Emission Reduction in the Natural Gas Sector Through Project Based Mechanisms

EMISSION REDUCTIONS IN THENATURAL GAS SECTOR THROUGH

PROJECT-BASED MECHANISMS

international energy agencyagence internationale de lenergie

IEA INFORMATION PAPER2003

Emission Reductions in the Natural Gas Sectorthrough Project-Based Mechanisms

2ACKNOWLEDGEMENTS

This paper was prepared by Lisa Hanle while on an assignment to the International Energy Agency.The author is especially grateful to Jonathan Pershing and Martina Bosi (IEA) who provided guidanceand overall direction for the paper. In addition, Jonathan Pershing provided valuable insight on thepetroleum industry while Martina Bosis extensive knowledge of project-based mechanisms wasinvaluable throughout the drafting of this paper. The author would also like to thank several otherindividuals for their input on natural gas issues, including among others, Ralf Dickel, Sylvie Cornot-Gandolphe, Paul Gunning and John Shinn. Finally, the author would like to thank all of the reviewersof earlier drafts of this report.

Questions and comments should be sent to:

Ms. Martina BosiAdministrator, Energy and Environment DivisionInternational Energy Agency9, rue de la Fdration75015 Paris, FRANCEE-mail: [email protected]: (33 1) 40 57 67 39IEA website: http://www.iea.org

3TABLE OF CONTENTS

EXECUTIVE SUMMARY...................................................................................................................... 5

INTRODUCTION.................................................................................................................................. 12

SECTION 1: OVERVIEW OF THE UPSTREAM AND MIDSTREAM NATURAL GASINDUSTRY AND GREENHOUSE GAS EMISSIONS...................................................................... 15

OVERVIEW OF THE SECTOR ...................................................................................................................................15Extraction/Production......................................................................................................................................15Natural Gas Processing ...................................................................................................................................15Transmission ....................................................................................................................................................16Storage .............................................................................................................................................................17Distribution ......................................................................................................................................................18

GREENHOUSE GAS EMISSIONS FROM THE MIDSTREAM AND UPSTREAM NATURAL GAS SYSTEMS.......................18General Overview of Sector Emissions ............................................................................................................18Global Estimates of CO2 and CH4 emissions ...................................................................................................19

SECTION II: TECHNOLOGICAL OPTIONS AND OPPORTUNITIES FOR REDUCINGEMISSIONS ........................................................................................................................................... 31

REDUCTION POTENTIAL ........................................................................................................................................31Reducing Fugitive Methane Emissions ............................................................................................................32Reduction of Flaring ........................................................................................................................................35Improving Energy Efficiency............................................................................................................................36

SECTION III: PROJECT-BASED ACTIVITIES IN THE MIDSTREAM AND UPSTREAMNATURAL GAS INDUSTRY............................................................................................................... 38

CDM/JI Baselines: Conclusions Reached at COP 7........................................................................................38Baseline Construction ......................................................................................................................................39Aggregation......................................................................................................................................................41Key Underlying Assumptions ...........................................................................................................................44Units for Emission Baselines............................................................................................................................46Project Boundaries...........................................................................................................................................48Data Issues .......................................................................................................................................................50Crediting Lifetime ............................................................................................................................................56

SECTION IV: BASELINE DEVELOPMENT: DECISION TREES ............................................... 59DECISION TREE: FUGITIVE EMISSIONS REDUCTIONS.............................................................................................60DECISION TREE: FLARING REDUCTION/ELIMINATION PROJECTS ..........................................................................71DECISION TREE: ENERGY EFFICIENCY PROJECTS: COMPRESSORS ........................................................................85ADDITIONALITY AND THE NATURAL GAS INDUSTRY ........................................................................................90MONITORING....................................................................................................................................................92

SECTION V: POTENTIAL ECONOMIC VALUE OF PROJECT-BASED ACTIVITIES......... 96DISCUSSION: SHOULD OTHERWISE PROFITABLE PROJECTS BENEFIT FROM CARBON CREDITS? ...............................99

SECTION VI: POLICIES TO SUPPORT THE IMPLEMENTATION OF PROJECT-BASEDACTIVITIES ........................................................................................................................................ 102

Barriers to Investment in the Midstream and Upstream Natural Gas Industry .............................................102Role of Stakeholders.......................................................................................................................................106

SECTION VII: CONCLUSIONS....................................................................................................... 108STANDARDIZATION OF BASELINES.......................................................................................................................108FUGITIVE EMISSIONS REDUCTIONS PROJECTS .....................................................................................................108FLARING REDUCTION/ELIMINATION PROJECTS ....................................................................................................109ENERGY EFFICIENCY PROJECTS ..........................................................................................................................109

4APPENDIX I: INCREASED USE OF NATURAL GAS AS PART OF A PORTFOLIO FORADDRESSING CLIMATE CHANGE............................................................................................... 111

WHAT IS NATURAL GAS?.....................................................................................................................................111NATURAL GAS: PART OF THE SOLUTION TO ENVIRONMENTAL CHALLENGES ..............................................112

Natural Gas as an Environmental Option......................................................................................................112Natural Gas as an Economic Option .............................................................................................................114Natural Gas for Energy Security Reasons......................................................................................................115Environmental Concerns Associated with Natural Gas Production and Consumption .................................115

APPENDIX II: WORLD GAS MARKETS...................................................................................... 118CENTERS OF SUPPLY AND DEMAND IN WORLD GAS MARKETS ..........................................................................118

Global Gas Demand.......................................................................................................................................118Global Gas Supply .........................................................................................................................................119Development of Regional Markets .................................................................................................................122

APPENDIX III: SELECTED BACKGROUND DATA FOR BASELINES DEVELOPMENT . 124

APPENDIX IV: ESTIMATED HORSEPOWER REQUIREMENTS FOR GREENFIELDPROJECTS .......................................................................................................................................... 126

GLOSSARY.......................................................................................................................................... 127

ABBREVIATIONS .............................................................................................................................. 129

CONVERSIONS .................................................................................................................................. 130

REFERENCES..................................................................................................................................... 131

5EXECUTIVE SUMMARY

This case study builds on earlier emissions baseline work completed by the International EnergyAgency (IEA) and the Organisation for Economic Co-operation and Development (OECD), largelyundertaken on behalf of the Annex I Experts Group. Previous studies examined the issues that need tobe considered in standardising greenhouse gas emissions baselines for electricity generation, energyefficiency, cement and iron and steel projects, as well as forest-related sinks projects. This studylooks in depth at the midstream and upstream natural gas industry, examining various project types,the potential for emissions reductions, and options that may be considered in developing baselines inthis sector.

The World Energy Outlook (IEA, 2002) projects a continued rise in the demand for natural gas atleast through 2030. A combination of cost, convenience, and environmental benefits are promotingits use. Gas-fired power generation is often the least cost option for new electricity generation. Andin a world where environmental concerns are gaining increasing resonance, natural gas has theadvantage of being less carbon intensive and producing fewer criteria air pollutants, such as sulphurdioxide and nitrous oxide, than other fossil fuels. Even with such rapid growth, natural gas reserves,currently estimated at over twice world cumulative production, are expected to be more than sufficientto meet this demand.

While significantly cleaner than other fossil fuels, the production and consumption of natural gasdoes, nevertheless, result in emissions of greenhouse gases (GHGs). This study examines the GHGemissions associated with natural gas production, specifically in the midstream and upstreamsegments of the industry (i.e., extraction/production, processing, transmission and storage, anddistribution). To do so, it draws on the considerable volume of material available on the natural gassector, both from academic and industry studies, as well as on the GHG mitigation activities alreadyundertaken in the midstream and upstream natural gas industry. This study consolidates many of thelessons learned, and in so doing, seeks to assist future project developers in carrying out creditableproject activities.

One of the rationales for this study is the potential for emissions reductions projects to generateemission credits for reductions efforts either under the international auspices of the Kyoto Protocol(through its Clean Development Mechanism, or Joint Implementation), or through nationalprogrammes seeking to reduce emissions. In order to generate credits, a projects GHG performanceis typically compared against an emissions baseline representing the best estimate for what wouldhave occurred in the absence of the project; the difference between this baseline and the actual projectemissions levels represents the projects emission reductions. Thus, the determination of the emissionbaseline is critical for assessing a projects GHG reductions and associated emission credits. Thisstudy seeks to provide insights on the development of emission baselines for GHG mitigation projectsin the natural gas sector.

While the GHG emissions statistics from the midstream and upstream natural gas industry have arather high degree of uncertainty associated with them, current data suggest that global emissions ofmethane from the production and use of oil and gas are between 30-70 million metric tons per year(MMt) (IPCC, 1996). Russia and countries of the former Soviet Union account for approximately 55per cent of these emissions (Gale and Freund, 2000). Carbon dioxide (CO2) statistics are considered

6more accurate than those of methane (CH4): the IEA estimates that world-wide CO2 emissions fromthe production and use of natural gas totalled 4,690 million metric tons of CO2 in 2000 (IEA 2002a).

