Policy and International Affairs “Draft Technical Guidelines Voluntary Reporting of Greenhouse Gases (1065b) Program,” Office of Policy and Internal Affairs United States Department of Energy” (March 2005)

• US DOE Energy Information Administration (EIA) Office of Integrated Analysis and Forecasting “Documentation for Emissions of Greenhouse Gases in the United States 2002” (January 2004)

• US DOE EIA. Emissions of Greenhouse Gases in the United States 2001, DOE/EIA- 0573(2001) (December 2002)

• US DOE EIA Office of Integrated Analysis and Forecasting “Emissions of Greenhouse Gases in the United States 2003” (December 2004)

• US DOE “Guidelines for Voluntary Greenhouse Gas Reporting” 10 CFR part 300, RIN 1901-AB11 (March 2005)

• United States Environmental Protection Agency (US EPA), Office of Air Quality Planning and Standards; “AP 42, Fifth Edition: Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area Sources” (January 1995); Supplement A, B, and C, (October 1996); Supplement D (July 1998) Supplement E, 1999; and Supplement F, April 2000.

• US EPA “US Emissions Inventory 2004 Inventory of US Greenhouse Emission and Sinks: 1990-2002” (April 2004)

• US EPA “Quality Assurance/Quality Control and Uncertainty Management Plan for the U.S. Greenhouse Gas Inventory: Procedures Manual for Quality Assurance/Quality Control and Uncertainty Analysis” EPA 430-R-02-007B (June 2002)

• US EPA, US Emissions Inventory 2005: Inventory of US Greenhouse Gas Emissions and Sinks: 1990 - 2003, EPA 430-R-003, US Environmental Protection Agency, Washington, D.C., (April 2005)

24

• U.S. EPA Office of Atmospheric Programs, “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000”, EPA 460-R-02-003, Washington, DC, April 15, 2002.

• US EPA “Draft Inventory of US Greenhouse Gas Emissions and Sinks: 1990 – 2003” (February 2004)

• US EPA, 1995 “Protocol for Equipment Leak Emission Estimates”, EPA-453/R-95-017, November 1995

• US EPA “Quality Assurance/Quality Control and Uncertainty Management Plan for the U.S. Greenhouse Gas Inventory: Background on the U.S. Greenhouse Gas Inventory Process” EPA 430-R-02-007A (June 2002)

• Co-operative Programme for Monitoring and Evaluation of the Long Range transmission of Air Pollutants in Europe/The Core Inventory of Air Emissions in Europe (EMEP/CORINAIR) “Atmospheric Emission Inventory Guidebook, 3rd Edition, September 2003 Update” (October 2003).

• De Soete G.G., “Nitrous Oxide from Combustion and Industry”, Proceedings of International IPCC Workshop Methane and Nitrous Oxide, pp 287-358, 1993

• De Soete, G. G. and B. Sharp, “Nitrous Oxide Emissions: Modifications as a Consequence of Current Trends in Industrial Fossil Fuel Combustion and In Land Use”, EUR-13473, 1991.

• Ritter, K.; Lev-On, M; Shires, T. “Development of a Consistent Methodology for Estimating Greenhouse Gas Emissions from Oil and Gas Industry Operations”, Presented at the 11th Emissions Inventory Conference of the U.S. Environmental Protection Agency, Atlanta, GA, April 2002.

• Ryan, J. V., and W.P. Linak, “On-line Measurement of Nitrous Oxide from Combustion Sources by Automated Gas Chromatography”, EPA/600/A-92/215, NTIS PB 93106847, 1993

• Draft Memorandum from URS to GTI, “Nitrous Oxide Emissions from Natural Gas-Fired Reciprocating Internal Combustion Engines”, January 2002

A key conclusion from the review of existing data sources is that the majority of vented and fugitive emission factors associated with natural gas industry operations are based on work conducted by the Gas Research Institute (GRI) and Environmental Protection Agency (EPA).10 This study was conducted for the purpose of developing a national CH4 emissions inventory; the purpose was not to develop default emission factors for individual company inventory development. With most of the measurements conducted in the early 1990’s, emissions data from the GRI/EPA study may not accurately characterize current technologies, operating practices, voluntary initiatives such as Natural Gas STAR, 10 Gas Research Institute (GRI) and EPA. Methane Emissions from the Natural Gas Industry, June 1996.

25

government regulation of emissions, and economic conservation driven by the increased price of natural gas. EPA and the industry associations – AGA, INGAA, and API – are currently evaluating and prioritizing activities to update specific emission factors from the GRI/EPA study.

IV.2 Emission Factors

As discussed above, GHG emissions are generally estimated as the product of a source-specific emission factor (EF) and an activity factor (AF) that relates to the level of activity or extent of use of the emission source. Emission factors are generally presented in terms of the mass of GHG emissions (primarily CO2, CH4, or N2O for the NG T&D sector) per unit of activity, where the activity is typically a process rate or equipment count. For example, lb of CO2

per MMBtu of natural gas combusted, kg of methane leaks per number

of reciprocating compressors. The emission factors provided in the following sections represent current factors from the literature. In general, for natural gas systems, most of the factors have been derived from the GRI / EPA Study completed in the mid-1990’s.

Emission factors represent a “typical” or “average” emission rate based on the industry norm. These are often referred to as “default” emission factors. A particular company or facility may have actual emissions or operating conditions that vary from the “norm” represented by the emission factor.

Note: where emission factors are converted from a volume basis to a mass basis for a gas stream, the standard conditions are defined as 14.7 psia and 60°F. Using the ideal gas law:

nRTPV = (Equation 2)

where, P = pressure (psia or atm) V = volume (ft3 or cm3) n = number of moles R = gas constant = 10.73 psi ft3/lbmole °R

= 0.73 atm ft3/lbmole °R = 82.06 atm cm3/gmole K

T = absolute temperature (°R or K)

This equates to 1 lbmole = 379.3 standard cubic feet (scf) at the specified standard conditions of 14.7 psia and 60°F. In metric units, 1 gmole = 23,685 cm3 (23.685 m3/kg-mole) at these same conditions.

There are many different sets of standard or reference conditions, where “standard” often depends on the application or the industry convention. For example, physical properties of gases are often reported in terms of 0°C and 760 mm Hg (CRC, 1984). To convert a

26

volumetric rate from one set of standard conditions to another, the following equation can be used:

)(T )(P)(T )(P VV

12

2112 ⎥

⎦

⎤⎢⎣

⎡= (Equation 3)

where subscript "2" corresponds to the new set of standard conditions and subscript "1" corresponds to the initial conditions. Note that absolute temperatures (°R or K) are required for this equation. This conversion is demonstrated in the following exhibit.

Sample Calculation for Converting between Sets of Standard Conditions

INPUT DATA: The CH4 emission factor for a pneumatic device was determined to be 345 scfd/device based on the standard conditions of 14.7 psia and 60°F.

a) What is the emission factor at the EPA reference conditions of 14.73 psia and 298 K (77°F)?

b) What is the emission factor at 0°C and 760 mm Hg?

CALCULATION METHODOLOGY (a): The ideal gas law requires absolute temperatures. First, convert 60°F to an absolute basis, in this case Kelvin (K) so it will be on the same basis as the new conditions:

K 288.7273.15 1.8

32 - F 60=+

°

Using Equation 3, calculate the volume for the new standard conditions:

K298 andpsia 14.73at ,scf 355.4 K)(288.7 psia) (14.73

K)(298 psia) (14.7 scf) (345V

)(T )(P)(T )(P VV

2

12

2112

=⎥⎦

⎤⎢⎣

⎡=

⎥⎦

⎤⎢⎣

⎡=

CALCULATION METHODOLOGY (b): From Table 3-3, 0°C = 273.15 K. From Table 3-2, 760 mmHg = 14.696 psi Using Equation 3, calculate the emission factor volume corresponding to these new conditions:

mmHg 760 and C0at ,scf 326.51 K)(288.7 psia) (14.696

K)(273.15 psia) (14.7 scf) (345V2o=⎥

⎦

⎤⎢⎣

⎡=

27

IV.2.1 Confidence Intervals

The uncertainty associated with an emission factor depends upon both the application and the technical limitations associated with the dataset that forms the basis of the factor. The uncertainty also depends on the accuracy of the measurement methods associated with the emissions data. For example, combustion CO2 emission factors are more accurate due to the relative simplicity of the CO2

emission determination, while fugitive CH4 emissions

have a higher uncertainty due to the complexity of directly measuring fugitive emissions as well as facility-to-facility differences.

The GRI/EPA Methane Emissions study included a sampling program designed to address precision, bias, and accuracy calculations, with a national inventory accuracy objective of 0.5% of US production on the basis of a 90% confidence interval (GRI/EPA, 1996). Confidence intervals were established for each emission factor used in the study, where the confidence interval represents the lower and upper tolerances associated with an estimated number. In Sections VI and VII, confidence intervals are expressed in terms of precision where emissions factors from the GRI/EPA study are cited. Additional details on the confidence intervals can be found in the documents: Methane Emissions from the Natural Gas Industry, Volume 3: General Methodology and Volume 4: Statistical Methodology (Harrison, et. al., 1996; and Williamson, et. al, 1996).

IV.3 Emission Factor Adjustments for Gas Composition

Many of the vented and fugitive CH4 emission factors in the Sections VI and VII are based on a default industry segment CH4 composition of 93.4 mol% for transmission, storage, and distribution operations (default CH4 compositions are also noted in the emission factor tables). The CH4 default emission factors can be scaled based on the ratio of the site-specific CH4 content to the default emission factor concentration provided in the table if the site natural gas has a significantly different CH4 content from the default basis, as illustrated by the following equation:

⎟⎟⎠

⎞⎜⎜⎝

⎛×⎟⎟⎟

⎠

⎞

⎜⎜⎜

⎝

⎛=

4

444 CH % moldefault

CH % mol specific site

FactorEmission CH

Default Factor Emissions CH Site

(Equation 4)

Also, if the gas contains significant quantities of CO2, the CH4 emission factors can be adjusted based on the relative concentrations of CH4 and CO2 in the gas to estimate the CO2 emissions. The equation for ratioing the CH4 emission factor to obtain a CO2 emission factor is provided below:

28

⎟⎟⎠

⎞⎜⎜⎝

⎛×⎟⎟⎠

⎞⎜⎜⎝

⎛×

⎟⎟⎠

⎞⎜⎜⎝

⎛×⎟⎟⎠

⎞⎜⎜⎝

⎛×⎟⎟⎠

⎞⎜⎜⎝

⎛=

2

22

44

442

CO lbmolCO lb 44

gas lbmolCO % lbmol specific-site

CH % lbmoldefault gas lbmol

CH lb 16CH lbmol

FactorEmission CH

Factor Emission CO Site

(Equation 5)

29

V. DIRECT EMISSIONS - COMBUSTION This section addresses combustion emissions from stationary and mobile sources, flares, and other miscellaneous combustion sources.

V.1 Fuel Properties

Several of the combustion emission estimation approaches presented in this section rely on physical properties of the fuels. The primary fuels in the transmission and distribution segment are natural gas, diesel, gasoline, and propane. Table V-1 provides some default physical property data including density, higher heating value (HHV), and carbon content for these fuels. Consistent with the General Reporting Protocol (GRP), the heating value provided below are on a higher or gross heating value basis.

Table V-1. Typical Physical Property Data for Fuels Commonly Used in the Natural Gas Transmission, Storage, and Distribution Segments

Fuel Density Higher Heating Value Carbon Content

Natural Gas 1 lb/23.8 ft3 a (API) 1 lb/23.24 ft3 (WRI)

1027 Btu/scfb (Power Protocol) 1020a, 1004f Btu/scf (API)

947 Btu/scf (WRI)

76 wt. % C a (API) 33 lb C/MMBtu (WRI) 32 lb C/MMBtu (Power

Protocol) Diesel 7.1 lb/galc (API)

7.0-7.8 lb/gal (WRI) 7.04 lb/gal (GRP)

5.75 MMBtu/bblc (API) 5.96 MMBtu/bbl (WRI)

5.83 MMBtu/bbl (INGAA) 5.825 MMBtu/bbl (GRP-distillate)

87.3 wt.% C (INGAA) 44 lb C/MMBtu (WRI) 44 lb C/MMBtu (Power

Protocol) Gasoline 6.17 lb/galc (API)

6.2 lb/gal (WRI) 6.15 lb/gal (GRP)

5.46 MMBtu/bblc (API) 5.21 MMBtu/bbl (WRI)

85.5 wt. % Cd (API) 42 lb C/MMBtu (WRI)

Propane (liquid)

4.24 lb/galc (API) 3.824 MMBtu/bble (Power Protocol) 3.80 MMBtu/bblc (API)

81.6 wt. % Cd (API) 38 lb C/MMBtu (Power

Protocol)) Propane (gas) 1 lb/8.33 ft3 (WRI) 21,700 BTU/lb (WRI) 37.7 lb C/MMBtu (WRI)

Sources/Notes: Some values above required units conversions from the units provided in the source documents in order to report on a comparable basis a EPA AP-42, Section 1.4, Natural Gas Combustion, 1998. bDOE EIA 0384(2002), Annual Energy Review 2002, October 2003. c EPA AP-42, Appendix A, Miscellaneous Data Conversion Factors, 1995. d North American Combustion Handbook, Volume I: Combustion Fuels, Stoichiometry, Heat transfer, Fluid Flow, Third Edition, 1986. e EPA430-R-03-004, Table B-9, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2001, April 2003. f Canadian Association of Petroleum Producers (CAPP), Calculating Greenhouse Gas Emissions, Table 1-5, Canadian Association of Petroleum Producers, Publication Number 2003-03, April 2003.

30

Fuel property information should be readily available for the natural gas transported or stored by the pipeline companies. Properties based on natural gas measurements are preferred over default values. Fuel-specific information may be available from the fuel suppliers or from Material Safety Data Sheets for purchased fuels, such as diesel, gasoline, and propane.

The density data for natural gas, diesel (distillate), and gasoline in the API Compendium agreed with the data provided in Appendix B of the GRP and with the WRI/WBCSD Stationary Combustion Tool (with the exception of some small round-off differences). The density of liquid propane was not specifically provided in Appendix B of the GRP, and the WRI/WBCSD tool provided a gas-phase propane density.

Higher heating value data from Table 5.2 of the of the Power/Utility Reporting Protocol and from the WRI/WBCSD Stationary Combustion Tool differ slightly from the API Compendium for natural gas and propane as shown in the table. Diesel and gasoline heating values were not specifically listed in the Power/Utility Reporting Protocol.

The carbon contents are reported on different bases, so the API Compendium values and the other documents can not be directly compared.

INGAA’s natural gas transmission and storage GHG emissions guidance document (INGAA, 2005) presents similar fuel property data as the API Compendium in their Table 2-1. However, their diesel heating value is a little higher at 5.83 MMBtu/bbl compared to the API Compendium’s value of 5.75 MMBtu/bbl. INGAA also provides a diesel carbon content of 87.3 weight % based on Appendix A of AP-42, although this value could not be located in Appendix A of AP-42.

WRI/WBCSD’s GHG Protocol guidance for stationary combustion (WRI/WBCSD, 2005), Section 2.2.2.1, refers to the IPCC’s Good Practice and Uncertainty Management Guidance (IPCC, 2000) and the 1996 IPCC Guidelines for default heating values. Additionally, the WRI/WBCSD’s companion spreadsheet tool provides default higher heating value data on a mass basis. This spreadsheet tool is available on WRI/WBCSD’s GHG Protocol Initiative web page.

IPCC’s 2006 Guidelines document provides default lower (net) heating value data in Table 1.2 of Volume 2, Energy (IPCC, 2006). IPCC provides emission factors on a lower heating value (LHV) basis while the GRP relies on a higher heating value basis. IPCC’s heating value data are also on a mass basis (in addition to being on a LHV basis), so a direct comparison to the data provided in Table V-1 above cannot be made.

31

32

V.2 Energy Output to Energy Input Conversions

Many of the combustion emission factors presented in this discussion paper are on an energy input basis. This approach is consistent with the actual fuel consumption volumes or mass rates, and accounts for the loss in efficiency. Equipment vendors may specify Btu/hp-hr for a particular device to convert between power output and energy input. In the absence of this information, Table V-2 provides conversion factors for some common combustion sources that are taken from Table 3-6 of the API Compendium (API, 2004). These factors can be used to convert from a rated power output to an estimated energy input. These same power to energy conversions are provided in Table C-1 of the 2005 INGAA guidance document.

Table V-2. Power Output to Energy Input Conversions for Prime Movers

Fuel/Service Original Units,

Btu/kW-hr

Converted to HHV basis, Btu/hp-hr

No. 2 Fuel Oil / Combined Cycle Turbine 12,420 9,262 No. 2 Fuel Oil / Gas Turbine 14,085 10,503 No. 2 Fuel Oil / Internal Combustion Engine 10,847 8,089 No. 2 Fuel Oil / Steam Turbine (Boiler) 8,653 6,453 Gasoline / Industrial Enginea 9,387

(converted) 7,000

(original units) Natural Gas / Combined Heat and Power b 5,000 - 6,000 3,729 - 4,474 Natural Gas / Combined Cycle Steam Turbine with Supplemental Firing

10,229 7,628

Natural Gas / Combined Cycle Single Shaft 8,952 6,676 Natural Gas / Combined Cycle Combustion Turbine 11,648 8,686 Natural Gas / Gas Turbine 13,918 10,379 Natural Gas / Internal Combustion Engine 10,538 7,858 Natural Gas / Steam Turbine (Boiler) 10,502 7,831 Liquefied Propane Gas / Gas Turbine 13,503 10,069 Liquefied Propane Gas / Steam Turbine (Boiler) 14,200 10,589

Sources: EIIP, Guidance for Emissions Inventory Development, Volume VIII: Estimating Greenhouse Gas Emissions, EIIP Greenhouse Gas Committee, October 1999. a EPA, AP-42, Supplements A, B, and C, Table 3.3-1, October 1996. b Assumed output to input energy conversion based on industry best practice.

V.3 Stationary Combustion

Figure V-1 provides a decision tree for estimating CO2 emissions from stationary combustion sources based on available information. In addition, Table V-3 summarizes the advantages and disadvantages of different emission estimation methods for stationary combustion sources.

Figure V-1. Decision Tree for CO2 Emissions from Stationary Combustion Sources

Total volumes of fuels (by type) combusted

See Section V.3.1 of this Discussion Paper

Use emission factors in Section V.3.2

Yes

CO2 Emission Estimation Options Based on Available Information

No

See Section V.3.4.

Alternative Approaches

See Section V.2 for conversion from power output basis to energy input basis.

Equipment manufacturer or test data available, using similar fuel quality

Yes

Assume heating value based on Table V-1. Use emission factors in Section V.3.2

No

Equipment power output data and operating hours

Is a fuel carbon content available?

Options based on available information

Is a fuel Higher Heating Value (HHV) available?

Total volumes of fuels (by type) combusted

See Section V.3.1 of this Discussion Paper

Use emission factors in Section V.3.2

Yes

CO2 Emission Estimation Options Based on Available Information

No

See Section V.3.4.

Alternative Approaches

See Section V.2 for conversion from power output basis to energy input basis.

Equipment manufacturer or test data available, using similar fuel quality

Yes

Assume heating value based on Table V-1. Use emission factors in Section V.3.2

No

Equipment power output data and operating hours

Is a fuel carbon content available?

Options based on available information

Is a fuel Higher Heating Value (HHV) available?

