Oil and Gas Exploration and Production Greenhouse Gas Protocol

773 San Marin Drive, Suite 2115, Novato, CA 94998 415.899.0700

Oil and Gas Exploration and Production Greenhouse Gas Protocol

Task 2 Report Significant Source Categories

and Technical Review of Estimation Methodologies

Prepared for: Western States Regional Air Partnership

Oil and Gas Greenhouse Gas Protocol Steering Committee

Prepared by ENVIRON International Corporation

773 San Marin Drive, Suite 2115 Novato, CA 94998

and

Science Applications International Corporation (SAIC)

10140 Campus Point Drive San Diego, California 92121

April 22, 2010

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TABLE OF CONTENTS

EXECUTIVE SUMMARY .......................................................................................................... 1

INTRODUCTION......................................................................................................................... 2

OBJECTIVES ............................................................................................................................... 4

SOURCES OF DATA................................................................................................................... 5

GEOGRAPHIC DOMAIN......................................................................................................... 10

GHG EMISSIONS SOURCE CATEGORY RANKINGS...................................................... 41

METHODOLOGIES.................................................................................................................. 74

OVERVIEW OF EPA MANDATORY GHG REPORTING RULE................................... 125

SPECIFIC IMPLICATIONS TO THE OIL AND GAS EXPLORATION AND PRODUCTION INDUSTRY .................................................................................. 128

SUBPART C - GENERAL STATIONARY FUEL COMBUSTION SOURCES............... 130

SUBPART W - OIL AND NATURAL GAS SYSTEMS....................................................... 140

SUBPART NN - SUPPLIERS OF NATURAL GAS AND NATURAL GAS LIQUIDS................................................................................................................... 146

SUBPART PP- SUPPLIERS OF CARBON DIOXIDE ........................................................ 148

PUBLIC COMMENT............................................................................................................... 150

CONCLUSIONS ....................................................................................................................... 151

REFERENCES.......................................................................................................................... 152

APPENDICES

Appendix A: Annotated Table summarizing comments received on methodologies for

estimation of emissions from oil and gas exploration and production source categories

LIST OF TABLES

Table 1. Sources of data used in the screening-level inventories and GHG source

category rankings for each state/province and basin...................................................... 7

Table 2. 2006 production statistics for the San Juan Basin in New Mexico, including San Juan, Rio Arriba, McKinley and Sandoval Counties. ........................................... 11

Table 3. 2007 production statistics for the Permian Basin in New Mexico, including Chaves, Eddy, Lea, Roosevelt, De Baca, Lincoln and Otero Counties. ...................... 13

Table 4. 2007 production statistics for the Raton Basin in New Mexico, including only Colfax County. ............................................................................................................. 15

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Table 5. 2006 production statistics for the Uinta Basin in Utah, including Carbon, Duchesne, Emery, Grand and Uintah Counties. .......................................................... 17

Table 6. 2006 production statistics for the Paradox Basin in Utah, including Garfield, Kane, Paiute, San Juan, Sanpete, Sevier and Wayne Counties.................................... 19

Table 7. 2006 production statistics for the Williston Basin in Montana, including Carter, Custer, Daniels, Dawson, Fallon, Garfield, McCone, Prairie, Richland, Roosevelt, Sheridan, Valley, and Wibaux Counties.................................... 21

Table 8. 2006 production statistics for the North-Central Montana (Great Plains) Basin in Montana, including Blaine, Cascade, Chouteau, Fergus, Glacier, Golden Valley, Hill, Judith Basin, Liberty, Musselshell, Petroleum, Phillips, Rosebud, Teton, Toole, Wheatland, Yellowstone Counties. ....................................... 23

Table 9. 2006 production statistics for the portion of the Powder River Basin in Montana, including Big Horn and Powder River Counties ......................................... 25

Table 10. 2007 production statistics for northern California, including the production counties of San Joaquin, Contra Costa, Solano, Sacramento, Yolo, Sutter, Colusa, Butte, Glenn and Tehama................................................................................ 27

Table 11. 2007 production statistics for California off-shore wells in state waters. ................... 29

Table 12. 2007 production statistics for the San Joaquin Valley region, including production counties of Fresno, Kern, Kings, San Benito, and Tulare. ........................ 31

Table 13. 2007 production statistics for the Southern California region, including production counties of Los Angeles, Orange, Ventura, and Santa Barbara................. 33

Table 14. 2007 production statistics for the province of British Columbia................................. 35

Table 15. 2007 production statistics for the province of Manitoba. ............................................ 37

Table 16. Identification of Production Types and Total Oil and Gas Production for Each Basin.................................................................................................................... 40

Table 17. San Juan (South) Basin ranking of GHG source categories including contributors to top 95% of CO2(e) emissions using a screening-level inventory for the basin. ................................................................................................ 44

Table 18. Uinta Basin ranking of GHG source categories including contributors to top 95% of CO2(e) emissions using a screening-level inventory for the basin. ................ 47

Table 19. California Off-Shore (OCS) ranking of GHG source categories including contributors to top 95% of CO2(e) emissions using a screening-level inventory for OCS sources. .......................................................................................... 50

Table 20. California Offshore Sources (State Waters) ranking of GHG source categories including contributors to top 95% of CO2(e) emissions using a screening-level inventory for offshore sources in State Waters. .................................................. 52

Table 21. San Joaquin Valley Region – Heavy Oil ranking of GHG source categories including contributors to top 95% of CO2(e) emissions using a screening-level inventory for the region....................................................................................... 54

Table 22. San Joaquin Valley Region – Wells drilled in 2007.................................................... 56

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Table 23. San Joaquin Valley Region – Light Oil ranking of GHG source categories including contributors to top 95% of CO2(e) emissions using a screening-level inventory for the region....................................................................................... 57

Table 24. Tight sands gas production ranking of GHG source categories including contributors to top 95% of CO2(e) emissions using a screening-level inventory for the production type................................................................................. 58

Table 25. CBM gas production ranking of GHG source categories including contributors to top 95% of CO2(e) emissions using a screening-level inventory for the production type................................................................................. 61

Table 26. Conventional oil production ranking of GHG source categories including contributors to top 95% of CO2(e) emissions using a screening-level inventory for the production type................................................................................. 64

Table 27. Dry gas production ranking of GHG source categories including contributors to top 95% of CO2(e) emissions using a screening-level inventory for the production type. ........................................................................................................... 67

Table 28. Ranking of significant source categories contributing 95% GHG by state, by area and by production type. ........................................................................................ 71

Table 29 Ranking of significant source categories based on similar production type.................. 72

Table 30. Summary of all methodologies considered for estimation of emissions from the source categories considered in the screening-level inventories and source category rankings. ........................................................................................................ 75

Table 31. Cross Reference of Oil and Gas Source Categories with Mandatory Reporting Rule Elements ............................................................................................................ 128

Table 32. Threshold Analysis for the Oil and Gas Industry Segments...................................... 131

Table 33. Four-Tiered Approach for Calculating CO2 Emissions from Stationary Combustion Sources. ................................................................................................. 132

Table 34. Source Specific Monitoring Methods and Emissions Quantification......................... 142

Table 35. GHG Source Category Ranking (Fugitive Emissions). .............................................. 143

Table 36. Threshold Analysis for NGLs from Processing Plants. .............................................. 146

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LIST OF FIGURES Figure 1. 2006 well locations by well type in the San Juan Basin in New Mexico,

including Rio Arriba, San Juan, McKinley and Sandoval Counties. ........................... 12

Figure 2. 2007 well locations by well type in the Permian Basin in New Mexico, including Chaves, Eddy, Lea, Roosevelt, De Baca, Lincoln and Otero Counties. ...................................................................................................................... 14

Figure 3. 2007 well locations by well type in the Raton Basin in New Mexico, including Colfax, Harding, Mora, and Union Counties. .............................................. 16

Figure 4. 2006 well locations by well type in the Uinta Basin in Utah, including Carbon, Duchesne, Emery, Grand and Uintah Counties.............................................. 18

Figure 5. 2006 well locations by well type in the Paradox Basin in Utah, including Garfield, Kane, Piute, San Juan, Sanpete, Sevier and Wayne Counties ...................... 20

Figure 6. 2006 well locations by well type in the Williston Basin in Montana, including Carter, Custer, Daniels, Dawson, Fallon, Garfield, McCone, Prairie, Richland, Roosevelt, Sheridan, Valley, and Wibaux Counties.................................... 22

Figure 7. 2006 well locations by well type in the North Central Montana (Great Plains) Basin in Montana, including Blaine, Cascade, Chouteau, Fergus, Glacier, Golden Valley, Hill, Judith Basin, Liberty, Musselshell, Petroleum, Phillips, Rosebud, Teton, Toole, Wheatland, Yellowstone Counties. ....................................... 24

Figure 8. 2006 well locations by well type in the portion of the Powder River Basin in Montana, including Big Horn and Powder River Counties. ........................................ 26

Figure 9. 2007 well locations by well type in Northern California. ............................................ 28

Figure 10. 2007 California off-shore well locations (not including any wells located in federal waters in the Outer Continental Shelf)............................................................. 30

Figure 11. 2007 well locations by well type in the San Joaquin Valley, including production counties of Fresno, Kern, Kings, and Tulare and including DOGGR Districts 4 and 5. ........................................................................................... 32

Figure 12. 2007 well locations in Southern California, including the production counties of Los Angeles, Orange, San Bernardino, and Ventura and DOGGR Districts 1, 2 and 3. ...................................................................................................... 34

Figure 13. Current (2009) well locations in British Columbia, showing only active (producing) oil and gas wells. ...................................................................................... 36

Figure 14. Current (2009) well locations in Manitoba, showing only active (producing) oil wells. ....................................................................................................................... 38

Figure 15. Percentage GHG emissions contribution to the San Juan (South) Basin inventory by source category (GHG emissions reported as CO2(e))............................. 45

Figure 16. Percentage GHG emissions contribution to the Uinta Basin inventory by source category (GHG emissions reported as CO2(e)). ................................................. 48

Figure 17. Percentage GHG emissions contribution to the California Off-shore platform inventory (Outer Continental Shelf) by source category (GHG emissions reported as CO2(e)). ....................................................................................................... 51

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Figure 18. Percentage GHG emissions contribution to the California Off-shore platform Inventory (State Waters) by source category (GHG emissions reported as CO2(e)). ....................................................................................................................... 53

Figure 19. Percentage GHG emissions contribution to the San Joaquin Valley Region – Heavy Oil platform inventory by source category (GHG emissions reported as CO2(e)). ..................................................................................................................... 55

Figure 20. Percentage GHG emissions contribution to the San Joaquin Valley Region – Light Oil platform inventory by source category (GHG emissions reported as CO2(e)). ........................................................................................................................ 57

Figure 21. Percentage GHG emissions contribution to the inventory for generic tight sands gas production by source category (GHG emissions reported as CO2(e)). ........................................................................................................................ 59

Figure 22. Percentage GHG emissions contribution to the inventory for generic CBM gas production by source category (GHG emissions reported as CO2(e)). ................... 62

Figure 23. Percentage GHG emissions contribution to the inventory for generic conventional oil production by source category (GHG emissions reported as CO2(e))........................................................................................................................... 65

Figure 24. Percentage GHG emissions contribution to the inventory for generic conventional dry gas production by source category (GHG emissions reported as CO2(e)). ....................................................................................................... 68

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EXECUTIVE SUMMARY

The purpose of this report is to present and describe the greenhouse gas (GHG) screening inventory analysis developed for the Oil & Gas (O&G) Exploration and Production (E&P) sector, for state and provincial members of the Western Climate Initiative (WCI) with E&P activities in their jurisdictions. These screening inventories, by basin and production type, were used to rank GHG source categories associated with E&P operations. Readily and reasonably available methods were used to calculate screening inventory emissions, and then were used to determine the resulting rankings of major sources on both a production type and WCI partner jurisdictional basis. This report is not intended to list, describe, or review GHG emissions calculation methods used for purposes of mandatory or voluntary emissions reporting protocols. Readers are advised that the methods listed in the report are not necessarily comprehensive or the best available for mandatory or voluntary reporting protocols, but are a starting point for further work for those efforts. This O&G E&P GHG source ranking analysis is limited in geographic scope to the four U.S. states and two Canadian provinces with E&P activities in their jurisdictions which are part of the WCI, including the portions of any sovereign tribal nations with these E&P activities, contained wholly or partially within the boundaries of these states and provinces:

• New Mexico • Utah • Montana • California • British Columbia • Manitoba

The analysis and results in this report present source rankings for each basin and production type individually, and also provide a comparison of the significant sources among basins for which data was available and for those basins which have similar activities. These rankings identify significant source categories from the O&G E&P sector from the standpoint of their GHG emissions. Some of the analysis and subsequent guidance is general in nature and may be applicable to O&G production regions beyond these six states and provinces. The prioritizing of emission sources at the basin level is intended as a guide for regulators who are developing mandatory reporting rules, by highlighting the major emitting sources. The specific calculation methods to be used for mandatory reporting will be fine-tuned during the rule development process.

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INTRODUCTION This report presents the analysis and results of the second task in the development of an oil and gas exploration and production greenhouse gas (GHG) protocol. This report references the Background and Scoping paper, completed as part of the first task of this oil and gas (O&G) exploration and production (E&P) GHG protocol. This report focuses on the identification of “significant” source categories from the O&G E&P sector from the standpoint of their GHG emissions (the term “significant” is defined in more detail below), and a discussion of the methodologies used to identify these significant sources. The aim of this work is to provide guidance to the member states and provinces of the Western Climate Initiative (WCI) as these states/provinces draft GHG reporting regulations that would cover this industry and sector. This analysis is intended as guidance only, and is not intended to be used directly in the crafting of the reporting protocols, for which each state/province is responsible individually. This analysis is limited in geographic scope to the four U.S. states and two Canadian provinces which are part of the WCI and which are considered in this analysis, including any sovereign tribal nations contained wholly or partially within the boundaries of these states/provinces:

• New Mexico • Utah • Montana • California • British Columbia • Manitoba

Some of the analysis and subsequent guidance is general in nature and may be applicable to O&G production regions beyond these six states/provinces. The rationale for limiting the scope of this work to the six states/provinces listed above is that these are the states and provinces sponsoring this work who have asked for this guidance in developing their GHG reporting regulations. The basic geographic unit used for developing source category rankings is the geological basin, consistent with previous WRAP-sponsored inventory projects. Production types, equipment usage and configurations and other aspects of O&G field development are assumed to be reasonably uniform within a basin. However, from basin to basin the production types, production levels, and hence the rankings of significant GHG source categories are expected to vary widely. For these reasons, a basin-by-basin analysis is necessary to characterize significant GHG source categories in all of these six states/provinces, since some categories deemed significant in one basin may not be significant in others. In addition, the methodologies used to generate the rankings may vary from state to state and from basin to basin, based on the data available from which to generate the rankings. These considerations are discussed further in this report. This analysis is focused on the six states/provinces listed above, on the identification of significant GHG sources in the O&G E&P sector which are active in these states/provinces, and on a discussion of the methodology used in identifying these significant sources which may also be used as guidance in the development of a reporting regulation which requires the use of some of these methodologies. However, this report will not cover all GHG sources from the O&G E&P sector, or all methodologies available for measuring, estimating or otherwise quantifying GHG emissions from these source categories for the purposes of reporting these GHG emissions. A comprehensive analysis of the quantification methodologies for all O&G E&P sector GHG

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source categories will be presented in the third task of this protocol development project – a voluntary reporting protocol for The Climate Registry (TCR). The third task will address more comprehensively and with more detail the methodologies available to quantify GHG emissions for all source categories in this sector, including discussions of accuracy and the appropriateness of selecting methodologies for all O&G E&P sector GHG source categories. The limited focus of this Task 2 analysis is due to several factors. A comprehensive review of the GHG estimation methodologies available for all O&G E&P source categories, including accuracy, data availability, and measurement methods is not possible within the time frame dictated by the reporting regulation development process. Therefore the six states/provinces listed above have indicated the specific need to focus the development of reporting regulations for this sector on those source categories likely to be significant GHG emitters. These significant source categories may also be those which are part of any future carbon cap and trade programs developed by the WCI members. Finally, the GHG reporting protocol developed for this sector as part of the TCR voluntary program will need to address all source categories and consider all methodologies available for estimating and reporting GHG emissions from these source categories. The ranking of GHG emissions source categories for this sector for the six states/provinces above represents the results of a quantitative analysis and engineering judgment, and attempts to provide this ranking as accurately as possible for the widely varying O&G activities in this geographic domain. These rankings are intended only to provide guidance to these states/provinces, and therefore future analysis or information available to the state/provincial regulating authorities may result in additional source categories being considered for each state’s or province’s reporting regulation, or removal of some source categories from the significant group. The screening-level inventories from which the rankings are developed are not intended to be complete GHG inventories, and are not presented as such. They are used only for purposes of ranking source categories. The methodologies described herein that were used for this ranking and which discuss data availability in the O&G development areas of these states/provinces, are intended only for guidance. Ultimately the individual regulatory agencies may choose other methodologies to use in their GHG reporting regulations.