The relative importance of emissions from the various sub-sectors of the midstream and upstreamnatural gas industry (exploration, production, processing, transmission, storage and distribution)differs among countries. For example, in Nigeria and Venezuela, exploration and production,specifically flaring1, is a more significant source of emissions, while in the United States and Russia,the gas transmission system (and specifically compression of gas for pipelines) is a relatively moresignificant source of emissions.

This study analyses the major sources of emissions in this sector, and explores three project types foremissions mitigation: fugitive emissions reduction projects, projects to reduce/eliminate flaring, andprojects to improve the energy efficiency of compressors2. A comprehensive data source does notexist for any of these project categories, as few studies have been completed to date and associatedstatistics have generally not been collected. However, some data does exist:

For fugitive emissions reduction projects, limited studies have been carried out in NorthAmerica, Russia, and Europe, and some regional-based conclusions have been drawn. Inaddition, some countries report fugitive emissions from the oil and gas industry in theNational Communications they submit under the United Nations Framework Conventionon Climate Change;

Concerning flaring, Cedigaz, an international association dedicated to providing naturalgas information, reports flaring information submitted by governments or companies.However, data is not listed in their reports for Russia or China;

While compressors are a significant source of emissions in transmission, LNG andstorage facilities, few energy audits have been carried out to determine baselineefficiencies.

Despite the lack of a comprehensive set of data, it does seem clear that this sector provides a host ofopportunities for emissions reductions projects, and as such, it is valuable to explore the developmentof baselines methodologies that are environmentally credible and that enhance the degree oftransparency and certainty with respect to the potential emission credits resulting from GHGmitigation project activities, while maintaining adequate incentives to undertake projects.

However, the scarcity of data does limit the options for developing standardised baselines (i.e. defaultbaseline emission levels). Instead, and as with baselines in other areas (e.g., energy efficiency), it isrecommended that a standardised methodology be followed in developing the baseline emission level.A standardised baseline methodology would provide project participants with a reasonable guideregarding the information that must be collected in defining a project baseline, and some certainty tothe project developer regarding project transaction costs3, thus making investment in these emission

1 This study includes flaring in the upstream oil industry only as it pertains to the production of associated gas.2 Throughout this study, the word compressor is used to refer to the whole gas compression package,including the driver, either a gas/diesel engine or gas turbine.3 The term transaction costs refers, here, to the costs associated with the process to generate emission credits,and not to the more general transaction costs associated with doing normal business.

7reduction opportunities potentially more attractive. Standardisation in the baseline developmentprocess also promotes consistency in the evaluation of GHG mitigation projects. The baselinemethodologies outlined in this paper attempt to take into account all these factors.

Several factors are assessed, including, whether to use historical or projected data in setting abaseline; how and where to draw boundaries around projects to insure that appropriate account istaken of linkages between action in one area and consequences up- or down-stream; what unit to usein assessing reductions (e.g., CO2 emissions, or CO2/MWh); whether or not to treat greenfieldprojects differently from brown-field projects; how to evaluate projects with respect to additionality(i.e., emissions reductions are additional to any that would occur in the absence of the projectactivity); and issues related to emissions monitoring and project measurement. The assessment andrecommendations for these various issues are briefly described in Box ES-1 below.

Box ES-1. Summary of Assessment and Recommendations

Methodological Issue Assessment/Recommendations

Data While there are a number of advantages and disadvantages to bothhistorical and projection data sets, the use of historical data isrecommended for setting baselines. Historical data is preferredbecause of the reduced potential to game the system and use anoverly lenient baseline, and because of the increased uncertaintyassociated with projection data

The use of default data may assist developers in baseline development,while maintaining environmental integrity and minimising transactioncosts. This paper outlines some default values that may be usedinitially to develop baselines for fugitive emissions reductions projects.

As more detailed data becomes available over time, it may beimportant to review and re-evaluate baseline construction guidance fornatural gas project activities.

Project boundaries From the time natural gas is extracted from a well to the time it reachesa consumer, it is contained in and conveyed through a closed system.Because of the closed nature of the system, defining the projectboundary is key. Depending on the project type, there are a number ofoptions for determining the boundary:

For flaring projects, the project boundary could include just theflare itself, or, in some cases, may be extended to the locationdownstream where the gas is consumed;

Project boundaries for activities to reduce fugitive emissions mayinclude one pneumatic device, or could be extended to include afull pipeline segment;

Projects to improve energy efficiency might include a string of sixdifferent compression stations, or could focus on a single highlyinefficient technology.

Because there are a number of options, a set of criteria is proposed thata project developer could use to establish the project boundary, ratherthan a specific boundary for each project type

8Baseline Units Different project types in the midstream/upstream natural gas industrymay require different baseline units:

Projects to enhance the energy efficiency of technologies andprojects to reduce flaring could have baselines expressed as a functionof output (ie.tCO2e/MWh) and as a function of throughput (i.e.tCO2e/Mcm) respectively;

Similarly, some projects to reduce fugitive CH4 emissions can beexpressed by emissions as a percentage of throughput, such as methanelosses in production and processing activities (m3 CH4 leaked duringgas processing/ m3 total gas processed), and leakage in LNG plants;

Projects to reduce fugitive emissions from transmission anddistribution lines may be better represented as a function of distance(tCO2e /km/year).

Additionality A multitude of factors affect the decision to invest in a gas project,and irrefutable proof that emissions reductions from a singlenatural gas project activity is additional to what emissions wouldhave been in the absence of a certified project activity is difficult,if not impossible.

It might be more straightforward for project proponents to developtheir case and argue that a retrofit project is additional to whatwould have occurred otherwise, than that a greenfield project isadditional.

The baseline options outlined in this paper attempt to take uncertaintyinto account through the use of conservative assumptions, often placingthe onus on the project participant to show why their project isadditional.

Monitoring Several options are available for monitoring fugitive emissionsfrom natural gas systems, including Toxic Vapour Analyzers, Hi-Flow Samplers and rotameters.

For flaring projects, monitoring technologies include mass balancecalculations, photogrammetry, and the use of flowmeters.

Energy-efficiency improvements can be measured with fuel metersinstalled in the compressor units to monitor fuel consumption.None of these monitoring technologies would be consideredcommon practice today.

9Box ES-2. Fugitive Emission-Reduction ProjectsEstablishing baselines and using emissions factors

Six proposals for setting baselines for projects to reduce fugitive emissions are assessed. Five of theseare based on already identified emissions factors for various components of the sector. Thesemethodologies differ in the type of data that needs to be collected in order to use the emissions factor.

(1) The first option uses the results of a study by the International Gas Union that produced low,medium and high emissions factors for different sub-sectors of the natural gas system.

(2) The second and third options rely on emissions factors developed by the IPCC.

(3) The fourth option utilises emissions factors that were developed for individual technologycomponents, and the fifth option streamlines the technology specific option by assuming that thereare an average number of components in the major technologies (for example, compressors anddehydrators).

(4) The sixth alternative is fundamentally different in that it requires site-specific assessments todetermine emissions factors.

Treatment of greenfield and brownfield projects

A distinction has been made between fugitive emission reduction projects carried out on infrastructureseven years or older and projects carried out on newer infrastructure (including greenfield), based on thenotion that default values derived from studies using older infrastructure may not represent theemissions resulting from more recent technologies.

Figure ES-1. Decision Tree for Project Developers interested in undertaking a FugitiveEmissions Reductions Project

Fugitive Emissions

Is project based on infrastructure7 years or older?

YESNO

Opt

ion

s

1. Use IGU default values, or

2. IPCC Tier 1 Method (2000, based on NA), or3. IPCC Tier 1 Method (1996, Regional), or4. Technology Specific, or

5. Generic Fitting Count, or

6. Do rigorous bottom-up analysis

Is a data set available fromsimilar project activities

undertaken in the last 7 years

NO YES

Options are the same as 1-6 above forprojects based on older infrastructure, exceptoption 1 would be slightly modified by usingdiscounted IGU default values.

Options1. Use recent set ofdata

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Box ES-3. Flaring Reduction Projects

Distinguishing between brownfield and greenfield projects:

An initial determination must be made as to whether the project developer is seeking credit for upstream(i.e., at the flaring site) or downstream emissions reductions (i.e., displacing coal consumption inelectricity generation), or both.

If the project boundary includes only the upstream portion, the major distinction is whether the projecttakes place at an existing facility or is a greenfield project.

Establishing baselines:

Baseline development for existing projects may be more straightforward than for greenfield projects,where collection of information related to flow rate, gas composition and wind velocity may be moresubjective.