33

34

Table V-3. Summary of Emission Estimation Methods for Stationary Combustion Sources

Method Information

Requirements Advantages DisadvantagesReference for

EFs or Technique Industry sector general emission factor

Total pipeline length for transmission

Station count for storage Main length for distribution

Simplest approach Low cost

Least accurate approach Assumes the type and quantities of

fuels consumed for a particular industry sector

Applies assumed fuel carbon contents and heating values

INGAA Tables 2-2 and 2-5

Fuel-based default emission factors

Quantity of fuel consumed by fuel type

Simple approach Low cost

Default factors rely on assumed fuel carbon contents and heating values

Doesn’t account for impact of equipment characteristics on CH4 and N2O emissions

Section V.3.2 of this Discussion Paper

Fuel based material balance approach

Quantity of fuel consumed by fuel type

Simple approach Low cost Good accuracy for CO2 emissions

when based on actual fuel carbon content

Doesn’t account for impact of equipment characteristics on CH4 and N2O emissions


Equipment level emission factors

Quantity of fuel combusted (volume, mass or heat content) by fuel type and equipment type

Fuel consumption can be determined from equipment ratings and operating hours

Accurate for CH4 and N2O emissions

Fuel consumption may not be metered at the equipment level and may be difficult to reconcile between equipment estimates and metered consumption


Manufacturer data for specific equipment

Energy content of fuel consumed

Accurate for CH4 and N2O emissions

Limited availability of information Data may reflect new equipment or

optimal conditions and may not be representative of actual operations


Measured emissions CEMS data or other emissions measurements

Accurate when CEMS are calibrated to measure CO2

Costly and time consuming to measure all equipment

Accuracy is diminished when CO2 is determined by algorithm

V.3.1 Stationary Combustion – Fuel Based Material Balance

Carbon dioxide emissions from combustion sources are not equipment specific. A highly accurate approach for estimating CO2 emissions from combustion sources is to apply a material balance that is based on the fuel usage and carbon content of the fuel (API, Section 4.1, 2004). The GRP (Section III.8.3) also allows participants to quantify emissions from CEMS reports if a CEMS is used. Additionally, the GRP allows companies to use certifiable combustion emission factors, but it does not present the material balance approach. (It should be noted that CEMS might introduce uncertainty in the estimation if the CEMS are not calibrated directly with CO2 but rather have an internal algorithm to compute CO2 based on fuel volume and CO/O2 content).

The Compendium approach conservatively assumes 100% oxidation of the fuel carbon to CO2. The 2006 IPCC Guidelines also assume 100% oxidation as the default assumption for stationary combustion (Note: previous versions of the IPCC Guidelines provided default, non-unity oxidation factors). Other inventory protocols (WRI/WBCSD, INGAA, the GRP) apply a percent carbon oxidation fraction, intended to reflect carbon that is emitted as soot or ash. The WRI/WBCSD spreadsheet companion tool to their stationary combustion guidance (WRI/WBCSD, 2005) provides default IPCC oxidation factors (i.e., pre-2006 IPCC guidance), though the current 2006 IPCC Guidelines no longer include default non-unity oxidation factors (i.e., 100% oxidation is now conservatively assumed by IPCC).

A general form of the material balance equation is provided below for gaseous fuels (e.g., natural gas). This equation is appropriate when the fuel usage in standard cubic feet (scf) and carbon content are known. For transmission and distribution pipeline companies, natural gas composition data should be readily available.

⎟⎠⎞

⎜⎝⎛×⎟⎟

⎠

⎞⎜⎜⎝

⎛×⎟⎠⎞

⎜⎝⎛×⎟

⎠⎞

⎜⎝⎛×

⎟⎠⎞

⎜⎝⎛×⎟

⎠⎞

⎜⎝⎛×⎟

⎠⎞

⎜⎝⎛×⎟⎟

⎠

⎞⎜⎜⎝

⎛=

lb 2204.62tonne

CO lbmoleCO lb 44

combusted C lbmoleformed CO lbmole 0.995

C lb 12C lbmole

fuel lbC lb content, carbon Fuel

fuel lbmolefuel lb MWT,

fuel scf 379.3lbmole

yearscf usage, Fuel (mt/yr) CO

2

22

2

(Equation 6) where:

scf = standard cubic feet of fuel at standard conditions of 1 atm. and 60°F; MWT = fuel molecular weight (lb/lbmole); and 0.995 lbmole CO2/lbmol C reflects the carbon oxidation for gas fuels.

35

A general form of the material balance equation for liquid fuels (e.g., diesel or gasoline) is provided below. It is appropriate when the fuel usage in gallons, the fuel density, and carbon content are known.

⎟⎠⎞

⎜⎝⎛×⎟⎟

⎠

⎞⎜⎜⎝

⎛×⎟⎠⎞

⎜⎝⎛×

⎟⎠⎞

⎜⎝⎛×⎟

⎠⎞

⎜⎝⎛×⎟⎟

⎠

⎞⎜⎜⎝

⎛×⎟⎟⎠

⎞⎜⎜⎝

⎛=

lb 2204.62tonnes

CO lbmolCO lb 44

combusted C lbmol formed CO lbmol 99.0

C lb 12C lbmol

fuel lbC lb content, carbon Fuel

gal.lb density, Fuel

yeargal. usage, Fuel (mt/yr) CO

2

22

2

(Equation 7)

The above material balance equations are similar to the equations presented in Section 4.1 of the API Compendium, Section 2.2.3 of INGAA (INGAA, 2005), Section 2.2 of the WRI/WBCSD GHG Protocol stationary combustion guidance (WRI/WBCSD, 2005), and Section 2.3.1.1 of Volume 2 of the 2006 IPCC Guidelines. INGAA and WRI/WBCSD incorporate the fractional oxidation factor, while the API Compendium presents this as an optional adjustment. IPCC’s 2006 Guidelines do not include the fractional oxidation factor in their simple, default emission factor approach, but state that it can be included in their more detailed country-specific and technology-specific approaches. The carbon oxidization factors are provided in Table C.5 of the GRP, and agree with the oxidation factors provided in Table 4-3 of the API Compendium, Table 2-4 of INGAA, and Table 4 of the WRI/WBCSD GHG Protocol stationary combustion guidance.

V.3.2 Stationary Combustion – Fuel Based Emission Factors

Carbon Dioxide Emissions

If only the fuel usage is known, and the fuel carbon analysis is not known, then the emission factors provided in Table C.5 of the GRP can be used to estimate the CO2 emissions. Section IV.8.4 of the GRP provides more background on estimating CO2 emissions when the carbon content is not known. Table V-4 provides a comparison of the stationary combustion CO2 emission factors provided in the GRP for natural gas, distillate oil (diesel), gasoline, and propane with the API Compendium, INGAA, the 2006 IPCC Guidelines, and WRI/WBCSD’s GHG Protocol guidance for stationary combustion.

36

Table V-4. Comparison of Stationary Combustion CO2 Emission Factors (Higher Heating Value Basis)

Fuel GRPaAPI

Compendiumb INGAAc 2006 IPCCdWRI/

WBCSDe

Natural Gas, kg CO2/MMBtu

53.05 53.06 52 53.3, 51.6-55.4 53.06 55, 50-62

Distillate Oil (Diesel), kg CO2/MMBtu

73.15 73.15 74 74.3, 72.8-75.0 73.15 73, 70-77

Motor Gasoline, kg CO2/MMBtu

70.91 70.91 68 69.5, 67.7-73.2 70.91 70, 67-73

Propane, kg CO2/gal 5.70 6.42 Not provided Not provided Not provided Sources/Notes: Emission factors were converted from units shown in original source documents to the units shown in the above table for comparison purposes.a Table C.5 of GRP (CCAR, 2006). Oxidation factors have not been applied to the GRP factors. Original sources: EIA, 2001 and AP-42, fifth edition. b Table 4-1 of API Compendium (2004). The propane emission factor was converted from a heat basis to a volumetric basis using the HHV provided in Table 3-5 of the Compendium (3.80 MMBtu/bbl). The “pipeline” natural gas emission factor shown. Original source for emission factors: EIA, 2002. c Table 2-3 of INGAA (2005). The “default pipeline/processed” natural gas emission factor shown. d Volume 2, Table 2.2 (Energy Industries), 2006 IPCC Guidelines. Original IPCC emission factors were provided on an LHV basis and were converted to an HHV basis assuming that the LHV for oil and natural gas are 5% and 10% lower than the HHV, respectively, according to guidance provided in Section 1.4.1.2 of Volume 2 of the 2006 IPCC Guidelines. IPCC provides a default and range of emission factors as shown above. e WRI/WBCSD provides two emission factors: the top number is taken from Table 7 of Annex A of WRI/WBCSD’s GHG Protocol guidance for stationary combustion; the bottom numbers are taken from WRI/WBCSD’s companion spreadsheet tool, which provides a typical value and a range of emission factors as shown above.

The API Compendium CO2 stationary combustion emission factors are taken from Table 4 -1. The propane emission factor in the API Compendium was converted from a heat basis to a volumetric basis using a default higher heating value provided in Section 3.0 of the API Compendium. INGAA’s emission factors are taken from Table 2-3 of INGAA’s natural gas transmission and storage GHG emissions guidance document. IPCC’s stationary combustion CO2 emission factors are taken from Table 2.2 of Volume 2 of the 2006 Guidelines. These emission factors are applicable for the energy industries and are given on a lower (net) heating value basis. IPCC’s table provides lower, upper, and default emission factors by fuel type. Since the CO2 emission factors provided in Table C.5 of the GRP are on an HHV basis and IPCC’s emission factors are on an LHV basis, a direct comparison cannot be made. However, the IPCC emission factors were converted to an HHV basis as shown in Table V-4 above using guidance from Section 1.4.1.2 of Volume 2 of the 2006 IPCC Guidelines that the LHV for oil and natural gas are 5% and 10% lower than the HHV, respectively.

37

WRI/WBCSD’s emission factors are taken from Table 7 of Annex A of WRI/WBCSD’s GHG Protocol guidance for stationary combustion (note that the WRI/WBCSD emission factors were converted from a carbon basis to a CO2 basis for comparison purposes). The companion spreadsheet provided on WRI/WBCSD’s GHG Protocol Initiative web page also includes default carbon heat basis emission factors that include ranges of values, as well as “typical” and IPCC default emission factors.

Overall, the stationary combustion CO2 emission factors compare well among the five references shown in Table V-4. INGAA’s emission factors are a little different from the other references as shown, but the difference is slight. Also, the API Compendium propane emission factor is 13% higher than emission factor provided in the GRP. INGAA, IPCC, and WRI/WBCSD do not provide a propane emission factor.

Methane and Nitrous Oxide Emissions

Table C.6 of the GRP provides CH4 and N2O emission factors by fuel type and industry sector. INGAA’s Table 2-6 provides CH4 and N2O emission factors on a similar basis as the GRP’s Table C.6. Both sets of emission factors are taken or derived from 1996 IPCC data. WRI/WBCSD’s stationary combustion tool (Section 3) references the 1996 IPCC fuel/sector CH4 and N2O emission factors and provides them in their companion spreadsheet tool. Table 2.2 of Volume 2 of the 2006 IPCC Guidelines document provides CH4 and N2O emission factors on a similar fuel basis as the 1996 Guidelines, but several of the emission factors have been revised or added since the 1996 Guidelines were issued (the 2006 IPCC Guidelines indicate which emission factors have been revised or added). The GRP also does not provide the energy industry’s sector emission factors from IPCC, which seem most applicable to gas transmission and distribution systems (INGAA provides these emission factors).

Table V-5 compares the 1996 and 2006 IPCC Guidelines fuel-based CH4 and N2O emission factors for natural gas and liquid petroleum fuels for the energy industries. Although this table shows that the IPCC emission factors have not changed since the 1996 Guidelines were issued (note: one exception to this is that the 2006 Guidelines provide a range of emission factors, which were not provided in the 1996 Guidelines), the 2006 IPCC Guidelines have marked the CH4 natural gas, gasoline, and gas/diesel oil factors with an “r” to indicate that they have been revised since the 1996 Guidelines were issued.

38

Table V-5. Comparison of IPCC CH4 and N2O Stationary Combustion Emission Factors – Fuel Basis

(kg/TJ, Lower Heating Value Basis)

1996 IPCC Guidelinesa 2006 IPCC Guidelinesb

Fuel CH4 N2O CH4 N2O Natural Gas 1 0.1 1, 0.3-3 0.1, 0.03-0.3 Oil, Motor Gasoline, Gas/Diesel Oil c

3 0.6 3, 1-10 0.6, 0.2-2

Sources/Notes: a Volume 3, Tables 1-7 and 1-8 (for “energy industries”), 1996 IPCC Guidelines. b Volume 2, Table 2.2 (for “industrial sources”), 2006 IPCC Guidelines. A default emission factor and lower/upper limits are provided. c Listed as “Oil” in the 1996 IPCC Guidelines. Listed as “Motor Gasoline” and “Gas/Diesel Oil” in the 2006 IPCC Guidelines.

The API Compendium does not provide CH4 and N2O emission factors by fuel type, as these emissions are significantly influenced by the specific combustion equipment type, and control technology for N2O. As a result, the API Compendium provides emission factors on an equipment basis.

V.3.3 Stationary Combustion – Equipment Basis

While CO2 emissions are related to the fuel carbon content and consumption rate, CH4 and N2O emissions are impacted by combustor type, design, air pollution control(s), operation, age, and maintenance, as well as fuel properties. For example, CH4 emissions from natural gas fired IC engines are more significant that CH4 emissions from natural gas fired turbines, boilers and process heaters, and N2O emissions from stationary combustion are generally small with the exception of turbines with selective catalytic reduction (SCR). It should be noted, however, that where equipment-based combustion emission factors are available for N2O, the factors are generally based on limited measurements and have a high degree of uncertainty.

Equipment-based emission factors are provided in Tables 4-4a and 4-5 of the API Compendium. These emission factors are provided for external combustion sources such as boilers as heaters as well as internal combustion sources such as engines and turbines. Tables 2-7 and 2-8 of INGAA (INGAA, 2005) provide similar equipment-based CH4 and N2O emission factors. The 2006 IPCC Guidelines document provides equipment-based CH4 and N2O emission factors in Volume 2, Tables 2.6 through 2.10 (Table 2.7 is applicable for “industrial sources”). These IPCC emission factors were primarily taken from AP-42 (same sections referenced by the Compendium), and were converted from a higher to lower heating value basis by IPCC. WRI/WBCSD’s stationary combustion tool does not provide equipment based CH4 and N2O combustion emission factors.

39

40

Table V-6 presents a comparison of the API Compendium, INGAA, and 2006 IPCC equipment basis CH4 and N2O emission factors. The emission factors provided by IPCC were converted from a lower to higher heating value basis for comparison purposes with the Compendium and INGAA. This conversion was carried out by using the guidance provided in a footnote to IPCC’s emission factor table that the LHV is 5% less than the HHV for coal and oil and 10% lower for natural gas.

41

Table V-6. Comparison of CH4 and N2O Stationary Combustion Emission Factors – Equipment Basis (tonnes/MMBtu, Higher Heating Value Basis)

API Compendiuma INGAAb 2006 IPCCc

Source CH4 N2O CH4 N2O CH4 N2O Natural Gas Boiler/Furnace/Heater 1.0E-06 9.8E-07

2.8E-07 (controlled) 1.0E-06 (<300MW) 1.3E-06 (>300 MW) 9.8E-07

2.8E-07 (LNB) 9.5E-07 9.5E-07

Diesel Boiler 1.8E-07 g Not Available 1.7E-07 8.6E-07 2.0E-07 4.0E-07Natural Gas Engine, 2-cycle lean 6.6E-04 2.3E-06 6.6E-04 2.3E-06 6.58E-04 Not Available Natural Gas Engine, 4-cycle lean 5.7E-04 1.4E-06 5.7E-04 1.4E-06 5.67E-04 Not Available Natural Gas Engine, 4-cycle rich 1.0E-04 4.5E-07 1.0E-04 4.5E-07 1.04E-04 Not Available Duel Fuel Engine 2.7E-04

(95%NG/5%DS) Not Available 2.4E-04 Not Given Not Given Not Given

Gasoline Engine 1.37E-04d 9.0E-07f 3.9E-05 (4 stroke) 1.2E-04 (2-stroke)

9.0E-07 (4 stroke) Not Given Not Given

Diesel Engine (<600 hp) 1.6E-05d 1.10E-05f 4.0E-06 1.1E-05 Not Given Not Given Diesel Engine (>600 hp) 3.7E-06e 2.21E-06f 3.7E-06 2.2E-06 4.0E-06 Not availableDiesel Turbine Not Given Not Given No Data No Data Not Given Not Given Gas Turbine 3.9E-06

1.4E-06

1.4E-05 (SCR) 3.9E-06 3.8E-06

1.4E-05 (SCR) 3.8E-06 (DLNB) 2.8E-06 (Water/ Steam Injection)

3.8E-06 (> 3MW)

9.5E-07 (> 3MW)

Sources/Notes: a Tables 4-4a and 4-5 of the API Compendium (2004). Refer to the Compendium for the original references. b Tables 2-7 and 2-8 of INGAA (2005). Refer to the INGAA document for the original references. c Volume 2, Table 2.7 (for “industrial sources”), 2006 IPCC Guidelines. IPCC’s emission factors were taken from AP-42 and converted from an HHV basis to an LHV basis. They have been converted back to an HHV basis in the above table using the guidance from a footnote to IPCC’s table that the net caloric heating value is 5% less than the gross value for coal and oil and 10% lower for natural gas. d Converted original TOC (total organic carbon) emission factor to CH4 basis assuming 10 wt. % CH4 in the exhaust gas based on engineering judgment. e Converted original TOC (total organic carbon) emission factor to CH4 basis assuming 9 wt. % CH4 in the exhaust gas based on AP-42. f Converted from a tonnes/gal basis to a tonnes/MMBtu basis assuming a default gasoline HHV of 5.46 MMBtu/bbl and a default diesel HHV of 5.75 MMBtu/bbl provided in Table 3-5 of the Compendium (API, 2004). g Converted from a tonnes/tonnes fuel basis to a tonnes/MMBtu basis assuming a default diesel density of 7.1 lb/gal and a HHV of 5.75 MMBtu/bbl provided in Table 3-5 of the Compendium (API, 2004).

For the most part, there is agreement in the equipment-based CH4 and N2O provided in Table V-6 above. Nevertheless, there are some differences in emission factors and sources presented due to citing different references. For example, INGAA and the API Compendium both cite AP-42 for some of the emission factors, but INGAA also cites CORINAIR11. Also, each guidance document does not include the same source categories. For example, IPCC does not include duel fuel and gasoline engines.

V.3.4 Stationary Combustion – Manufacturer’s Data

The Canadian Association of Petroleum Producers (CAPP), Calculating Greenhouse Gas Emissions document provides two tables of manufacturer specific emission factors, shown in Tables V-7 and V-8 below. The emission factors are given on power output basis, but can be converted from a fuel input basis using the conversion factors for each type of engine provided in Table V-2 of this Discussion Paper.

Appendix B of the API Compendium includes both of these tables (but does not include N2O emission factors for the Waukesha engines). Table 2-9 of INGAA’s Guidelines provides the Waukesha CH4 and N2O emission factors.

Table V-7. Waukesha Reciprocating Engines Combustion Emission Factors

Model Carburetor

Setting

Excess Air

Ratio CO2, g/kW-hr CH4, g/kW-hr N2O, g/kW-hrAT25GL Standard 1.74 580.8 9.39 0.0201 AT27GL Standard 1.74 Not Given 6.03 0.0302 Ultra Lean 2.00 526.9 4.16 0.0252 VHP G, GSI Lowest manifold 0.97 581.29 2.61 0.1709 Equal NOx & CO 0.99 581.29 2.61 0.2414 Catalytic Converter 0.99 581.29 2.28 0.2615 Standard 1.06 581.29 1.68 0.443 VHP 3524 GSI Equal NOx & CO 0.99 576.13 1.14 0.2816 VHP 7044 GSI Catalytic Converter 0.99 573.7 1.07 0.3018 Standard 1.06 Not Given 0.80 0.4626

11 The Co-operative Programme for Monitoring and Evaluation of Long Range Transmission of Air Pollutants in Europe (EMEP) worked jointly with the Core Inventory of Air Emissions in Europe (CORINAIR) to provide a comprehensive guide to atmospheric emissions inventory methodology for the emissions-generating activities listed in the 1997 Selected Nomenclature for Air Pollution (SNAP97). The EMEP/CORINAIR technical unit worked closely with IPCC to insure compatibility between the guidebook and the IPCC guidelines. This guidebook appears to be the Tier 3 methodology referenced in IPCC’s Reference Manual.