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OBJECTIVES The specific objectives of this report are to:

(1) Identify significant GHG emissions source categories – this task focuses on the development of screening level inventories of emissions of CO2, CH4, and N2O from oil and gas emissions sources in the six states and provinces within the geographic domain of this analysis, for the purposes of ranking these source categories by GHG emissions. A detailed description is provided of the various basins within each of the states/provinces, production levels for current years, and the types of production occurring in the various basins. This production information and other sources of data used to develop the screening level inventories and the source category rankings are discussed, including data limitations and the subsequent approaches used to address this issue. As presented below, GHG source category rankings were developed for each of the production types occurring in the six states/provinces in this geographic domain, rather than for each basin, since basin-specific information was not available to cover the entire domain.

(2) Identify and discuss methodologies used to rank GHG emissions source categories and recommendations for potential methodologies to be used in reporting regulations – the methodologies used to develop the rankings for each of the production types occurring in the six states/provinces are presented, in addition to a more complete listing for the significant source categories of other methodologies and the criteria used in the ranking for selecting a particular methodology. A detailed analysis, including accuracy of the method and discussion of potential additional measurements that could improve GHG estimates for source categories is intended to form part of the third task, the TCR protocol development, and is not included in this analysis.

(3) Discuss how the significant GHG emissions source categories and their GHG estimation methodologies relate to the recently-released draft Environmental Protection Agency (EPA) GHG reporting rule –the EPA recently released a draft EPA GHG reporting regulation which is analyzed to discuss how this draft regulation would impact the significant source categories identified in this analysis, and what specific methodologies are recommended by the draft regulation for estimation of GHG emissions from these source categories. Other issues of conformity between the recommendations of the screening level analysis and the draft EPA reporting regulation are discussed.

The analyses and data sources for each of the objectives are described in detail below, along with a detailed description of O&G E&P activity and production levels in the six states/provinces considered in this analysis.

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SOURCES OF DATA

A number of data sources were used to obtain production and well statistics for the states/provinces in this analysis, to develop the rankings of source categories and determine the significant sources, and to describe the methodologies used to develop the rankings for the significant source categories. These data sources included past inventory efforts sponsored by WRAP and other agencies for the Intermountain West (the Rocky Mountain States of New Mexico, Utah, Montana) which were able to provide activity estimates and O&G E&P process data for use in the development of the screening level GHG inventories (WRAP, 2005; WRAP, 2007; WRAP, 2008; NMED, 2006). The previous WRAP studies were criteria pollutant emissions inventories although some estimates were developed for GHG emissions. Therefore, additional work was required to estimate GHG emissions using the information gathered as part of the previous WRAP studies. Individual activity data from some of the WRAP projects is confidential and therefore is aggregated and presented at the basin level. In addition, data sources for activity unique to California were obtained, primarily from permit information for on-shore and off-shore oil and gas sources maintained by California’s Air Quality Management or Air Pollution Control Districts (Snyder, 2009; Villalvazo, 2009). Data was obtained for the Canadian provinces from a variety of sources including provincial sources such as British Columbia’s Ministry of Energy, Mines and Petroleum Resources (M. EMPR, 2009), national emissions inventory assessments for GHG’s from Environment Canada (Environment Canada, 2008), and the Canadian Association of Petroleum Producers (CAPP) (CAPP, 2004; CAPP, 2009). In general, two distinct data sources were required for development of the screening-level inventories for each state/province, and for the separate basins within the states: (1) production statistics including well counts by well type, spud counts, and gas and oil production by production type; and (2) activity information including counts of equipment, installed horsepower of engines or total fuel consumption of heaters/boilers, gas composition analyses, activity estimates for venting events and other O&G field data. The production statistics data are available in the U.S. from Oil and Gas Conservation Commissions (OGCC’s) or equivalent in most states, including the four U.S. states included in this geographic domain. These OGCC’s maintain databases of well and production statistics, often at the level of an individual well, that cover the geographic extent of each basin in the four U.S. states. However, significant work is often needed to process this data due to incorrect or missing entries and therefore inherent inaccuracies are present in the summary statistics obtained through OGCC’s. Nevertheless the majority of O&G inventory analysis for criteria pollutants in the Western U.S. has made use of these statistics in some form. It should be noted that for basins that have been the subject of previous criteria pollutant inventory development, summary statistics have already been compiled for a recent year (2006), and this database is referenced directly in this analysis (WRAP, 2008). In addition, the U.S. Department of Energy’s Energy Information Administration (EIA) compiles summary statistics on both produced and marketed gas and oil for all U.S. states in this geographic domain, and this was used for comparison purposes with the data compiled through the OGCC databases (EIA, 2009). For the Canadian provinces, provincial officials have provided detailed summary information on oil and gas production in British Columbia (M. EMPR, 2009). For Manitoba, summary production statistics for the province in recent years were available from both CAPP statistical summaries and from Environment Canada documents (CAPP, 2009; Environment Canada, 2008). The production statistics by

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basin, and state/province were generally available and considered to be of high quality for use in the generation of the screening-level inventories for purposes of ranking GHG source categories. Equipment, process and activity data availability varies widely among the six states/provinces in the geographic domain. For some of the basins in the Intermountain West, very detailed equipment and activity data is available based on previous criteria pollutant inventories sponsored by WRAP. It should be noted that significant additional calculations were necessary to utilize equipment and activity information gathered as part of these inventories and generate GHG emissions for purposes of the rankings. For California O&G development areas, detailed permit data was obtained for off-shore and some on-shore activities that were used to develop the rankings, and again additional calculations were needed to estimate GHG emissions for some source categories. However the data obtained do not cover all of the basins in the four U.S. states, and detailed inventories were not available for the two Canadian provinces. Two approaches were used to address the lack of data for some of the basins or regions in the geographic domain: (1) rankings were developed by production type (e.g. tight sands gas, conventional oil, coal bed methane gas, etc.) using data sources available and then these rankings would be considered applicable to similar production types occurring in other basins; and (2) a final review was conducted of the source category rankings and engineering judgment was used to include or exclude additional source categories which may also be significant for these production types. In conducting the overall review of the rankings in step (2) above, data on O&G companies’ rankings of source categories were used. These rankings were obtained through a data needs request distributed to a number of companies through the coordination of the American Petroleum Institute (API). The analysis for developing the rankings by production type and discussions of production types occurring in the various basins and regions in the geographic domain are discussed further below. Table 1 summarizes the data sources gathered and used in some form for this analysis, organized by state/province and basin, including information on the usage of the data.

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Table 1. Sources of data used in the screening-level inventories and GHG source category rankings for each state/province and basin. State/Province Basin Data Source Comments

San Juan

WRAP criteria pollutant inventories Phases I, II and III

Detailed inventories provided data both on production statistics and equipment, usage, activity, and processes (WRAP, 2005; WRAP, 2007; WRAP, 2008)

Data on company-specific rankings provided through API submission

This data was used qualitatively to evaluate rankings developed for conventional oil and conventional gas production types Permian

New Mexico Oil Conservation Division (NMOCD)

Data on wells, spuds and production obtained through NMOCD “Go-Tech” database (NMOCD, 2009)

Data on company-specific rankings provided through API submission

This data was used qualitatively to evaluate rankings developed for conventional gas and CBM gas production types

New Mexico1

Raton New Mexico Oil Conservation Division (NMOCD)

Data on wells, spuds and production obtained through NMOCD “Go-Tech” database (NMOCD, 2009)

Uinta

WRAP criteria pollutant inventories Phases I, II and III

Detailed inventories provided data both on production statistics and equipment, usage, activity, and processes (WRAP, 2005; WRAP, 2007; WRAP, 2008)

No equipment, activity or process data available

Rankings developed for production types occurring in the Paradox Basin, using data from other basins, are applied to Paradox

Utah1

Paradox Utah Division of Oil, Gas and Mining (UTDOGM)

Data on wells, spuds and production obtained through UTDOGM (UTDOGM, 2009)


Rankings developed for CBM gas, using data from other basins, are applied to Powder River

Powder River Department of Natural Resources and Conservation (DNRC) Board of Oil and Gas

Data on wells, spuds and production obtained through DNRC Board of Oil and Gas database (MTDNRC, 2009)


Rankings developed for production types occurring in Williston Basin, using data from other basins, are applied to Williston Williston Department of Natural

Resources and Conservation (DNRC) Board of Oil and Gas



Rankings developed for production types occurring in Williston Basin, using data from other basins, are applied to Williston

Montana1

Great Plains Department of Natural Resources and Conservation (DNRC) Board of Oil and Gas


California2

Off-shore

Permit data for off-shore platforms obtained from Santa

Follow-up discussions with Santa Barbara APCD staff were conducted to evaluate representativeness of

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State/Province Basin Data Source Comments Barbara APCD platforms selected for GHG emissions

estimates and source category rankings (Snyder, 2009)


Rankings developed for conventional dry gas, using data from eastern part of the D-J Basin applied to Northern California Northern

California California Division of Oil Gas and Geothermal Resources (DOGGR)

Data on wells, spuds and production obtained through DOGGR databases (CADOGGR, 2009)

Permit database for heavy/intermediate oil production sources obtained from the San Joaquin Valley APCD

Permit data contained information on a variety of source categories including equipment, usage, activity and process information. Follow-up discussions held with SJVAPCD staff to obtain gas/oil composition analyses (Villalvazo, 2009)

San Joaquin Valley (Kern County) California Division of

Oil Gas and Geothermal Resources (DOGGR)



Rankings developed for production types occurring in the Los Angeles Basin, using data from eastern part of the D-J Basin, applied to Los Angeles Los Angeles

Basin California Division of Oil Gas and Geothermal Resources (DOGGR)


Ministry of Energy, Mines, and Petroleum Resources (EMPR)

Quantitative data on production statistics, and fuel consumption and flaring/venting losses specific to some source categories provided directly by Ministry staff. Follow-up discussions with Ministry staff were conducted to provide review of source category rankings for BC O&G operations (M. EMPR, 2009)

British Columbia All Production Areas

Canadian Association of Petroleum Producers (CAPP)

Data on wells, spuds and production at the provincial level obtained through CAPP Statistical Handbook database (CAPP, 2009)


Rankings developed for the Williston basin are assumed applicable to the oil production regions in Southern Manitoba Manitoba All Production

Areas Canadian Association of Petroleum Producers (CAPP)

Data on wells, spuds and production at the provincial level obtained through CAPP Statistical Handbook database (CAPP, 2009)

1 Information from WRAP studies were developed for criteria pollutant inventories and additional work is required to develop GHG emissions. Also, some data from the WRAP studies is confidential and can only be presented at the Basin level. 2 Rankings for Northern California and Los Angeles Basins were based on conventional dry gas from the eastern portion of the Denver-Julesburg Basin.

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In addition to the data sources listed in Table 1, which are specific to the state/province and basin or region for which the analysis was conducted, other data sources were identified and used as reference for production information, methodologies for estimating GHG emissions from source categories, and other background information. These data sources included:

• EIA Annual Energy Outlook (AEO) 2009 – provided summary production statistics for the entire U.S. including on- and off-shore production in each state (EIA, 2009)

• API 2004 Compendium of GHG Estimation Methodologies – provided methodology description and some quantitative emissions factors which were used in estimating GHG emissions for the screening level inventories (API, 2004)

• The Climate Registry’s General Reporting Protocol (GRP) – provided reference and methodology information for some source categories (TCR, 2008)

• Environment Canada’s National Inventory Report (NIR): GHG Sources and Sinks in Canada 1990-2006 – provided reference data for GHG estimation for some of the Canadian O&G activities in British Columbia and Manitoba (Environment Canada, 2008)

A more complete set of all data sources used in the analysis is provided in the references section of the report.

April 2010 10

GEOGRAPHIC DOMAIN The geographic domain of this analysis includes the six states/provinces described above, and the basins located within these states/provinces. For the four U.S. states, the screening-level inventories for purposes of the GHG source category rankings exercise were examined at the basin level (in California at the “regional” level as described further below) (USGS, 2008). In previous criteria pollutant inventory efforts for the O&G sector conducted by WRAP (WRAP, 2005; WRAP, 2007; WRAP 2008), the Central States Regional Air Partnership (CENRAP) (CENRAP, 2008), and state and other agencies, the basin level was the basic geographic unit used in the development of these inventories. The basin is considered a reasonable basic geographic unit because it is assumed that within basins for an individual production type, much of the characteristics of the O&G E&P production and the input data used in inventory analyses are relatively uniform. These same characteristics would be expected to vary widely from basin to basin. In the case of the two Canadian provinces, production in these provinces was considered in total without a regional or basin breakdown. An effort was made to obtain data that was specific to the basins within the four U.S. states in the geographic domain. For some of the basins detailed inventories have been compiled with information that was used to develop screening-level GHG emissions estimates, but for other basins such detailed information was not available. Therefore the rankings were developed by production type, rather than exclusively by basin or region, and it was assumed that for an individual production type occurring in a basin where detailed information was not available, the GHG source category rankings from a similar production type occurring in another basin would be used. For example, the analysis of CBM gas production GHG emissions and source category rankings in the San Juan South, San Juan North and Uinta Basins were considered applicable to the Powder River Basin in Montana. This approach recognizes that there may be some source category rankings, even for a single production type, which would vary from basin to basin. Given that the overall goal of this analysis is to develop a list of significant source categories to be presented as guidance to state agencies in the drafting of reporting regulations, emphasis was placed on generating inclusive rankings. Since data was unavailable for some of the basins or production regions in the geographic domain, engineering judgment was used in final revisions of the significant source category lists. It is expected that further follow-up and information requests would be conducted by state agencies in their development of GHG reporting regulations. Below are more detailed descriptions of the production statistics for each of the basins in the geographic domain. It is intended that these descriptions provide the linkage between the GHG source category rankings presented by production type and the characterization of production in the basins relevant to WCI member states/provinces.