Three options which may not be mutually exclusive - are outlined for greenfield flaring reductionprojects: (1) A baseline reflecting GHG emissions as a function of total associated gas produced in thecountry, (2) Automatic qualification/ disqualification for certain project types; and (3) A more bottom-up methodology requiring project developer justification as to why his particular field would, or wouldnot have, flared in the absence of a registered project activity.

Figure ES-2. Decision Tree for Project Developers interested in undertaking a FlaringReduction/Flaring Elimination Project Activity

Flaring ReductionProjects

Does project lead to emissions reductions in1. downstream use of gas2. upstream reduction of greenhouse gas emissions.

Downstream Upstream

Use Electricity Sectorbaseline recommendations NO YES

Is project based on existingflaring site?

1. Determine Flow Rate, and2. Determine CombustionEfficiency. (To accomplish,determine gas composition and awind categorization for the site ORassume a 99.5 per cent combustionefficiency)

1. Baselines are determined by greenhouse gas emissionsfrom flaring as a function of total oil production and thegas to oil ratio, using appropriate data from the last 7years.

2. Immediate qualification/disqualification of certainflaring reduction projects as credit-worthy3. Qualitative project-specific assessment of what wouldhave happened otherwise.

Opt

ion

s

Retrofit Greenfield

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Box ES-4. Efficiency Improvement Projects

Distinguishing between brownfield and greenfield projects:

Need to distinguish between (1) projects designed to reduce emissions at an existing facility; and (2)greenfield projects.

Establishing baselines:

For retrofit-type projects, project proponents should be required to collect the following information: Operating hours per year; Power Output (max kW); Design Fuel Usage (MJ/kWh); Load Factor (kW used/max kW); IPCC Emissions Factors for Fuel.

The same information would be required for greenfield projects. Where data is not available for recentenergy-efficiency improvement projects in the country or region, some conservative default valuesshould be assumed.

Figure ES-3. Decision Tree for Project Developers interested in undertaking a CompressorEnergy-Efficiency Improvement Project Activity

Energy Efficiency Projects: CompressorsIs project designed to improve efficiency in anexisting facility or a new facility (greenfield)?

Existing facility Greenfield

1 Where fuel gas meters are available, determinefuel gas usage and convert to emissions, or

2: Gather the following pieces of data fortechnology(ies) within the project boundaryOperating hours per year

Power Output (max kW)Design Fuel Usage (MJ/kWh)Load Factor (kW used/max kW)IPCC Emissions Factors for Fuel

The same pieces of informationwould have to be collected as in thecase of a project designed to improveefficiency of an existing facility.

Instead of collecting information foran existing facility, better thanaveragevalues should be concludedfrom a most recent set of data, wherepossible.

Opt

ions

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INTRODUCTION

According to the World Energy Outlook 2002, world primary gas demand is expected to continueincreasing steadily by an average of 2.4 per cent per year until 2030. The projected increase indemand for natural gas around the world will require increased capacity. This increased capacity cancome from existing transmission systems, where excess capacity is still available. Where capacity isnot available, pipelines and liquefaction and re-gasification terminals will have to be constructed tomeet the burgeoning demand.

Aware of the demand trends, companies in Indonesia, Malaysia and Brunei Darussalam continue toinvestigate the opportunities for producing and exporting liquefied natural gas (LNG) to Japan, SouthKorea, Taiwan and other potential buyers. Construction of the Yamal-Europe pipeline betweenRussia and Western Europe is underway, while discussions have already begun between Russia andinterested parties in Western and Eastern Europe concerning the possibility of constructing an inter-system connection between the Yamal Europe pipeline and an existing trunk system within Slovakia.In the Southern Cone of South America, where natural gas demand is expected to double betweennow and 2010, Bolivia, where large reserves are located, is emerging as a natural gas hub for theregion. Qatar and other Middle East and North African countries recognise the potential for increasedexports of LNG to a market in the United States poised to continue increasing its natural gas demand.

This dynamic and growing market coincides with a growing international concern about increasedcarbon emissions. Natural gas can pose an attractive option for countries forecasting increased energydemand in a carbon-constrained world; its emissions are 25 per cent below oil per unit of energyproduced, and 40 per cent below coal. However, while natural gas is less carbon intensive than theother fossil fuels, GHGs are nevertheless emitted during the process of extraction, production,processing, transmission, storage and distribution.

As part of the Activities Implemented Jointly (AIJ) pilot programme under the United NationsFramework Convention on Climate Change, several companies and countries, already haveundertaken projects to reduce GHG emissions of both CO2 and CH4 in this sector. From a businessperspective, CH4 emissions translate directly into lost revenues from the potential sale of the naturalgas. In a carbon-constrained world, such as Kyoto, where carbon emissions assume a price, thereduction of these emissions provides a potential additional income in the form of saleable emissionscredits. Much can be learned from these initial AIJ projects, as well as current projects underwayaround the world (Table 1), as governments and investors attempt to capitalise on the emissionsreductions potential in the midstream and upstream natural gas industry4.

4 Throughout this document we refer to midstream and upstream to mean all activities in the natural gasindustry short of end-use consumption (i.e., exploration and production, processing, transmission, storage anddistribution). We also include upstream oil production, but only to the extent that we consider the associated gasthat is flared in the production of oil.

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Table 1: Selected Mid- and Upstream Natural Gas Emission Reduction ProjectActivities

ProgrammeType Project Partners Description

AIJ Modelling and Optimisation ofGrid Operation of the GasTransportation System UshgorodCorridor of Volgotransgas.

Germany andthe RussianFederation

Pipeline system optimised to reducefuel consumption and lowergreenhouse gas emissions.

AIJ Chile Natural Gas Project:Capturing Fugitive MethaneEmissions

Australia andChile

Project utilises nylon pipelinetechnology to reduce fugitiveemissions from distribution system.

AIJ Atlantic Methanol ProductionCompany EnvironmentallyResponsible Gas Processing onBioko Islands.

United Statesand EquatorialGuinea

Project entails building a methanolplant adjacent to the gas processingplant to utilise emissions that wouldhave otherwise been flared.

AIJ RUSAGAS: Capturing FugitiveGas Emissions from CompressorStations

United Statesand RussianFederation

Project designed to seal leakingvalves in two compressor stations inRussias transmission anddistribution systems.

World EnergyCouncil (WEC)

Reduction of Leaks in NaturalGas Pipelines

United Statesand China

Project focuses on minimising, andwhere possible, eliminating leaksfrom control valves. Projectexamines leak detection andmaintenance programmes.

WEC Nigeria Escravos Gas ProcessingPlant

Chevron andNigeria

Chevron has increased the efficiencyand capacity for processing gas thatwould otherwise be flared.

WEC Nigeria Shell Gas FlaringReduction

Shell andNigeria

Part of Shells commitment toeliminate continuous flaring by2008.

WEC Nigeria Shell halting the ventingof methane.

Shell andNigeria

Shell has committed to stoppingventing by 2003 and to stop flaringby 2008.

WEC Nigeria West African GasPipeline

ChevronNigeria

Gas that was previously flared willbe transported to Ghana and Beninto be used in power plants.

While a number of studies look at opportunities for reducing GHG emissions in the downstreamsector (i.e., end-use consumption)5, this paper analyses the potential for the mid-and upstream naturalgas industry to contribute to GHG emissions reductions. Section 1 provides an overview of the mid-and upstream natural gas industry, including a discussion of significant sources of GHG emissions in

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the sub-sectors (i.e., extraction/production, processing, transmission and storage and distribution),while Section II explores technological options for reducing these emissions. Section III extendswork previously completed by the OECD/IEA (2000) on emissions baselines and project-basedmechanisms, and identifies issues pertinent to developing baselines for the natural gas industry.Based on this foundation, Section IV develops options that may be used for construction of GHGemissions baselines for the mid-and upstream natural gas industry. Section V provides an economicanalysis to illustrate the potential return on investment from project-based activities in the gasindustry. Section VI examines one of the questions highlighted in Section V why some profitableprojects may not be undertaken by exploring some typical barriers to project development.Conclusions made throughout the document are then highlighted in Section VII.

Finally, several appendices are provided at the end of the document to supplement the discussion inthe paper. In addition, to providing technical information, the appendices may be useful inhighlighting the potential for world markets to support project-based activities.

5 For information on baselines for natural gas use in the electric power industry, see OECD/IEA (2000) andKartha, Lazarus and Bosi (2002).

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SECTION 1: OVERVIEW OF THE UPSTREAM AND MIDSTREAM NATURAL GASINDUSTRY AND GREENHOUSE GAS EMISSIONS

In order to understand the potential for GHG reductions in the gas sector, it is first necessary to reviewthe structure of the midstream and upstream industry. The four major sub-sectors of the industry are:extraction/production; processing; transmission and storage; and distribution. Only end-useconsumption (i.e., consumption in the industrial, residential, commercial and transportation sectors) isnot evaluated.