42

Table V-7. Waukesha Reciprocating Engines Combustion Emission Factors (continued)

Model Carburetor

Setting

Excess Air

Ratio CO2, g/kW-hr CH4, g/kW-hr N2O, g/kW-hrVHP 5794 GSI Equal NOx & CO 0.99 568.7 3.42 0.272 Catalytic Converter 0.99 Not Given 3.29 0.2916 Standard 1.06 Not Given 2.75 0.443 VHP GL Standard 1.74 592.3 6.03 0.0302 VGF Model G Lowest manifold 0.97 575.0 2.28 0.2414 Equal NOx & CO 0.98 Not Given 2.28 0.3018 Catalytic Converter 0.99 Not Given 2.28 0.3219 Standard 1.12 Not Given 1.41 0.5633 VGF Model GSID Catalytic Converter 0.99 575.0 1.68 0.3219

Std.: high speed turbo 1.53 575.0 5.7 0.0524 VGF GL, GLD 11:1 CR T.A. Luft emissions 1.59 Not Given 4.09 0.0252 VGF GL 8.7:1 CR Std.: high speed turbo 1.53 575.0 4.09 0.0402 VSG G, GSI, GSID Lowest manifold 0.97 566.8 3.42 0.2012 Equal NOx & CO 0.98 Not Given 3.42 0.2807 Catalytic Converter 0.99 Not Given 3.08 0.3018 Standard 1.10 Not Given 2.28 0.5030 F1197G G Lowest manifold 0.97 Not Given 3.35 0.2012 Equal NOx & CO 1.0 Not Given 2.61 0.2816 Catalytic Converter 0.99 Not Given 2.61 0.272 Standard 1.06 Not Given 1.27 0.443 F8176 G Lowest manifold 0.97 Not Given 2.61 0.1709 Equal NOx & CO 1.0 Not Given 2.28 0.2615 Catalytic Converter 0.99 Not Given 2.28 0.2414 Standard 1.06 Not Given 2.28 0.3621 Note: All data in this table are based on maximum horsepower and engine speed. "Lowest manifold" setting refers to best power setting while "Standard" setting refers to best economy setting. N2O emission factors are estimated based on 1.5% of Nox emissions. Source: Canadian Association of Petroleum Producers (CAPP), Calculating Greenhouse Gas Emissions, Table 1-7, Canadian Association of Petroleum Producers, Publication Number 2003-03, April 2003.

43

44

TableV-8. CAT Reciprocating Engines Combustion Emission Factors

Power Speed Carbon Dioxide

Model kW rpm % O2 Original Units,

g/kWh tonnes/kW-hr 3412 SITA 447 1800 1.5 436 4.36E-04 3508 SITA 384 1200 7.7 574 5.74E-04 3508 SITA 470 1400 8.0 590 5.90E-04 3512 SITA 604 1200 8.2 579 5.79E-04 3512 SITA 705 1400 7.7 595 5.95E-04 3516 SITA 809 1200 8.3 567 5.67E-04 3516 SITA 943 1200 7.9 581 5.81E-04 3606 SITA 1242 1000 12.3 347 3.47E-04 3608 SITA 1659 1000 12.3 347 3.47E-04 3612 SITA 2487 1000 12.3 347 3.47E-04 3616 SITA 3315 1000 12.3 347 3.47E-04 G398 TALCR 522 1200 2.0 Not Given Not Given G398 TAHCR 522 1200 2.0 Not Given Not Given Catalyst 522 1200 0.5 Not Given Not Given G398 TAHCR 32C (low emissions)

522 1200 6.2 Not Given Not Given

Source: Canadian Association of Petroleum Producers (CAPP), Calculating Greenhouse Gas Emissions, Table 1-7, Canadian Association of Petroleum Producers, Publication Number 2003-03, April 2003.

V.4 Flaring

Table V-9 presents the options for estimating emission from flares. The approaches are similar to those presented for stationary combustion sources, however default emission factors for natural gas flares are not widely available. Those that are available focus on flares in the upstream sector of the petroleum industry (exploration, production, and gas processing) and refineries. Default emission factors for pipeline sector flares are not addressed.

The API Compendium’s preferred approach to estimate flare emissions is to use test data or vendor specific information. However, this information is not widely available in the pipeline sector. In the absence of this information, the alternative emissions calculation approach, according to the API Compendium, is based on knowing or estimating the flare gas flow rate and composition and applying a material balance approach. Flares are not specifically covered in the GRP.

45

Table V-9 Summary of Emission Estimation Methods for Flares

Method Information


EFs or Technique Industry sector general emission factor

Broad sector data, such as total length of pipeline

No published factors for the pipeline sector

IPCC provides emission factors for upstream operations. EPA provides a default emission factor for the refining sector

Material balance approach based on assumed gas composition and estimated flared volume

Operational data that relates to the quantity of gas flared


Default factors rely on assumed gas carbon contents and heating values

Limited information available for N2O emissions

Section V.4 of this Discussion Paper

Material balance approach based on measured gas composition and measured or estimated flared volume

Quantity of fuel combusted (volume, mass or heat content) by fuel type and by equipment type

Fuel consumption can be determined from equipment ratings and operating hours


Limited information available for N2O emissions

Section V.4 of this Discussion Paper

Test data or vendor specifications

Accurate for design/tested flare conditions

Costly May not be representative of

actual operations

The general material balance equations for estimating emissions from flared natural gas12 are:

CH4 Emissions = Volume Flared × CH4 Mole fraction × % residual CH4 × Molar volume × MW CH4

(Equation 8)

N2O Emissions = Volume Flared × N2O emission factor (Equation 9)

gas mole

CO mole

combusted C moleformed CO mole 98.0

efficiency Combustion

nHydrocarbo mole

Cmole Xgas mole

nHydrocarbo mole

COMW meMolar voluFlared Volume Emissions CO

22

22

⎥⎥⎥⎥⎥

⎦

⎤

⎢⎢⎢⎢⎢

⎣

⎡

+⎟⎠⎞

⎜⎝⎛×

⎟⎟⎠

⎞⎜⎜⎝

⎛×

×

××=

∑(Equation 10)

To estimate CO2 emissions, 98% combustion efficiency is the petroleum industry’s recommended conversion factor for flare gas carbon to CO2 (API, Section 4.4, 2004). For CH4 emissions from flares, general industry practice assumes 0.5% residual, unburned CH4 remaining in the flared gas for well designed and operated flares, such as in refineries. For production flares, where greater operational variability exists, CH4 emissions may be based on an assumed value of 2% noncombusted. In the transmission, storage, and distribution segments, the flares are assumed to be similar to production flares, and, therefore, the CH4 flare emissions should conservatively be estimated based on 2% remaining noncombusted. INGAA’s natural gas transmission and storage GHG emissions guidance document (Section 2.4) also assumes that 2% of the CH4 remains uncombusted in the flare (INGAA, 2005).

As stated above, published emission factors for pipeline sector flares are not available. Table V-10 provides default flare emission factors for other sectors of the natural gas and oil industry. These are cited in API Compendium Table 4-7.

12 Natural gas used as pilot gas for a flare should be treated as a stationary combustion source with emissions determined based on the methods presented in Sections IV.1.3 and IV.1.4.

46

Table V-10. GHG Emission Factors for Gas Flares

Units Converted to tonnes/106 scf or tonnes/1000 bbl Emission Factors

Flare Source CO2 CH4 N2O Units Flaring - gas production a 5.1E-02 3.1E-04 5.9E-07 tonnes/106 scf gas production Flaring - sweet gas processing a 5.9E-02 3.7E-04 7.1E-07 tonnes/106 scf gas receipts Flaring - sour gas processing a 0.13 8.2E-04 1.5E-06 tonnes/106 scf gas receipts

7.9E-04 - Flaring - conventional oil production a

10.7 4.3E-02

1.0E-04 tonnes/1000 bbl conventional oil production

7.9E-03 - Flaring - heavy oil production a

7.8 3.2E-02

7.3E-05

tonnes/1000 bbl heavy oil production

Flaring - crude bitumen production a

3.5 1.4E-02 3.8E-05 tonnes/1000 bbl crude bitumen production

Flaring – Refining b,c No data 3.62E-06 No data tonnes/1000 bbl refinery feed Sources: aIPCC, IPCC Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories, Chapter 2 (Energy), Table 2.16, May 2000. bU.S. Environmental Protection Agency (EPA). Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001. EPA-430-R-03-004, U.S. Environmental Protection Agency, Washington D.C., April 15, 2003, Annex H, Table H-3. cCH4 emission factors converted from scf or m3 are based on 60°F and 14.7 psia.

Very little information is available for N2O emissions from petroleum industry flares, but these emissions are likely negligible compared to the CO2 emissions from the flares. INGAA cites an N2O flare emission factor of 1.0 ×10-10 tonne/scf of flare gas combusted (CAPP 2003, Alberta EUB 2001) that is derived from NOx emissions data with the assumption that N2O equals 1.5% of NOx.

Incinerators and catalytic oxidizers may be used in transmission or distribution. Combustion emissions from these sources vary widely from process to process. Thus, there is not a set of published emission factors associated with these equipment/processes. The material balance approaches presented for flares in this Discussion Paper can be used to determine these emissions. For example, for a thermal incinerator, the combustion emission factors described in Sections V.3.1 and V.3.2 of this discussion paper may be used to estimate the emissions contribution from the fuel combustion, and a material balance approach may be used to estimate the noncombusted CH4 emissions from the waste gas stream (assuming 98% CH4 destruction). Section 2.5 of INGAA presents a similar approach for estimating incinerator emissions. Nitrous oxide emissions from incinerators or catalytic oxidizers are not addressed in published emission factor guidance documents.

47

V.5 Recommendations and Considerations for Stationary Combustion Sources

A key consideration for estimating natural gas combustion emissions for pipeline operations is the availability and reliability of measured gas volume data. Transmission and storage facilities may not directly meter the volume of natural gas used for combustion (distribution facilities generally do not require combustion equipment). Often, these facilities have a central or master gas meter that measures the overall gas used by the facility. The majority of the gas consumed at these facilities is for combustion, but the central meter volume may also capture natural gas losses due to vented activities, fugitive emissions, and meter inaccuracies.13

For permits and non-metered combustion equipment, the volume of natural gas consumed by the combustion equipment is estimated based on equipment ratings and operating hours. However, natural gas volumes determined from equipment data may not be reconciled against metered gas volumes, where available for individual combustion equipment or groups of equipment. Calculated gas volumes can differ from metered gas volumes and introduce uncertainty in the emissions calculation.

Recommendations for the NG T&D protocol for stationary combustion sources are:

• Where available, metered natural gas volumes are preferred over calculated volumes;

• CO2 emissions from natural gas combustion should be based on the fuel-specific carbon content and applying the material balance equations presented above (Equations 6 and 10).

• CO2 emissions from fuels other than natural gas should be based on Equation 7, using measured or calculated consumption volumes, and vendor or default fuel properties.

• CH4 and N2O emissions for stationary combustion sources should be based on equipment-specific emission factors, presented in Table V-6.

• CH4 emissions from flares, incinerators, or catalytic oxidizers should be based on fuel-specific CH4 content and Equation 8.

• N2O emissions from flares, incinerators, or catalytic oxidizers should be based on Equation 9 and the emission factor for sweet gas processing provided in Table V-10, unless more accurate information is available.

13 Fugitive and vented emissions from compressors and throughput related equipment will not be captured by fuel meters.

48

49

V.6 Mobile Combustion

Mobile combustion sources are non-stationary sources such as automobiles, trucks, and other off-road vehicles. Table V-11 presents estimation methodologies for mobile source combustion emissions.

Tables C.3 and C.4 of the GRP provide the mobile source vehicle emission factors referenced in Chapter 7 of the document. In addition to the fuel based CO2 emission factors provided in Table C.3 of the GRP, the material balance approach described in Section V.3.1 of this discussion paper can be used to estimate the CO2 emissions if the fuel carbon content and fuel usage of the mobile source devices are known.

The API Compendium (Section 4.5.1) recommends using the stationary combustion emission factors to estimate CO2 emissions, with the option to apply an oxidation factor (default of 1.0 is assumed for the oxidation factor). Likewise, Table 3.2.1 of the 2006 IPCC Guidelines (in Volume 2) provides default CO2 road transport emission factors that are the same as their stationary combustion emission factors, and assumes a default of 100% oxidation. The Compendium and 2006 IPCC stationary combustion CO2 emission factors were described previously in Section V.3.2 of this discussion paper.

WRI/WBCSD’s GHG Protocol guidance for mobile sources (Table 3) provides default CO2 emission factors for various fuels (WRI/WBCSD, 2005). These CO2 emission factors were taken from the 1996 IPCC Guidelines and are on an LHV basis. Table 4 of the WRI/WBCSD guidance also provides default fuel economy (mpg) data and CO2 emission factors based on vehicle kilometers traveled (similar data are provided in Tables 4-10 and 4-11 of the Compendium). A companion spreadsheet to estimate mobile source CO2 emissions is also provided on WRI/WBCSD’s GHG Protocol Initiative web page.

The CH4 and N2O mobile source vehicle emission factors provided in the GRP (Table C.4) are based on data from the California Energy Commission (CEC). INGAA’s natural gas transmission and storage GHG emissions guidance document (INGAA, 2005), Table 2-11, provides CH4 and N2O emission factors on a similar miles traveled basis taken from a 2005 EPA report (CO2 is also presented this way in INGAA). Tables 3.2.3 and 3.2.4 of the 2006 Guidelines provide vehicle specific emission factors primarily based on a couple of EPA reports from 2004. The 2006 IPCC emission factors are different from the GRP and INGAA emission factors in that the 2006 Guidelines provide CH4 and N2O emission factors for both cold starts (mg/start) and running (hot) mode (mg/km).

50

Table V-11 Summary of Emission Estimation Methods for Mobile Source Combustion

Method Information


EFs or Technique Vehicle miles traveled by

general vehicle classifications

Vehicle miles may be tracked for HSE reporting

May be difficult to isolate company owned vehicles from others

May not capture off-road vehicles

INGAA and GRP factors provided in Table V-12.

Default emission factors based on very general classifications of vehicles Volume of fuel consumed by

general vehicle classifications and fuel types

Accurate estimate of CO2 achieved by relating to fuel consumption

Requires accounting practice to track fuel purchases

IPCC factors provided in Table V-13

Vehicle miles traveled by specific vehicle classifications

Vehicle miles may be tracked for HSE reporting

Requires record keeping by vehicle classification

GRP and IPCC factors provided in Table V-12

Default emission factors based on more specific classifications of vehicles Volume of fuel consumed by

specific vehicle classifications and fuel types

Accurate estimate of CO2 achieved by relating to fuel consumption

Requires fuel consumption accounting by vehicle purchases

API Compendium factors provided in Table V-13

51

According to Section 3.2.1.1 of the 2006 IPCC Guidelines, the cold start emission factors should be applied for the initial fraction of the vehicle’s trip, up to approximately 3 km or 180-240 seconds, at which point the hot running emission factors should be used. Cold starts refer to vehicle engine starts that occur when the engine temperature is below the point at which the catalyst starts to operate (approximately 300°C), or before the engine reaches it normal operating temperature for non-catalyst models. Also, note that some of the cold start emission factors are negative; negative emission factors indicate that a vehicle starting cold produces fewer emissions than a vehicle starting warm or running warm.

Table V-12 provides a comparison of the mobile source CH4 and N2O emission factors on a distance traveled basis. The emission factors from the original sources have been converted to a common set of units as necessary for the comparison. As shown in the comparison table, the vehicle categories do not line up exactly among the three documents. The GRP categorizes the vehicles by model year. Only the most recent model years have been included in the comparison table (e.g., 1990 and later). INGAA and IPCC categorize the vehicles on a similar control technology basis rather than model year. IPCC’s “running” or hot mode emission factors are most applicable for comparison with the other emission factors. The cold start emission factors have also been included in the comparison table, although these emission factors are based on the number of starts rather than the distance traveled. The comparison table shows both similarities and differences in the emission factors among the three sources, depending on the source category. For example, the GRP diesel light duty automobile emission factors are several times larger than INGAA’s and IPCC’s emission factors.

IPCC’s 2006 Guidelines also provide CH4 and N2O emission factors (Volume 2, Table 3.2.2) on an energy basis that are fuel specific and general in nature with regard to the vehicle types. The API Compendium’s mobile source vehicle CH4 and N2O emission factors (from API Compendium Table 4-9), which are taken from Environment Canada, are on a fuel consumption basis and, therefore, can be compared to the IPCC’s energy basis emission factors. Table V-13 presents a comparison of the fuel use basis CH4 and N2O emission factors from the IPCC 2006 Guidelines and the API Compendium. The IPCC emission factors were converted from a heat basis to a volumetric basis using default lower heating value data for the fuel for comparison purposes with the API Compendium emission factors, which are on a volumetric basis.

Table V-12. Comparison of CH4 and N2O Mobile Source Combustion Emission Factors – Distance Basis

GRPa,d INGAAb IPCCc

CH4 N2O

Source CH4

(g/mile) N2O

(g/mile) CH4

(g/mile) N2O

(g/mile) Running (g/mile)

Cold Start e

(mg/startup) Running(g/mile)

Cold Start e

(mg/startup) Light Duty Gasoline Automobile (Uncontrolled) - Low Emission Vehicle - Advanced Three-Way Catalyst - Early Three-Way Catalyst - Oxidation Catalyst - Non-oxidation Catalyst

0.05 (1994-1999)

0.04

(2000-)

0.04 (1994-1999)

0.04

(2000-)

0.017

0.022

0.163 0.0097 0.011 0.063 0.13 0.15

62 32 55 34 9

59

0.013 0

0.014 0.042 0.032 0.013

28 90 113 92 72 28

Gasoline Light Duty Truck (Uncontrolled) - Low Emission Vehicle - Advanced Three-Way Catalyst - Early Three-Way Catalyst - Oxidation Catalyst - Non-oxidation Catalyst

0.06 (1994-1999)

0.05

(2000-)

0.06 (1994-1999)

0.06

(2000-)

0.022

0.015

0.187 0.011 0.023 0.063 0.13 0.175

71 46 82 72 99 67

0.014 0.0016 0.040 0.069 0.042 0.014

32 59 200 153 93 32

Gasoline Heavy Duty Vehicle (Uncontrolled) - Low Emission Vehicle - Advanced Three-Way Catalyst - Early Three-Way Catalyst - Oxidation Catalyst - Non-oxidation Catalyst - EPA Tier 1

0.12 (1990-)

0.20 (1990-)

0.043

0.066

0.029

0.18

0.423 0.023 0.024 0.195 0.179 0.385

162 94

163 183 215 147

0.034 0.0016 0.084 0.14

0.089 0.032

74 120 409 313 194 70

Diesel Light Duty Automobile (Uncontrolled) - Advanced Control - Moderate Control

0.01 (all model

years)

0.02 (all model

years)

0.0006 0.0005 0.0005

0.0012 0.0010 0.0010

0.0016 0.0016 0.0016

-3 -3 -3

0.0016 0.0016 0.0016

-1 0 0

Diesel Light Duty Truck (Uncontrolled) - Advanced Control - Moderate Control

0.01 (all model

years)

0.03 (all model

years)

0.0006 0.0005 0.0005

0.0017 0.0015 0.0014

0.0016 0.0016 0.0016

-4 -4 -4

0.0016 0.0016 0.0016

-1 -1 -1

Diesel Heavy Duty Vehicle (Uncontrolled) - Advanced Control

0.06 (1996-)

0.05 (1996-)

0.0051

0.0048

0.0064 0.0064

-11 -11

0.0048 0.0048

-2 -2

Gasoline Motorcycles (Uncontrolled) - Non-catalyst Controls

0.09 (1996-)

0.01 (1996-)

0.090 0.067

0.087 0.0069

0.085 0.064

33 24

0.0064 0.0048

15 12

52

53

GRPa,d INGAAb IPCCc

CH4 N2O

Source CH4

(g/mile) N2O

(g/mile) CH4

(g/mile) N2O

(g/mile) Running (g/mile)

Cold Start e

(mg/startup) Running(g/mile)

Cold Start e

(mg/startup) CNG Light Duty Vehicle 0.04 0.04 Not Given Not Given 0.346-

1.17 Not Given 0.043-

0.11 Not Given

LPG Light Duty Vehicle 0.04 0.04 Not Given Not Given 0.039 Not Given 0.008 Not Given CNG Heavy Duty Vehicle/Truck 3.48 0.05 Not Given Not Given 9.629 Not Given 0.30 Not Given LNG Heavy Duty Vehicle/Truck 3.48 0.05 Not Given Not Given 6.857 Not Given 0.44 Not Given LPG Heavy Duty Vehicle Not Given Not Given Not Given Not Given 0.11 Not Given 0.15 Not Given

Sources/Notes: a Table C.4 of GRP (CCAR, 2006). Emission factors derived from California Energy Commissions, 2002. b Table 2-11 of INGAA (2005). Emission factors converted from tonnes/mile basis to g/mile basis. Refer to the INGAA document for table footnotes with more information on the emission factors. Original source for emission factors: EPA, 2005. c Volume 2, Tables 3.2.3 and 3.2.4 of the 2006 IPCC Guidelines. Emission factors for “Running (hot)” mode converted from mg/km basis to g/mile basis. Original source for emission factors: EPA, 2004. d The GRP provides mobile source emission factors by model year rather than by emissions control technology. Several model years are provided in Table C.4 of the GRP, but the most recent model years are provided in the table above. e Negative emission factors indicate that a vehicle starting cold produces fewer emissions than a vehicle starting warm or running warm.