April 2010 11

New Mexico New Mexico O&G production occurs primarily in three basins: (1) the San Juan Basin in northwestern New Mexico; (2) the Permian Basin in southeastern New Mexico; and (3) the Raton Basin in north-central New Mexico. Descriptions of the production characteristics of these three basins are provided below. San Juan Basin The San Juan Basin in New Mexico is a mix of tight sands gas and shale gas, and CBM gas production. The basin includes primarily San Juan and Rio Arriba Counties, with some additional minor production in adjacent McKinley and Sandoval Counties. The basin also includes some Navajo Nation and Jicarilla Apache tribal land. Boundaries of tribal land for New Mexico (and for all U.S. states) were obtained from the Institute for Tribal Environmental Professionals (ITEP) (ITEP, 2005). Table 2 below summarizes 2006 production statistics for the San Juan Basin. Gas production is dominated by tight sands gas and CBM gas, with only a very minor contribution from associated gas from older oil wells. Tight sands gas and CBM gas are considered the two significant production types in the San Juan Basin. Figure 1 shows a map indicating 2006 San Juan Basin well locations by well type. Table 2. 2006 production statistics for the San Juan Basin in New Mexico, including San Juan, Rio Arriba, McKinley and Sandoval Counties. Parameter Value Unit

Oil 1,581 Gas Wells (non-CBM) 14,905 CBM Wells 4,163

Active Well Count

TOTAL 20,649 Oil Production 1,002,060 bbl Condensate Production 1,634,751 bbl Oil Production TOTAL 2,636,811 bbl Oil Wells (Associated Gas) 12,136,801 MCF Gas Wells (non-CBM) 507,924,068 MCF CBM Wells 499,953,982 MCF

Gas Production

TOTAL 1,020,014,851 MCF Spuds 919

April 2010 12

Figure 1. 2006 well locations by well type in the San Juan Basin in New Mexico, including Rio Arriba, San Juan, McKinley and Sandoval Counties.

April 2010 13

Permian Basin The Permian Basin in southeastern New Mexico (and extending significantly into western Texas) is comprised primarily of conventional oil production with some conventional gas production. There is significant sour gas production in the Permian Basin, and previous analysis has identified a number of large gas plants in the Permian Basin in New Mexico with SO2 emissions greater than 100 tons per year. The Permian Basin is primarily located in Chaves, Eddy and Lea Counties in southeastern New Mexico, with additional minor O&G production activity in Roosevelt County. Table 3 summarizes 2007 production statistics for the Permian Basin. Permian Basin oil production is significant and represents approximately 89% of 2007 oil production in New Mexico. Gas production in Permian Basin is a combination of associated gas and conventional gas. Figure 2 shows a map indicating 2007 Permian Basin well locations by well type. Table 3. 2007 production statistics for the Permian Basin in New Mexico, including Chaves, Eddy, Lea, Roosevelt, De Baca, Lincoln and Otero Counties. Parameter Value Unit

Oil 18,381 Gas Wells (non-CBM) 6,446 CBM Wells N/A

Active Well Count

TOTAL 24,827 Oil Production 52,157,599 bbl Condensate Production 4,364,429 bbl Oil Production TOTAL 56,522,028 bbl Oil Wells (Associated Gas) 216,857,956 MCF Gas Wells (non-CBM) 302,051,467 MCF CBM Wells N/A MCF

Gas Production

TOTAL 518,909,423 MCF Spuds 781

April 2010 14

Figure 2. 2007 well locations by well type in the Permian Basin in New Mexico, including Chaves, Eddy, Lea, Roosevelt, De Baca, Lincoln and Otero Counties.

April 2010 15

Raton Basin The Raton Basin in New Mexico is composed of primarily CBM activity in several producing formations straddling the Colorado-New Mexico state line. There is also some gas shale activity in the basin. The Raton Basin in New Mexico is located exclusively in Colfax County with respect to O&G production and activities. There is no oil or condensate production in this basin. Table 4 summarizes 2007 production statistics for the Raton Basin. Only conventional gas/gas shale and CBM gas production activity types would be applicable to this basin. Figure 3 shows a map indicating 2007 Raton Basin well locations by well type. Table 4. 2007 production statistics for the Raton Basin in New Mexico, including only Colfax County. Parameter Value Unit

Oil 0 Gas Wells (non-CBM) 199 CBM Wells 374

Active Well Count

Total 573 Oil Production 0 bbl Condensate Production 0 bbl Oil Production Total 0 bbl Oil Wells (Associated Gas) 0 MCF Gas Wells (non-CBM) 13,917,814 MCF CBM Wells 12,896,253 MCF

Gas Production

Total 26,814,067 MCF Spuds 194

April 2010 16

Figure 3. 2007 well locations by well type in the Raton Basin in New Mexico, including Colfax, Harding, Mora, and Union Counties.

April 2010 17

Utah Utah basins considered in this analysis include: (1) the Uinta Basin in the northeastern portion of the state; and (2) the Paradox Basin in the southeastern portion of the state near the Four Corners area. Details of O&G production activities in these basins are provided below. Uinta Basin The Uinta Basin is comprised of three primary O&G production types: conventional oil wells, tight sands gas wells, and CBM gas wells. Oil activity in the Uinta Basin is concentrated primarily in Duchesne County, with some additional production in Uintah County. Tight gas production, which has grown in activity in the last decade, is focused primarily in Uintah County. CBM gas production in Uinta Basin is concentrated only in Carbon and Emery Counties. In addition, some minor production occurs in Grand County. There is a significant portion of the geographic area of the Uinta Basin that is considered a tribal “airshed”, which includes both tribal land as well as state or fee land in which the EPA is the regulatory agency with permitting authority. Tribal land is primarily that of the Uinta and Ouray tribes (ITEP, 2005). Table 5 summarizes 2006 production statistics for the Uinta Basin. Tight sands gas, conventional oil production and CBM gas would all be considered significant production types in the Uinta Basin based on the production data in Table 5. Figure 4 shows a map indicating 2006 Uinta Basin well locations by well type. Table 5. 2006 production statistics for the Uinta Basin in Utah, including Carbon, Duchesne, Emery, Grand and Uintah Counties. Parameter Value Unit

Oil 2,263 Gas Wells (non-CBM) 3,755 CBM Wells 863

Active Well Count

TOTAL 6,881 Oil Production 9,758,247 bbl Condensate Production 1,769,874 bbl Oil Production TOTAL 11,528,121 bbl Oil Wells (Associated Gas) 26,815,062 MCF Gas Wells (non-CBM) 227,404,370 MCF CBM Wells 77,624,904 MCF

Gas Production

TOTAL 331,844,336 MCF Spuds 1,069

April 2010 18

Figure 4. 2006 well locations by well type in the Uinta Basin in Utah, including Carbon, Duchesne, Emery, Grand and Uintah Counties.

April 2010 19

Paradox Basin The Paradox Basin in southeastern Utah is characterized primarily by conventional oil production from a number of active formations, primarily the large Aneth field which lies in Navajo Nation land (ITEP, 2005). The oil production in Paradox has used waterflooding for enhanced oil recovery (EOR) for a number of years, but there is also recent interest in CO2 flooding for EOR. Some minor conventional gas production also occurs in the basin. The Paradox Basin includes Garfield, Kane, Paiute, San Juan, Sanpete, Sevier and Wayne Counties in Southeastern Utah. Table 6 summarizes 2006 production statistics for the Paradox Basin. Given the relatively minor gas production in this basin, and the few gas wells relative to oil wells, conventional oil production with EOR is considered the significant production type in this basin. Figure 5 shows a map indicating 2006 Paradox Basin well locations by well type. Table 6. 2006 production statistics for the Paradox Basin in Utah, including Garfield, Kane, Paiute, San Juan, Sanpete, Sevier and Wayne Counties. Parameter Value Unit


Active Well Count

Total 685 Oil Production 5,989,236 bbl Condensate Production 20,552 bbl Oil Production Total 6,009,788 bbl Oil Wells (Associated Gas) 7,606,718 MCF Gas Wells (non-CBM) 4,840,958 MCF CBM Wells 6,968 MCF

Gas Production


April 2010 20

Figure 5. 2006 well locations by well type in the Paradox Basin in Utah, including Garfield, Kane, Piute, San Juan, Sanpete, Sevier and Wayne Counties.

April 2010 21

Montana Montana O&G production basins include: (1) the Williston Basin; (2) the North-Central Montana Basin (also referred to as the Great Plains Basin); and (3) a small portion of the Powder River Basin. Details of O&G production activities in these basins are provided below. Williston Basin The Williston Basin occupies a large part of eastern Montana (and extends into western North Dakota). It is primarily an oil production basin, with some conventional and unconventional gas production. Oil production is centered on the Bakken Formation, which includes the highly-productive Elm Coulee Field in Richland County. The Williston Basin has had conventional oil E&P activities for some decades, but in the past decade this activity has increased significantly with the application of directional drilling techniques to enhance production of oil from the Bakken Formation. The definition of the boundaries of the Williston Basin vary depending on the source of the definition, but for purposes of this analysis the definition used in previous WRAP criteria pollutant inventories is referenced, which includes Carter, Custer, Daniels, Dawson, Fallon, Garfield, McCone, Prairie, Richland, Roosevelt, Sheridan, Valley, and Wibaux Counties. Portions of Daniels, Roosevelt, Sheridan and Valley Counties lie within the Assiniboine and Sioux Fort Peck Indian Reservation, although there is not significant O&G production from tribal land (ITEP, 2005). Table 7 summarizes 2006 production statistics for the Williston Basin. Conventional oil production with directional drilling is considered a significant production type in this basin, in addition to conventional and unconventional gas production. While there is some CBM production in the Williston Basin using the definition of the basin boundary described above, it is relatively minor compared to gas production from gas wells and associated gas production from oil wells. Figure 6 shows a map indicating 2006 Williston Basin well locations by well type. Table 7. 2006 production statistics for the Williston Basin in Montana, including Carter, Custer, Daniels, Dawson, Fallon, Garfield, McCone, Prairie, Richland, Roosevelt, Sheridan, Valley, and Wibaux Counties. Parameter Value Unit

Oil 1,892 Gas Wells (non-CBM) 906 CBM Wells 2

Active Well Count

Total 2,800 Oil Production 33,596,745 bbl Condensate Production 71,672 bbl Oil Production Total 33,668,417 bbl Oil Wells (Associated Gas) 19,610,760 MCF Gas Wells (non-CBM) 24,155,287 MCF CBM Wells 52,648 MCF

Gas Production


April 2010 22

Figure 6. 2006 well locations by well type in the Williston Basin in Montana, including Carter, Custer, Daniels, Dawson, Fallon, Garfield, McCone, Prairie, Richland, Roosevelt, Sheridan, Valley, and Wibaux Counties.

April 2010 23

North-Central Montana (Great Plains) Basin The North-Central Montana (Great Plains) Basin includes some conventional oil production and some tight gas production from low-pressure shallow wells (3,000-6,000 feet depth). The production in the basin occurs primarily in northern counties on the U.S.-Canada border, including Glacier, Poole, Ponder, Liberty, Hill, Blaine and Phillips Counties. Due to low pressures, gas production in the North-Central Montana Basin tends to be grouped around particularly high-producing fields and formations. This basin also lacks the extensive O&G gathering and processing infrastructure developed in other basins in the Intermountain West. The western development area of the North-Central Montana Basin lies partially in Blackfeet Indian tribal land. Chippewa Cree, Assiniboine and Gros Ventre tribal land also lies within parts of the North-Central Montana Basin (ITEP, 2005). Table 8 summarizes 2006 production statistics for the North-Central Montana Basin. Conventional oil production and gas shale production are the two significant production types occurring in this basin. CBM production is considered insignificant compared to gas production from tight gas wells. Figure 7 shows a map indicating 2006 North-Central Montana Basin well locations by well type. Table 8. 2006 production statistics for the North-Central Montana (Great Plains) Basin in Montana, including Blaine, Cascade, Chouteau, Fergus, Glacier, Golden Valley, Hill, Judith Basin, Liberty, Musselshell, Petroleum, Phillips, Rosebud, Teton, Toole, Wheatland, Yellowstone Counties. Parameter Value Unit

Oil 2,135 Gas Wells (non-CBM) 4,296 CBM Wells 1

Active Well Count

Total 6,432 Oil Production 1,804,589 bbl Condensate Production 13,585 bbl Oil Production Total 1,818,174 bbl Oil Wells (Associated Gas) 541,262 MCF Gas Wells (non-CBM) 55,876,102 MCF CBM Wells 27,497 MCF

Gas Production


April 2010 24

Figure 7. 2006 well locations by well type in the North Central Montana (Great Plains) Basin in Montana, including Blaine, Cascade, Chouteau, Fergus, Glacier, Golden Valley, Hill, Judith Basin, Liberty, Musselshell, Petroleum, Phillips, Rosebud, Teton, Toole, Wheatland, Yellowstone Counties.

April 2010 25

Powder River Basin The majority of the Powder River Basin, including many of the highly productive fields, lie in northeastern Wyoming, with the exception of Big Horn and Powder River Counties in Montana. The majority of this production is CBM gas, and the majority of the CBM gas production is in Big Horn County. There are some older conventional oil wells in Powder River County Montana with annual oil production of approximately 250,000 barrels. A significant portion of Big Horn County lies within the Crow and Northern Cheyenne nations’ tribal land, but the majority of O&G production does not occur on tribal land in this basin (ITEP, 2005). Table 9 summarizes 2006 production statistics for the portion of the Powder River Basin in Montana. CBM gas production is considered the most significant production type in this basin, with some minor conventional oil production. This is an area with significant exploration activity in recent years, as demonstrated by the large number of spuds in the two Montana counties of the Powder River Basin, relative to the number of active CBM wells in the basin. Figure 8 shows a map indicating 2006 Powder River Basin well locations by well type. Table 9. 2006 production statistics for the portion of the Powder River Basin in Montana, including Big Horn and Powder River Counties. Parameter Value Unit


Active Well Count

Total 881 Oil Production 247,916 bbl Condensate Production 0 bbl Oil Production Total 247,916 bbl Oil Wells (Associated Gas) 11,560 MCF Gas Wells (non-CBM) 89,886 MCF CBM Wells 11,755,363 MCF

Gas Production


April 2010 26

Figure 8. 2006 well locations by well type in the portion of the Powder River Basin in Montana, including Big Horn and Powder River Counties.