OVERVIEW OF THE SECTOR6

Extraction/Production

The extraction/production phase begins with the identification and characterisation of recoverablenatural gas reserves thousands of feet underground, either on land or sea. Historically, this processhas been one of trial and error, involving expensive drilling activities to determine success.However, new technologies today involving 3-D seismic and 4-D time-lapse visualisation techniques,as well as remote sensing, have resulted in fewer than half as many wells required today to achievethe same reserve additions as twenty years ago (DOE, October 1999).

After natural gas is detected, exploratory wells are drilled to test the quantity and quality of thehydrocarbons present; assessments are made of the geologic reservoir structure, including its aerialextent and thickness. Drilling techniques today have advanced considerably: three-dimensionalexploration in the subsurface is now possible from a single well.

The gas exits the well under very high pressure, often greater than 70 kilograms per square centimetre(EPA September 1999), where it is then transported to either processing plants or to national orinternational pipelines (if the natural gas meets the quality conditions required for transport).

Natural Gas Processing

Most natural gas streams require some level of processing. Natural gas processing must take place ifgas is sour or wet, otherwise the gas can corrode the transmission and distribution systems. Twoprimary functions of the natural gas processing facility involve removing water and removing anyacidic substances such as hydrogen sulfide (H2S) and/or CO2. Water is fractionated out by one ofthree measures: passing the gas over a dessicant for absorption; injecting chemicals to precipitate thewater; or by chilling the water vapour component below its condensation point. The acid gases arealso fractionated out by adsorption or by mixing with agents to precipitate the molecules.

If the gas stream is relatively lean (i.e., not containing significant levels of heavier hydrocarbons,such as ethane, propane, butane, and/or pentane), the natural gas can be charged to the transmissionsystem after dehydration and removal of the acid gases. If heavier hydrocarbons are present furtherextraction and fractionation processes are undertaken to remove these hydrocarbons, often referred toas natural gas liquids, prior to charging the natural gas to the system. These natural gas liquids can bemarketed for sale.

6 The source for this section is United Nations, September 1986, unless otherwise noted.

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Figure 1: Overview of the Midstream and Upstream Natural Gas Industry

Transmission

After processing, gas is ready to be transported to the market. The two primary methods oftransportation are by land (through pipelines) and by sea (in liquefied natural gas tankers or viaoffshore pipelines). Whether transportation occurs over land or by sea is primarily a function ofdistance, as long distance pipelines are rather expensive and often constitute a major element of thefinal price of the natural gas. With costs of LNG falling faster than pipeline construction costs, thedynamics are shifting in these markets.

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Pipeline Transportation

Pipeline transportation includes the gas gathering pipeline systems used to move natural gas from thewell to the gas processing plant, as well as the pipeline transmission system itself. Pipeline systemsinclude a number of compressor stations to efficiently move the natural gas through the pipes. Whilethere is no precise standard distance between compressor stations, they are located, on average every100-150km along a pipeline.

Pipelines also contain a number of valves located along their length, allowing for isolation of leakycomponents, access to a failed segment of the pipeline, or access for any other reason that requires asegment must be turned off.

Liquefied Natural Gas (LNG)

For long transport distances, LNG is often a more economically viable option. The LNG Chain isexactly the same as described above until the point of pipeline transportation. At that point, insteadof transporting the natural gas to end-users via pipelines, natural gas is liquefied and loaded into LNGtankers for shipping to its destination.

After the gas processing step described above, the gas is refrigerated, cooling it to approximately 162C. Simultaneously the gas/refrigerant mixture is compressed (with gas turbines primarilyproviding the drive for compression) to form the liquefied natural gas. The LNG is compressed to avolume approximately 600 times smaller than that of the same mass at atmospheric pressure. TheLNG is then transported into a storage tank before loading onto an LNG tanker.

LNG is transported primarily in one of three different types of cargo containment tanks: membrane-type tanks, self-supporting spherical tanks, or self-supporting prismatic tanks. A reception terminal atthe destination awaits the LNG tanker. Here a number of different methods are used to vaporise theLNG. Some terminals use the heat from seawater to vaporise the LNG, while others use a gas-firedprocess, whereby the combustion heat is transferred to the LNG via a hot water bath. The vaporisedLNG is then transported to end-users via pipeline.

Storage

Storage facilities, whether they are depleted oil fields, aquifers, salt caverns or LNG storage facilities,are primarily designed to balance supply and demand in the natural gas market. The most frequentlyused means of geologic storage for pipeline gas are depleted reservoirs. Because these formationsformerly contained either oil or gas, they have a demonstrated integrity with respect to their ability tocontain the gas. Before injection into a depleted reservoir it must be determined that natural gas canbe withdrawn as needed from the reservoir and that the reservoir contains a satisfactory cap rock toprevent leakage.

Aquifers are porous spaces underground that can also serve as reservoirs for natural gas. Aquifersneed to be porous and permeable, and possess a sufficient cap to prevent leakage. Salt caverns are athird means of storage. Salt caverns are used as storage by dissolving the salt and then removing thesubsequent brine. A single well can then be used to either inject or extract gas from the cavern. Saltcaverns have advantages over other means of storage in that they offer a high production rate and

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degree of availability, as well as high levels of safety (OECD/IEA 1993); however, they also havesmaller capacities.

LNG can be stored either above ground or below ground, however, storage facilities are increasinglybeing sited below ground to prevent visual intrusion, as well as to reduce damage from any potentialleaks. Above ground tanks normally contain double walls and many have outer walls with reinforcedconcrete to help prevent fractures. In-ground facilities also contain an inner lining to prevent leaks(OECD/IEA 1993).

Distribution

Gas distribution involves local natural gas distribution companies (LDCs) taking gas from thepipeline serving its area and reducing the pressure, adding an odorant to better detect gas leakage, andmoving the natural gas into a smaller-diameter local distribution pipeline system. LDCs transport thegas to the local end-users.

GREENHOUSE GAS EMISSIONS FROM THE MIDSTREAM AND UPSTREAM NATURALGAS SYSTEMS

General Overview of Sector Emissions

The two primary types of emissions from natural gas systems are CO2 and CH4. Nitrous oxide isreleased to a much lesser extent, through combustion, however because it is negligible compared withemissions of CO2 and CH4 it will not be addressed in this study. Table 2 illustrates the results of a lifecycle emissions analysis of GHGs from the natural gas industry in terms of CO2 equivalent. It isworthy to note that while the quantity of CH4 emissions does not appear significant compared to CO2(column 1), considering the global warming potential of CH4, these emissions are responsible forabout 12 per cent of total CO2e emissions (column 5)7.

Table 2: Life-Cycle Greenhouse Gas Emissions and GWP from a 505 MW Natural GasCombined Cycle Power Plant

Source: Spath and Mann: September 2000

7 As will be discussed below, this figure should not be used to determine emissions from individual projects,rather to be considered a ball park figure. The actual amount of CH4 emissions depends on a number of factorsincluding CH4 content of natural gas, and the age and the condition of the natural gas infrastructure.

Emissions(g/kWh)

% of GHG inthis table

GWP relativeto CO2

GWP value(gCO2e/kWh)

Contribution to totalCO2e emissions (%)

CO2 439.7 99.4 1 439.7 88.1CH4 2.8 0.6 21 59.2 11.9N2O 0.00073 0.0002 310 0.2 0.04

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Table 3 expands on Table 2 by disaggregating the global warming potential (in CO2e) of the GHGsinto subsectors of the natural gas system. From this table it is clear that while combustion isresponsible for a majority of life-cycle GHG emissions, the midstream and upstream account for asignificant enough percentage (about 25 per cent) to warrant further investigations into mitigatingthese emissions8.

Table 3: Disaggregation of Upstream and Downstream Greenhouse Gas Emissions from theNatural Gas Industry

Source: Adapted from Spath and Mann 2000

Global Estimates of CO2 and CH4 emissions

Global emissions of CH4 from the oil and gas sector were estimated to be between 30-70 millionmetric tons per year (MMT/y) in 1996 (IPCC, 1997), with Russia and countries of the former SovietUnion accounting for approximately 55 per cent of these emissions (Gale and Freund, 2000). Withglobal production 2,537 bcm in 2000, emission intensity ranges from approximately 11.83 metrictons/MMcm to 27.6 metric tons/MMcm per year.

According to Gale and Freund, these emissions are expected to rise by about 60 per cent by 2025,primarily resulting from increased production of natural gas and a larger number of pipelinesconveying natural gas a greater distance. However, there is a rather high degree of uncertaintyassociated with these numbers, as evident by the large range of values for current emissions. Methanedata is not collected uniformly throughout the world, and where it is, emissions are not necessarilymeasured, rather they are inferred from the difference between production and consumption (i.e.unaccounted for gas). Unaccounted for gas does not accurately reflect emissions, however, due tometering inaccuracies and the fact that a portion of unaccounted for gas is actually used internally topower equipment such as compressors.