Table V-13. Comparison of CH4 and N2O Mobile Source Combustion Emission Factors – Fuel Use Basis (tonnes/1000 gallons)

API Compendiuma 2006 IPCC b, c

Source CH4 N2O CH4 N2O Gasoline Fuel Motor Gasoline – Uncontrolled 4.3E-03, 1.3E-03 – 1.43E-02 4.2E-04, 1.3E-04 – 1.4E-03 Motor Gasoline – Oxidation Cat. 3.3E-03, 9.8E-04 – 1.12E-2 1.0E-03, 3.4E-04 – 3.1E-03 Light-Duty Gasoline Automobiles (LDGA)

5.0E-04, 1.4E-04 – 1.7E-03 (low mileage, 1995 and later)

7.4E-04, 2.5E-04 – 2.2E-03 (low mileage, 1995 and later)

Tier 1, Three-way catalyst 4.5E-04 9.8E-04 Tier 0, New Three-way catalyst 1.2E-03 9.5E-04 Tier 0, Aged Three-way catalyst 1.2E-03 2.2E-03 Oxidation Catalyst 1.6E-03 7.6E-04 Non-Catalyst 2.0E-03 1.1E-04 Light-Duty Gasoline Trucks (LDGT) Tier 1, Three-way Catalyst 8.3E-04 1.6E-03 Tier 0, New Three-way Catalyst 1.6E-03 1.7E-03 Tier 0, Aged Three-way Catalyst 1.6E-03 3.8E-03 Oxidation Catalyst 1.7E-03 7.6E-04 Non-Catalyst 2.1E-03 1.1E-04 Heavy-Duty Gasoline Vehicles (HDGV)

Three-way Catalyst 6.4E-04 3.8E-03 Non-Catalyst 1.1E-03 1.7E-04 Uncontrolled 1.9E-03 3.0E-04 Diesel Fuel 5.3E-04, 2.2E-04 – 1.3E-03 5.3E-04, 1.8E-04 – 1.6E-03 Light-Duty Diesel Automobiles (LDDA)

Advance Control 1.9E-04 7.6E-04 Moderate Control 2.6E-04 7.6E-04 Uncontrolled 3.8E-04 7.6E-04 Light-Duty Diesel Trucks (LDDT) Advance Control 2.6E-04 7.6E-04 Moderate Control 2.6E-04 7.6E-04 Uncontrolled 3.0E-04 7.6E-04 Heavy-Duty Diesel Vehicles (HDDV) Advance Control 4.5E-04 3.0E-04 Moderate Control 4.9E-04 3.0E-04 Uncontrolled 5.7E-04 3.0E-04 Natural Gas Vehicles 8.3E-05 2.3E-07 92, 50 – 1540 kg/TJ (LHV) 3, 1 – 77 kg/TJ (LHV) Propane Vehicles 2.0E-03 1.1E-04 Sources/Notes: a Table 4-9 of the API Compendium (2004). Original source for emission factors: Environment Canada, 2003. b Volume 2, Table 3.2.2 of the 2006 IPCC Guidelines. A default emission factor and lower/upper limits are provided. c Converted IPCC emission factors from a kg/TJ (LHV) basis to a tonnes/1000 gallons basis assuming default LHVs taken from Table 3-5 of the Compendium (API, 2004), which are: 5.19 MMBtu/bbl for gasoline and 5.46 MMBtu/bbl for diesel..

54

The vehicle categories for the API Compendium and IPCC emission factors do not line up exactly for the fuel basis emission factors. The API Compendium emission factors are provided with more sub-categories of control technologies than IPCC’s. Similar to the distance based emission factors, there are variations in the data for the fuel basis emission factors. The natural gas vehicle emission factors from IPCC were not converted to a volumetric basis since the pressure of the fuel is not specified, so it is not clear what heating value should be used.

WRI/WBCSD’s mobile source guidance (Section I.D) states that CH4 and N2O emissions from mobile sources are small compared to CO2 emissions, and the document therefore does not provide CH4 and N2O emission factors.

V.6.1 Non-road Vehicles

The GRP does not provide emission factors for non-road vehicles (e.g., rail, marine, or air transportation), so emission factors provided in API Compendium Table 4-9 may be used, which are presented in Table V-14.

Table V-14. CH4 and N2O Combustion Emission Factors for Non-Road Mobile Sources – Volume Basis

Source CH4,

tonnes/1000 gal fuel N2O,

tonnes/1000 gal fuel Off-Road Vehicles Other Gasoline Vehicles 1.0E-02 1.9E-04 Other Diesel Vehicles 5.3E-04 4.2E-03 Diesel Rail Transportation 5.7E-04 4.2E-03 Marine Transportation Gasoline Boats 4.9E-03 2.3E-04 Diesel Ships 5.7E-04 3.79E-03 Light Fuel Oil Ships 1.1E-03 2.6E-04 Heavy Fuel Oil Ships 1.1E-03 3.0E-04 Air Transportation Conventional Aircraft 8.29E-03 8.71E-04 Jet Aircraft 3.0E-04 9.5E-04

Source: Environment Canada, Canada's Greenhouse Gas Inventory 1990-2001, Greenhouse Gas Division, Environment Canada, August 2003, Table A7-5.

The 2006 IPCC Guidelines provide energy based CO2, CH4, and N2O emission factors for rail transport (IPCC Tables 3.4.1 and 3.4.2, Volume 2) and water-borne navigation (Tables 3.5.2 and 3.5.3). Simple, energy-based CO2, CH4, and N2O emission factors for civil aviation are provided in Tables 3.6.4 and 3.6.5 of the 2006 IPCC Guidelines. A summary

55

of the non-road mobile source CH4 and N2O emission factors from the 2006 IPCC Guidelines is presented below in Table V-15. The IPCC CO2 emission factors for rail transport, water-borne navigation, and aircraft (cruising) transportation are not shown here because they are the same as IPCC’s stationary combustion emission factors, and assume a default of 100% oxidation (the stationary combustion emission factors described or presented in Section V.3.2 of this discussion paper are used to estimate these emissions).

Table V-15. CH4 and N2O Combustion Emission Factors for Non-Road Mobile Sources – Energy Basis

CH4, kg/TJ N2O, kg/TJ

Source Default Range or Precision Default

Range or Precision

Rail Transportation a,e,f,g Diesel Rail 4.15 1.67 to 10.4 28.6 14.3 to 85.8 Sub-bituminous Coal Rail 2 0.6 to 6 1.5 0.5 to 5 Ocean-going Shipsb,c,h 7 +/- 50% 2 +140% / -40%Aircraftd 0.5 i +100% / -57% 2 +150% / -70%

Sources/Notes: a EEA, Emission Inventory Guidebook – 2005, EMEP/CORINAIR, European Environment Agency, Technical report No 30. Copenhagen, Denmark, December 2005. The emission factors for diesel are derived from Table 8-1 while the coal rail emission factors are derived from Table 2.2 of the Stationary Combustion chapter. b Lloyd’s Register. Marine Exhaust Emissions Research Programme, Lloyd’s Register House, Croydon, England, 1995. c EC. Quantification of Emissions from Ships Associated with Ship Movements between Ports in the European Community, Final Report Entec UK Limited, July 2002, page 12. d Intergovernmental Panel on Climate Change (IPCC). Aviation and the Global Atmosphere, Eds: J.E. Penner, D.H. Lister, D.J. Griggs, D.J. Dokken, M. McFarland, Intergovernmental Panel on Climate Change, Cambridge University Press, 1999. e For an average fuel consumption of 0.35 liters/bhp-hr for a 4000 hp locomotive (0.47 liters per kWh for a 2983 kW locomotive) (Dunn, 2001). f The following pollutant weighting factors apply to the CH4 emission factors depending on the engine type: 0.8 for naturally aspirated direct injection; 0.8 for turbo-charged direct injection / inter-cooled turbo-charged direct injection; 1.0 for naturally aspirated pre-chamber injection; 0.95 for turbo-charged pre-chamber injection; and 0.9 for inter-cooled turbo-charged pre-chamber injection. The weighting factor for N2O for each of these engine types is 1.0. Source: Table 8-9, EEA, 2005. g To account for the increase in rail transportation emissions with engine age, the default CH4 emission factors may be increased by 1.5 percent per year while the increase in N2O emission factors is negligible (EEA, 2005). h The default ocean-going ship emission factors are derived for diesel engines using heavy fuel oil. i CH4 emissions are assumed to be negligible in the cruise mode (Wiesen et al., 1994). For LTO cycles only (i.e., below an altitude of 3000 ft), the CH4 emission factor is 5 kg/TJ (10% of total VOC factor) (Olivier, 1991). Since globally about 10% of the total fuel is consumed in LTO cycles (Olivier, 1995), the resulting fleet averaged factor is 0.5 kg/TJ.

Aircraft specific CO2, CH4, and N2O emission factors are provided in IPCC Table 3.6.9 for landing/take-off cycles (LTOs). Aircraft specific NOx emission factors are provided in

56

Table 3.6.10 of IPCC for cruise level flying mode. These emission factors are reproduced here in Table V-16 for the smaller aircraft that may be associated with the natural gas transmission and distribution segments.

Table IV-16. Aircraft Specific Emission Factors

Landing/Take-Off (LTO) Cycle a,h Cruising Mode i

Aircraft CO2

e, kg/LTO

CH4 f,

kg/LTO N2O g,

kg/LTO

LTO Fuel Consumption,

kg/LTO NOx, g/kg

RJ-RJ85 1910 0.13 0.1 600 15.6 b

BAE 146 1800 0.14 0.1 570 8.4 b

CRJ-100ER 1060 0.06 0.03 330 8.0 b

ERJ-145 990 0.06 0.03 310 7.9 b

Fokker 100/70/28 2390 0.14 0.1 760 8.4 b

BAC111 2520 0.15 0.1 800 12.0 b

Dornier 328 Jet 870 0.06 0.03 280 14.8 c

Gulfstream IV 2160 0.14 0.1 680 8.0 c

Gulfstream V 1890 0.03 0.1 600 9.5 c

Reg

iona

l Jet

s

Yak-42M 2880 0.25 0.1 910 15.6 d

Low

Thr

ust

Jets

Cessna 525/560 1070 0.33 0.03 340 7.2 d

Beech King Air 230 0.06 0.01 70 8.5 b

DHC8-100 640 0.00 0.02 200 12.8 b

Turb

o-p

rops

ATR72-500 620 0.03 0.02 200 14.2 b

Sources/Notes: a2006 IPCC Guidelines for National Greenhouse Gas Inventories, Intergovernmental Panel on Climate Change (IPCC), 2006. bSutkus, D.J., S.L. Baughcum, D.P. DuBois. Scheduled Civil Aircraft Emission Inventories for 1999: Database Development and Analysis, NASA/CR—2001-211216, National Aeronautics and Space Administration, Glenn Research Center, USA, October 2001. cSAGE model (Kim, 2005 – two reports; Malwitz, 2005). dAverage of data from SAGE (Kim, 2005 – two reports; Malwitz, 2005) and AERO2k (Eyers et al., 2004). eBased on 3.16 kg CO2/kg fuel, then rounded to 10 kg. fRepresentative of turboprop aircraft with shaft horsepower of more than 2000 shp/engine. gEstimates based on default values (EF ID 11053), as in the 1996 IPCC Guidelines. hInformation regarding the uncertainties associated with the LTO emissions data can be found in Lister and Norman, 2003 and ICAO, 1993. iInformation to assist in computing uncertainties for the cruising NOx emission factors can be found in: Baughcum et al, 1996; Sutkus, et al, 2001; Eyers et al, 2004; Kim, 2005 (two reports); Malwitz, 2005.

The LTO emissions factors are based on the number of landings/take-offs while the cruising NOx emission factors are based on the fuel used during the cruise mode. Section 3.6.1.2 of IPCC states that the CH4 cruise level emissions are assumed to be negligible, and the N2O emissions can be estimated indirectly from the NOx emissions (though no default N2O to NOx ratio is supplied). CO2 emissions during the cruise mode can be estimated

57

using the stationary combustion emission factors described earlier in Section V.3.2 of this discussion paper.

In addition, INGAA provides GHG emission factors for construction equipment based on fuel consumption for gasoline and diesel powered construction equipment (Table 2-12, INGAA, 2005), as shown in Table V-17.

Table V-17. Mobile Source Construction Equipment GHG Emission Factors – Volume Basis

Tonne/gal Fuel CO2 CH4 N2O

Gasoline/Petrol 8.8E-3 5.0E-7 2.2E-7 Diesel 1.0E-2 5.8E-7 2.6E-7

a U.S. Emissions Inventory 2005: Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 - 2003, EPA 430-R-003, U.S. Environmental Protection Agency, Washington, D.C., (April 2005) b Tonne/gal based on fuel properties listed in Table 2-1 and EFs of 0.08 g N2O/kg fuel and 0.180 g CH4/kg/fuel for both gasoline and diesel.

The 2006 IPCC Guidelines also present off-road mobile source and machinery GHG emission factors, but a direct comparison to the INGAA construction equipment emission factors cannot be made since the IPCC factors are on a heat basis. IPCC’s off-road mobile source emission factors are presented in Table 3.3.1 of Volume 2 of the Guidelines, and the CH4 and N2O emission factors are shown below in Table V-18. IPCC’s CO2 emission factors are not presented in the table since the stationary combustion emission factors presented in Section V.3.2 of this discussion paper can be used to estimate these emissions.

Table V-18. Mobile Source Off-Road and Machinery Equipment GHG Emission Factors – Energy Basis

CH4 b, kg/TJ N2O c, kg/TJ

Engine Type a Default Lower Upper Default Lower Upper Diesel 4.15 1.67 10.4 28.6 14.3 85.8 Motor Gasoline 4-Stroke 50 20 125 2 1 6 Motor Gasoline 2-Stroke 130 52 325 0.4 0.2 1.2

Source: EEA, Emission Inventory Guidebook – 2005, EMEP/CORINAIR, European Environment Agency, Technical report No 30. Copenhagen, Denmark, December 2005. a Emission factors shown are for the “Industry” category and are based on European off-road mobile sources and machinery. b Includes diurnal, soak and running losses. c In general, off-road vehicles do not have emission control catalysts installed (there may be exceptions among off-road vehicles in urban areas, such as ground support equipment used in urban airports and harbors). Properly operating catalysts convert nitrogen oxides to N2O and CH4 to CO2. However, exposure of catalysts to high-sulfur or leaded fuels, even once, causes permanent deterioration (Walsh, 2003). This effect, if applicable, should be considered when adjusting emission factors.

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59

VI. DIRECT EMISSIONS - PROCESS VENTS Vented emissions are releases to the atmosphere as a result of the process or equipment design or operational practices. There are a number of vented emission sources associated with natural gas transmission and distribution operations. These vented emissions may come from a variety of non-fired stacks and vents.

Table VI-1 presents options for estimating emissions for vented sources. The options range from simple default emission factors to engineering estimates or process simulators to source specific measurements. The selection of an estimation methodology should consider the contribution of emissions from the particular source or group of sources to an overall entity’s GHG inventory. The selection of an estimation approach should also consider the data available to support the estimate.

In compiling vented emissions for an entity inventory, care must be taken when combining different emission factor methodologies to ensure that emissions from sources are not double counted. For example, where emissions are determined for a specific venting event using the general cold vent approach provided in Section VI.5, these emissions should not also be accounted for using a non-routine emission factor from Section VI.6.

Direct process vents in the natural gas transmission and distribution industry segments are not specifically covered in the GRP. However, the API Compendium (API, 2004), INGAA (INGAA, 2005), and other references present these emissions sources, which are discussed below in more detail.

VI.1 Glycol Dehydrator Vents and Pumps

Glycol dehydration, using triethylene glycol, is a common method used to remove water from gas streams. The liquid glycol absorbs the water from the gas stream, and the water is driven from the glycol by heating it in the reboiler (or regenerator). Methane emissions from glycol units occur because a small amount of CH4 is absorbed by the glycol and driven off to the atmosphere in the glycol regeneration step. Note that combustion emissions from the glycol reboiler are not included in this section, and should be estimated using the combustion techniques presented in Section V.

For non-triethylene glycol dehydrators, manufacturers may be able to provide estimates of CH4 emissions for a specific process unit or as a percentage of emissions from a comparable glycol dehydration unit.

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Table VI-1. Summary of Emission Estimation Methods for Vented Sources

Method Information


EFs or Technique Industry sector general emission factors. Generally combines multiple sources into single factor.

Broad sector data, such as total length of pipeline


Low accuracy Does not account for site-

specific characteristics or control efforts

INGAA Table 3-1 (derived from GHGCalc)

Average source-level emission factors, generally based on most significant emission sources

Activity data related to broad categories of emission sources, such as pneumatic device count or maintenance/ upset emissions based on gas throughput or pipeline length

Activity data are generally available

Slightly better accuracy than general industry sector emission factors

Does not account for site-specific characteristics or control efforts

Tables VI-2 and VI-3 for dehydrators

Average factors in Tables VI-4 and VI-5

Table VI-6 for non-routine emissions

Source-specific emission factors

Source-specific activity data such as counts of pneumatic devices by device type

Reasonable accuracy Some accounting of site-specific

characteristics and control efforts

Requires more detailed activity data

Device factors in Tables VI-4 and VI-5

Tables VI-7 and VI-8 for non-routine emissions

Mass balance or engineering estimates

Source specific parameters Good accuracy Good accounting of site

characteristics and control efforts

Available for some emission sources

Equations 12, 13, and 16

Process simulators or correlation equations

Source specific parameters Methods are often accepted for regulatory reporting

Good accounting of site characteristics and control efforts

Available for some emission sources

Requires detailed process data

Equation 11

Source-specific measurements or manufacturers data

Emissions measurements and operating conditions

Accurate for design/tested conditions

Costly

According to Section 5.1.1 of the API Compendium, the preferred approach to estimate CH4 emissions from glycol dehydrators is to use measured test data of the dehydrator vent or manufacturer data, though this is not expected to be widely available. If vented test data or manufacturer information are not available, but detailed information about the site-specific glycol dehydrator unit is known, then a process simulator or other computer software such as GRI-GLYCalc (GRI, 2000) can be used to estimate the emissions. Alternatively, EPA developed the following correlation equation based on glycol circulation rate, contactor pressure, flash tank pressure (if applicable), and inlet CH4 flow rate14:

FactorSG FactorPumpP RateGC0066.0t throughpugas MMscfd

EmissionsCHMMscfy 4 +×××=

(Equation 11) where:

GC Rate = Glycol circulation rate in gallons/hr P = Flash tank pressure in psia, if a flash tank is present, or the

contactor pressure in psia Pump Factor = 2.5, if a gas assist pump is installed

SG Factor = 0.245 = stripping gas factor, if stripping gas is used

If there is not enough detailed input data to run a process simulator or to utilize the correlation equation, then industry specific emission factors provided in Table 5-1 of the API Compendium can be used, which are presented below in Table VI-2. These emission factors for glycol dehydrators are provided in Table 3-2 of INGAA (INGAA, 2005).

Table VI-2. Segment Specific Gas Dehydration CH4 Emission Factors

(Excludes Glycol Gas-Assisted Pump Emissions – See Table VI-3)

Industry Segment

CH4 Emission Factor, Original

Units CH4 Emission Factor,

Converted to Tonnes Basis a

CH4 Content Basis for Industry Segment

Precision b(+/- %)

Gas transmission

93.72 scf/106 scf gas processed

0.0017980 tonnes/106 scf gas processed

93.4 mole % 208

Gas storage 117.18 scf/106 scf gas processed


93.4 mole % 160

Source: Myers, D.B. Methane Emissions from the Natural Gas Industry, Volume 14: Glycol Dehydrators, Final Report, GRI-94/0257.31 and EPA-600/R-96-080n, Gas Research Institute and U.S. Environmental Protection Agency, June 1996. a CH4 emission factors converted from scf are based on 60°F and 14.7 psia. b Precision is based on a 90% confidence interval based on data used to develop the original emission factor.