April 2010 27

California California has a number of O&G production regions and production types. The US Geological Survey (USGS) basin boundary definitions, which were used for other basins described above, were not applied to California. The USGS definitions included a large number of basins, some of whose boundaries crossed through production regions in California likely to have similar characteristics. Because the USGS basin definitions proved intractable, California production was divided into 4 broad regions with the goal of accurately characterizing the major production types occurring in California. These include: (1) northern California; (2) California off-shore; (3) San Joaquin Valley (primarily Kern County); and (4) southern California (including the Los Angeles Basin). Details of O&G production activities in the four California regions are provided below. Northern California Northern California gas production is concentrated in several fields in the Sacramento Valley, including Union Island, McMullin Ranch and Vernalis. These are gas reservoirs in sandstone, and mostly dry gas is produced. The majority of the gas wells in this region are concentrated in Solano, Sacramento, Colusa, Sutter, Glen and Tehama Counties stretching approximately north-south through this region. The California DOGGR defines this region of O&G development as District 6. There are some small areas of tribal land in District 6, but not in the gas production regions. Table 10 summarizes 2007 production statistics for northern California dry gas production. The gas production in this region is considered to be conventional gas production for purposes of this analysis. Figure 9 shows a map indicating 2007 northern California well locations by well type. Table 10. 2007 production statistics for northern California, including the production counties of San Joaquin, Contra Costa, Solano, Sacramento, Yolo, Sutter, Colusa, Butte, Glenn and Tehama. Parameter Value Unit

Oil 20 Gas Wells (non-CBM) 1,312 CBM Wells N/A

Active Well Count

Total 1,332 Oil Production 16,078 bbl Condensate Production 43,709 bbl Oil Production Total 16,078 bbl Oil Wells (Associated Gas) 0 MCF Gas Wells (non-CBM) 82,018,313 MCF CBM Wells N/A MCF

Gas Production


April 2010 28

Figure 9. 2007 well locations by well type in Northern California.

April 2010 29

California Off-Shore California has off-shore O&G development within state waters off the central and southern coasts of California. Off-shore wells in state waters generated approximately 6% of California’s total 2007 oil production, and approximately 2% of California’s total 2007 gas production. Because of the unique configurations of off-shore platforms relative to on-shore O&G activities, off-shore production in California is treated as its own production type. Table 11 summarizes 2007 production statistics for California off-shore O&G production. Figure 10 shows a map indicating 2007 California off-shore well locations. It should be noted that there are numerous wells associated with each location. Table 11. 2007 production statistics for California off-shore wells in state waters. Parameter Value Unit

Oil 1,105 Gas Wells (non-CBM) N/A CBM Wells N/A

Active Well Count

Total 1,105 Oil Production 14,677,995 bbl Condensate Production N/A bbl Oil Production Total 14,677,995 bbl Oil Wells (Associated Gas) 6,887,939 MCF Gas Wells (non-CBM) 312,459 MCF CBM Wells N/A MCF

Gas Production


April 2010 30

Figure 10. 2007 California off-shore well locations (not including any wells located in federal waters in the Outer Continental Shelf).

April 2010 31

San Joaquin Valley Production in the San Joaquin Valley was considered separately from other production regions in California. The majority of this production occurs in Kern County, and consists of both conventional oil and heavy oil production. Kern County represented 76% of all on-shore oil production in California in 2007. As discussed in the background and scoping paper, heavy oil production in this region involves GHG emissions source categories unique to this type of production. For this reason this production type is considered separately. Light oil production in the San Joaquin Valley is treated as conventional oil production for purposes of the ranking analysis discussed below (it should be noted that light oil production in California is sometimes referred to as intermediate oil production, considering the API gravity of the oil). For purposes of this analysis, the San Joaquin Valley region encompasses DOGGR Districts 4 and 5. Table 12 summarizes 2007 production statistics for San Joaquin Valley O&G production. Figure 11 shows a map indicating 2007 San Joaquin Valley well locations. Table 12. 2007 production statistics for the San Joaquin Valley region, including production counties of Fresno, Kern, Kings, San Benito, and Tulare. Parameter Value Unit

Oil 42,765 Gas Wells (non-CBM) 208 CBM Wells N/A

Active Well Count

Total 42,973 Oil Production 172,458,926 bbl Condensate Production 30,835 bbl Oil Production Total 172,489,761 bbl Oil Wells (Associated Gas) 177,086,187 MCF Gas Wells (non-CBM) 8,758,703 MCF CBM Wells N/A MCF

Gas Production

Total 185,844,890 MCF Spuds 2,968

April 2010 32

Figure 11. 2007 well locations by well type in the San Joaquin Valley, including production counties of Fresno, Kern, Kings, and Tulare and including DOGGR Districts 4 and 5.

April 2010 33

Southern California The majority of O&G production in southern California is conventional oil production, with negligible primary gas production. Major oil fields include the Wilmington, Huntington Beach and Torrance Fields. Oil production in this region of California has been in decline for decades, but still accounted for approximately 18% of 2007 on-shore oil production in California. This region includes oil production in heavily urbanized areas which utilizes some field practices unique to this region, however for purposes of the GHG emissions source category ranking, southern California oil production is considered conventional oil. In addition to oil production in Los Angeles and Orange Counties, defined as District 1 by the DOGGR, this analysis also considers on-shore production in Ventura, and portions of Los Angeles Counties, defined as District 2 by the DOGGR, to be part of the Southern California region. Table 13 summarizes 2007 production statistics for the Southern California O&G production region, including DOGGR Districts 1, and 2. Figure 12 shows a map indicating 2007 Southern California well locations. Table 13. 2007 production statistics for the Southern California region, including production counties of Los Angeles, Orange, and Ventura. Parameter Value Unit

Oil 7,655 Gas Wells (non-CBM) 12 CBM Wells N/A

Active Well Count

Total 7,667 Oil Production 46,012,798 bbl Condensate Production N/A (included in oil) bbl Oil Production Total 46,012,798 bbl Oil Wells (Associated Gas) 25,356,727 MCF Gas Wells (non-CBM) 334,928 MCF CBM Wells N/A MCF

Gas Production


April 2010 34

Figure 12. 2007 well locations in Southern California, including the production counties of Los Angeles, Orange, San Bernardino, and Ventura and DOGGR Districts 1, 2 and 3.

April 2010 35

British Columbia Production of oil and gas in British Columbia was not considered on the basin level, but rather for the province as a whole. The primary production region of British Columbia is the northeast corner of the province, from the Western Canadian Sedimentary Basin. There is conventional oil, and unconventional gas (mainly tight sands gas, with some shale gas and minor coal bed gas) production in this region, however the conventional oil production has been in decline for some time. Approximately 70% of British Columbia’s current natural gas production is conventional and 30% is unconventional. The proportion and volumes of unconventional tight gas and gas shale gas production are expected to increase substantially throughout the next decade. Discussions with staff at the Ministry of Energy, Mines and Petroleum Resources indicated that the focus of production, and therefore the focus for the screening level inventories and significant GHG source categories, is on gas shale. For purposes of this analysis, British Columbia’s gas shale activities are treated as a separate production type, however they resemble conventional gas and tight sands gas activities with respect to the GHG emissions source categories likely to be significant. Further input was provided by the Ministry to help refine the significant source category rankings for this production type. Table 14 summarizes 2007 production statistics for British Columbia O&G production. Detailed well-level data was available for the province through the British Columbia Oil and Gas Commission (BC Oil and Gas Commission, 2009). Current (2009) well locations are shown in Figure 13. Table 14. 2007 production statistics for the province of British Columbia. Parameter Value Unit

Oil 1,078 Gas Wells (non-CBM) 6,607 CBM Wells N/A (included in gas wells)

Active Well Count

Total 7,685 Oil Production 12,824,505 bbl Condensate Production 1,979,194 bbl Oil Production Total 14,803,699 bbl Oil Wells (Associated Gas) N/A (included in gas wells) MCF Gas Wells (non-CBM) 1,127,689,798 MCF CBM Wells N/A (included in gas wells) MCF

Gas Production

Total 1,127,689,798 MCF Spuds 827

April 2010 36

Figure 13. Current (2009) well locations in British Columbia, showing only active (producing) oil and gas wells.

April 2010 37

Manitoba Production of oil and gas in Manitoba was not considered on the basin level, but rather for the province as a whole. O&G activity in Manitoba is primarily concentrated in the south of the province including the Sinclair, Pierson and Waskada fields. These are primarily conventional oil wells and are assumed to be similar in characteristics to other fields in the Williston Basin, particularly the oil wells tapping the Bakken Formation. Some of the oil wells in Manitoba also tap the Bakken Formation, and thus the production types in Manitoba are expected to be similar in nature to those in Williston Basin. This assumption was consistent with overview information on Manitoba oil development provided by staff at Manitoba Science, Technology, Energy and Mines – Petroleum Branch (MB Petroleum Branch, 2009a). Table 15 summarizes 2007 production statistics for Manitoba O&G production. Detailed well-level data was available for the province through the Manitoba Science, Technology, Energy and Mines - Petroleum Branch (MB Petroleum Branch, 2009b). Figure 14 shows a map indicating current (2009) Manitoba well locations. Table 15. 2007 production statistics for the province of Manitoba. Parameter Value Unit

Oil 2,576 Gas Wells (non-CBM) 0 CBM Wells N/A (included in gas wells)

Active Well Count

Total 2,576 Oil Production 8,104,421 bbl Condensate Production 0 bbl Oil Production Total 8,104,421 bbl Oil Wells (Associated Gas) N/A (included in gas wells) MCF Gas Wells (non-CBM) 0 MCF CBM Wells N/A (included in gas wells) MCF

Gas Production

Total 0 MCF Spuds 345

April 2010 38

Figure 14. Current (2009) well locations in Manitoba, showing only active (producing) oil wells.

April 2010 39

Summary The basin-level descriptions above for the six states/provinces in the geographic domain of this analysis are intended to provide an indication of the types of O&G production occurring in these states/provinces. This is done for the purpose of identifying production types for which a GHG emissions source category ranking is presented in the following section. Inventory data is not available in sufficient detail on each of these basins to provide a basis from which to generate GHG emissions source category rankings unique to each basin. This is a limitation of this analysis. Some basins have been previously inventoried for criteria pollutants in regional and state/provincial efforts, and where activity and other data are available, they are used. Where a detailed inventory, with activity and equipment information and detailed characterization of E&P processes, is not available it is assumed that the rankings for a similar production type in another basin are applicable. The descriptions of production types in the basins above allow for a linkage between the rankings and the basins to which they would apply. The following production types have been identified for the entire geographic domain of this analysis:

• Tight sands (unconventional) gas production • Conventional gas production • CBM gas production • Gas shale (British Columbia) • Conventional oil production • Heavy oil production (California – San Joaquin Valley) • Off-shore oil production (California)

Table 16 below provides a listing of all Basins and types of production in each basin. The table also provides the total production of oil and gas within each basin. Due to lack of data we were not able to provide a breakdown of production for each of the production types (conventional gas, CBM gas, tight sands etc, within each Basin but the total oil and gas production totals will provide the reader with a comparison of the total activities among the Basins. The following section describes the results of the rankings of GHG emissions source categories using available data, and describes the production types (and in some cases the specific basins) to which these rankings are applicable.

April 2010 40

Table 16. Identification of Production Types and Total Oil and Gas Production for Each Basin. Gas Production Oil Production

State or Province Basin

Conv. Gas

CBM Gas

Associated Gas

Tight Sands

Gas Oil

Shale

Total Production (MCF) x 106

Conv. Oil Condensate

Heavy Oil

Offshore Oil

Total Production (bbl) x 106

San Juan x x x x 1,020 x x 3.0 Permian x x 519 x x 57.0

New Mexico

Raton x x 27 0.0 Uinta x x x x 332 x x 11.0 Utah Paradox x x x 12 x x 6.0 Powder River x x x 12 x 0.3 Williston x x x 44 x x 34.0 Montana

Great Plains x x x 56 x x 1.0 Off-shore x x 7 x x x 15.0 Northern California x 82 x x 0.0 San Joaquin Valley (Kern County) x x 169 x x x 172.0

California

Los Angeles Basin x x 26 x x x 46.0

British Columbia

All Production Areas x x 1,128 x x 15.0

Manitoba All Production Areas 0 x 8.0

April 2010 41

GHG EMISSIONS SOURCE CATEGORY RANKINGS The primary focus of this Task 2 report is to provide a ranking of quantifiable O&G E&P GHG emissions source categories for the various production types that are active within the six states/provinces that form the geographic domain of this analysis. These rankings are conducted by basin, region, or by production type, depending on the availability of data as described in more detail below. The purpose of these rankings is to provide guidance to state/provincial regulatory agencies as to the most significant source categories of GHG emissions from this sector – states and provinces may then choose to focus their efforts in developing reporting regulations on these significant source categories. These rankings are based on screening-level inventories of CO2, CH4 and N2O emissions (note that the other 3 Kyoto GHG’s are not included in this screening-level analysis) for basins, regions, or for a production type. There is significant uncertainty associated with the screening-level inventories, and they are not intended to represent the level of accuracy that would result from inventory data gathered through a detailed reporting protocol. Rather, these screening-level inventories are intended to be used as a guide to direct state/provincial agencies to focus on the most significant source categories for the O&G E&P sector. The screening-level inventories are not able to estimate GHG emissions from all source categories as described in the Background and Scoping paper. Limitations in the source categories that could be included in the screening-level inventories arise from three factors: (1) lack of activity and other input data from which to estimate GHG emissions for a particular source category; and (2) lack of a tractable methodology for estimating GHG emissions for a particular source category; and (3) emissions from source categories which are to be reported through other protocols (e.g. mobile sources). It should also be noted that indirect emissions from electricity and heat/steam imports – Scope 2 emissions – are not included in these screening-level inventories. The screening-level inventories focus on direct – Scope 1 – emissions from this sector. It is recommended that Scope 2 emissions be considered significant for this sector in general as states/provinces develop GHG reporting regulations. Screening-level inventories are developed for the three GHGs listed above, and summed to obtain the CO2 equivalent emissions by source category. Because screening level inventories were used, specific emissions are not identified for each source category. However, it should be noted that the primary emissions from combustion sources are CO2 and to a lesser degree N2O and CH4 and the primary emissions from venting and fugitive sources are CH4 and to a lesser degree CO2. The percentage contribution of each source category to the basin, region or production type total are tabulated and these percentages are presented below. For purposes of this analysis, those ranked source categories whose combined contribution to the GHG inventory for a basin, region or production type is 95% or greater are considered “significant”. This definition of significance was used for this screening- level approach in consideration of the definition that the California Air Resources Board (CARB) uses in its GHG reporting regulation for facilities (CARB, 2009). CARB’s “material misstatement” definition for a facility was considered a reasonable threshold for significance on a basin-wide or region-wide level. The inventories for basins, regions or production types were evaluated in a qualitative manner to determine if inclusion of any additional source categories in the “significant” group would be warranted. This was done for source categories that were considered potentially significant, but for which activity and input data at the basin or region level did not exist for purposes of

April 2010 42

estimating GHG emissions. Engineering judgment was used to determine if these source categories should be included as significant, with an emphasis on developing an inclusive list of significant source categories. If further information on these source categories becomes available to state/provincial regulatory agencies that would indicate that these categories are not significant for a particular basin or region, these agencies may choose not to consider these categories further. There may be additional source categories which state/provincial regulatory agencies may determine are significant for a basin or region, and which these agencies may choose to include in their reporting regulation development efforts. For example, sources of GHG emissions associated with well testing such as seismic testing, associated vehicles with well exploration may be significant in specific areas. Additionally, sources which are currently controlled in some areas may not be listed as significant but in other areas with less control may be significant. It should be noted again that the purpose of the screening-level inventories and rankings is to determine significant GHG source categories from the O&G E&P sector, and this information would be provided as guidance and used to assist states/provinces in the development of GHG reporting regulations. Where possible, the screening-level inventories were developed for individual basins (in California, for individual “regions”). This was possible for basins for which previous detailed criteria pollutant inventories of O&G E&P activities had been compiled, or for California regions in which detailed permit data was available and compiled by California air quality districts. For the geographic domain of this analysis, this included:

• San Juan (South) Basin in New Mexico – previously inventoried in the WRAP Phase I, II and III projects as well as through the work of the Four Corners Air Quality Task Force (WRAP, 2005; WRAP, 2007; WRAP, 2008; NMED, 2006)

• Uinta Basin in Utah – previously inventoried in the WRAP Phase I, II and III projects (WRAP, 2005; WRAP, 2007; WRAP, 2008)

• California Off-Shore Region – detailed permit data for a number of off-shore platforms were made available through the Santa Barbara APCD (Snyder, 2009)

• California San Joaquin Valley Region – detailed permit data and inventories of heavy oil and light oil production were made available through the San Joaquin Valley APCD (Villalvazo, 2009)

Previous detailed inventories or detailed activity data for O&G production were not available for the following basins or regions: the Permian and Raton Basins in New Mexico; the Paradox Basin in Utah; the Williston, Powder River, and North-Central Montana Basins in Montana; the Northern and Southern California Regions; and the provinces of British Columbia and Manitoba. For these basins and regions where no detailed activity was available, the section above identified the production types occurring in these regions and inventories from other basins or regions were used as surrogates for the production type occurring in these basins or regions. These surrogates by production type included:

• CBM Gas – data from the San Juan (North) Basin in Colorado, and CBM activity in parts of San Juan South and Uinta Basins were used as surrogates for CBM gas production rankings

• Conventional Gas – data from eastern Denver-Julesburg Basin (primarily Yuma County) were used as surrogates for conventional gas production and were compared to GHG source category rankings for conventional gas production obtained from some companies operating in the Permian Basin

April 2010 43

• Conventional Oil – data from San Joaquin Valley light oil production were used as surrogates for conventional oil production

• Gas Shale (British Columbia) – data from the San Juan (South) and Uinta Basin tight sands gas development areas were used as surrogates for gas shale activity in British Columbia, with additional review by Ministry of Energy, Mines and Petroleum Resources staff (M. EMPR, 2009)

The use of surrogates by production type introduces additional uncertainty into the GHG rankings, and so some additional qualitative evaluation of the rankings was conducted for those basins or regions where these surrogates were used. The GHG emissions source category rankings are first presented by basin or region, where detailed activity data was available and could be used to prepare basin- or region-specific screening-level inventories and the associated rankings. Following this are rankings by production type using surrogates from other basins or regions. A brief discussion is provided for each set of rankings. In addition to rankings, the quality of the data used to provide the rankings was scored as High Medium or Low. Criteria used for scoring the quality of data were based on availability and quality of data in the specific region or specific category. For example, detailed activity data was available for compressor engines, heaters and boilers and wellhead fugitives in the San Juan Basin from a number of prior studies that developed inventories of specific equipment and its configuration and characteristics, and therefore these categories for the San Juan Basin received a score of “High”. Where data for a specific source category for a specific basin or region were only sporadically available, and it was necessary to scale emissions based on production or other parameters in a region or category, a lower score was assigned to that ranking. Overall scoring for those categories where data was not available and where surrogates were used from other basins or regions also received a lower ranking. For example, the screening-level inventories and rankings for the CBM production type were generated by averaging inventory and GHG emissions data from several CBM production regions, to generate a single set of rankings that were considered representative of this production type. In these cases, quality of data received a lower score because detailed data specific to a particular basin or region were not available. It should be noted that the scoring of data quality is qualitative not quantitative and relies on engineering judgment of some of the criteria mentioned above as applied to data gathered through previous inventory efforts that were used as the basis for generating the screening-level inventories in this analysis.

April 2010 44

San Juan (South) Basin – New Mexico The San Juan (South) Basin in northwestern New Mexico has a combination of tight sands gas, CBM gas and some oil production. This basin has been extensively studied in past WRAP criteria pollutant inventory efforts (Phases I, II and III) as well as by the Four Corners Air Quality Task Force (WRAP, 2005; WRAP, 2007; WRAP, 2008; NMED, 2006). These studies provide sufficient activity, equipment and process information to generate a screening-level GHG inventory for the San Juan (South) Basin. This screening-level inventory was developed for 2006, the latest year for which the activity information was gathered from previous studies. Results of the rankings by source category for the basin are presented below in Table 17 as a percentage of the total CO2(e) emissions from all O&G E&P source categories included in the screening-level inventory for this basin. Table 17. San Juan (South) Basin ranking of GHG source categories including contributors to top 95% of CO2(e) emissions using a screening-level inventory for the basin.

Source Category1

(See Footnote 1) % Contribution Quality of Data2

(See Footnote 2) Notes

Permitted Compressor Engines3 24.5% H See Footnote 3Well Completion Venting3 17.8% M See Footnote 3Permitted Heaters/Boilers3 13.9% H See Footnote 3Unpermitted Compressor Engines3 13.0% H See Footnote 3Permitted NG Turbines3 7.4% H See Footnote 3Well Blowdowns3 7.2% M See Footnote 3Unpermitted Heaters/Boilers3 6.8% M See Footnote 3Workover Rigs3 1.6% M See Footnote 3Flaring3 1.2% L See Footnote 3Artificial Lift Engines3 1.2% M See Footnote 3Wellhead Fugitives3 1.1% H See Footnote 3CBM Pump Engines3 0.9% M See Footnote 3Pneumatic Devices3 0.8% M See Footnote 3Drill Rigs3 0.7% M See Footnote 3Misc. Engines3 0.6% L See Footnote 3Well Recompletion Venting3 0.4% M See Footnote 3Compressor Start Up and Shutdown3 0.4% L See Footnote 3Condensate Tanks3 0.1% H See Footnote 3Salt Water Disposal Engine Emissions3 0.1% L See Footnote 3

Pneumatic Pumps3 0.1% M See Footnote 3Permitted Fugitives3 0.1% M See Footnote 3Permitted Flares3 0.1% M See Footnote 3Permitted Generators3 0.0% M See Footnote 3Oil Tanks3 0.0% H See Footnote 3Dehydrators3 0.0% M See Footnote 3Permitted Thermal Oxidizers (Sulfur)3 0.0% H See Footnote 3

1 Yellow highlighting indicates source categories in the top 95% 2 Scoring: H=High, M=Medium, L=Low 3 These source category rankings are based on screening-level inventories that were not able to address all source categories due to data gaps and missing input information. Quality of the data used is also indicated in the table, and needs to be considered when applying the results of this ranking to other analyses.

April 2010 45

The results of the rankings are also displayed below in Figure 15.

% CO2(e) Contribution by source category for South San Juan Basin, New Mexico

Fugitives0.88%

Drill Rigs0.40%

Flaring1.44%

CBM Pump Engines0.84%

Pneumatic Devices0.83%

Workover Rigs1.83%

Artificial Lift Engines1.00%

Unpermitted Heaters/Boilers6.88%

Well Blowdowns7.17%

Permitted NG Turbines7.87%

Permitted Compressor Engines 24.45%

Well Completion Venting17.75%Permitted Heaters/Boilers

13.93%

Unpermitted Compressor Engines13.50%

Permitted Compressor Engines

Well Completion Venting

Permitted Heaters/Boilers

Unpermitted Compressor Engines

Permitted NG Turbines

Well Blowdowns

Unpermitted Heaters/Boilers

Workover Rigs

Flaring

Artificial Lift Engines

Fugitives

CBM Pump Engines

Pneumatic Devices

Drill Rigs

Misc Engines

Well Recompletion Venting

Compressor Start Up andShutdownCondensate Tanks

Salt Water Disposal Engines

Pneumatic Pumps

Permitted Fugitives

Permitted Flaring

Permitted Generators

Oil Tanks

Dehydrators

Permitted Thermal Oxidizer(Sulfur)

Figure 15. Percentage GHG emissions contribution to the San Juan (South) Basin inventory by source category (GHG emissions reported as CO2(e)). Discussion Some source categories were not considered in this ranking. These include:

• Mobile sources – with the exception of off-road mobile sources such as drill and workover rigs, on-road and off-road mobile sources were not considered in this GHG emissions source category ranking for San Juan (South) Basin.

• Water treatment – evaporation ponds, degassing of drilling mud, water storage tanks and water storage pits were not considered in this analysis. For most of these source categories, neither sufficient activity data nor a tractable methodology was identified to estimate GHG emissions from these source categories. It should be noted that an analysis was conducted to try to quantify CH4 emissions from produced water tanks using two methods: (1) a general emissions factor from the API Compendium (API, 2004); and (2) specific E&P TANKS runs using water composition data collected as part of the WRAP Phases I, II and III studies (WRAP, 2005; WRAP, 2007; WRAP, 2008). In both cases the calculations would show that water tanks are not a significant source category, but the uncertainty in these calculations did not allow for inclusion of water tanks as a quantified source category in the rankings for this basin above.

April 2010 46

• Pipelines – pipeline fugitives and pipeline blowdowns were not included in the GHG rankings above, but both would fall into the general fugitives and blowdowns categories, which would likely represent a higher percentage contribution to CO2(e) emissions for this basin if these were estimated for pipelines. Insufficient activity data was available to estimate a volume of gas vented during a pipeline blowdown or the frequency of these events. Total mileages for the San Juan (South) pipeline infrastructure were not known nor were the components located on these pipelines: therefore a total pipeline fugitive emissions estimate was not possible. It would be necessary to obtain such data from the pipeline companies and other producers that own and operate gathering pipelines, as well as detailed information on the frequency of blowdown events and other venting events along the pipeline network.

• Acid gas removal – GHG emissions from amine units were not estimated in this analysis, however activity data gathered for this basin as part of the WRAP Phases I, II and III studies indicated that these are not used significantly in the San Juan (South) Basin for field operations (WRAP, 2005; WRAP, 2007; WRAP, 2008). They may be used more extensively in gas processing plants.

• Fracing – venting of gas associated with well completions and recompletions is captured in the ranking analysis above, as are the large mobile rigs used to work over a well (“workover rigs”), for example when additional drilling is needed. However, the large mobile pumps used in the actual hydraulic fracturing operations are not included in this analysis. Activity and configuration data for these pumps (including horsepower, load factors, usage for a representative fracing operation, fuel type, etc.) were not available as part of the WRAP Phases I, II and III inventory projects (WRAP, 2005; WRAP, 2007; WRAP, 2008). It should be noted that WRAP is sponsoring an oil and gas mobile source pilot project aimed at better quantifying the activity associated with O&G mobile sources including these pumps.

The significant GHG source categories determined from this ranking analysis include both “permitted” and “unpermitted” sources. This refers to sources permitted by either New Mexico Environment Department (NMED) or the EPA (Part 71 for large sources on tribal land). EPA-administered permitted sources were either large gas processing plants or large compressor stations. NMED-administered permits included both large point sources similar to the EPA permits, and some smaller compressor stations. Workover rigs were a significant source category since gas wells in the San Juan Basin require frequent workovers. The fugitives source category included in the significant GHG emissions source category refers to wellhead fugitives from wellhead components including compressors. Fugitives from gas processing plants and large compressor stations were classified as “permitted fugitives” for this analysis.

April 2010 47

Uinta Basin – Utah The Uinta Basin in northeastern Utah has a combination of tight sands gas, CBM gas and conventional oil production. This basin has also been extensively studied in past WRAP criteria pollutant inventory efforts (Phases I, II and III) (WRAP, 2005; WRAP, 2007; WRAP, 2008). These studies provided the activity, equipment and process information to generate a screening-level GHG inventory for this basin. This screening-level inventory was developed for 2006, the latest year for which the activity information was gathered from previous studies. Results of the rankings by source category for the basin are presented below in Table 18 as a percentage of the total CO2(e) emissions from all O&G E&P source categories included in the screening-level inventory for this basin. Table 18. Uinta Basin ranking of GHG source categories including contributors to top 95% of CO2(e) emissions using a screening-level inventory for the basin.

Source Category1



Pneumatic Devices3 32.2% M See Footnote 3 Heaters/Boilers3 21.9% H See Footnote 3 Pneumatic Pumps3 15.6% M See Footnote 3 Unpermitted Compressor Engines3 6.3% H See Footnote 3 Permitted Compressor Engines3 5.9% H See Footnote 3 Artificial Lift Engines3 5.6% M See Footnote 3 Wellhead Fugitives3 4.1% M See Footnote 3 Drill Rigs3 3.8% M See Footnote 3 Dehydrators3 0.9% M See Footnote 3 Permitted NG Turbines3 0.8% H See Footnote 3 Blowdowns3 0.7% M See Footnote 3 Well Completion Venting3 0.5% M See Footnote 3 Oil Tanks3 0.3% H See Footnote 3 Compressor Start Up and Shutdown3 0.3% L See Footnote 3 Condensate Tanks3 0.2% H See Footnote 3 Permitted Generators3 0.2% H See Footnote 3 Permitted Fugitives3 0.2% M See Footnote 3 Misc Engines3 0.1% L See Footnote 3 Permitted Flaring3 0.1% M See Footnote 3 Workover Rigs3 0.1% M See Footnote 3 Well Recompletion Venting3 0.1% M See Footnote 3 Permitted Heaters/Boilers3 0.0% H See Footnote 3 Flaring3 0.0% L See Footnote 3 1 Yellow highlighting indicates source categories in the top 95% 2 Scoring: H=High, M=Medium, L=Low 3 These source category rankings are based on screening-level inventories that were not able to address all source categories due to data gaps and missing input information. Quality of the data used is also indicated in the table, and needs to be considered when applying the results of this ranking to other analyses.


April 2010 48

% CO2(e) Contribution by source category for Uinta Basin

Permitted Heaters/Boilers0.04%

Flaring0.03%

Unpermitted Heaters/Boilers21.86%


Pneumatic Pumps15.61%

Unpermitted Compressor Engines6.27%

Well Completion Venting0.52%

Permitted Compressor Engines5.92%


Fugitives4.09%

Drill Rigs3.81%

Dehydrators0.88%

Permitted NG Turbines0.82%

Well Blowdowns0.73%

Pneumatic Devices

Unpermitted Heaters/Boilers

Pneumatic Pumps

Unpermitted Compressor Engines

Permitted Compressor Engines


Fugitives

Drill Rigs

Dehydrators


Well Blowdowns


Oil Tanks

Compressor Start Up and Shutdown

Condensate Tanks

Permitted Generators

Permitted Fugitives

Misc Engines

Permitted Flaring

Workover Rigs


Permitted Heaters/Boilers

Flaring

Figure 16. Percentage GHG emissions contribution to the Uinta Basin inventory by source category (GHG emissions reported as CO2(e)). Discussion Some source categories were not considered in this ranking. These include:

• Mobile sources – with the exception of off-road mobile sources such as drill and workover rigs, on-road and off-road mobile sources were not considered in this GHG emissions source category ranking for Uinta Basin.

• Water treatment – evaporation ponds, degassing of drilling mud, water storage tanks and water storage pits were not considered in this analysis. For most of these source categories, neither sufficient activity data nor a tractable methodology was identified to estimate GHG emissions from these source categories.

• Pipelines – pipeline fugitives and pipeline blowdowns were not included in the GHG rankings above, but both would fall into the general fugitives and blowdowns categories, which would likely represent a higher percentage contribution to CO2(e) emissions for this basin if these were estimated for pipelines. Insufficient activity data was available to estimate a volume of gas vented during a pipeline blowdown or the frequency of these events. Total mileages for the Uinta Basin pipeline infrastructure were not known nor were the components located on these pipelines: therefore a total pipeline fugitive emissions estimate was not possible. It would be necessary to obtain such data from the pipeline companies and other producers that own and operate gathering pipelines, as well as detailed information on the frequency of blowdown events and other venting events along the pipeline network.