While CO2 statistics from the combustion of natural gas are collected more uniformly than CH4statistics, (e.g., IEA 2001a, U.S. EIA 2002) GHG emissions resulting specifically from midstream andupstream activities are not. Carbon dioxide in the midstream and upstream natural gas sector resultsprimarily from flaring of associated gas and combustion associated with operating the equipment. Forexample, in the United States in 1997, of the CO2 produced along with natural gas, nearly 69 per centof CO2 emissions were released during gas production, with the remainder emitted during

8 For further analysis of baseline construction for combustion, see the electricity generation case study(OECD/IEA 2000).

Process Step GWP (g CO2e/kWh)Contribution toTotal CO2e (%)

Power Plant Operation 372.2 74.6Natural Gas Productionand Distribution 124.5 24.9Construction andDecommissioning 2 0.4Other 0.4 0.1Total 499.1 100

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transmission, distribution and consumption (EIA 1999)9. When examining the life-cycle of LNG,CO2 becomes an even more significant factor because of the fuel consumption required to power thecompressors in liquefaction plants, and to a lesser extent, consumption associated with the LNGtankers, and re-gasification terminals.

Specific Sources of Greenhouse Gas Emissions in this Sector

The relative importance of emissions from the various sub-sectors: exploration; production;processing; transmission; storage and distribution differ among countries. For example, in Nigeriaand Venezuela, flaring is currently a more significant source of emissions, while in the United Statesand Russia, the gas transmission system (and specifically compression) are a relatively moresignificant source of emissions. Table 4 illustrates the general sources of emissions from the varioussub-sectors of the natural gas system.

Table 4: Sources of Emissions from the Mid/Upstream Natural Gas Industry

EXPLORATIONPRODUCTION ANDPROCESSING

TRANSMISSIONAND STORAGE DISTRIBUTION

Drilling Gas Plants Pipelines Pipelines and metersWell Tests Separation Tankers Pneumatic devicesFugitive EmissionsDehydration Compressors Fugitive Emissions

Compressors Fugitive Emissions MaintenanceVenting and Flaring MaintenanceFugitive EmissionsMaintenance

Source: Moore, S. et al. 1998. Chart can be found at http://www.ieagreen.org.uk

The diversity of the subsectors reflected in Table 4 suggests that it may not be appropriate to developemissions baselines for each sub-sector (i.e., exploration, production/processing, transmission andstorage, and distribution). Instead, it may be more appropriate to define baseline methodologies fordifferent project types (such as projects focusing on fugitive emissions or projects to reduceemissions from compressors) for the midstream and upstream natural gas industry.

This conclusion is reached for a number of reasons. First, projects may not be defined by the specificsub-sectors listed above, rendering an analysis of project boundaries based purely on these sub-sectorsas ineffective. This problem is exacerbated as the natural gas system is a fairly closed system10, andproject participants may thus legitimately elect to draw the boundaries of the project where theybelieve the greatest emission reduction potential exists. The boundary may be drawn from thepipeline that feeds the gas processing facility to a point on the pipeline 100km away, or around anindividual pipeline segment, in order to reduce emissions from a single compressor.

Secondly, and perhaps more importantly, there are certain practices or technologies that produceemissions in all or a number of sub-sectors. For example, fugitive emissions (emissions from leakyvalves, loose seals, flanges and/or venting) can be found throughout the system, while compressors

9 These values represent an estimated national average. Actual percentages will vary from field to field, andeven within fields over time.10

Closed system refers to the fact that natural gas moves from one process to the next within a transportinfrastructure, either pipeline or tanker, and is not exposed to the outside elements once within this system.

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and pneumatic devices are two components that produce significant single sources of CH4 emissionsin more than one sub-sector. Three broad project types might thus be identified: elimination orreduction of flaring of associated gas; elimination or reduction of venting and/or fugitive emissionsfrom defined segments of the system; and improving energy efficiency, especially of compressors.Using such a framework, the choice of baseline methodology would be more a function of the type ofproject proposed than of the project sub-sector.

Figure 2 illustrates sources of CH4 emissions in the natural gas system. It is important to rememberthat while this figure highlights the importance of compressors, fugitive emissions (venting anddistribution leaks), and flaring (associated gas) as significant contributors to CH4 emissions, many ofthese sources also contribute to CO2 emissions. For example, compressors are a significant source ofemissions for both pipelines and LNG trains, while the flaring of associated gas releases both CO2 andCH4.

Figure 2: Methane Emissions Sources in Oil and Gas Industries

Source: Moore, S. et al. June 1998

Fugitive Emissions and Venting

The category of fugitive emissions is rather broad, and can include emissions vented or otherwiseleaked during normal operations in the system or during maintenance procedures. Venting and/orleakage occur in all of the sub-sectors listed above. In general, gas is normally vented to prevent adangerous build up of pressure in the system, or to release gas in order to undertake maintenance on asection of the system.

Leakage occurs throughout the chain of activities, resulting from leaky seals or joints in pneumaticdevices and compressors, or resulting from flaws or cracks in elements designed to hold or conveynatural gas. Leaks from compressors are a large single point emissions source. Pneumatic devicesare also significant sources of leakage, accounting for approximately 14 per cent of CH4 emissions(Figure 2).

AssociatedGas27%

Other8%

Vents,Maintenance

andExploration

8%

DistributionLeaks18%

PneumaticDevices

14%Compressors25%

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Compressors

Compressors, along with the drivers that power them, are used throughout the natural gas system.They are used in gas processing facilities and pipelines to convey natural gas, maintaining pressure inthe system after losses of pressure due to friction. Compressors are used in the liquefaction of naturalgas, and in storage facilities, and to help inject the natural gas into the high-pressure storage field.This technology is both ubiquitous in the natural gas system and, because of the driver, a significantsource of emissions. Compressor emissions arise from one of two sources: CH4 emissions due toleakage; and emissions of CO2 associated with fuel combustion to power equipment. Fugitive CH4emissions are discussed here while emissions of CO2 will be discussed in the following section.

Compressor stations can have upwards of 2,500 different components, nearly all of which aresusceptible to leaks whether intentionally (vented emissions) or unintentionally (fugitive emissions).A joint study undertaken by the U.S. EPA Natural Gas Star Programme and Partners, the GasResearch Institute and the American Gas Pipeline Research Committee found that leaks can begrouped by technological component and facility. In a study of four compressor stations, they foundthat approximately 96 per cent of the emissions came from about 20 per cent of the components(Figure 3) (EPA 1997a).

Figure 3: Leak Distribution for Four Compressor Stations in the United States

Furthermore, a study at the same group of 11 stations revealed that three of the 11 stations accountedfor 75 per cent of total emissions (EPA 1997c). Because of the large number of leaks arising fromcompressor stations and the relative concentration of the emissions sources, within limitedcomponents and limited facilities, compressors may prove an attractive arena for projects, and in facthave already been host to AIJ and various national and independent company mitigation activities.

The most common form of compressor leaks arises from wet seals (centrifugal compressors), pressurerelief valves and compressor rod packing systems (reciprocating compressors) (Table 5). The tablebelow illustrates the potential for emissions reductions from replacement of compressor rod packingsystems and replacement of wet seals with dry seals, among other compressor components.

32

14

62 1 0 0

44

05

101520253035404550

Top1%

Next4%

Next5%

2nd10%

3rd10%

4th10%

5th10%

Rest

% of Leaky Components

%o

fMea

sure

dG

asLo

ss Source: EPA 1997a

23

Typical leak rates for U.S. compressor components

Component Type Average Volume(Mcm/year)Wet Seal System 595.4-2,977.0Pressure Relief Valve 33.6Compressor Rod Packing 24.4Blowdown Valve 14.6Station Blowdown 13.2Fuel Gas Blowdown 7.4Starter Vent 5.6Regulator 2.7Ball/Plug Valve 1.9OEL 1.4Compressor Loder Valve 1.4Control Valve 0.7Flange 0.4Gate/Needle Valve 0.4Pipe Thread 0.3

Source: Adapted from U.S.EPA 1997a, wet seals valueaddedfrom U.S.EPA 1997b.- all assume 100% load

Table 5 : Typical Leak Rates for Compressor Components in the United States

All compressor rod-packing systems leak, even brand new ones. Newly installed systems may loseapproximately 14.9Mcm/year, assuming 100 per cent load. As the system ages, leaks in the UnitedStates averaged 24.4Mcm/year. Another, much larger, source of emissions in compressors are wetseals, which use oil circulated under high pressure to form a barrier preventing escape of natural gas.These units typically emit 600 to nearly 3000Mcm/year. These leaks arise from normal leakage aswell as degassing of the circulating oil and the power required to circulate that oil.