14 Presented at the 7th Annual Implementation Workshop, October, 2000 http://www.epa.gov/gasstar/pdf/workshop_summary.pdf

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The emission factors in Table VI-2 can be scaled based on the ratio of the site-specific CH4 content to the default emission factor concentration provided in the table, if the site natural gas has a significantly different CH4 content from the default basis (refer to Equation 4). Also, if the gas contains significant quantities of CO2, the CH4 emission factors can be adjusted based on the relative concentrations of CH4 and CO2 in the gas to estimate the CO2 emissions (refer to Equation 5).

In addition to the glycol dehydrator vents, there may be emissions associated with the glycol pump if it is gas-assisted. Both electric and gas-assisted pumps are used to circulate glycol in the dehydrator system. If a gas-assisted pump is used, the low-pressure glycol is pumped into the absorber by pistons driven by the high-pressure glycol that is entrained with natural gas leaving the absorber. The GRI/EPA CH4 emissions study estimated the gas-assisted glycol pump emissions separate from the dehydrator vent emissions, though they are emitted from the same vent. This GRI/EPA study (Volume 15) did not find any glycol dehydrator pumps in the transmission and storage segments (Myers and Harrison, 1996). However, if any gas-assisted pumps are used, then the processing sector glycol pump emission factor provided in Table 5-3 of the API Compendium may be used in the absence of data. This emission factor is provided in Table VI-3 below. This table also includes the default CH4 content that can be used for adjusting the emission factors to other CH4 contents. INGAA (INGAA, 2005) provides a “storage” kimray pump emission factor in their Table 3-5 which is the same emission factor that is shown below in Table VI-3.

Table VI-3. GRI/EPA Kimray Pump CH4 Emission Factors

Segment


Units

CH4 Emission Factor, Converted to Tonnes

Basis a

CH4 Content Basis of Factor

Precision b(+/- %)

Processing 177.75 scf/106 scf gas processed


87 mole % 56.8

Source: Myers, D.B. and M.R. Harrison. Methane Emissions from the Natural Gas Industry, Volume 15: Gas Assisted Glycol Pumps, Final Report, GRI-94/0257.33 and EPA-600/R-96-080o, Gas Research Institute and U.S. Environmental Protection Agency, June 1996. a CH4 emission factors converted from scf are based on 60°F and 14.7 psia. b Precision is based on a 90% confidence interval based on data used to develop the original emission factor.

Using desiccant dehydrators results in much lower emissions than glycol dehydrators since the emissions only occur when the vessel is opened to add new desiccant material. Therefore, the approach to estimate these emissions is to perform a mass balance to estimate the gas that depressurizes to atmosphere using the pressure and volume of the

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vessel and the frequency of the depressurizations. The gas that depressurizes could include CH4 and possibly CO2. These emissions can be estimated using the cold vent calculation approaches provided later in Section VI.5 of this Discussion Paper.

VI.2 Gas Driven Pneumatic Devices

The API Compendium’s preferred approach for estimating CH4 emissions (and CO2 emissions if CO2 is present in the gas stream) from gas-driven pneumatic devices is to use site-specific device measurements. Note, manufacturer’s data have been found to underestimate emissions for pneumatic devices in operation. More commonly, simplified pneumatic device emission factors are applied based on the number of devices in general, or on the population of different types of devices. The emission factors provided in Table VI-4 for the transmission and distribution segments are taken from Table 5-15 of the API Compendium. This table also includes the default CH4 content that can be used for adjusting the emission factors to other CH4 contents (refer to Equation 4). Also, if the gas contains significant quantities of CO2, the CH4 emission factors can be adjusted based on the relative concentrations of CH4 and CO2 in the gas to estimate the CO2 emissions (refer to Equation 5).

Table VI-4. Gas-Driven Pneumatic Device CH4 Emission Factors

Device Type Emission Factor, Original

Units Precisionc

(±%) CH4 Emission Factor, Converted to

Tonnes Basis d

Transmission and Storage Based on 93.4 mole% CH4a

Continuous bleed a (also referred to as high-bleed devices)

497,584 scf gas/device-yr 29 8.915 tonnes/device-yr

Pneumatic/hydraulic valve operator a 5,627 scf gas/device-yr 112 0.1008 tonnes/device-yr

Turbine valve operator a 67,599 scf gas/device-yr 276 1.211 tonnes/device-yr

Transmission or Storage average a (if device type is unknown)

162,197 scfy CH4/device 44 3.111 tonnes/device-yr

Distribution Pneumatic isolation valvesb based on 93.4 mole% CH4

0.366 tonnes CH4/device-yr

Precision not specified

0.366 tonnes/device-yr

Pneumatic control loops b based on 94.4 mole% CH4

3.465 tonnes CH4/device-yr

Precision not specified


Distribution average b (if device type is unknown)

based on 94.9 mole% CH4 weighted

avg.

2.941 tonnes/yr/device Precision not specified


Sources: a Shires, T.M. and M.R. Harrison. Methane Emissions from the Natural Gas Industry, Volume 12: Pneumatic Devices, Final Report, GRI-94/0257.29 and EPA-600/R-96-080l, Gas Research Institute and U.S. Environmental Protection Agency, June 1996; and Harrison, M.R., L.M. Campbell, T.M. Shires, and R.M. Cowgill. Methane Emissions from the Natural Gas Industry, Volume 2: Technical Report, Final Report, GRI-94/0257.1 and EPA-600/R-96-080b, Gas Research Institute and U.S. Environmental Protection Agency, June 1996.

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b Shires, T.M. and C.J. Loughran. Updated Canadian National Greenhouse Gas Inventory for 1995, Emission Factor Documentation, Technical Memorandum, August 23, 2001. c Precision based on 90% confidence interval. d CH4 emission factors converted from scf or m3 are based on 60°F and 14.7 psia.

The transmission and storage pneumatic device emission factors presented in Table VI-4 are the same ones presented in Table 3-3 of INGAA (INGAA, 2005); the distribution segment is not included within the scope of the INGAA guidance document. INGAA presents additional transmission and storage pneumatic device emission factors for isolation valves and control loops in their Table 3-4 that are taken from GHGCalc™. However, we were unable to trace these emission factors back to GHGCalc™, so they are not presented here.

VI.3 Gas Driven Pneumatic Pumps

Natural gas-driven chemical injection pumps (CIPs) are a source of CH4 emissions due to venting of the gas used to act on a piston or diaphragm to pump chemicals into the process equipment lines. The CIPs can also be a source of CO2 emissions if the gas used to drive the pump contains a significant amount of CO2. The API Compendium’s preferred approach for estimating GHG emissions from CIPs is to use site specific gas usage measurements or manufacturer’s data. More commonly, simplified emission factors are applied. Table 5-16 of the API Compendium provides default emission factors for piston and diaphragm type pumps, and an average emission factor is given if the type of pump is unknown. The original emission factors provided in the API Compendium were based on a CH4 content of 78.8 mole %, which is typical for production. The 1996 GRI/EPA study observed that gas-powered chemical injection pumps are most commonly found in the production segment where electricity may not be readily available (Shires, Volume 13, 1996). These emission factors are presented below in Table VI-5 and have been adjusted from their original basis in API Compendium Table 5-16 by ratioing them to a CH4 content of 93.4%, which is the typical CH4 content of gas in the transmission segment presented in the API Compendium. Therefore, if there are any CIPs in transmission or distribution, then Table VI-5 can be used to estimate the emissions.

The emission factors in Table VI-5 can be adjusted to other CH4 contents, if needed (refer to Equation 4). Also, if the gas contains significant quantities of CO2, the CH4 emission factors can be adjusted based on the relative concentrations of CH4 and CO2 in the gas to estimate the CO2 emissions (refer to Equation 5).

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Table VI-5. Gas-Driven Chemical Injection Pump CH4 Emission Factors

Type of Chemical Injection Pump

CH4 Emission Factor, Original Units,

Based on 78.8 mole% CH4 a

Precisiond

±(%)

CH4 Emission Factor, Converted to Tonnes Basis,e

Adjusted to 93.4 mole% CH4f

Piston pumps (207 kPag) 48.9 a scfd CH4/pump 106% 0.405 tonnes/pump-yr Piston pumps (140 kPag) 0.04 b m3 gas/hr/pump Not specified 0.23 tonnes/pump-yr Piston pumps (240 kPag) 0.06 b m3 gas/hr/pump Not specified 0.33 tonnes/pump-yr Diaphragm pumps (pressure unspecified)

446 a scfd CH4/pump 77% 3.702 tonnes/pump-yr

Diaphragm pumps (140 kPag) 0.4 b m3 gas/hr/pump Not specified 2.3 tonnes/pump-yr Diaphragm pumps (240 kPag) 0.6 b m3 gas/hr/pump Not specified 3.3 tonnes/pump-yr

248 a scfd CH4/pump 83% 2.058 tonnes/pump-yr Average pump (if type not known) 0.3945 c m3 gas/hr/pump Not specified 2.186 tonnes/pump-yr

Sources: a Shires, T.M. Methane Emissions from the Natural Gas Industry, Volume 13: Chemical Injection Pumps, Final Report, GRI-94/0257.30 and EPA-600/R-96-080m, Gas Research Institute and U.S. Environmental Protection Agency, June 1996. b Canadian Association of Petroleum Producers (CAPP), Calculating Greenhouse Gas Emissions, Table 1-12, Canadian Association of Petroleum Producers, Publication Number 2003-03, April 2003. Note that the emission factors provided by this source are for the total gas emitted and were converted to a methane basis using the methane content shown in the table. c Canadian Association of Petroleum Producers (CAPP), Estimation of Flaring and Venting Volumes from Upstream Oil and Gas Facilities, Table 3-4, Canadian Association of Petroleum Producers, Publication Number 2002-0009, May 2002. Factor shown is based on data collected in Alberta, and was converted from a total gas basis to a methane basis using the methane content shown in the table. d Precision based on 90% confidence interval. e CH4 emission factors converted from scf or m3 are based on 60°F and 14.7 psia. f CH4 emission factors have been converted from the original basis of 78.8 mole % presented in the API Compendium (Table 5-16) to a more typical CH4 gas content of 93.4 mole % in the transmission sector (the assumed transmission gas content presented in the API Compendium).

INGAA presents similar CIP emission factors as the API Compendium (INGAA Table 3-5, presented by pump type, but without pressure categorization) but ratioed them based on 90% CH4 in transmission. A CH4 concentration of 93.4 mol% was applied in Table VI-5 for consistency with the API Compendium.

VI.4 Storage Tanks, Loading/Unloading, and Transit

In the NG T&D sector, storage tanks, loading/unloading, and transit emissions are potential vented emission sources for LNG operations. (Fugitive emission estimation methods applicable to LNG operations are addressed in Section VII.)

In the natural gas storage sector, LNG peak-shaving facilities are used for storing surplus natural gas that is to be used to meet the requirements of peak consumption later during winter or summer. Each peak-shaving facility has a regasification unit attached but may or may not have a liquefaction unit. Facilities without a liquefaction unit depend on tank trucks to supply LNG from other nearby sources. Of the approximate 113 active LNG

65

facilities in the United States, 57 are peak-shaving facilities. The other LNG facilities include marine terminals, storage facilities, and operations involved in niche markets such as LNG vehicle fuel.

LNG is commonly transported long distances in double-hulled ships specifically designed to handle the low temperature of LNG. These carriers are insulated to limit the amount of LNG that boils off or evaporates. This boil-off gas is sometimes used to supplement fuel for the carriers. Worldwide, there are currently 136 ships which transport more than 120 million metric tons of LNG every year. (Source: University of Houston IELE, Introduction to LNG.)

During ship unloading operations, a portion of the boil-off gas will be returned to the ship to compensate for the volume of liquid pumped out to maintain the ship’s tank pressure. Boil-off gas that is not returned to the ship will be compressed, condensed by direct contact with LNG and then combined with the send-out natural gas prior to being pumped up to pipeline pressure in the send-out pumps.

When LNG is received at a terminal, it is transferred to double-walled, insulated storage tanks that are built specifically to hold LNG. These tanks can be found above or below ground and keep the liquid at a low temperature to minimize the amount of evaporation. If tank LNG vapors are not released, the pressure and temperature within the tank will continue to rise. LNG is characterized as a cryogen, a liquefied gas kept in its liquid state at very low temperatures. The temperature within the tank will remain nearly constant if the pressure is kept constant by allowing the boil off gas to escape from the tank. This is known as auto-refrigeration. The boil-off gas is collected and used as a fuel source in the facility or on the tanker transporting/unloading it. When natural gas is needed, the LNG is warmed to a point where it converts back to its gaseous state. This is accomplished using a regasification process involving heat exchangers.

Methane emission factors for LNG vents and fugitive sources are not well developed. In its liquid form, LNG systems are designed to avoid contact with the outside air, which would gasify the LNG. Thus, great effort is taken to prevent vented and fugitive losses. Vapor recovery systems are used to capture boil off gas and re-route it for use as a fuel or to the send-out natural gas pipeline. In an emergency, flares are available to burn the CH4 rather than release it to the atmosphere. Once vaporized, emission factors applicable to natural gas storage or pipeline operations apply. .

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VI.5 General Cold Vent

“Cold” process vents refer to the vented release of natural gas emissions without combustion. A general approach to estimating these cold vent emissions is to use a material balance equation, which can be applied for CH4 as well as CO2 emissions. This approach is applicable to activities that result in vented emissions where the volume released can be determined from the internal volume of the equipment and where the number of release episodes are tracked. Examples of these types of activities include pipeline or vessel blowdowns, pigging, or “pull backs” (venting associated with water removal). Section 5.3 of the API Compendium provides further discussion.

The material balance equation for an intermittent process vent is:

nVTconversionmemolar volu

MWFVRE xxx ××××= (Equation 12)

where, Ex = emissions of “x” (CH4, or CO2) in units of mass (pounds, kg,

tonnes) per year “x” = the greenhouse gas compound of interest (CH4, or CO2 for

CO2 rich streams) VR = the volume released at STP conditions (scfm or m3/min) per

event Fx = the molar fraction of compound “x” in the vent gas stream

MWx = molecular weight of compound “x” Molar volume

conversion = conversion from molar volume to mass (379.3 scf/lbmole or

23.685 m3/kgmole) VT = the time duration of the venting event in minutes

N = the number of events of this type and magnitude annually

This equation calculates the total amount of any compound released during the event. To estimate an annual emission rate, the frequency and duration of such venting episodes on a yearly basis must be estimated using either documentation from actual venting events or averages from past events.

The approach is similar for a continual process vent. In this case the emission estimation equation is:

conversionmemolar voluMWFVRE x

xx ××= (Equation 13)

where, Ex = emissions of “x” in units of mass (pounds, kg, tonnes) per unit

of time

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“x” = the greenhouse gas compound of interest (CH4 or CO2, for CO2 rich streams)

VR = the vent rate in volume units at STP conditions per unit of time (e.g., scfm or m3/min)

Fx = the molar fraction of compound “x” in the vent gas stream MWx = molecular weight of compound “x”

Molar volume conversion

= Conversion from molar volume to mass (379.3 scf/lbmole or 23.685 m3/kgmole)

Engineering assumptions may be required to estimate the volume of gas released. For example, the volume released may be based on the internal volume of a piece of equipment or the volume contained within a pipe section (assuming the entire contents are released) and converted from actual cubic feet of gas to standard cubic feet using the density of the gas. For pigging operations, the volume released would be based on the segment of pipeline depressurized plus the volume of the pig catcher or launcher.

The density of the gas can be calculated using an additional term in the gas law:

nRTPV z= (Equation 14) where,

P = pressure (psia or atm) V = Volume z = compressibility factor, tables for CH4 and CO2 are provided in Perry’s

Chemical Engineer’s Handbook Tables 3-172 and 3-166, respectively (Perry, 1984)

N = number of moles R = gas constant T = absolute temperature (°R or K)

Rearranging, the equation becomes:

RTPV nz

= (Equation 15)

Using this equation, the moles of gas emitted can be converted to a mass basis by applying the molecular weight of CH4 or CO2. The following equation results:

YearEvents#MWMole%

Event ReleasedGas Moles E

24 COor CHCO2or CH4CO2or CH4 ×××= (Equation 16)

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The detailed, engineering calculation approach is presented in Section 3.4.1 of the 2005 INGAA gas transmission/storage guidance document and is similar to the approach described above.

VI.6 Non-Routine Activities

VI.6.1 Transmission/Storage

If detailed information is lacking to use the engineering calculation approaches in the previous subsection to estimate non-routine vented emissions, then simple emission factors for common non-routine activities are available. Table VI-6 presents a summary of simple natural gas transmission and storage non-routine activity emission factors taken from Table 5-24 of the API Compendium. These same emission factors are presented in Table 3-6 of the 2005 INGAA guidance document. Table 3-6 of the INGAA document also includes a storage pipeline blowdown CH4 emission factor that is provided in Table 5-21 of the API Compendium as a production sector gathering gas pipeline blowdown emission factor.

Note that the gas compressor station blowdown emission factor presented in Table VI-6 is an overall station factor that includes compressor blowdowns, compressor starts, PRV releases, ESD activation, and other non-routine venting. The gas transmission pipeline venting emission factor is based on transmission pipeline blowdowns due to maintenance activities, such as pipe repairs or pigging operations. The storage station emission factors presented here apply to below-ground facilities. As mentioned previously, a joint industry/EPA program intends to develop LNG emission factors. Until these are available, cold vent methods similar to those presented in Section VI.5 should be applied.

The gas compressor station emission factor is broken down into specific source types as shown in Table VI-7. These categories include compressor blowdowns, engine starts, PRV lifts, ESD activation, and other miscellaneous venting activities.

The non-routine emission factors given in Tables VI-6 and VI-7 can be adjusted based on the CH4 content of the site-specific gas, if the natural gas has a significantly different CH4 content from the default basis (refer to Equation 4). Also, if the facility gas contains significant quantities of CO2, the CH4 emission factor can be adjusted based on the relative concentrations of CH4 and CO2 in the gas to estimate the CO2 emissions (refer to Equation 5).

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Table VI-6. Transmission/Storage Segment CH4 Emission Factors for Non-Routine Activities

Source CH4 Emission Factor,

Original Units

CH4 Emission Factor, Converted to

Tonnes Basis d


Precisione

(±%) Gas compressor station blowdowns a

5300 ×103 scfy/station 101.7 tonnes/station-yr 93.4 mole % 52

M&R station blowdowns b 0.020 ×106 m3/sation-yr 13.75 tonnes/station-yr 95 mole % Not available

Gas transmission pipelines venting/ blowdowns a

40,950 scfy/mile 0.7855 tonnes/mile-yr 93.4 mole % 60

Gas storage station venting c

4359 × 103 scfy/station 83.61 tonnes/station-yr 93.4 mole % 262

Production sector gathering gas pipelinec

309 scfy/mile 0.00593 tonnes/mile-yr

78.8 mole % 32

Sources/Notes: a Shires, T.M. and C.J. Loughran. GHGCalc Version 1.0 Emission Factor Documentation, Draft, Section 5.1.3, November 2001. Includes U.S. and Canadian data. b URS Corporation. Updated Canadian National Greenhouse Gas Inventory for 1995, Emission Factor Documentation. Technical Memorandum, Final, October 2001. c Shires, T.M. Methane Emissions from the Natural Gas Industry, Volume 7: Blow and Purge Activities, Final Report, GRI-94/0257.24 and EPA-600/R-96-080g, Gas Research Institute and U.S. Environmental Protection Agency, June 1996. d CH4 emission factors converted from scf or m3 are based on 60°F and 14.7 psia. e Precision based on 90% confidence interval.

Table VI-7. Transmission/Storage Segment CH4 Emission Factors for Non-Routine Activities by Specific Activity Type

Source CH4 Emission Factor,

scf Basis


Basis a


Precisionb

(±%) Compressor Blowdowns 2457.4 ×103 scfy/station 47.14 tonnes/station-yr 93.4 mole % 125 Engine Starts 1515.1 ×103 scfy/station 29.06 tonnes/station-yr 93.4 mole % 100 PRV Lifts 192.1 ×103 scfy/station 3.68 tonnes/station-yr 93.4 mole % Not

available ESD Activation 415.4 ×103 scfy/station 7.97 tonnes/ station-yr 93.4 mole % 235 Miscellaneous (includes M&R, odorizer, drips, sampling, pigging, dehydrators)

1134.1 ×103 scfy/station 21.75 tonnes/station-yr 93.4 mole % 21.5

Source: Developed from data used for the June 1996 GRI/EPA methane emissions study. Emission factors are based on averaging data by site. Notes: aCH4 emission factors converted from scf are based on 60°F and 14.7 psia. b Precision based on 90% confidence interval.