April 2010 49

• Fracing – venting of gas associated with well completions and recompletions is captured in the ranking analysis above, as are the large mobile rigs used to work over a well (“workover rigs”), for example when additional drilling is needed. However, the large mobile pumps used in the actual hydraulic fracturing operations are not included in this analysis. Activity and configuration data for these pumps (including horsepower, load factors, usage for a representative fracing operation, fuel type, etc.) were not available as part of the WRAP Phases I, II and III inventory projects (WRAP, 2005; WRAP, 2007; WRAP, 2008). It should be noted that WRAP is sponsoring an oil and gas mobile source pilot project aimed at better quantifying the activity associated with O&G mobile sources including these pumps.

• Amine Units – detailed activity data on field amine units was not obtained through the previous WRAP Phases I, II and III inventory efforts, and permit data for large gas processing plants and compressor stations did not specify activity for amine units (WRAP, 2005; WRAP, 2007; WRAP, 2008). However it is recommended that amine units (or other acid gas removal systems) be considered a potentially significant source category for this basin.

• CBM Pump Engines – CBM gas activity in the Uinta Basin is concentrated primarily in Carbon County, and represents a relatively minor fraction of total gas production from this basin. Activity data for CBM well pump engines was not obtained as part of the WRAP Phases I, II and III survey efforts and thus this source category was not estimated in the rankings for Uinta Basin presented above (WRAP, 2005; WRAP, 2007; WRAP, 2008). Given the relatively minor production of CBM gas, it is not expected to be a significant source category.

The significant GHG source categories determined from this ranking analysis include both “permitted” and “unpermitted” sources. This refers to sources permitted by either Utah Division of Air Quality (UTDAQ) or the EPA (Part 71 for large sources on tribal land). EPA-administered and UTDAQ-administered permitted sources were either large gas processing plants or large compressor stations. UTDAQ does not permit minor sources and therefore activity data for these were obtained through the WRAP Criteria Pollutant inventory studies. Pneumatic devices and pneumatic pumps, distributed throughout the fields, collectively represent the single largest GHG emissions source category for this basin. These devices in use in the Uinta Basin are generally high-bleed devices.

April 2010 50

California – Off-Shore Region The California off-shore region includes 27 platforms of which twenty-three oil and gas production facilities are installed in Federal waters in the Pacific Outer Continental Shelf (OCS) Region and four platforms are in state waters. For the purposes of this category we have divided the discussion between significant sources on the OCS and those in State Waters as it is uncertain at the time of this report which sources will be under the jurisdiction of California for the purposes of reporting GHG. Outer Continental Shelf To assess the significant offshore sources of GHG, the Santa Barbara APCD was contacted and provided permits for two offshore platforms in the OCS: Heritage and Harvest (Snyder, 2009). One platform (Harvest) generates its own power and the other (Heritage) uses onshore power. According to the APCD, these platforms are typical of most offshore platforms in California (Snyder, 2009). The permits provided for Heritage and Harvest Platforms include activity data by source category and emissions from criteria pollutants by source category. In addition to the permits, a 2007 emissions inventory data for the two platforms was provided by the Santa Barbara APCD, which identified the type of equipment, process information, physical size of equipment and annual process data. Utilizing the data provided, as well as the fuel composition analysis provided by the Santa Barbara APCD the criteria pollutant emissions were converted to GHG emissions estimates (reported as CO2(e)) for each source category. Table 19 summarizes the combined CO2(e) by source category for both platforms. Table 19. California Off-Shore (OCS) ranking of GHG source categories including contributors to top 95% of CO2(e) emissions using a screening-level inventory for OCS sources.

Source Category1



Natural Gas Turbines3 57.7% H See Footnote 3 Flaring3 20.1% M See Footnote 3 Fugitives3 16.1% M See Footnote 3 Supply Boats3 2.2% H See Footnote 3 Heaters/Boilers3 1.2% H See Footnote 3 Cranes3 1.1% H See Footnote 3 Crew Boats3 0.7% H See Footnote 3 Helicopters3 0.5% M See Footnote 3 IC Engines3 0.3% H See Footnote 3 Emergency Generators3 0.1% H See Footnote 3 Firewater Pumps3 0.1% M See Footnote 3 1 Yellow highlighting indicates source categories in the top 95% 2 Scoring: H=High, M=Medium, L=Low 3 These source category rankings are based on screening-level inventories that were not able to address all source categories due to data gaps and missing input information. Quality of the data used is also indicated in the table, and needs to be considered when applying the results of this ranking to other analyses.


April 2010 51

% CO2(e) Contribution by source category for California Offshore Platforms

Supply Boat2.21%

Heater/Boiler1.17%

Crane1.09%

Crew Boat0.67%

Helicopter0.53%

Firewater Pump0.05%

IC Engine0.31%

Generator0.10%

Fugitive16.08%

Natural Gas Turbine57.72%

Flare20.07%

Natural Gas Turbine

Flare

Fugitive

Supply Boat

Heater/Boiler

Crane

Crew Boat

Helicopter

IC Engine

Generator

Firewater Pump

Figure 17. Percentage GHG emissions contribution to the California Off-shore platform inventory (Outer Continental Shelf) by source category (GHG emissions reported as CO2(e)). Discussion Some source categories were not considered in this ranking. These include:

• Stand-by boats – these vessels are used in response to spills or other emergency events, and were not considered a significant source category. Activity and engine configuration data for these boats were not available for purposes of estimating GHG emissions for this ranking.

• Electricity imports (Scope 2) – this category is mentioned explicitly for off-shore platforms, since many platforms are connected to shore-side power. If connected to the shore-side electrical grid, GHG emissions from electricity imports could be very significant for platforms as much of the equipment on the platform is electrified.

For platforms with on-site power generation – through a turbine generator – these turbines represent the most significant GHG source category for these platforms, as they would provide electrical power to a number of devices. It should be noted, however, that of the 16 OCS platforms in Santa Barbara County, all but 3 use onshore power. Thus turbine generators become less significant when considered with all offshore platforms in the OCS.

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State Waters To assess the significant offshore sources of GHG in California State Waters, ENVIRON contacted the Santa Barbara County Air Pollution Control District (SBAPCD) and was provided criteria pollutant permit data for offshore platform Holly1. In addition to the permit, we were provided 2007 emissions inventory data for the platform that identified the type of equipment, process information, physical size of equipment and annual process data. Utilizing the data provided, as well as the fuel composition analysis provided by the SBAPCD we converted the criteria pollutant emissions to the CO2 equivalent (CO2(e)) for each source category. Table 20 summarizes the CO2(e) by source category for platform Holly. Table 20. California Offshore Sources (State Waters) ranking of GHG source categories including contributors to top 95% of CO2(e) emissions using a screening-level inventory for offshore sources in State Waters.

Source Category1



Flare3 47.6% M See Footnote 3 Crew Boat3 39.9% H See Footnote 3 Drill Rig3 7.8% H See Footnote 3 IC Engine3 3.6% H See Footnote 3 Supply Boat3 1.1% H See Footnote 3 Fugitives3 0.1% M See Footnote 3 1 Yellow highlighting indicates source categories in the top 95% 2 Scoring: H=High, M=Medium, L=Low 3 These source category rankings are based on screening-level inventories that were not able to address all source categories due to data gaps and missing input information. Quality of the data used is also indicated in the table, and needs to be considered when applying the results of this ranking to other analyses.

As shown in the table, green house gas emissions from flares, crew boat and drill rig engines are significant, contributing around 95% of CO2(e). Internal combustion engines, supply boats and fugitive equipment leaks contribute the remaining small percentage towards the GHG total. It should be noted that crew boats are more significant for platforms in State Waters than the OCS as crews are shuttled back and forth to the platform on a daily basis. It should also be noted that turbine generators are not significant for offshore platforms in State Waters because these platforms tend to use onshore power. The results of the rankings are also displayed below in Figure 18

1 Permit to Operator , Platform Holly, Santa Barbara County Air Pollution Control District, May 19, 2006

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% CO2(e) Contribution by source category for California Offshore Platforms on State Water

Drill Rig8%

IC Engine4%

Supply Boat1.11%

Fugitives0.13%

Flare47%

Crew Boat40%

Flare

Crew Boat

Drill Rig

IC Engine

Supply Boat

Fugitives

Figure 18. Percentage GHG emissions contribution to the California Off-shore platform Inventory (State Waters) by source category (GHG emissions reported as CO2(e)). Discussion Some source categories were not considered in this ranking. These include:

• Heater/Reboiler - Heaters are typically used to keep separators and tanks warm and as part of glycol dehydration units which operate year-round to provide thermal input to the dehydration cycle. Heaters can produce appreciable quantities of GHG emissions, most importantly of CO2. Activity data for heaters were not available for purpose of estimating GHG emissions for this ranking as most of these sources are associated with on-shore operations.

• Stand-by boats – these vessels are used in response to spills or other emergency events, and were not considered a significant source category. Activity and engine configuration data for these boats were not available for purposes of estimating GHG emissions for this ranking.

• Electricity imports (Scope 2) – this category is mentioned explicitly for off-shore platforms, since many platforms are connected to shore-side power. If connected to the shore-side electrical grid, GHG emissions from electricity imports could be very significant for platforms as much of the equipment on the platform is electrified.

April 2010 54

San Joaquin Valley Region – Heavy Oil California’s onshore oil producing activities are concentrated in Southern California (counties of Orange, Los Angeles, San Luis Obispo, Santa Barbara and Ventura), and the central valley (primarily Kern and Fresno Counties). This discussion is focused on the unique operations in the central valley (San Joaquin Valley) where heavy oil exploration and production operations exist. There are many oil production companies ranging in size from the “major” oil companies to small independent producers that may own just a few wells. In addition, there are many small independent companies that specialize in well drilling, remedial work and welding services as subcontractors to these oil companies. The types of activities include primary, secondary and tertiary or thermally enhanced production. A significant amount oil produced in California is heavy oil (20 degrees API gravity or less) produced through enhanced oil recovery techniques. . Table 21 summarizes the combined CO2(e) by source category for heavy oil operations in the San Joaquin Valley. Table 21. San Joaquin Valley Region – Heavy Oil ranking of GHG source categories including contributors to top 95% of CO2(e) emissions using a screening-level inventory for the region.

Source Category1



Steam Generators3 79.9% H See Footnote 3 Cogeneration 3 15.2% H See Footnote 3 Heater Treaters3 2.2% H See Footnote 3 Oil Tanks3 1.1% L See Footnote 3 Drilling3 0.8% L See Footnote 3 IC Engines3 0.5% H See Footnote 3 Fugitives3 0.04% L See Footnote 3 1 Yellow highlighting indicates source categories in the top 95% 2 Scoring: H=High, M=Medium, L=Low 3 These source category rankings are based on screening-level inventories that were not able to address all source categories due to data gaps and missing input information. Quality of the data used is also indicated in the table, and needs to be considered when applying the results of this ranking to other analyses.


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% CO2(e) Contribution by source category for San Joaquin Valley Region – Heavy Oil

Drilling0.79%

IC Engines0.48%

Fugitives0.04%

Oil Tanks1.44%

Heater/Reboiler2.19%

COGEN15.15%

Generators79.91%

Generators

COGEN

Heater/Reboiler

Oil Tanks

Drilling

IC Engines

Fugitives

Turbines

Figure 19. Percentage GHG emissions contribution to the San Joaquin Valley Region – Heavy Oil platform inventory by source category (GHG emissions reported as CO2(e)). Discussion Most of the heavy oil operations in the San Joaquin Valley use pipeline natural gas to generate steam that is used to enhance recovery of the heavy oil, and also produce natural gas as a by-product (in some cases produced gas is used as the fuel for steam generation). Steam is injected to improve the viscosity, or thin the oil to improve its ability to flow through the reservoir. Steam is produced in steam generators (boilers) and injected under pressure into the reservoir. The steam can be injected on a cyclic (intermittent) or continuous basis. Other less used methods include in-situ combustion, (fireflooding) and chemical flooding. In fire flooding compressors are used to inject air into the reservoir to maintain combustion. The compressors are driven by internal combustion engines. Due to difficulties in handling heavy oil, heater-treaters are used to reduce viscosity and oil density. As a result much of the GHG emissions associated with these activities are combustion related. Very little quantitative information was available for determining fugitive emissions in heavy oil production. As a result, the following information is based on information from discussions with producers as well as previous inventories that were conducted for volatile organic compound emissions. Using representative data on typical heavy oil gas compositions, we were able to identify the most significant fugitive sources. However, heavy oil production fugitive emissions tend to be less significant although more volatile gases associated with production do result in emissions, primarily methane from tanks, and pipeline operations. Other potential GHG emissions sources such as venting activities, pneumatic pumps and devices also tend to be minimal due to the regulatory requirements of the San Joaquin Valley Unified Air Pollution Control District including inspection and maintenance programs. For example, most, if not all

April 2010 56

tanks are fixed rood tanks with vapor recovery. Furthermore, open sumps used in the past to separate oil and gas have virtually been eliminated and natural gas pneumatic devices have largely been converted to compressed air systems. Finally, venting of gases generally does not occur with the exception of workover wells, however, most workover wells are killed and therefore very minimal venting occurs2. Information regarding the emissions from drilling operations was not available. However, the number of wells drilled in 2007 was obtained from the California Division of Oil, Gas and Geothermal Resources (DOGGR).3 To determine drilling emissions in the San Joaquin Valley, emissions per well from Duchesne County in Utah were used and then adjusted for the number of wells and the average depth of the wells in the San Joaquin Valley. Duchesne County was chosen because it is primarily an oil producing area and specific information on drilling operations was available in that area. The emissions for heavy oil and light oil drilling operations were then proportioned to the production of heavy and light oil in the San Joaquin Valley. Table 22 below shows the number of spuds that occurred in the two development areas of the San Joaquin Valley which are District 4 (primarily Kern County) and District 5 (primarily Fresno County. It should be noted that emissions from drilling were estimated to be only a minor GHG emissions source category in heavy oil operations in the San Joaquin Valley. Table 22. San Joaquin Valley Region – Wells drilled in 2007 .

2007 Wells Drilled

Development Area Oil & Gas Service

Prospect Total

District 4 2,079 674 42 2,795 District 5 112 53 8 173

San Joaquin Valley Region – Light Oil Similar to the discussion for heavy oil development in the San Joaquin Valley, light oil exploration and production is concentrated in Southern California (counties of Orange, Los Angeles, San Luis Obispo, Santa Barbara and Ventura), and the western central valley (primarily Kern and Fresno Counties). This discussion is focused on the light oil operations in the central valley (San Joaquin Valley). As with heavy oil, there are many oil production companies ranging in size from the “major” oil companies to small independent producers that may own just a few wells. In addition, there are many small independent companies that specialize in well drilling, remedial work and welding services as subcontractors to these oil companies. Because the light oil in the San Joaquin Valley has an API gravity of 20 to 30 range, similar activities occur including primary, secondary and tertiary or enhanced production such as waterflooding (by comparison, in many other basins in the U.S., the API gravity of produced oil is greater than 30 degrees). Table 23 summarizes the combined CO2(e) by source category for light oil in the San Joaquin Valley. 2 Personal discussion with Betty Coppersmith of Chevron on May 6, 2009 3 2007 Annual Report of the State Oil & Gas Supervisor, California Department of Conservations, Division of Oil, Gas & Geothermal Resources, Publication No. PR06

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Table 23. San Joaquin Valley Region – Light Oil ranking of GHG source categories including contributors to top 95% of CO2(e) emissions using a screening-level inventory for the region.