Pneumatic Devices

The Natural Gas Star Programme found that, in the United States, pneumatic devices were the singlelargest source of vented emissions from the natural gas industry (U.S. EPA 1998). Pneumaticdevices, which are often powered by pressurised natural gas, but can also be powered by electricity orair, are used in the natural gas industry as liquid level and valve controllers, as well as pressure andtemperature regulators. Pneumatic devices come in three basic designs, continuous, intermittent andself-contained. Continuous devices continually moderate normal activities in the system, and as such,steadily leak CH4. Continuous devices are often referred to as high-bleed, and typically emit from1.4Mcm/yr to 22Mcm/yr.

Intermittent and self-contained devices are often referred to as low-bleed in that they emit less than1.4Mcm/yr. Intermittent bleed devices primarily release emissions when a valve is open or closed.Self-contained devices under normal circumstances do not emit CH4 as they redirect would-beemissions into the downstream pipeline. In general, up-to-date maintenance will have a greaterinfluence on lowering the leak rates for pneumatic devices, then will the average age of theinfrastructure.

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Transmission and Distribution Systems

There are two categories of gas losses that can arise from transmission and distribution systems: majorand minor releases. Major releases often result from a build-up of pressure in the system leading to ablowout of emissions into the atmosphere11. Minor leaks from transmission and distributionsystems often result from gas escaping through the containing pipeline; the extent of the leaks dependon the type of material the pipeline is constructed from (e.g., cast iron, unprotected or protected steel,or plastic) and the pressure of the natural gas within the system. An additional source of leakage inthe distribution system is at the gate station or other surface facilities where the pressure of thenatural gas is reduced, and CH4 is emitted as a result of leaks in valves, flanges and variousinstruments, such as pneumatic devices.

Pipelines constructed of cast iron are much more susceptible to leaks than pipelines constructed fromprotected steel or plastic. In the United States (1997), there were 55,288 miles of pipeline constructedof cast iron (emissions factor of 238.7 Mscf/mile-yr, or approximately 4.2 Mcm/km-yr) comparedwith 254,595 miles of plastic pipeline (emissions factor of 19.3 Mscf/mile-yr, or approximately0.34Mcm/km-yr). Obviously, in comparing a transmission system and a distribution system with thesame size leak, the transmission system will result in a greater total amount of CH4 emissions as thepressure in these systems is comparatively higher than the distribution system, magnifying the impactof the leak.

Maintenance

Regular maintenance can be both a potentially significant source of emissions, as well as apreventative measure taken to reduce overall emissions from the natural gas system. Maintenancetypically requires depressurising the affected area prior to any work. A common approach foraccomplishing this is to block off the affected segment and then vent the CH4 that is present into theatmosphere. In an example from Russia (further elaborated below), CH4 emissions from repairs to theRAO Gazprom system were estimated to be 4,800 m3/km/yr. In the United States in 1998,approximately 255 MMcm (around 510 m3/km) of CH4 were vented into the atmosphere duringroutine maintenance and pipeline upsets12.

Maintenance, however, if undertaken regularly, can also prevent potentially dangerous blowouts ofCH4 in the system due to the presence of cracks and other pipeline deformities. One tool fordetermining the integrity of the pipeline system is a pig. Diagnostic pigs are balloon-like toolsinserted into pipelines to clean the internal surfaces as well as identify any potentially defectivesections. The combination of cleaning and detection has reduced the accident ratio in Russia from0.26 accidents/1000 km to 0.24 accidents/1000 km in 1998 (Altfeld et al. 2000).

11 Blowouts can occur in other parts of the system as well. In 1999, Anadarko Canada Corporation (now calledAnadarko Canada Energy Limited) experienced a blowout in a drilling rig, causing methane to be released for a12 day period. It was estimated that the total volume of gas released was 17 MMscm, approximately half ofwhich was burned. This one episode caused the companys emissions to rise from 1,508 kt to 2,149 kt CO2e,about 30 per cent of their total emissions (Source: Anadarko Canada Corporation, 2000 Voluntary ClimateChange Challenge Progress Report).12 Pipeline upsets can result in the necessity to operate emergency pressure relief systems to prevent the buildup of dangerous concentrations of the natural gas. The result is venting of methane emissions into theatmosphere.

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Fugitive Emissions in Russia and the United States

Although limited studies have been undertaken to examine fugitive emissions in the natural gasindustry, some insights can be gleaned from studies carried out in Russia and the United States. In theearly to mid 1990s, studies undertaken in Russia, for example, estimated that fugitive CH4 emissionsfrom the natural gas industry amounted to between 1.67 per cent and 9.35 per cent of total throughputper year (Rabchuk et al. 1991, Minayev 1996, WRI 1996, among others). A more recent studyundertaken by RAO Gazprom in 1999, however, estimated that fugitive emission losses were closer to1 per cent of throughput.

These latter results were extrapolated from an analysis undertaken on a segment of the Volgotransgazpipeline. The study estimated that emissions associated with leaks, ruptures and repair to the entireGazprom transmission system amounted to 8200 m3/km/yr, equal to about 0.21 per cent of the totalgas volume transported. When transmission system emissions were added to production andprocessing leaks, (0.06 per cent of total quantity of gas produced), and compressor leaks,(approximately 0.69 per cent of production), total CH4 emissions due to venting and fugitiveemissions in Russia were estimated to be 1 per cent of throughput, (i.e., about 4 MMt/year.). There issignificant uncertainty in these figures however. Russian uncertainty is estimated at 50 per cent,(Dedikov et al.1999), compared to an estimated uncertainty of 33 per cent in the EnvironmentalProtection Agency (EPA) figures for the United States cited below. Although emissions fromdistribution were not addressed here, another study suggests that these amounted to 5bcm in 1998,about 0.8 per cent of throughput (OECD/IEA 2002).

In the United States, a study undertaken by the U.S. EPA (1999) determined that CH4 emissions fromventing and fugitive emissions amounted to 5.8 MMt in 1997, or about 1.5 per cent of throughput.Based on a study by the EPA and the Gas Research Institute (1996)13, over 50 per cent of the leakswere due to compressors and pneumatic devices. Compressors accounted for approximately 37 percent of these fugitive emissions (equal to 0.60 per cent of total production), while venting and leakingfrom pneumatic devices accounted for about 15 per cent of the total (equal to about 0.23 per cent ofthroughput). A large part of the remainder of the fugitive emissions resulted from leaky valves, jointsand flanges in the distribution system (about 25 per cent of total CH4 emissions, equalling 0.40 percent of throughput) and an accumulation of small leaks in other pieces of equipment.Table 6: Percentage of Greenhouse Gas Emissions in Various Components of the Natural Gas

System

Fugitive Emissionsfrom Compressors (%of throughput)

Fugitive Emissions in theTransmission/DistributionSystem (% of throughput)

EstimatedUncertainty

Russia 0.69% 0.21%* 50%United States 0.60% 0.90% 33%

Sources: Dedikov1999, EPA/GRI 1996.

* The figures for emissions from the transmission/distribution system are not directly comparable because theRussian study did not extrapolate to consider distribution system emissions, while the US study did. Taking intoaccount the OECD/IEA study, an additional 0.8 per cent would be added to Russian fugitive emissions toaccount for distribution losses.

13 Based on 1992 data.

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Box 1: Varying Quantities of GHG Emissions from the Flaring of Natural Gas

Emissions of CO2 and CH4 can vary between two different flares, and can even changebetween two points in time for a given flare, thus making it very difficult to assess globalemissions with only data available on the quantity flared. Knowing the total quantity ofgas flared versus gas vented will have a significant impact on the total global warmingpotential of emissions from a single flare.

For example, suppose we assume that 108bcm are flared annually, with 100 per centcombustion efficiency, so all of the released emissions are CO2. Under this scenario,global emissions would be approximately 212MMtCO2e. However, if we assume that notall of this is flared, and rather 18bcm are actually vented (i.e. CH4 emissions are directlyreleased into the atmosphere), this increases the total CO2e emissions into the atmosphereby over a factor of 2, to approximately 447MMtCO2e. This still assumes that the naturalgas that is flared is flared with 100 per cent combustion efficiency.

Knowing the actual combustion efficiency of the flare is also a significant factor indetermining the global warming potential of emissions from the flare. In the first exampleabove, if the flare were only 95 per cent efficient, instead of 100 per cent efficient, totalemissions would increase approximately 30 per cent from 212 MMTCO2e to 277MMTCO2e.

Emissions from Production and Processing: Flaring

It is difficult to assess world-wide emissions from the flaring of natural gas. A study undertaken bythe World Bank estimates that approximately 108bcm of natural gas were flared in 200014. There issome degree of uncertainty associated with this value, however, due to the fact that a singlecomprehensive source for flaring data does not exist. A primary source of data is Cedigaz, howeverthey do not provide flaring values for Russia and China. In addition to uncertainty in the levels offlaring, additional uncertainties exist when attempting to associate emissions of GHGs from the flares(Box 1). The figure of 108bcm translates into approximately 212 MMTCO2 annually world-wide.This is significant considering that the World Energy Outlook 2000 estimates that the differencebetween Annex I Parties Kyoto Protocol targets and their projected emissions levels (including theUnited States) are equal to 1,523 MMtCO2. In other words, global emissions from flaring are equalto approximately 14 per cent of the estimated emissions gap that exists between Parties commitmentsand their projected 2010 emissions15.