Note that Tables VI-6 and VI-7 do not provide an emission factor for surge or breakout tanks. These tanks are used to provide excess volume to relieve pressure in a liquid pipeline system or to provide temporary storage when switching product lines or

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performing maintenance on the pipeline system. “Breakout tanks” is the preferred terminology for liquid pipeline operations, while the term “surge tanks” is generally associated with processing. Since liquid pipelines and processing are not covered by this guidance, no emissions estimation guidance is provided for breakout and surge tanks.

VI.6.2 Distribution

Table VI-8 presents a summary of simple natural gas distribution non-routine activity emission factors. These emission factors are taken from Table 5-25 of the API Compendium. These distribution segment emission factors are not provided in the 2005 INGAA guidance document since the distribution segment was not included within the scope of that report.

Table VI-8. Gas Distribution Segment CH4 Emission Factors for Non-Routine Activities

Source


Units


Basis c


Precision d

(±%) M&R Station maintenance/upsets a

4.27 m3/station-yr 0.002895 tonnes/station-yr 94.8 mole % Not available

Odorizer and gas sampling vents a

33.59 m3/station-yr 0.02275 tonnes/station-yr 94.8 mole % Not available

Pipeline blowdowns (based on mains and services length) b

1680 scfy/mile 0.03223 tonnes/mile-yr 93.4 mole % 95

Pipeline dig-ins (based on mains and services length) b

1590 scfy/mile 0.03050 tonnes/mile-yr 93.4 mole % 1922

Pressure relief valves (based on pipeline mains length) b

50 scfy/mile 9.591E-4 tonnes/mile-yr 93.4 mole % 3914

Sources/Notes:

a URS Corporation. Updated Canadian National Greenhouse Gas Inventory for 1995, Emission Factor Documentation, Technical Memorandum, Final, October 2001. b Shires, T.M. and C.J. Loughran. GHGCalc Version 1.0 Emission Factor Documentation, Draft, January 2002 c CH4 emission factors converted from scf or m3 are based on 60°F and 14.7 psia. d Precision based on 90% confidence interval.

Dig-ins are unintentional mishaps that result in gas being released to the atmosphere from main or service distribution gas pipelines. Similar to the transmission segment, the non-routine emission factors given in Table VI-8 can be adjusted based on the CH4 content of the site-specific gas, if the natural gas has a significantly different CH4 content from the default basis (refer to Equation 4). Also, if the facility gas contains significant quantities of CO2, the CH4 emission factor can be adjusted based on the relative concentrations of CH4 and CO2 in the gas to estimate the CO2 emissions (refer to Equation 5).

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VI.7 Fire extinguishers

The use of fire suppression equipment may result in high global warming potential (GWP) emissions as a result of using substitutes for ozone-depleting substances (ODSs). The GHGs of concern from such fire suppression equipment are typically hydrofluorocarbons (HFCs) or perfluorocarbons (PFCs). The global warming potentials for such HFCs and PFCs are typically several thousand times larger than for CO2.

Chapter 11 of the GRP refers to the Power/Utility Appendix for guidance on estimating fugitive emissions from fire suppression equipment. However, Chapters 3 and 7 of the Power/Utility Appendix refer back to the GRP for guidance on estimating these emissions. Therefore, existing Registry guidance on estimating these emissions could not be located. The 2005 INGAA guidance document does not provide guidance on fire extinguisher emissions.

To estimate the fire extinguisher emissions, a material balance approach, such as provided by Equation 12, should be used. The material balance should consider the amount of fire suppressant released in each event, the number of events annually, and the composition of the particular GHG in the fire suppressant. Table III.6.1 of the GRP provides GWPs that can be used to convert the fire suppression species emissions to a CO2 equivalent basis (CO2e). For a more rigorous approach to estimate these fire extinguisher emissions, refer to Appendix H of EPA’s draft 1990-2020 inventory of global non-CO2 emissions document (EPA, 2005).

VI.8 Lost and Unaccounted for Gas

Lost and unaccounted for gas (also referred to as LUG, L&U, or UAF), refers to the reconciliation between gas receipts and gas deliveries. The two primary contributors to lost and unaccounted for gas are leakage from the system and measurement inaccuracies. Some companies may also include unmeasured gas. As a result lost and unaccounted for gas is not an accurate surrogate for vented and fugitive emissions.

72

73

VII. DIRECT EMISSIONS – FUGITIVES Fugitive emissions refer to emissions from equipment leaks, where any pressurized equipment has the potential to leak. These leaks generally occur through valves, flanges, seals, or related equipment. Fugitive emissions also include non-point evaporative sources such as from wastewater treatment, pits, and impoundments. Direct fugitive emissions are described in Part II, Chapter 11 of the GRP, but it is not specific to natural gas transmission, storage, and distribution operations. Therefore, this section addresses these fugitive emissions for these industry segments.

In compiling fugitive emissions for an entity inventory, care must be taken when combining different emission factor methodologies to ensure that emissions from sources are not double counted. For example, emission factors provided in Table VII-2 are based on an assumed “average” population of equipment represented in Table VII-3. Likewise, emission factors provided in Table VII-3 are base on an assumed “average” population of fugitive sources represented in Tables VII-4 and VII-5.

VII.1 Methodologies for Equipment Leaks

The approaches for estimating equipment leak fugitives vary from simple facility-level emission factors to individual component measurements and site monitoring data. Table VII-1 provides an overview of the different approaches that can be used for estimating equipment leak fugitives.

The selection of an estimation methodology for fugitive emissions should consider the contribution of fugitive emissions to an overall entity’s GHG inventory. The selection of a fugitive equipment leak estimation approach should also consider the data available to support the estimate. The facility-level average emission factor approach requires only identifying the type of facility and knowing its capacity or pipeline mileage. General equipment counts are required for the second approach. Component-level average emission factor approaches require detailed counts of components (such as valves, connections, pump seals, etc.), and for some emissions factors, these component counts are further delineated by service type (such as for valves in gas, light liquid, or heavy liquid service). Some of the more rigorous component-level approaches also require monitoring data, in addition to component counts.

Ultimately, the available data must be balanced against the materiality of the fugitive emissions. If the available data will not support a level of accuracy consistent with the fugitive emission materiality, additional data gathering may be required.

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Table VII-1. Summary of Methods for Estimating Equipment Leak Fugitives

Method Information


Emission Factors Facility-level emission factors Broad sector data, such

as total length of pipeline

Simplest approach Low cost Useful if there is no component

count inventory

Least accurate approach Does not account for control efforts

Table VII-2 in this discussion paper

Equipment-level emission factors Equipment inventories Second simplest approach Low cost Useful if there is no component

count inventory

Second least accurate approach Does not account for control efforts

Table VII-3 Tables VII-4 and VII-5 provide

additional detail

Average component-level emission factors

Component count inventories

Simple Low cost

Poor accuracy Requires component count inventory

API Compendium Table B-17 INGAA Guidelines Table 4-12

- Screening approaches: Leak/no-leak factors Stratified factors Published leak-rate correlations Custom leak-rate correlations


Leak survey results

Identifies leaking components Control efforts reflected in

results

Labor intensive Moderate costs Poor to moderate accuracies

API Compendium Tables B-22 through B-24

INGAA Guidelines Tables 4-6 through 4-8

Screening coupled with direct measurements for significant leakers: Hi-flow sampler Bagging


Leak survey results

Identifies leaking components Excellent accuracy

Labor intensive Moderate to high costs

No emission factors

Whole-facility quantification approaches: Remote sensing Plume transect method Trace/pollutant ratio technique

Minimal SimpleCost effective for large facilities Reasonable accuracies

Susceptible to weather problems Potential interference from other nearby

sources Costly for small facilities Usually not practicable for identifying

individual leakers, but can be useful for quickly delineating high-emission zones

No emission factors

The API Compendium recommends starting with the simplest method to evaluate the contribution of fugitive emissions relative to the entity inventory. If the total emissions from equipment leaks exceed some predefined percentage (perhaps 5% or 10%) of the overall inventory, than a more detailed, equipment based approach would be warranted. If an entity or facility conducts a leak detection and repair program (LDAR), component level information would be available to apply a more rigorous estimation method.

VII.2 Equipment Leaks

There are a variety of fugitive emission sources related to oil and gas industry operations. The type of fugitive emissions discussed in this subsection are equipment leaks from valves, flanges, pump seals, compressor seals, relief valves, sampling connections, process-drains, open-ended lines, and other miscellaneous component types.

VII.2.1 Facility-Level Fugitive Emission Factors

Applying average facility-level emission factors is the simplest method for estimating CH4 emissions from transmission, storage, and distribution facilities. It is especially useful for an existing facility where detailed component counts (valves, flanges, etc.) are not available. These emission factors are presented in Table VII-2 and are taken from Table 6-1 of the API Compendium. These same transmission and storage segment emission factors are provided in Table 4-2 of the INGAA gas transmission and storage guidance document (INGAA, 2005); the distribution segment is not included within the scope of the INGAA guidance document.

Table VII-2. Facility-Level Average Fugitive Emission Factors

Source Emission Factor Original Units

Precision(± %) a

Gas Content Basis of Factor

Emission Factorb, Converted Units

Gas storage stations 1,489,000 lb CH4/station 57 93.4 mole % CH4 6.754E+02 tonnes CH4/station Gas transmission pipelines

CH4 from pipeline leaks 7,923 lb CH4/mile-yr 84 3.594E+00 tonnes CH4/mile-yr CO2 from oxidation d 7.59 lb CO2/mile-yr 65

93.4 mole % CH4 3.443E-03 tonnes CO2/mile-yr

CO2 from pipeline leaks 466.7 lb CO2/mile-yr 84 2 mole % CO2 2.117E-01 tonnes CO2/mile-yr Gas distribution pipelines

CH4 from pipeline leaks 3,551 lb CH4/mile-yr 48 1.611E+00 tonnes CH4/mile-yr CO2 from oxidation d 1,237 lb CO2/mile-yr 69

93.4 mole % CH4 5.611E-01 tonnes CO2/mile-yr

CO2 from pipeline leaks 235.6 lb CO2/mile-yr 45 2 mole % CO2 1.069E-01 tonnes CO2/mile-yr Source: Shires, T.M. and C.J. Loughran. GHGCalc Version 1.0 Emission Factor Documentation, Draft, Gas Technology Institute (GTI), January 2002, fugitive emission factors from Table 4-26. a Precision is based on a 90% confidence interval from the data used to develop the original emission factor. b The CH4 emission factors can be adjusted based on the relative concentrations of CH4 and CO2 to estimate CO2

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emissions c Storage stations refer to underground natural gas storage. Fugitive emission factors for LNG are not specifically addressed in published sources. d A portion of CH4 emitted from underground pipeline leaks is oxidized to form CO2.

The table above provides pipeline leak emissions that include both CH4 and CO2 emissions. Fugitive emissions from buried pipelines originate from two sources: (1) gas leaks which result in CH4 and CO2 emissions in proportion to the gas composition, and (2) the partial oxidation of CH4 as it migrates through the soil. This partial oxidation of CH4 to CO2 emissions is described in the GRI/EPA methane emissions study (Campbell, et. al, Volume 9, 1996). The degree of oxidation depends on factors such as the depth of cover, soil composition, and leak rate which is a function of pipeline material. Both types of CO2 emissions are shown in the tables in this subsection. Oxidation rates and fugitive emission rates for different pipeline materials (cast iron, protected steel, unprotected steel, copper, and plastic) shown in the tables in this subsection were measured as part of the GRI/EPA U.S. methane emissions study (Campbell, et. al., 1996).

As described in Section 6.1.2 of the API Compendium, the following equations were used in developing the CO2 emission factors from pipeline fugitive emissions:

(1) CH4 emissions from gas leaks: ( ) ( )Oxidation Soil %100leaked CH Total Factor Emission CH 44 −×= (Equation 17)

The equation above accounts for the portion of leaked CH4 that is not oxidized to CO2.

(2) CO2 emissions from CH4 oxidation:

⎟⎟⎠

⎞⎜⎜⎝

⎛×⎟⎠⎞

⎜⎝⎛×⎟

⎠⎞

⎜⎝⎛×⎟⎟

⎠

⎞⎜⎜⎝

⎛=

4

242 CHMW

COMW 100Oxidation Soil %

Oxidation Soil % - 100100

Factor EmissionCH

EFCO

(Equation 18)

The equation above accounts for the CO2 formed from the oxidation of leaked CH4 as the gas migrates through the soil. The second term in the equation corrects the CH4 emission factor to its "pre-oxidized" form. The third term converts the total moles of CH4 to moles of CO2 formed as a result of oxidation. The final term corrects for the molecular weights of CO2 and CH4.

(3) CO2 emissions from gas leaks:

⎟⎟⎠

⎞⎜⎜⎝

⎛×⎟⎟⎠

⎞⎜⎜⎝

⎛×⎟⎠⎞

⎜⎝⎛×⎟⎟

⎠

⎞⎜⎜⎝

⎛=

4

2

4

242 CHMW

COMW CH mol%default CO mol%default

Oxidation Soil % - 100100

Factor EmissionCH

EFCO

(Equation 19)

The last equation shown above accounts for CO2 that is emitted from pipeline fugitive leaks. This equation starts with the CH4 emission factor, which is converted to its "pre-oxidized" form by the

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second term. The third term corrects for the molar ratio of CO2 to CH4 in the default gas composition, and the final term corrects for the molecular weights of CO2 and CH4.

VII.2.2 Equipment-Level Fugitive Emission Factors The equipment-level average emission factor approach allows the fugitive emission estimate to be tailored to a particular facility based on the population of major equipment at the facility. This approach requires more information than the facility-level approach, but results in a slightly more accurate emission estimate than the facility-level approach. It is especially useful when trying to estimate GHG emissions for a planned facility that has not yet been fully designed or for an existing facility where no detailed minor component population data are available.

Table VII-3 provides fugitive emission factors for equipment associated with natural gas transmission, storage, and distribution operations. These emission factors are taken from Tables 6-5 and 6-6 of the API Compendium (2004, 2005 errata). Carbon dioxide emissions from buried pipeline leaks were discussed earlier. The default CH4 emission factors can be adjusted for other CH4 concentrations by the ratio of the actual CH4 content to the default value. The CH4 emission factors can also be used to estimate CO2 emissions based on the ratio of CO2 to CH4 in the gas. The equations for these concentration adjustments are presented at the beginning of this emissions estimation section (Refer to Equations 4 and 5).

Tables 4-3 and 4-5 of the 2005 INGAA guidance present the same emission factors as shown Table VII-3 with a few exceptions. INGAA’s transmission compressor station emission factor includes stations, reciprocating compressors, and centrifugal compressors combined into one emission factor while Table VII-3 lists them separately (INGAA also lists them separately in their Table 4-4). Similarly, INGAA’s storage station emission factor shown in their Table 4-3 includes stations and wells that are listed separately in Table VII-3 (they also list them separately in their Table 4-5). INGAA provides an emission factor for gathering pipeline leaks in their Table 4-5. That emission factor is not presented here since its applicability to storage station pipeline (generally confined to the station area and much shorter in length) is unclear. INGAA also lists CO2 emissions from leaks from transmission stations and meter/regulators that are not provided here. These CO2 leak emissions can be estimated using Equation 5 if the relative CH4 and CO2 concentrations are known.

Some additional, more detailed transmission segment equipment-level emission factors are provided in Table VII-4, which are taken from GHGCalc Version 1.0 (Shires, 2002). These emission factors are useful if the type of buried transmission pipeline is known. The pipeline emission factors in GHGCalc were derived from emission factors in the GRI/EPA methane emissions project (Campbell, et. al, Volume 9, 1996) that were converted from a an equivalent leak basis in the original GRI/EPA study to a transmission mainline pipeline mile basis in GHGCalc.

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The emission factors in Table VII-4 were not presented to the level of detail shown here in the API Compendium, but are included in Table 4-4 of the INGAA guidance. INGAA also lists CO2 emissions from leaks from compressor stations and meter/regulators that are not provided here. These CO2 leak emissions can be estimated using Equation 5.

Table VII-3. Fugitive Emission Factors for Gas Transmission, Storage, and Distribution Equipment

Equipment Basis Reference Emission Factor,

Original Units Precision(± %) a

Emission Factorb, Converted Units

Transmission Based on 93.4 mole% CH4, 2% CO2

Compressor Stations 8,778 scfd CH4/facility 102 7.02E-03 tonne CH4/station-hr Compressor Stations – Reciprocating

15,205 scfd CH4/comp. 65 1.22E-02 tonne CH4/compressor-hr

Compressor Stations – Centrifugal


Meter/Reg. Stations 60,010 scf CH4/station-yr 80 1.31E-04 tonne CH4/station-hr Gas Transmission Pipeline 23.08 lb CH4/mile-yr 90 1.20E-06 tonne CH4/mile-hr CO2 from oxidation c 7.59 lb CO2/mile-yr 65 3.93E-07 tonne CO2/mile-hr CO2 from pipeline leaks 1.522 lb CO2/mile-yr 84 7.88E-08 tonne CO2/mile-hr Storage Based on 93.4 mole% CH4, 2% CO2

Storage Stations 21,507 scfd CH4/facility 100 1.72E-02 tonne CH4/station-hr Storage – Reciprocating Compressor


Storage – Centrifugal Compressor


Storage Wells 114.5 scfd CH4/well 76 9.15E-05 tonne CH4/well-hr Distribution Based on 93.4 mole% CH4, 2% CO2

Customer Meters 129.15 scf/meter-yr 22 2.83E-07 tonne CH4/meter-hr Distribution Meter/Reg. Stations

207,018 scf/station-yr 90 4.53E-04 tonne CH4/station-hr

Distribution Pipelines 1,357 lb CH4/mile-yr 69 7.03E-05 tonne CH4/mile-hr CO2 oxidation EF for distribution pipeline c

1,205 lb CO2/mile-yr 71 6.24E-05 tonne CO2/mile-hr

CO2 leaks from distribution pipeline

105.7 lb CO2/mile-yr 63 5.47E-06 tonne CO2/mile-hr

Distribution Services 1,067 lb CH4/mile-yr 142 5.52E-05 tonne CH4/mile-hr CO2 oxidation EF for distribution services c


CO2 leaks from distribution services


Source: Shires, T.M. and C.J. Loughran. GHGCalc Version 1.0 Emission Factor Documentation, Draft, Gas Technology Institute, January 2002. Cites data from multiple tables. Notes: a Precision is based on a 90% confidence interval from the data used to develop the original emission factor. b Emission factors converted from scf are based on 60 °F and 14.7 psia. The average CH4 concentration associated with these emission factors is 93.4 mole %; the average CO2 concentration (for buried pipelines) is 2 mole %. If the actual concentration differs from the default value, the emission factors shown above can be adjusted by the ratio of the site concentration to the default concentration. c A portion of CH4 emitted from underground pipeline leaks is oxidized to form CO2.

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Table VII-4. More Detailed Fugitive Emission Factors for Transmission Equipment

Source Emission Factora Precisionb ± (%) M&Rc Stations (Farm Taps or Direct Sales)

480.8 lb CH4/station-yr 80%

M&R Stations (Transmission Interconnects)

61,390 lb CH4/station-yr 80%

Cast Iron Pipeline 10,079 lb CH4/mile-yr 64% Cast Iron Pipeline (Oxidation) d 18,710 lb CO2/mile-yr 73% Cast Iron Pipeline (Leak) 994.2 lb CO2/mile-yr 69% Plastic Pipeline 22.51 lb CH4/mile-yr 225% Plastic Pipeline (Oxidation) d 1.264 lb CO2/mile-yr 228% Plastic Pipeline (Leak) 1.353 lb CO2/mile-yr 226% Protected Steel Pipeline 15.13 lb CH4/mile-yr 131% Protected Steel Pipeline (Oxidation) d 1.287 lb CO2/mile-yr 136% Protected Steel Pipeline (Leak) 0.9185 lb CO2/mile-yr 133% Unprotected Steel Pipeline 275.9 lb CH4/mile-yr 139% Unprotected Steel Pipeline (Oxidation) d

13.91 lb CO2/mile-yr 143%

Unprotected Steel Pipeline (Leak) 16.55 lb CO2/mile-yr 141% Source: Shires, T.M. and C.J. Loughran. GHGCalc Version 1.0 Emission Factor Documentation, Draft, Gas Technology Institute, January 2002. Cites data from Table 4-7. a The average CH4 concentration associated with these emission factors is 93.4 mole %; the average CO2 concentration (for buried pipelines) is 2 mole %. If the actual concentration differs from the default value, the emission factors shown above can be adjusted by the ratio of the site concentration to the default concentration. b Precision based on 90% confidence interval. c Metering and Pressure Regulating (M&R) stations. d A portion of CH4 emitted from underground pipeline leaks is oxidized to form CO2.