Source Category1



Generators3 53.5% H See Footnote 3 Oil Tanks3 14.1% L See Footnote 3 Heater Treaters3 10.3% H See Footnote 3 Drill Rigs3 9.3% L See Footnote 3 IC Engines3 8.7% H See Footnote 3 Fugitives3 4.0% L See Footnote 3 Turbines3 0.1% H See Footnote 3 1 Yellow highlighting indicates source categories in the top 95% 2 Scoring: H=High, M=Medium, L=Low 3 These source category rankings are based on screening-level inventories that were not able to address all source categories due to data gaps and missing input information. Quality of the data used is also indicated in the table, and needs to be considered when applying the results of this ranking to other analyses.


% CO2(e) Contribution by source category for San Joaquin Valley Region – Light Oil

Heater/Reboiler10.33%

Drilling 9.32%

IC Engines8.67%

Fugitives3.97%

Turbines0.11%

Generators53.47%

Oil Tanks14.12%

Generators

Oil Tanks

Heater/Reboiler

Drilling

IC Engines

Fugitives

Turbines

COGEN

Figure 20. Percentage GHG emissions contribution to the San Joaquin Valley Region – Light Oil platform inventory by source category (GHG emissions reported as CO2(e)). Discussion While similar activities occur in light oil operations, activity levels are significantly less when compared to heavy oil operations. This is due to the greater need for steam generation in heavy oil

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fields for thermal recovery and processing as well as the higher level of heavy oil production. In addition, there is a greater need for heaters in heavy oil operations. Finally, the data show that cogeneration is not used in the light oil operations and this category is therefore not significant. As discussed in the previous section on heavy oil, drilling emissions were determined from the number of wells drilled (See Table 22), per well emissions from the oil producing area in Duchesne County, Utah and adjusted to account for differences in drilling depths and the production of light oil. Tight Sands Gas Production Tight sands gas production, which represents a significant percentage of unconventional gas production in the Rocky Mountain states, was considered as a separate production type for purposes of the GHG emissions source category rankings. Four sources of data were used to characterize tight sands gas production for purposes of developing the screening-level inventories and GHG emissions source category rankings: (1) the San Juan Basin in New Mexico; (2) the Uinta Basin in Utah; (3) the Piceance Basin in Colorado; and (4) the Denver-Julesburg Basin in Colorado. All of these regions have been studied in detail as part of previous WRAP criteria pollutant inventories, and detailed equipment, activity and E&P process information was available for use in GHG estimations (WRAP, 2005; WRAP 2007; WRAP, 2008). Where multiple production types exist in these basins – for example concurrent CBM production in San Juan and Uinta Basins – activity and source categories associated with tight sands gas production were estimated separately from other production types. All of these basins’ inventories have been evaluated for the 2006 calendar year, the most recent year for which detailed activity data was available. Results of the rankings by source category for tight sands gas production are presented below in Table 24 as a percentage of the total CO2(e) emissions from all O&G E&P source categories included in the screening-level inventory for this production type. Table 24. Tight sands gas production ranking of GHG source categories including contributors to top 95% of CO2(e) emissions using a screening-level inventory for the production type.

Source Category1



Compressor Engines3 33.0% M See Footnote 3 Heaters/Boilers3 17.5% M See Footnote 3 Pneumatic Devices3 14.3% M See Footnote 3 Fugitives3 10.9% M See Footnote 3 Flaring3 7.6% L See Footnote 3 Drill Rigs3 3.9% M See Footnote 3 Condensate Tanks3 2.7% M See Footnote 3 Well Blowdowns3 2.2% L See Footnote 3 Workover Rigs3 1.8% L See Footnote 3 Turbines3 1.6% M See Footnote 3 Misc. Engines3 1.2% L See Footnote 3 Pneumatic Pumps3 1.0% M See Footnote 3 Dehydrators3 0.9% M See Footnote 3 Well Recompletion Venting3 0.8% L See Footnote 3 Well Completion Venting3 0.6% L See Footnote 3 1 Yellow highlighting indicates source categories in the top 95% 2 Scoring: H=High, M=Medium, L=Low 3 These source category rankings are based on screening-level inventories that were not able to address all source categories due to data gaps and missing input information. Quality of the data used is also indicated in the table, and needs to be considered when applying the results of this ranking to other analyses.


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% CO2(e) Contribution by source category for Tight Sands Gas Production


Fugitives10.90%

Flaring7.59%

Drill Rigs3.92%

Condensate Tanks2.70%

Well Blowdowns2.16%

Workover Rigs1.81% Turbines

1.59%


Compressor Engines32.96%

Heaters/Boilers17.48%

Compressor Engines

Heaters/Boilers

Pneumatic Devices

Fugitives

Flaring

Drill Rigs

Condensate Tanks

Well Blowdowns

Workover Rigs

Turbines

Misc. Engines

Pneumatic Pumps

Dehydrators



Figure 21. Percentage GHG emissions contribution to the inventory for generic tight sands gas production by source category (GHG emissions reported as CO2(e)). Discussion Some source categories were not considered in this ranking. These include:

• Mobile sources – with the exception of off-road mobile sources such as drill and workover rigs, on-road and off-road mobile sources were not considered in this GHG emissions source category ranking for CBM gas production.

• Amine units (or other acid gas removal) – the activity data collected for the four inventories that were used to categorize tight sands gas production indicated little usage of amine units for CO2 removal or other acid gas removal processes. More data would be needed to determine whether usage of acid gas removal systems would indicate that this is a significant GHG emissions source category, and therefore it is recommended that amine units/acid gas removal systems be included in the list of potentially significant source categories.


• Fracing – venting of gas associated with well completions and recompletions is captured in the ranking analysis above, as are the large mobile rigs used to work over a well (“workover rigs”), for example when additional drilling is needed. However, the large

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mobile pumps used in the actual hydraulic fracturing operations are not included in this analysis. Activity and configuration data for these pumps (including horsepower, load factors, usage for a representative fracing operation, fuel type, etc.) were not available as part of the WRAP Phases I, II and III inventory projects (WRAP, 2005; WRAP, 2007; WRAP, 2008). It should be noted that WRAP is sponsoring an oil and gas mobile source pilot project aimed at better quantifying the activity associated with O&G mobile sources including these pumps.

• Pipelines – pipeline fugitives and pipeline blowdowns were not included in the GHG rankings above, but both would fall into the general fugitives and blowdowns categories. Insufficient activity data was available to estimate a volume of gas vented during a pipeline blowdown or the frequency of these events. Insufficient data was available to estimate pipeline infrastructure length (mileages) for a typical production region, and mileages are expected to vary from basin to basin. Therefore no data was available to determine component counts and determine fugitive emissions from pipelines.

The GHG emissions source category rankings for tight sands gas are based on very detailed activity data for a number of production basins where tight sands gas is the dominant production type. Therefore the screening-level inventory for this production type is the least uncertain of the production types presented in this ranking analysis. Despite the highly detailed activity data used in the ranking for tight sands gas production, the source categories listed above were not estimated due to lack of activity data. Particularly important in the list of categories not estimated are fracturing equipment, including frac pumps used to pump fracing fluid into the formations. As noted above, these may be significant source categories for this production type, but insufficient activity data was collected to make an estimation of GHG emissions for this source category. Emissions for this production type were not reported as “permitted” vs. “unpermitted”, and therefore no distinction was made between sources that would be considered large points sources (gas processing plants and compressor stations) or more distributed area sources (wellhead compressors, wellhead fugitives). This is because permitting thresholds and the definitions of permitted vs. unpermitted sources vary between the 4 basins used to construct the tight sands gas production ranking.

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CBM Gas Production Three sources of data were used to generate rankings for CBM gas production: (1) the WRAP Phases I, II and III criteria pollutant inventories for CBM gas production only in San Juan (South) Basin; (2) the WRAP Phases I, II and III inventories for CBM gas production only in the Uinta Basin; and (3) a detailed inventory for CBM gas production in the San Juan (North) Basin from work done in the WRAP Phases I, II and III inventories and the Four Corners Air Quality Task Force analyses (WRAP, 2005; WRAP, 2007; WRAP, 2008; NMED, 2006). The screening-level inventories and rankings for these three CBM production regions were averaged to generate a single set of rankings that were considered representative of this production type. All of these inventories have been evaluated for the 2006 calendar year, the most recent year for which detailed activity data was available. Results of the rankings by source category for CBM gas production are presented below in Table 25 as a percentage of the total CO2(e) emissions from all O&G E&P source categories included in the screening-level inventory for this production type. Table 25. CBM gas production ranking of GHG source categories including contributors to top 95% of CO2(e) emissions using a screening-level inventory for the production type.

Source Category1



Compressor Engines3 46.0% M See Footnote 3 Heaters/Boilers3 25.4% M See Footnote 3 Well Blowdowns3 15.3% L See Footnote 3 Fugitives3 4.7% M See Footnote 3 Pneumatic Devices 3 3.5% M See Footnote 3 Flaring3 2.6% L See Footnote 3 Dehydrators 3 2.2% M See Footnote 3 Misc. Engines3 0.3% L See Footnote 3 Drill Rigs3 0.0% M See Footnote 3 Condensate Tanks3 0.0% M See Footnote 3 1 Yellow highlighting indicates source categories in the top 95% 2 Scoring: H=High, M=Medium, L=Low 3 These source category rankings are based on screening-level inventories that were not able to address all source categories due to data gaps and missing input information. Quality of the data used is also indicated in the table, and needs to be considered when applying the results of this ranking to other analyses.


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% CO2(e) Contribution by source category for CBM Gas Production

Fugitives4.72%

Pneumatic Device 3.54%

Flaring2.63%

Dehydrator 2.18%

Miscellaneous Engines0.25%

Drill rigs0.01%

Condensate Tank0.01%

Blowdown15.34%

Compressor engines45.96%

Heaters/Reboiler25.36%

Compressor engines

Heaters/Reboiler

Blowdown

Fugitives

Pneumatic Device

Flaring

Dehydrator

Miscellaneous Engines

Drill rigs

Condensate Tank

Figure 22. Percentage GHG emissions contribution to the inventory for generic CBM gas production by source category (GHG emissions reported as CO2(e)). Discussion Some source categories were not considered in this ranking. These include:

• Mobile sources – with the exception of off-road mobile sources such as drill and workover rigs, on-road and off-road mobile sources were not considered in this GHG emissions source category ranking for CBM gas production.

• Amine units (or other acid gas removal) – the activity data collected for the three inventories that were used to categorize CBM gas production indicated little usage of amine units for CO2 removal or other acid gas removal processes. This may be specific to the CBM regions used in this ranking analysis, and therefore more data would be needed to determine whether this is a significant source category for other CBM gas production regions. It is therefore recommended, in order to present an inclusive list, that amine units/acid gas removal systems be considered significant for this production type.


• Pipelines – pipeline fugitives and pipeline blowdowns were not included in the GHG rankings above, but both would fall into the general fugitives and blowdowns categories. Insufficient activity data was available to estimate a volume of gas vented during a pipeline blowdown or the frequency of these events. Insufficient data was available to

April 2010 63

estimate pipeline infrastructure length (mileages) for a typical production region, and mileages are expected to vary from basin to basin. Therefore no data was available to determine component counts and determine fugitive emissions from pipelines.

It should be noted that GHG emissions from drilling are a relatively minor contribution to this ranking for CBM gas production. This is because CBM well drilling activity is relatively minor in the 3 basins which were used to generate the CBM gas production type ranking. It is recommended that drilling be added as an additional significant source category. Other CBM regions, such as the Powder River Basin in Wyoming and Montana, have experienced significant growth in the last decade with significant associated drilling activity. CBM gas production does not produce significant quantities of condensate, or other associated hydrocarbon liquids, and therefore condensate/oil tanks and other GHG emissions source categories associated with condensate production are negligible. CBM gas is also high in methane content relative to other gas production types and therefore venting and fugitive GHG emissions source categories are significant for this production type. Some producers have indicated that CBM operations in the Raton Basin in New Mexico use electrified equipment. In this case, indirect (Scope 2) emissions should be considered a potential significant source category. As noted above, it is generally assumed that Scope 2 emissions from electricity or heat/steam imports are a significant source category for all basins, regions and production types.’ Emissions for this production type were not reported as “permitted” vs. “unpermitted”, and therefore no distinction was made between sources that would be considered large points sources (gas processing plants and compressor stations) or more distributed area sources (wellhead compressors, wellhead fugitives). This is because permitting thresholds and the definitions of permitted vs. unpermitted sources vary between the 3 basins used to construct the CBM gas production ranking. Therefore, in order to make this ranking generally applicable to the CBM gas production type, no distinction was made between these source types.

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Conventional Oil Rankings of GHG emissions source categories for the conventional oil production type were based on activity and production data gathered for a number of individual oil fields in basins which were inventoried in detail through the WRAP Phases I, II and III, including oil production in the Piceance (CO), Uinta (UT) and San Juan Basins (NM) (WRAP, 2005; WRAP, 2007; WRAP, 2008). It should be noted that this production type does not include off-shore oil production. Emissions factors specific to the oil production in these fields were not available, and so the screening-level inventory for conventional oil used emissions factors presented as part of the EPA’s draft national inventory of greenhouse gases (USEPA, 2009). EPA has indicated that oil tank flashing emissions factors were likely underestimated in the draft national inventory, and so for this category emissions factor data were taken from the API Compendium (API, 2004). General emissions factors were used for crude oil storage tank flashing, rather than emissions factors derived from either a standing correlation or the Vasquez-Beggs equation since this would require specific input data and these rankings are intended to apply to conventional oil production as a general production type. Results of the rankings by source category for this production type are presented below in Table 26 as a percentage of the total CO2(e) emissions from all O&G E&P source categories included in the screening-level inventory for this production type. This inventory was developed using activity data for the 2006 calendar year, the latest year for which this data was available. Table 26. Conventional oil production ranking of GHG source categories including contributors to top 95% of CO2(e) emissions using a screening-level inventory for the production type.

Source Category1


(See Footnote 2) NOTES

Heaters/Boilers 26.6% M See Footnote 3 Artificial Lift Engines 18.9% M See Footnote 3 Pneumatic Devices 15.5% M See Footnote 3 Oil Tanks 12.0% L See Footnote 3 Pneumatic Pumps 10.9% M See Footnote 3 Fugitives 6.7% M See Footnote 3 Drill Rigs 6.0% M See Footnote 3 Compressors 2.6% M See Footnote 3 Dehydrators 0.4% M See Footnote 3 Misc. Engines 0.2% L See Footnote 3 Workover Rigs 0.2% L See Footnote 3 Flaring 0.1% L See Footnote 3 Compressor Startup and Shutdown 0.0% L See Footnote 3 Well Completion Venting 0.0% L See Footnote 3 Blowdowns 0.0% L See Footnote 3 1 Yellow highlighting indicates source categories in the top 95% 2 Scoring: H=High, M=Medium, L=Low 3 These source category rankings are based on screening-level inventories that were not able to address all source categories due to data gaps and missing input information. Quality of the data used is also indicated in the table, and needs to be considered when applying the results of this ranking to other analyses.