While flaring as a percentage of natural gas production has fallen over the past decades, absolutelevels of flaring have remained fairly constant. In 2000, approximately 3.1 per cent of world-widegross natural gas production was flared, while about 11.6 per cent was re-injected. In 1990, 4.4 percent of gross production was flared, while about 9.5 per cent was re-injected. Figure 4 illustratesregional activity for flaring and re-injection of natural gas in 2000. In 2000, Africa was the leadingregion for both re-injection and flaring as a percentage of total gas production and the leader in

14 When the word flaring is used for these statistics, the data actually collected represents flared and ventedgas. This level of aggregation introduces additional uncertainty as the global warming potential of ventedmethane is 21 times per unit of volume greater than that for 100 per cent-efficient flared gas.15 Again this comparison is rather uncertain. The value of 212 MMtCO2 assumes that nearly all, if not all, gasis flared (not vented) and that combustion efficiencies are high. Both of these are rather liberal assumptions,and it is likely that emissions from flaring are actually higher than this.

27

absolute values (36.83bcm vented and flared). While the Middle East used to trail only Africa interms of flaring and venting as a percentage of gross production, the Middle East gave way to LatinAmerica around 1995 partially due to significant efforts to reduce, and nearly eliminate flaring inSaudi Arabia.

Figure 4: Gas Re-injected and Vented and Flared as Percentage of Gross Production: RegionalValues

Source: Derived from data from Chabrelie (2000)Note: Values are slightly different than those produced by the International Energy Agency.

Figure 5, which breaks down the regions into representative countries, provides some additionalinformation and insights. First of all, while on the whole, Africa may be the single largest contributorto the flaring (and venting) of natural gas during production, the story within Africa is different fordifferent countries. For example, while Nigeria recorded 75 per cent flaring of natural gas (in 1996),Algeria flared only about 5 per cent while re-injecting nearly half of the gas produced. A fairlysignificant difference in practices can be observed in the Middle East as well, for example, betweenAbu Dhabi and Iran in the latter a much larger percentage of production was re-injected. Thisdifference in practices, even within regions, has implications for baseline development for flaringreduction projects. A single regional baseline value does not appear to be ideal for a default baseline,as practices can differ significantly within a region, making national defaults more reflective of thecurrent situation.

254.9

331.82

297.23 322.65208.99

910.72

741.46

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

Africa CIS Europe Far East LatinAmerica

MiddleEast

NorthAmerica

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Bill

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Cubi

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rs(B

cm

)

Gas Re-Injected (% of Gross Production)Gas Vented and Flared (% of Gross Production)Gross Production

28

Figure 5: Gas Re-injected and Flared as a Percentage of Gross Production: Selected Countries

Source: Janssen 1998. Note, Janssen, in his own calculations, has disaggregated data from Cedigaz todistinguish between venting and flaring. This graph illustrates just flaring.

Emissions Associated with Energy Consumption of Compressors and LNG facilities.

As discussed above, compressors are large single point emissions sources for many countries,resulting in both a significant source of CH4 emissions, as well as CO2 emissions from fuelcombustion to power the compressors16. Thus, implementing newer compressor technology as part ofan energy-efficiency project will serve to reduce both CH4 and CO2 emissions.

Reducing emissions from LNG production is discussed under this project category as well, because asignificant source of emissions results from fuel combustion to power compressors in the liquefactionprocess. There are emissions associated with the transport of LNG, however, they will not bediscussed for a number of reasons. First of all, ships are, to a large extent, powered by boil off onthe high seas -- the vapour emitted as the liquefied gas slowly warms. Any shortfall in fuel is madeup by fuel oil. Furthermore, shipping is sometimes excluded from data for reasons of differing vesselownership and port of registration, making emission allocation difficult (Woodside Australian Energy1998). There are also some combustion emissions associated with re-gasification, but these emissionsare usually offset by use of the cryogenic energy outside the receiving terminal (Tamura, et al 2001).

16 While other energy efficiency project are possible, for example, improving the energy efficiency ofdehydrators in gas processing facilities, this is not discussed further because the emissions reduction potential iscomparatively small when considering compressors and pneumatic devices. Nevertheless, energy efficiencyprojects examining other elements of the natural gas system would be undertaken in the same fashion asdiscussed below.

687.55

89.4782.4

31.6135.45

138.84

59.4551.28

198.11

0

10

20

30

40

50

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80

Canada UnitedStates

Venezuela Norw ay Algeria Nigeria Abu-Dhabi Iran Indonesia

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)

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Bill

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eter

s(B

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Gas Re-Injected (% of Gross Production)Gas Flared (% of Gross Production)Gross Production

29

Prior to liquefaction, emissions associated with natural gas production and processing will be thesame as discussed above. This project category of improving the energy efficiency of the system aimsto isolate those portions of the natural gas system unique to LNG manufacturing.

Emissions from Compressors

The fuel combustion required to power compressors can be a significant source of CO2 emissions. Inan AIJ project by the Russian and German governments, operation of the Ushgorod Corridor of theVolgotransgas transmission system (containing 6 compressor stations and 133 compressor units)required about 3bcm of natural gas per year, resulting in 6 MMTCO2.

As CO2 emissions from compressors are a function of fuel consumption, improvements in the energyefficiency of a compressor will result in a reduction of fuel consumption and, thus, a reduction in CO2emissions. The two primary factors required to determine the fuel consumption of compressors areload factor (the number of hours per year that a given compressor or group of compressors is actuallyin operation) and fuel consumption per kilowatt-hour (kWh; a function of the design of thecompressor). Sometimes this type of data is collected at the company level, but often not aggregated.In general, however, few energy audits on compressors have been undertaken. One audit, by McKee,et al (2000) estimated that energy savings of up to 5-10 per cent could be realised at many compressorstations.

Emissions from LNG

Products of combustion are the most significant source of emissions from the liquefaction of naturalgas, and are emitted from the heaters and gas turbines used to power heat and electrical processes.The production process for LNG includes liquefaction, transport and re-gasification; of these,liquefaction comprises a majority of the energy budget.

Over half of the CO2 emissions associated with liquefaction of natural gas arise from the refrigerationcompressors/turbines used to cool and compress the natural gas (Table 7). Another significant sourceof emissions arises from the removal of CO2 from the feed gas stream, however, emissions can varygreatly from field to field depending on the CO2 content of the source gas.

Table 7: Example of Carbon Dioxide Emissions from a 10Mt/yr LNG Facility in AustraliaPROCESS CARBON DIOXIDE EMISSIONS

(TONS/YEAR)Heaters/Flares (including inlet gas heaters,acid gas incinerator fuel, acid gas in feed gasand flare pilots and purge gas).

1,878,558

Flares (including ship cool down) 42,477

Gas Turbines (including RefrigerationCompressor/Turbines andpower generation turbines

2,403,455235,450

TOTAL 4,559,940Source: Phillips 66. March 2002

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There is some venting of CO2 associated with LNG production. For example, while the CO2 contentof raw gas may be low enough to be suitable for pipeline transport, it still may have to be removedduring liquefaction. Carbon dioxide has a higher freezing point than LNG, so if it is not removedprior to liquefaction, it will freeze out in the processing train causing blockages. As part of the CO2removal process, the gas is often vented into the atmosphere. There are also emissions arising fromleaky compressor seals.

Gas vapours also are released when LNG is loaded into tanks on cargo ships. These vapours areeither flared, or collected by a compressor and re-injected into the LNG liquefaction process. Thetemperature of the ship when it arrives will impact the amount of vapours released, and thus thefeasibility, and costs, of flaring versus recovery. Ships will normally arrive cold, but not as cold aswhen the LNG is in the ship. As these ships are loaded with LNG, some of the LNG immediatelyvaporises. These initial vapours are normally flared. As the ship cools, the vapours are reduced andthese can be effectively collected and recovered. If a ship arrives warm, perhaps as a result of earliermaintenance on the ship, vaporisation of the LNG will be much greater, and usually results in agreater amount of gas flared. A study undertaken in Australia estimated that the arrival of a warmship occurred approximately four times a year out of a total of eighty ship loading, so the extraemissions associated with warm ship loading would not be considered the normal practice (Phillips66, 2002).