Table VII-5 includes some additional, more detailed distribution segment equipment-level emission factors, which are taken from GHGCalc Version 1.0 (Shires, 2002). These are similar to the level of detail shown in the Table VII-4 for the transmission segment. The pipeline leak emission factors were derived from the GRI/EPA methane emissions project (Campbell, et. al, Volume 9, 1996). These emission factors were not provided to this level of detail in the API Compendium. They are also not provided in the 2005 INGAA guidance as the distribution segment was not included within the scope of that document.

Care should be taken when applying the more detailed emission factors in Tables VII-4 and VII-5 to avoid double-counting with the emission factors provided in Table VII-3. That is, the meter, pipeline, and distribution service fugitive emission factors should either be used from Table VII-3 or from Tables VII-4/VII-5, but not from both Table VII-3 and the latter two tables.

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Table VII-5. More Detailed Fugitive Emission Factors for Distribution Equipment

Source Emission Factora Precisionb ± (%) Commercial/Industrial Meters 2.022 lb CH4/meter-yr 35% Residential Customer Meters 5.847 lb CH4/meter-yr 17% Cast Iron Pipeline, Main Length 10,079 lb CH4/mile-yr 64% Cast Iron Pipeline, Main Length (Oxidation) c 18,710 lb CO2/mile-yr 73% Cast Iron Pipeline, Main Length (Leak) 994.2 lb CO2/mile-yr 69% Plastic Pipeline, Main Length 693.0 lb CH4/mile-yr 282% Plastic Pipeline, Main Length (Oxidation) c 38.89 lb CO2/mile-yr 284% Plastic Pipeline, Main Length (Leak) 41.64 lb CO2/mile-yr 283% Protected Steel Pipeline, Main Length 129.5 lb CH4/mile-yr 118% Protected Steel Pipeline, Main Length (Oxidation) c 11.01 lb CO2/mile-yr 123% Protected Steel Pipeline, Main Length (Leak) 7.862 lb CO2/mile-yr 121% Unprotected Steel Pipeline, Main Length 4652 lb CH4/mile-yr 122% Unprotected Steel Pipeline, Main Length (Oxidation)

234.5 lb CO2/mile-yr 127%

Unprotected Steel Pipeline, Main Length (Leak) 278.9 lb CO2/mile-yr 124% Copper Pipeline, Services 10.74 lb CH4/service-yr 154% Copper Pipeline, Services (Oxidation) c 0 lb CO2/service-yr N/A Copper Pipeline, Services (Leak) 0.6322 lb CO2/service-yr 156% Plastic Pipeline, Services 0.3926 lb CH4/service -yr 222% Plastic Pipeline, Services (Oxidation) c 0.2905 lb CO2/service-yr 225% Plastic Pipeline, Services (Leak) 0.0293 lb CO2/service-yr 223% Protected Steel Pipeline, Services 7.451 lb CH4/service -yr 169% Protected Steel Pipeline, Services (Oxidation) c 0.5470 lb CO2/service -yr 173% Protected Steel Pipeline, Services (Leak) 0.4505 lb CO2/service -yr 171% Unprotected Steel Pipeline, Services 71.81 lb CH4/service -yr 189% Unprotected Steel Pipeline, Services (Oxidation) c 2.196 lb CO2/service -yr 192% Unprotected Steel Pipeline, Services (Leak) 4.276 lb CO2/service -yr 191% Source: Shires, T.M. and C.J. Loughran. GHGCalc Version 1.0 Emission Factor Documentation, Draft, Gas Technology Institute, January 2002. Cites data from Table 4-10. a The average CH4 concentration associated with these emission factors is 93.4 mole %; the average CO2 concentration (for buried pipelines) is 2 mole %. If the actual concentration differs from the default value, the emission factors shown above can be adjusted by the ratio of the site concentration to the default concentration. b Precision based on 90% confidence interval. c A portion of CH4 emitted from underground pipeline leaks is oxidized to form CO2.

VII.2.3 Facility and Equipment Level Emission Factor Considerations

An independent review of the API Compendium emission factors conducted for the California Energy Commission pointed out some areas for improvement (ICF, 2005). Those related to NG T&D sources included fugitive emissions from plastic pipelines in the distribution sector and compressor seals.

For centrifugal compressors, two technologies are available to seal the rotating shaft at one or both ends of the compressor case. The more mature technology, referred to as a wet seal, uses oil. This

80

technology was common during the time that the emission factors referenced by the API Compendium (and reflected in Table VII-3) were developed. Industry today more commonly uses dry seals, which result in lower operating costs and lower CH4 emissions than wet seals. EPA’s Natural Gas STAR provides vendor design data for dry seals used in mainline transmission compressors which indicate emissions of 6 scf/min or lower.15 Emissions reported by Gas STAR partner companies from wet seals range from 40 to 200 scf/min.

For plastic distribution mains, the CH4 emission factor referenced by the API Compendium is based on six sample points, spanning five orders of magnitude. Statistical analysis of the data did not warrant excluding the two high data points.16 However, it is possible that two of the data points reflect plastic pipes with leaks due to brittle cracking, a phenomenon associated with plastic pipe manufactured before 1982.

ICF Consulting has proposed revised emission factors for plastic pipe based on combining the original GRI/EPA data12 with data reported by Southern California Gas Company.17 For pre-1982 plastic pipe, or where the breakout of plastic pipe by age is not available:

CH4 EF = 5.85 scf/hr (based on 93.4 mol% CH4 and soil oxidation rate of 2%)

For plastic pipe produced based on the revised ASTM D2837 standard18 (i.e., post-1982)

CH4 EF = 0.99 scf/hr (based on 93.4 mol% CH4 and soil oxidation rate of 2%)

VII.2.4 Average Component-Level Fugitive Emission Factors

The component-level average emission factor approach estimates emissions based on the number of components (e.g., valves, flanges, etc.) in the facility. For some emission factors, component counts are required for each service category, such as valves in gas, light liquid, or heavy liquid service. Section B.3.1 in Appendix B of the API Compendium provides more details on average component-level fugitive emission factors (API, 2004).

For some emission factors, component counts are required for each service category, such as valves in gas, light liquid, or heavy liquid service. Gas service is defined as any material that is in a gaseous or vapor state at process conditions. Light liquid service is defined as naphtha and more volatile petroleum liquids. Alternately, light liquid service may be defined as any material in a 15 Natural Gas STAR, Lessons Learned – Replacing Wet Seals with Dry Seals in Centrifugal Compressors, EPA 430-B-03-012, U.S. Environmental Protection Agency. 16 Campbell, L.M., M.V. Campbell, and D.L. Epperson. Methane Emissions from the Natural Gas Industry, Volume 9: Underground Pipelines, Final Report, GRI-94/0257.26 and EPA-600/R-96-080i. Gas Research Institute and U.S. Environmental Protection Agency, June 1996. 17 Southern California Gas Company, A Study of the 1991 Unaccounted-for Gas Volume at the Southern California Gas Company, April 1993. 18 ASTM D2837: Standard Test Method for Obtaining Hydrostatic Design Basis for Thermoplastic Pipe Materials or pressure Design Basis for Thermoplastic Pipe Products.

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liquid state in which the sum of the concentration of individual constituents with a vapor pressure over 0.3 kPa at 20°C is greater than or equal to 20 weight percent. A heavy liquid is any liquid that is not in gas/vapor or light liquid service, which would generally include kerosene and less volatile petroleum liquids.

It should be noted that the component-level average emission factors were developed for estimating total organic compounds (TOC), also referred to as total hydrocarbon compounds (THC), or volatile organic compounds (VOC), rather than CH4. The emission factors can be applied to estimate CH4 emissions based on the following equation:

NWFFE44 CHACH ××= (Equation 20)

where, ECH4 = Emission rate of CH4 from all components of a given type in the

stream FA = Average emission factor for the component type from the applicable

tables WFCH4 = Average weight fraction of CH4N = Number of components of the given type in the stream

For natural gas transmission and storage operations, Table B-17 of the API Compendium provides component-level average fugitive emission factors (API, 2004). Refer to the API Compendium if this approach is used. If equipment counts are known (e.g., farm taps, reciprocating compressor units, etc.) but the fugitive component counts are unknown (e.g., connectors, control valves, etc.), then Table 4-12 of the 2005 INGAA guidance can be used to estimate the component counts using default component populations for common equipment.

VII.2.5 Screening-based Fugitive Emission Methodologies

A screening-based approach to emission estimation requires that a full leak detection program be conducted at the facility. This requires that all equipment and components with the potential for fugitive leaks are screened. Screening-based approaches are generally used for companies voluntarily opt into leak detection and repair (LDAR) or Directed Inspection and Maintenance (DI&M) programs.

The U.S. EPA Protocol for Equipment Leak Emission Estimates (EPA, 1995) provides a guidance for acceptable approaches for screening-based fugitive emission estimates. All of the screening-based methods require implementation of U.S. EPA Reference Method 21 – which uses an instrument such as an Organic Vapor Analyzer to “sniff” components and measure the hydrocarbon concentration of a leak. The leaks are then categorized based on the measured concentration.

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When using the screening range factor approach, the components should be grouped into “streams” where all the components have approximately the same TOC weight fraction and monitoring readings within the same category. The following equation is used in the calculations:

)N(F)N(FE LLGGTOC ×+×= (Equation 21)

where,

ETOC = Emission rate of TOC from all components of a given type in the stream. FG = Emission factor for components with screening values greater than or

equal to 10,000 ppmv NG = Number of components with screening values greater than or equal to

10,000 ppmv FL = Emission factor for components with screening values less than or equal

to 10,000 ppmv NL = Number of components with screening values less than or equal to

10,000 ppmv.

Methane emissions can be estimated from the TOC emission factors using Equation 20.

Leak/No-Leak and Stratified Fugitive Emission Factors

The screening range factor approach, also called the leak/no-leak approach, is based on monitoring data that have been categorized into two or more ranges. Monitoring data are broken down into standardized categories of “leakers” and “non-leakers” based on the concentration readings of the monitoring data resulting from EPA Method 21. Each of these categories is assigned an emission factor. Section B.3.2 of the API Compendium and Section 4.4.1 of the 2005 INGAA guidance discuss this approach. Table 4-6 of the 2005 INGAA guidance provides transmission segment leak/no-leak CH4 fugitive emission factors for various components (i.e., valves, connectors, etc.). Table 4-7 of INGAA provides three-stratum fugitive emission factors for gas transmission facilities on a component basis.

Correlation Equation Fugitive Emission Estimates

The correlation approach predicts the mass emission rate as a function of the screening value for a particular equipment type. As described in Section B.3.3 of the API Compendium, the screening value to leak rate correlations were developed based on data collected from petroleum industry units, including refineries, marketing terminals, and oil and gas production operations. The key difference between this approach and those previously discussed is that the user must estimate the emission rate for each component individually, rather than in large groups. This is generally only practical when the site maintains a specialized database that records Leak Detection and Repair (LDAR) activities and calculates the emission rates, although a facility with a few components

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could use a spreadsheet to estimate the emissions by the correlation approach. The specialized databases are common in refineries, but uncommon in other oil and gas industry facilities.

The correlation equations apply to the entire range of the analyzer used for monitoring. The form of the correlation is:

BTOC SVAE ×= (Equation 22)

where: ETOC = emission rate expressed as kg of TOC/hour A and B = constants developed in the correlation fitting SV = screening value in ppmv estimated according to US EPA Method 21

The correlation equations do not directly allow for estimating the emissions for components whose monitoring value is below the lower limit of detection of the analyzer (often called “default zero”) or above the upper limit of detection (often called “pegged”). Default zero and pegged emission factors are used for these types of readings as an adjunct to the correlation equations. These default zero or pegged emission factors are applied as in the following equation:

NFE ATOC ×= (Equation 23)

where, FA = the applicable default zero or pegged emission factor N = the number of components found to be default zeros or pegged

components

Tables B-22 through B-24 of the API Compendium provide EPA correlation approach equations for various fugitive components in the petroleum industry. Likewise, Table 4-8 of the 2005 INGAA guidance provides correlation equation parameters by component.

Unit-Specific Correlation Equation Fugitive Emission Estimates

It is also possible to develop unit-specific and/or site-specific correlations that can be used in the same manner as the petroleum industry correlation equations described earlier. As described in Section B.3.4 of the API Compendium, developing unit-specific correlations requires the collection of screening values and measured mass emissions for a subset of components from the subject process unit. These data must then be statistically analyzed to develop the correlation equations. An in-depth description of the Unit-Specific Correlation Approach may be found in the EPA Protocol for Equipment Leak Emission Estimates, Section 2.3.4 (EPA, 1995). This approach can be quite expensive. An existing unit-specific correlation (if available) may be used for the

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subject process, but it would seldom be justified to try to develop unit-specific correlations to support GHG emission estimates. Section 4.4.4 of the 2005 INGAA guidance also addresses unit-specific correlation equation emission estimates, and refers to the EPA leak protocol guidance as well.

VII.3 Other Fugitives

In addition to fugitive equipment leaks, there may be one or more of a variety of other non-point emission sources associated with oil and gas industry operations. These other non-point emission sources include wastewater treating, sludge/solids handling, impoundments, pits, and cooling towers. These emission sources will generally not be a significant source of CH4 or CO2 emissions and are not typically found in the NG T&D sectors; these emission sources are more typically found in refining. Therefore, detailed emissions estimation guidelines for these other fugitive emissions are not provided here and are also not described in the 2005 INGAA transmission/storage emissions guidance document. For more details on estimating these emissions, refer to Section 6.2 of the API Compendium (API, 2004).

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VIII. INDIRECT EMISSIONS Indirect emissions are emissions that are a consequence of the reporting entity, but are generated from sources owned or controlled by another entity (WRI/WBCSD Corporate Standard Scope 2 emissions). The indirect emissions that are of potential interest for transmission, storage, and distribution operations are from purchased electricity, purchased heat/steam, and purchased cooling water. These indirect emissions are described in more detail below.

INGAA’s natural gas transmission and storage guidance document and the 2006 IPCC Guidelines do not provide guidance for estimating indirect emissions (INGAA, 2005; IPCC, 2006). Section 1.4.2.3 of Volume 2 of the IPCC Guidelines refers to other guidance documents including the EMEP/CORINAIR Guidebook for estimating indirect emissions.

A key consideration with respect to purchased electricity is the availability of reliable usage records. Due to the geographic distribution of NG T&D operations, many (sometimes hundreds) of service providers may sell electricity to the company. Often accounting systems do not track the electricity consumption (kWhr or MWhr), and only track the dollar expenditures. Electric bills can often include expense that are not directly tied to the electric consumption, such as customer usage fees, taxes, voltage demand charges, and billing adjustments. In addition, the $/kWhr rate can vary significantly from one location to another due to fluctuations in fuel prices, variable demand charges, and negotiated rates. Without specific accounting for electricity consumption, determining the consumption from accounting charges is nearly impossible.

VIII.1 Purchased Electricity

Indirect emissions from purchased electricity use are described in Part II, Chapter 6 of the GRP. Certifiable emission factors specific to the source of the electricity should be used to estimate the indirect electricity usage emissions. In the absence of these source-specific emission factors, Chapter 6 of the GRP refers to default CO2, CH4, and N2O electricity emission factors in Tables C-1 and C-2. Table C-1 provides CO2 electricity emission factors by geographic regions in the U.S. and are taken from the U.S. EPA’s eGRID database. Table C-2 presents CH4 and N2O electricity emission factors by state for the years 2001 through 2003 and are based on emission factors provided by the U.S. Department of Energy (DOE).

The API Compendium (Section 4.7.1) also refers to eGRID. Table 4-12 of the API Compendium provides CO2, CH4, and N2O electricity emission factors by generation method. Table B-4 of the API Compendium also provides default CO2, CH4 and N2O emission factors by state taken from the U.S. DOE (same CH4 and N2O emission factors provided in the GRP). International electricity emission factors are provided in the API Compendium as well (Table 4-13). As noted previously,

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INGAA’s natural gas transmission and storage guidance document and the 2006 IPCC Guidelines do not include indirect emissions estimation guidance.

Consistent with the GRP and API Compendium, the WRI/WBCSD’s indirect CO2 emissions guidance document (in Section III.B) also refers to eGRID for electricity emission factors (WRI/WBCSD, 2005). The WRI/WBCSD’s companion spreadsheet tool, available on the WRI/WBCSD’s GHG Protocol Initiative web page, provides eGRID CO2 emission factors by U.S. geographical region and by year from 1996 through 2000. The emission factors for 2000 match the emission factors provided in Table C.1 of the GRP. The companion spreadsheet tool also provides international CO2 emission factors by country (including the United States). Note, however, that these emission factors include CO2 emissions resulting from fossil fuel combustion to generate both electricity and heat. Table 4-13 of the API Compendium provides international electricity emission factors that explicitly exclude fossil fuel emissions associated with heat generation.

For consistency purposes, Part II, Chapter 6 of the GRP should be followed to estimate indirect electricity usage emissions.

VIII.2 Purchased Heat/Steam

Indirect emissions from using purchased heat or steam are described in Section II.9.2 of the GRP, and this section should therefore be followed. The approach is very similar to the approach provided in Section 4.7.2 of the API Compendium, except that the GRP assumes a default boiler efficiency of 75%, while the API Compendium assumes 92% to estimate these indirect emissions. The GRP and API Compendium approaches address CO2, CH4, and N2O emissions. WRI/WBCSD’s indirect CO2 emissions guidance document covers purchased steam CO2 emissions (WRI/WBCSD, 2006). Section III.A of WRI/WBCSD’s guidance document recommends converting the steam thermal rate (e.g. Btu) to power units (e.g., kWh). WRI/WBCSD does not provide steam-specific emission factors in their indirect CO2 emissions guidance document, but it is implied that the electricity grid emission factors should be used.

VIII.3 Purchased Cooling Water

Indirect emissions from purchased district cooling water are described in Section II.9.3 of the GRP. Purchased district cooling water has indirect emissions due to the electricity or fossil fuel combustion used to drive the compressor system that produces the cooling. These emissions are not covered by the API Compendium. Refer to Section II.9.3 of the GRP to estimate these indirect cooling water emissions.

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IX. WHAT SHOULD BE REPORTED? IX.1 GHG emissions

Carbon dioxide (CO2) and methane (CH4) are the most signification GHG emissions for the NG T&D industry. Carbon dioxide is primarily emitted from combustion sources, but a small amount, generally less than 2% for pipeline applications, may also be present in the natural gas. Carbon dioxide is also formed as a result of the oxidation of CH4 leaked from buried sources due to microbes in the soil.

Methane is emitted when natural gas leaks from fugitive sources or when natural gas is vented during process operations, maintenance activities or emergency releases. Methane is also found in exhaust gases as a result of incomplete fuel combustion.

Nitrous oxide emissions will result from stationary and mobile combustion sources, but they are orders of magnitude lower than CO2 or CH4.. Air conditioning (mobile and stationary), refrigeration, and fire suppression equipment are sources of hydrofluorocarbons (HFCs) and perfluorocarbons (PFCs) emissions.

Sulfur hexafluoride (SF6) is most often used for circuit breaker applications electric power industry. However, pipeline companies may use SF6 as a tracer gas for leak detection.

IX.2 CO2-equivalent emissions

Calculating CO2 equivalent emissions is discussed in Part III, Chapter 6 of the GRP. This same approach applies to emissions from the NG T&D sector.

It should be noted that the 2006 IPCC Guidelines for National Greenhouse Inventories address the inclusion of carbon emitted from gases other than CO2, which result from the atmospheric oxidation of the carbon in CH4, CO, and NMVOC emissions. For the purpose of this protocol we recommend not including emissions from the oxidation of CH4, CO and NMVOC to form CO2 in entity inventories. There is significant uncertainty associated with addressing emissions from these sources and these indirect emissions are best addressed at the local level in response to local air quality concerns.

IX.3 De Minimis and Materiality considerations

The following table outlines potential de minimis emission sources that may apply to pipeline operations. Acceptable conservative calculation methods are provided in this section to assist pipeline companies in determining the mix of emission sources that may be defined as de minimis for their operations.

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Table IX-1. Potential de Minimis Emission Sources

Potential de Minimis Emission Source

Potential de Minims GHGs Comment

Stationary combustion sources

CH4 These are likely to be the largest of the de minimis sources. Refer to Section V.3.2 and V.3.3 for emission factors.

Stationary combustion sources

N2O Although these emissions are small, the same activity value used to estimate CH4 emissions applies to N2O, so it is generally a minimal effort to add in the N2O emissions. Refer to Section V.3.2 and V.3.3 for emission factors.

Mobile combustion sources CH4, N2O Refer to Section V.6 for emission factors. Flares CH4, N2O Refer to Section V.4 for emission factors. Process vents Fugitive sources

CO2 CO2 emissions can be calculated based on the total vented and fugitive CH4 emissions for a pipeline system or facility with a consistent gas composition. Refer to Section IV.1 for the emission calculation approach. Refer to Sections VI and VII for emission factors.

Purchased electricity CH4, N2O CH4 and N2O emissions are estimated using the same activity data (MWhr) as CO2. However, CH4 and N2O emission factors may correspond to a state or sub-region different than the CO2 emission factors. Refer to Section VIII.1 for guidance on estimating emissions

Purchase heat/steam and cooling water

CH4, N2O These energy streams are not commonly used for the NG T&D sector. Refer to Sections VIII.2 and VIII.3 for guidance on estimating emissions.

Fire extinguishers HFCs, PFCs Refer to Section VI.7 for guidance. Chillers Mobile air conditioning units Stationary refrigeration/AC

HFCs, PFCs The steps provided in Part III Chapter 11 of the GRP can be used to determine if HFC emissions from refrigeration and cooling units are de minimis.

Anaerobic wastewater treatment

CH4 Not generally associated with pipeline operations

Aerobic wastewater treatment

CO2 Any non-biogenic carbon treated in the wastewater system would be converted to CO2. However, emission estimation methods generally do not address CO2 emissions from aerobic wastewater treatment.

IX.4 Industry specific efficiency metrics

When reporting GHG emissions there are two principal quantities of interest, one is the absolute quantity of GHG emitted over the reporting period (the numerator) relative to some measure of output (the denominator) to enable tracking operational efficiency. Typically the measures of

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output are either expressed in monetary value, i.e. emissions per dollar of sales, or per physical unit of output such as tonnes, barrels, miles of pipeline, or kilowatt-hours.

The normalization of emissions facilitates tracking performance from year to year; enables comparisons of regional performance of similar business operations of a given entity; or comparisons of GHG operational efficiency among different companies in the same sector.

For the NG T&D sector it is not recommended to use the monetary value of the product as a normalizing factor. The product - being a commodity - is subject to potentially wide fluctuations that do not correlate with the GHG performance of operations. Hence for public reporting, gross normalization of emissions by output would be more appropriate. In order for the normalized emissions (i.e., Emissions Intensity) to provide the relevant information about emissions trends, one has to select appropriate output measures that are meaningful for the type of operation considered. Table IX-2 provides a preliminary list of examples of such normalization factors that could be useful for reporting and tracking operational efficiency for the NG T&D sector.

Table IX-2. Examples of Output Measures for Normalizing GHG Emissions for Entity Reporting

INDUSTRY SUBSECTOR OUTPUT MEASURE UNITS Pipeline transmission High-pressure pipeline traffic

in units of throughput (at standard conditions) and factoring distance

SBCF or MMBtu; SBCF-mile or MMBtu-mile;

Marine Vessels Cargo transported by type SBCF or MMBtu or tonnes;

Storage Volume stored (at standard conditions)

SBCF

Cargo Transport Cargo transported by type SBCF or MMBtu or tonnes Pipeline Distribution Volume distributed at low

pressure SBCF or MMBtu (Therms)

SBCF = standard billion cubic feet; 1 SBCF = 28.3168 Million m3

Therm = 100,000 BTUs ≅ 100 scf gas (assuming 1000 BTU/scf HHV) MMBtu = million British Thermal Units; 1 MMBtu Btu = 1.055056 GJ (Giga Joules)

All the metrics in Table IX-2 are constructed to track CO2 Equivalent (CO2Eq) emissions/MMBtu delivered to the customer. All of these metrics are designed to assess and compare the efficiency of transmitting and distributing the natural gas to customers, such as utilities, industrial and commercial facilities and residences. As part of the need to conserve resources, such as natural gas, Demand Side Management programs are becoming widespread in order to assist customers in increasing their end-use efficiency. For such programs, one could define additional metrics that

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would track User CO2Eq emissions/MMBtu delivered, or User CO2Eq emissions/operational activity index.

It is not the intent here to propose a definitive set of metrics, but rather to suggest some examples. In general, all metrics proposed would need to be carefully constructed in collaboration with industry sector representatives to ensure their practicality and industry access to the data that would be required.

IX.5 Other Optional Reporting

Other activities that a company may choose to report with their GHG inventory include:

• Purchases and sales of GHG emission reductions. A company may wish to report emissions associated with reduction activities. Ideally, these activities would be captured in the inventory. However, there is a possibility that the emission estimation methodologies used for the inventory are not sufficiently detailed to reflect the reduction activity. Note that the reductions should not be netted from the inventory total, but a company may choose to report them separately. At a minimum, the company should describe the reduction activity and report the quantity of emission reduction. It should be noted if the emission reductions were purchased or sold, and it should be noted if the reductions were reported to other registries and/or regulatory agencies.

• Contractual agreements assigning or limiting liability. Companies may have contractual arrangements that specifically address the ownership of GHG emissions. It would be useful to report information associated with any contractual agreements that assign ownership of emissions or limit liability associated with specific emissions, particularly where these agreements differ from commonly recognized organizational boundary approaches (i.e., equity share or operational control).

• Demand-side management. Natural gas demand-side management (DSM) programs reduce natural gas consumption by improving the energy efficiency of buildings, space heating systems, water heating, and other gas appliances. Similar to reporting other emission reduction activities, a company may wish to report emission reductions or efficiency improvements achieved through DSM programs. At a minimum, the company should describe the DSM program and report the quantity of emission reduction. It should be noted if the emission reductions were sold, and it should be noted if the reductions were reported to other registries and/or regulatory agencies.

• Technology or Process Improvements. Companies may want to highlight GHG emission reductions that are attributable to directed action taken by companies to improve energy efficiency. These actions could include: introduction of new processing technologies, substitution of existing signage with LEDs, use of efficient lighting fixtures, upgrading compressor engines, replacing low efficiency air

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conditioning systems, or similar. When reporting on such activities it is important to note whether those are continuous or discrete activities and if the resultant emission reductions were reported to other registries or regulatory agencies.

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X. CERTIFICATION This section provides guidance for reviewing and certifying the portions of an entity’s inventory that are significant or unique to the activities of NG T&D systems. These include:

• Stationary combustion emissions; • Indirect emissions associated with purchased electricity; • Methane emissions from process vents; and • Methane emissions from fugitive sources.

For activities not unique to natural gas pipeline systems, certification guidance is provided in the General Reporting and Certification Protocols available through the Registry.

X.1 Documents and Information to Review

The following table provides examples of documentation and sources of information that may be useful forconfirming that gas pipeline entity GHG emissions have been reported accurately. The sources listed in Table X-1 are intended to provide guidance on the type of documentation that may be available to support GHG reporting; it is not intended to imply that all of these sources should be available.

Table X-1 Sources of Documentation

Activity or Emission Source Documents Step 1: Identify Emission Sources Emission Source Inventory CARROT Report

Facility inventory List of permitted equipment Facility plot plans or process flow diagrams Fuel purchase records by fuel type Risk management plan

Organizational, Operational, and Geographic Boundaries

Security and Exchange Commission (SEC) Form 10K Corporate Annual Reports Regulated versus non-regulated system information Information available on entity web GIS reports/map of operations List of contracted activities

Step 2: Understand Management Systems and Methodologies Data Management Systems Location of data collection systems (centralized or

decentralized) Type of management system and parameters tracked Data acquisition and handling system

Responsibilities and Management

Entity organization chart Documentation and Retention Plan

Training Training Manual Operator Qualification Manual

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Activity or Emission Source Documents Procedures Manual

Methodologies Company GHG Protocol Other protocols or emission factors used (in addition to the

GRP) Meter calibration procedures Quality Assurance/Quality Control plans

Step 3: Verifying Emission Estimates Direct emissions from stationary combustion

Master/central meter volumes Fuel meter calibration and maintenance records Gas analyses Fuel purchase records Fuel in stock Operating hours and equipment ratings (for non-metered

equipment) Flare records (volumes, gas composition)

Direct emissions from mobile combustion sources

Fuel purchase records Fuel in stock Vehicle miles traveled Inventory of vehicles

Direct emissions from process vents

Gas throughput data Pipeline maintenance records Station maintenance records Compressor maintenance records Pipeline and Hazardous Materials Administration

(PHMSA) pipeline incidents reporting form Lost and unaccounted for records Dehydration volume Inventory of pneumatic devices

Direct emissions from fugitive sources

Leak detection and repair program records Lost and unaccounted for records Wastewater treatment records (COD, BOD, volumes) Station and equipment counts Pipeline length (by pipe material) Service length (by pipe type)

Direct fugitive (or venting) emissions from air conditioning and refrigeration systems (stationary and mobile)

Refrigerant purchase records Maintenance records for refrigerant equipment Refrigerant exchanges, sales or recycle records

Direct fugitive (or venting) emissions from fire suppression equipment

Fire suppression purchase records Fire drill training records Fire extinguisher exchanges or recycle records

Indirect emissions from purchased electricity, heat, or steam

Monthly utility bills Fuel and efficiency data from suppliers (if available) Emission factors (if not default)

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X.1.1 Reviewing Documentation

The natural gas pipeline sector already reports information on entity-level assets, operations, financial, and emissions data to state and federal agencies, including FERC, PHMSA, EPA, SEC, and AQMD filings. These reports are audited and verified by the receiving agencies. Natural gas pipeline companies may have also undergone third party review of their GHG inventory through voluntary corporate initiatives or participation in voluntary registry programs. Certifiers can accept that data taken from previously audited or certified reports are correct. However, certifiers should verify that data has been transferred into the CARROT correctly, and that meters and sensors used to collect the data reported to these agencies are properly maintained and functioning.

X.1.2 Questions to Consider in Verifying Emissions Estimates

Does the frequency of gas composition measurements reflect the variability of the gas composition?

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XI. OTHER INFORMATION XI.1 Managing Inventory Quality

A quality assurance process is a fundamental component of a reliable GHG inventory. Quality assurance/quality control (QA/QC) procedures should be designed to identify weaknesses and sources of error or uncertainty in data and management systems, implement procedures to reduce uncertainty, and improve the overall quality of the data and reliance that stakeholders can place on it.

Key components of an effective quality assurance process are:

• A QA/QC organizational structure with clearly defined roles and responsibilities; • Personnel training to ensure a clear understanding of the importance of reliable GHG

data, compliance with any internal and/or external GHG inventory protocol(s), and understanding of company quality assurance process and specific activities;

• Periodic internal technical review of the quantification methodologies, data inputs, unit conversions, and data processing steps.

• Periodic internal audits aligned with the corporate QA/QC process; • Review and benchmarking of intensity ratios and year-on-year data trends; and • Documentation of any problems identified, recommendations for corrective action,

and implementation results.

The following table provides a list of activities supporting GHG data quality management.

Table XI-1 General Quality Management Actions

Control Level Quality Management Actions Establish clear roles and responsibilities for the accounting and reporting of GHG emissions at the entity, Business Unit, and corporate levels Adequately train responsible persons to understand and implement the inventory protocol Implement and maintain management systems to aid in the consistent application of the inventory protocol Periodically assess compliance with the protocol and its consistent implementation across the entity by internal audits and technical reviews, and supported by external verification, to identify areas of improvement

Management Controls

Implement adequate controls (i.e., review and check procedures) over reported GHG data at the corporate, entity and facility levels Maintain a copy of data inputs and documentation on the source of information

Entity Level Controls

Confirm that any new emission sources are added to the inventory, and any emission sources that are no longer relevant are not included. Refer to WRI/WBCSD GHG Protocol guidance on acquisitions and divestitures, and baseline adjustments

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Control Level Quality Management Actions Document changes in data or methodology, along with rationale for the change, consistent with appropriate change management procedures Check a sample of input data for transcription and other sources of errors Confirm that the methodologies used to quantify emissions from the most significant sources are appropriate and accurate Confirm that activity data units of measure are consistent with data inputs and corresponding emission factors Confirm that key source data (e.g., fuel flow rates, fuel composition, gas composition) are supported by appropriate monitoring and calibration. Confirm that highly variable, site-specific data, such as fuel composition, is updated on an appropriate frequency Ensure clear understanding of uncertainties associated with emission estimation methodologies and source data; Continuous improvement should strive to minimize uncertainties for the most significant sources Document assumptions and criteria for selecting methods, activity data, emission factors, and other parameters Ensure that personnel training, communications, and change management procedures are implemented Ensure that copies of cited reference data have been archived Ensure that adequate version control procedures for any written methodologies or electronic files have been implemented Identify GHG inventory process modifications or improvements that could provide additional controls or checks on quality Check that entity boundaries and status of control and ownership are correct Review GHG estimates for the current reporting period against historical performance and forecasts

Corporate level controls

Perform periodic reviews and updates, as necessary, of internal GHG protocols and procedures to ensure continued appropriateness Confirm that bibliographical data references are included in any calculation tools and documentation (i.e., emission factors, activity data, calculation algorithms, and assumptions involved in estimating material GHG emissions) Ensure that adequate version control procedures for any written methodologies or electronic files have been implemented Check that conversion factors are correct Check all data processing steps for errors (e.g., data inputs, equations, calculated results, and reported data). Check that input data and calculated data are clearly differentiated Check a representative sample of calculations for accuracy

Data Management controls

Check the aggregation of data across source categories, business units, etc.

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XI.2 Key Terms BTU British thermal unit, a measure of the energy content of a fuel. The heat required raising the temperature of one pound of water by one degree Fahrenheit at a specified temperature and pressure. Approximately 1,027 BTUs equal one cubic foot of natural gas. Baseline A hypothetical scenario for what GHG emissions, removals or storage would have been in the absence of the GHG project or project activity. Base year A historic datum (a specific year or an average over multiple years) against which a company’s emissions are tracked over time. City-Gate The point at which the local distribution system connects to the natural gas transmission pipeline is known as the city gate. At the city gate the gas pressure is lowered to allow for distribution. The local distributor (a.k.a. gas utilities) then adds a sour-smelling odorant to the gas to help users detect even small quantities of leaking gas. Common Carrier Transporter required by law to provide service to all legitimate comers. Oil pipelines are common carriers, while gas pipelines are contract carriers. Contract Carrier Transporter, such as a gas pipeline, that provides its service on a contractual basis for other parties, as opposed to a common carrier. Custody-transfer The transfer of natural gas after processing and/or treatment in the production operations to pipelines or any other forms of transportation. Liquefied natural gas (LNG) Liquefied natural gas is natural gas or synthetic gas having methane (CH4) as its major constituent, which has been changed to a liquid by reducing the temperature to minus 260 degrees Fahrenheit. Liquefied Natural Gas facility A liquefied natural gas facility is a facility that is used for liquefying natural gas or synthetic gas or transferring, storing, or vaporizing liquefied natural gas.

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Liquefied Petroleum Gas (LPG) A gas containing certain specific hydrocarbons that are gaseous under normal atmospheric conditions but can be liquefied under moderate pressure at normal temperatures. Propane and butane are the principal examples. Local Distribution Company (LDC) Company engaged primarily in the purchase of natural gas for resale and distribution to end-users. Natural Gas Naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in porous geologic formations. The primary component is methane. Natural gas distribution Natural gas is delivered to its end-use customers via local distribution companies. These companies operate and service a network of distribution piping that is located downstream of the natural gas transmission line. Distribution networks serve individual residences, commercial buildings, etc. Local natural gas distribution pipelines are usually smaller in diameter than natural gas transmission pipelines and many are constructed out of plastic rather than steel. They consist of mains and smaller service lines that are normally installed underground, usually along or under streets and roadways. In the U.S., the pipeline safety regulations define distribution lines as pipelines other than ‘gathering’ or ‘transmission’ lines. Natural gas liquids (NGL) Hydrocarbon components of wet gas. Natural gasoline and liquefied petroleum gases fall in this category. Natural Gas Storage Natural gas may be temporarily removed from the transmission pipeline system and stored, and then later re-injected into the pipeline system. Storage serves several purposes: maximize the use of the system capacity year-around, and create additional flexibility in operation of the pipeline system. Many gas storage fields are depleted gas reservoirs, while others were created by leaching underground caverns in salt domes. Another way to store natural gas is to convert the gas to a liquid, commonly known as liquefied natural gas or LNG, and store the liquid in aboveground tanks. Natural gas transmission Natural gas transmission pipeline systems are often referred to as the "interstate highways" for natural gas transportation. They are generally the middle transportation link between gathering systems and storage and distribution systems. They transport large volumes of natural gas exiting the processing and treatment facilities, through thousands of miles of pipeline, to other areas

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where it is provided to direct-served customers (e.g., electric power generating stations) or to local distribution companies. North American Industry Classification System (NAICS) The North American Industry Classification System (NAICS) has replaced the U.S. Standard Industrial Classification (SIC) system. NAICS was developed jointly by the U.S., Canada, and Mexico to provide new comparability in statistics about business activity across North America. Unaccounted for gas The difference between the total gas available from all sources and the total gas accounted for as sales, net interchange and company use. This difference includes leakage or other actual losses, discrepancies due to meter inaccuracies, variations of temperature and/or pressure, and other variants, particularly due to measurements being made at different times and billing lags. (AGA, 1996) Tariff Schedule describing the different terms, conditions and rates for different gas services offered by a gas company.

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XII. REFERENCES American Gas Association (AGA). Glossary for the Gas Industry, Sixth Edition, 1996. American Petroleum Institute (API). Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry, API, Washington, DC, 2004. Errata, February, 2005. http://www.api.org/ehs/climate/new/upload/2004_COMPENDIUM.pdfhttp://ghg.api.org/documents/CompendiumErrata205.pdf Asociacion Regional De Empresas De Petroleo Y Gas Natural EN LatinoAmerica Y El Caribe (ARPEL). Atmospheric Emissions Inventories Methodologies in the Petroleum Industry. ARPEL Guideline # ARPELCIDA02AEGUI2298, Prepared by Jaques Whitford Environment Limited, December 1998. http://wps.arpel.org/wps/portal California Climate Action Registry. General Reporting Protocol, Reporting Entity-Wide Greenhouse Gas Emissions, Version 2.1, June 2006. California Climate Action Registry. Appendix to the General Reporting Protocol: Power/Utility Reporting Protocol, Reporting Entity-Wide Greenhouse Gas Emissions Produced by Electric Power Generators and Electric Utilities, Version 1.0, April 205. California Energy Commission. Inventory of California Greenhouse Gas Emissions and Sinks: 1990-1999, California Energy Commission, 2002. Campbell, L.M. and M. Gundappa. Characterization of Emissions from Oil and Gas Production Combustion Units, Draft Report, American Petroleum Institute, July 1999. http://global.ihs.com Campbell, L.M., M.V. Campbell, and D.L. Epperson. Methane Emissions from the Natural Gas Industry, Volume 9: Underground Pipelines, Final Report, GRI-94/0257.26 and EPA-600/R-96-080i. Gas Research Institute and U.S. Environmental Protection Agency, June 1996. (Part of the GRI/EPA methane emissions inventory project.) http://www.epa.gov/gasstar/reports.htm Canadian Association of Petroleum Producers (CAPP). Calculating Greenhouse Gas Emissions, Guide, Canadian Association of Petroleum Producers, Publication Number 2003-0003, April 2003. (Cited Table 1-5 for physical property data and Table 1-12 for pneumatic device and chemical injection pump emission factors). http://www.capp.ca Canadian Association of Petroleum Producers (CAPP), Estimation of Flaring and Venting Volumes from Upstream Oil and Gas Facilities, Guide, Canadian Association of Petroleum Producers, Publication Number 2002-0009, May 2002. (Cited Table 3-4 for pneumatic controller and chemical injection pump emission factors). http://www.capp.ca CRC Press, Inc. CRC Handbook of Chemistry and Physics, 65th Edition, 1984. www.crcpress.com

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http://www.api.org/ehs/climate/new/upload/2004_COMPENDIUM.pdf

http://ghg.api.org/documents/CompendiumErrata205.pdf

http://www.epa.gov/gasstar/reports.htm

http://www.capp.ca/

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