Three Japanese gas companies surveyed five of their major suppliers (from Alaska, Indonesia,Malaysia, Brunei, and Australia) to assess GHG emissions from the liquefaction of natural gas, aswell as transport of the LNG and ultimate re-gasification (Tamura et al 2001). Results from this studyconcur with the above study, with cooling of LNG consuming a majority of the energy budget, andthus CO2 emissions. In this study, CO2 from fuel combustion amounted to 1.43g carbon/MJ(compared with 0.15 gC/MJ of CH4 from venting, and 0.09 from flaring)17. According to Tamura etal., CH4 emissions from leakage were previously more significant (nearly 1 per cent of throughput),however, many companies have implemented technologies to inject the fuel back into the fuel lineand burn it through flaring.

Emissions from LNG transport were examined by looking at LNG transportation between Indonesiaand Japan. Using the average amount of fuel loaded, the amount of LNG boil off gas and fuel oilconsumed during transport and cargo handling, it was determined that average emissions wereapproximately 0.44 gC/MJ.Table 8: Average Emissions Intensity of Various Life-Cycle Stages of LNG Imported by Japan

Stage of life cycle Emissions intensity: gC/MJLiquefactionCO2 from fuel consumption

CO2 from flare combustionCH4 from ventCO2 in raw gas

2.151.430.090.150.48

LNG transport 0.44

Source: Tamura I. et al. 2001

17 The venting data is very site specific, to a much greater extent than CO2 from fuel combustion. In the foursurveys (which excluded Alaska for production) emissions from CO2 from fuel combustion ranged from 1.30-1.57 gC/MJ, while CH4 emissions illustrated greater variation ranging from 0.01-1.15 gC/MJ.

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SECTION II: TECHNOLOGICAL OPTIONS AND OPPORTUNITIES FOR REDUCINGEMISSIONS

According to a study undertaken by the IEA Greenhouse Gas R&D Programme (IEAGHG), it istechnically feasible to make substantial reductions throughout the midstream and upstream naturalgas industry, often times by implementing current best practices or commercially availabletechnologies. It can be misleading to make general assumptions about emission reduction potential,however, as there are several site-specific factors that can greatly enhance or reduce the effect ofimplementing best practice procedures or technologies. These site-specific factors include theknowledge base and the skill of those actually implementing the technologies, subsequentmaintenance procedures, and site-specific conditions in the rest of the system. For example,maintenance practices on pneumatic devices can impact the overall annual leakage of a particulardevice. Repairing leaky gaskets, along with regular cleaning and tuning can reduce CH4 emissions1.2-1.4 Mcm per year per device compared to a similar pneumatic device where no such maintenanceoccurs (U.S. EPA 1998)18.

Nevertheless, while keeping these considerations in mind, it is helpful to gain an overview of whattypes of technologies or best practices might be introduced as part of a project-based activity and themagnitude of reductions that might be expected from such projects.

REDUCTION POTENTIAL

A study undertaken by IEAGHG determined that it would be technically possible to prevent over 70per cent of present day emissions from the oil and gas industry. If one considers only currentlyavailable technologies, this figure could rise to 80 per cent by 2010. However, a full discussion mustnot only consider technical potential, but economic potential as well. Table 9 illustrates both thetechnical and economic potential of realising CH4 emissions reductions in the midstream andupstream natural gas industry. Unfortunately, comparable data could not be found that elaborates onthe technical and economic potential for reducing CO2 emissions in this sector. The economic costsare calculated over the projected life of the project and at a discount rate of 5 per cent19; note thatthese figures should only be considered as approximations.

18 Assuming full load.19 This may be low for developing countries. The IPCC Third Assessment Report, Working Group III, basedcost estimates on discount rates of 5-12 per cent, consistent with public sector discount rates. Private internalrates of return may be even higher.

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Table 9: Technical and Economic Potential for Emissions Reductions in SelectedTechnologies/Processes

While it would be nearly impossible to look at all technologies that could potentially be used inproject-based activities, it is useful to garner some lessons learned from companies already activelyengaged in project activities to reduce GHG emissions from this sector.

Reducing Fugitive Methane Emissions

Compressors

Techniques and application of best practices at compressor stations can have a significant impact onefforts to reduce emissions. Replacement of older, less efficient compressors can reduce CH4emissions from this source by up to 90 per cent. According to the IEAGHG, globally compressorstations offer the greatest potential for CH4 emissions reduction, with an estimated global reduction of10.6 MMt/year.

The Natural Gas STAR programme highlighted two best practices to reduce CH4 emissions,replacement of wet seals with dry seals and compressor rod and ring replacement. Compressor seals,which are designed to prevent the high-pressure gas from escaping, are a significant source of CH4leakage. As discussed above, older systems use oil-type seals, which emit significantly more CH4than more modern dry seals. While some compressor designs prohibit installation of dry seals, forexample, due to housing design or operational requirements, experience indicates that whereinstallation is possible, conversion from wet to dry seals will almost always result in significantenough cost savings to make the conversion economical (Table 10).

Industry Activity Technical Potential(% reduction)Economic Potential

(% reduction) Range of Mitigation Costs($) *Exploration 40 0 300Associated Gas 50-90 50 -2000 to 400Process Vents & Flares 70 (vents) 60 -90 to +500Maintenance 20 20 -190Electricity and Fuel Use 20 15 -215 to +350Compressors 90 80 -215 to +35Pneumatic Devices** 98 75 -375System Upsets 70 0 1500Fugitive Emissions 90 5 -270 to 2235

* A negative value signifies a financial benefit. Values calculated over the expected project lifetime,and at a discount rate of 5%.** Pneumatic device technical potential figure from Oil and Gas Journal, August 28, 2000.Source: IEAGHG Program. Table can be found at http://www.ieagreen.org.uk/ch4-3.htm.

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Table 10: A Comparison of Wet and Dry Seals

Gas LeakageRates

Power Consumption Reliability Annual O&MCosts

Dry Seals 6 scfm 5 kw/h Higher $6,000-10,000/year

Wet Seals 40-200 scfm 50-100 kw/h Lower Up to$100,000/year

Source: Drawn from information in EPA 1997b

Compressor rod packing systems consist of a series of flexible rings that create a seal around theshaft. Nevertheless, as described above, these systems leak. Leakage can be reduced through propermaintenance and alignment, and timely replacement of component parts, as well as through theaddition of leak recovery devices. Partners in the Natural Gas STAR programme could not come to aconsensus on achievable standard emission reduction potentials for these packing systems. This wasprimarily due to the many factors that can potentially affect existing emissions and emissions savings,such as cylinder pressure, alignment of packing parts, and amount of wear on the actual rods andrings. While new rod packing systems were estimated to leak 14.9Mcm/yr, leakage from existingsystems has been reported up to 223Mcm/yr.

Pneumatic Devices

Most natural gas producers use pneumatic devices powered by natural gas because the high-pressurefuel source is readily abundant in the system. These devices, however, in normal operations willbleed CH4 emissions into the atmosphere. Case studies have illustrated that emissions canprofitably be reduced by replacing or retrofitting high-bleed devices with low- or no-bleed devices.Encouraging timely maintenance also has proven to be valuable in ensuring optimal efficiency of theunits.

No-bleed devices are often powered by compressed air. Air-based pneumatic device systems can becost effective, however, their economic use requires a number of conditions to be satisfied. First ofall, conversion to an air-based system over natural gas powered pneumatic devices is most cost-effective when the facilities are very centralised. Even if the devices are centralised, there must beenough spare power generating capacity to push compressed air through the system. A significantcontributing factor dictating whether or not these devices are cost effective is the cost of electricityrequired to compress the air to power the pneumatic devices.

Spirit Energy, a unit of Unocal corporation, which is active throughout the world, invested $60,000 ina pilot project to determine the cost effectiveness of air compressed pneumatic devices. Theydetermined that converting to air-based pneumatic devices saved 5.4 Mcm/day, or 1,964Mcm/year, asavings worth $138,70020.

20 Assuming $2/Mcf (approximately $70.6/Mcm).

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Table 11: Economics of Replacing High-Bleed Pneumatic Devices

Replacing High-Bleed Pneumatic Devices

Replacement Option Cost ($) $Gas saved/year Payback

Replace before end of operationallife

1,350

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Preventative maintenance/detection can be crucial to reducing emissions, for example, fromtransmission systems. Such timely inspections can minimise emissions from normal wear and tearoperations and provide an indication of when parts such as valves and traps should be replaced. Suchregular detection activities also can indicate where the largest emissions sources are, and allowcompanies to prioritise their efforts to focus on the most cost-effective reductions.

Reduction of Flaring

There are several different options for utilising otherwise flared natural gas, including collection andre-injection of the gas in some type of storage facility (e.g. for reservoir pressure maintenance andenhanced oil recovery) or collection for consumption in domestic and/or international markets.Capture and the subsequent storage or re-injection of the gas is the most attractive alternative from anenvironmental perspective, as there are relatively low emissions associated

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Emission Reduction in the Natural Gas Sector Through Project Based Mechanisms

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