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% CO2(e) Contribution by source category for Conventional Oil Production

Blowdowns0.01%

Oil Tanks12.00%

Pneumatic Pumps10.88%

Fugitives6.67%

Drill Rigs6.04%

Compressors2.60% Dehydrators

0.36%Misc. Engines

0.18%




Heaters/Boilers


Pneumatic Devices

Oil Tanks

Pneumatic Pumps

Fugitives

Drill Rigs

Compressors

Dehydrators

Misc. Engines

Workover Rigs

Flaring

Compressor Startups and Shutdowns


Blowdowns

Figure 23. Percentage GHG emissions contribution to the inventory for generic conventional oil production by source category (GHG emissions reported as CO2(e)). Discussion Some source categories were not considered in this ranking. These include:

• Mobile sources – with the exception of off-road mobile sources such as drill and workover rigs, on-road and off-road mobile sources were not considered in this GHG emissions source category ranking for conventional oil production.

• Amine units (or other acid gas removal) – the oil fields in the 3 basins which were inventoried as part of the WRAP Phases I, II and III studies, and which were used to generate the screening-level inventories for conventional oil, did not have sufficient activity data to characterize usage of amine units or other acid gas removal systems (WRAP, 2005; WRAP, 2007; WRAP, 2008). If oil production in a region has a significant sulfur fraction, H2S may be a significant component of the associated gas and acid gas removal would therefore be a potentially significant GHG emissions source category. This is also dependent on the extent to which gas processing would occur in the region of the oil production.


• Pipelines – pipeline fugitives and pipeline blowdowns were not included in the GHG rankings above, but both would fall into the general fugitives and blowdowns categories.

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Insufficient activity data was available to estimate a volume of gas vented during a pipeline blowdown or the frequency of these events. Insufficient data was available to estimate pipeline infrastructure length (mileages) for a typical production region, and mileages are expected to vary from basin to basin. Therefore no data was available to determine component counts and determine fugitive emissions from pipelines.

There is some significant uncertainty associated with the rankings for conventional oil. For oil tank flashing, for example, general emissions factors were used for estimating CH4 emissions from oil tanks since insufficient detailed data was available to use a more accurate flashing emissions estimation methodology. All EPA emissions factors used in estimating fugitive and vented CH4 emissions assumed that the field would produce light oil, but significant variations in oil composition, API gravity, and associated gas composition are likely between oil fields. Combustion sources such as compressors and artificial lift engines were not estimated using EPA emissions factors. For these combustion sources, sufficient detailed information was available from previous studies to characterize activity and configuration for these sources to generate the screening-level GHG emissions estimates. However, it should be noted that the usage of some combustion source categories is highly dependent on the configuration of an individual oil field. For conventional oil production in fields that are electrified, combustion-driven artificial lift engines would likely not be a significant source category. For conventional oil production in fields with a pipeline infrastructure, in which produced oil flows directly to the pipeline system, oil tanks would likely not be a significant source category. Drilling rig GHG emissions are expected to be a significant source category only if active drilling is occurring in a particular oil production field, basin or region. However for purposes of the rankings the intention was to create an inclusive list of source categories that may be potentially significant GHG emissions source categories across a broad range of regions of oil production.

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Conventional Gas Gas production from conventional reservoirs is declining in the U.S. as a whole, and in the four U.S. states in the geographic domain of this analysis (EIA, 2005). New gas development is increasingly targeting unconventional resources such as tight gas sands, and CBM gas. Therefore conventional gas production was not a focus of this analysis. The basins for which detailed criteria pollutant inventories have been developed in previous efforts by WRAP and other agencies did not include basins with primarily conventional gas production. For those basins that have been previously studied in detail, it was not possible to differentiate conventional gas production from other production types, and therefore a basin-wide screening-level GHG inventory generated from this activity data would not be specific to conventional gas production. There are two basins/regions in the geographic domain where conventional gas production was identified as a primary production type: (1) the dry gas production in the Northern California region; and (2) conventional gas production in the Permian Basin. For the Permian Basin gas production, it is assumed that the rankings for tight sands gas production are sufficiently broad to cover the significant GHG emissions source categories for this basin. For dry gas production, detailed activity data from the eastern Denver-Julesburg (D-J) Basin was used as a surrogate for creating the screening-level inventories and source category rankings for this production type (WRAP, 2008). Eastern D-J Basin includes dry gas production primarily in Yuma County, Colorado, with additional production in Chase County, Nebraska and Cheyenne County, Kansas. The eastern D-J Basin inventory has been evaluated for the 2006 calendar year, the most recent year for which detailed activity data was available. Results of the rankings by source category for dry gas production are presented below in Table 27 as a percentage of the total CO2(e) emissions from all O&G E&P source categories included in the screening-level inventory for this production type. Table 27. Dry gas production ranking of GHG source categories including contributors to top 95% of CO2(e) emissions using a screening-level inventory for the production type.

Source Category1



Compressor Engines3 52.0% M See Footnote 3 Pneumatic Devices3 11.5% M See Footnote 3 Heater/Boilers3 11.3% M See Footnote 3 Fugitives3 8.2% M See Footnote 3 Drill Rigs3 7.4% M See Footnote 3 Well Blowdowns3 1.7% L See Footnote 3 Dehydrators3 1.7% M See Footnote 3 Well Recompletion Venting3 1.6% L See Footnote 3 Workover Rigs3 1.5% L See Footnote 3 Well Completion Venting3 1.2% L See Footnote 3 Misc. Engines3 1.0% L See Footnote 3 Pneumatic Pumps3 0.8% M See Footnote 3 Flaring3 0.0% L See Footnote 3 1 Yellow highlighting indicates source categories in the top 95% 2 Scoring: H=High, M=Medium, L=Low 3 These source category rankings are based on screening-level inventories that were not able to address all source categories due to data gaps and missing input information. Quality of the data used is also indicated in the table, and needs to be considered when applying the results of this ranking to other analyses.


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% CO2(e) Contribution by source category for Dry Gas Production

Fugitives8.21%

Drill Rigs7.36%

Well Blowdowns1.73%

Dehydrators1.68%

Well Recompletion Venting1.57%

Workover Rigs1.47%


Heater/Boilers11.26%

Compressor Engines52.20%


Compressor Engines

Pneumatic Devices

Heater/Boilers

Fugitives

Drill Rigs

Well Blowdowns

Dehydrators


Workover Rigs


Misc. Engines

Pneumatic Pumps

Flaring

Condensate Tanks

Figure 24. Percentage GHG emissions contribution to the inventory for generic conventional dry gas production by source category (GHG emissions reported as CO2(e)). Discussion Some source categories were not considered in this ranking. These include:

• Mobile sources – with the exception of off-road mobile sources such as drill and workover rigs, on-road and off-road mobile sources were not considered in this GHG emissions source category ranking for dry gas production.

• Amine units (or other acid gas removal) – no indications were given from the activity data collected for eastern D-J Basin that produced gas contained significant quantities of CO2 or H2S and thus GHG emissions from amine units or acid gas removal were not estimated for this region of the D-J Basin. However acid gas removal may be a significant source category for dry gas production.


• Pipelines – pipeline fugitives and pipeline blowdowns were not included in the GHG rankings above, but both would fall into the general fugitives and blowdowns categories. Insufficient activity data was available to estimate a volume of gas vented during a pipeline blowdown or the frequency of these events. Insufficient data was available to estimate pipeline infrastructure length (mileages) for a typical production region, and

April 2010 69

mileages are expected to vary from basin to basin. Therefore no data was available to determine component counts and determine fugitive emissions from pipelines.

Dry gas production is characterized by negligible production of liquid hydrocarbons, in the form of condensate or oil. Thus the GHG emissions source category rankings are dominated by gas-related sources including compression, pneumatics, heaters/boilers and fugitives. This would be characteristic of production in the Northern California region where condensate production is relatively low.

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Gas Shale Within the geographic domain of this analysis, gas shale production is primarily concentrated in British Columbia. Similar to tight sands gas, shale gas occurs in formations that are not normally permeable enough for commercial production without hydraulic fracturing. For purposes of this analysis, it is assumed that gas shale production would have similar GHG emissions source category rankings as tight sands gas. This assumption was reviewed with staff from the British Columbia Ministry of Energy, Mines and Petroleum Resources, who indicated that the list of significant GHG source categories for tight sands gas were a reasonable surrogate for shale gas development in the province (M. EMPR, 2009). Ministry staff did emphasize that flaring is a significant GHG emissions source category in British Columbia gas shale production, since well testing is frequently flared and underbalanced drilling (which is used in this region) requires flaring of produced gas during drilling operations. Summary Table 28 below provides a comparison of the significant sources among basins for which data was available. Table 29 provides a comparison of significant sources in areas with similar activities. For example, the significant sources for conventional oil production were based on activity and production data gathered for a number of individual oil fields in basins which were inventoried in detail through the WRAP Phases I, II and III, including oil production in the Piceance (CO), Uinta (UT) and San Juan Basins (NM) (WRAP, 2005; WRAP, 2007; WRAP, 2008). The significant sources determined from these data sources are identified as significant sources for areas which have conventional oil. Likewise, for dry gas production, detailed activity data from the eastern Denver-Julesburg (D-J) Basin was used as a surrogate for creating the screening-level inventories and source category rankings for this production type (WRAP, 2008). For example, these significant sources were assumed to be the same as those in Northern California. The prioritizing of emissions sources at the basin level provides a useful guide for regulators that are developing mandatory reporting rules.

April 2010 71

Table 28. Ranking of significant source categories contributing 95% GHG by state, by area and by production type. State or Province Area

Type of Production

Significant Source Category (95% GHG contribution)1

(See Footnote 1)

New Mexico San Juan

Combination of tight sands gas, CBM gas and some oil production

Permitted Compressor

Engines 24.5%

Well Completion

Venting 17.8%

Permitted Heaters/ Boilers 13.9%

Unpermitted Compressor

Engines 13.0%


7.4%

Well Blowdowns

7.2%

Unpermitted Heaters/ Boilers 6.8%

Workover Rigs 1.7%

Flaring1.2%

Artificial Lift

Engines 1.2%

Wellhead Fugitives

1.1%

Utah Uinta

Combination of tight sands gas, CBM gas and some oil production

Pneumatic Devices 32.1%

Heaters/ Boilers 21.9%

Pneumatic Pumps 15.6%

Unpermitted Compressor

Engines 6.3%

Permitted Compressor

Engines 5.9%

Artificial Lift

Engines 5.6%

Wellhead Fugitives

4.1% Drill Rigs

3.8% - - -

Off-shore Oil -Federal Water

Natural Gas Turbines 57.7%

Flaring 20.1%

Fugitives 16.1%

Supply Boats 2.2% - - - - - - -

Off-shore Off-shore Oil -State Water

Flaring 47.6%

Crew Boat 39.9%

Drill Rig 7.8% - - - - - - - -

San Joaquin Valley (Kern County) Heavy Oil

Steam Generators

79.9% Cogeneration

15.2% - - - - - - - - -

California

San Joaquin Valley (Kern County) Light Oil

Steam Generator

53.5% Oil Tanks

14.1%

Heater Treaters 10.3%

Drilling 9.3%

IC Engines8.7% - - - - -

1. These source category rankings are based on screening-level inventories that were not able to address all source categories due to data gaps and missing input information. Quality of the data used is indicated in the basin-specific tables above, and needs to be considered when applying the results of this ranking to other analyses.

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Table 29 Ranking of significant source categories based on similar production type. State or Province Area

Type of Production

Significant Source Category1

(See Footnote 1)

Conventional Gas

Compressor Engines 52.0%


Heater/Boilers11.3%

Fugitives 8.2%

Drill Rigs 7.4%

Well Blowdowns

1.7% Dehydrators

1.7% - - -

Permian Conventional Oil Heaters/Boilers

26.6%

Artificial Lift Engines 18.9%


Oil Tanks 12.0%


Fugitives 6.7%

Drill Rigs 6.0% - - -

Conventional Gas



Heater/Boilers11.3%

Fugitives 8.2%

Drill Rigs 7.4%

Well Blowdowns

1.7% Dehydrators

1.7% - - -

New Mexico Raton CBM Gas



Well Blowdowns

15.3% Fugitives

4.7%

Pneumatic Devices

3.5% Flaring 2.6% - - - -

Conventional Gas



Heater/Boilers11.3%

Fugitives 8.2%

Drill Rigs 7.4%

Well Blowdowns

1.7% Dehydrators

1.7% - - -

Utah Paradox CBM Gas



Well Blowdowns

15.3% Fugitives

4.7%

Pneumatic Devices

3.5% Flaring 2.6% - - - -

Conventional Gas



Heater/Boilers11.3%

Fugitives 8.2%

Drill Rigs 7.4%

Well Blowdowns

1.7% Dehydrators

1.7% - - -

Conventional Oil Heaters/Boilers

26.6%



Oil Tanks 12.0%


Fugitives 6.7%


Powder River CBM Gas



Well Blowdowns

15.3% Fugitives

4.7%

Pneumatic Devices

3.5% Flaring 2.6% - - - -

Conventional Gas



Heater/Boilers11.3%

Fugitives 8.2%

Drill Rigs 7.4%

Well Blowdowns

1.7% Dehydrators

1.7% - - -


26.6%



Oil Tanks 12.0%


Fugitives 6.7%


Williston CBM Gas



Well Blowdowns

15.3% Fugitives

4.7%

Pneumatic Devices

3.5% Flaring 2.6% - - - -

Conventional Gas



Heater/Boilers11.3%

Fugitives 8.2%

Drill Rigs 7.4%

Well Blowdowns

1.7% Dehydrators

1.7% - - -

Montana

Great Plains


26.6%



Oil Tanks 12.0%


Fugitives 6.7%


April 2010 73

State or Province Area

Type of Production

Significant Source Category1

(See Footnote 1)

CBM Gas



Well Blowdowns

15.3% Fugitives

4.7%

Pneumatic Devices

3.5% Flaring 2.6% - - - -

Conventional Gas



Heater/Boilers11.3%

Fugitives 8.2%

Drill Rigs 7.4%

Well Blowdowns

1.7% Dehydrators

1.7% - - -

Northern California Conventional Oil




Oil Tanks 12.0%


Fugitives 6.7%


Conventional Gas



Heater/Boilers11.3%

Fugitives 8.2%

Drill Rigs 7.4%

Well Blowdowns

1.7% Dehydrators

1.7% - - -

California Los Angeles Basin Conventional Oil




Oil Tanks 12.0%


Fugitives 6.7%


Conventional Gas



Heater/Boilers11.3%

Fugitives 8.2%

Drill Rigs 7.4%

Well Blowdowns

1.7% Dehydrators

1.7% - - -


26.6%



Oil Tanks 12.0%


Fugitives 6.7%


British Columbia

All Production Areas Tight Sand Gas

Compressor Engines

33.0 Heaters/Boilers

17.5

Pneumatic Devices

14.3 Fugitives

10.9 Flaring

7.6 Drill Rigs

3.9

Condensate Tanks

2.7

Well Blowdowns

2.2

Workover Rigs 1.8

Turbines 1.6

Manitoba All Production Areas Conventional Oil




Oil Tanks 12.0%


Fugitives 6.7%


1. These source category rankings are based on screening-level inventories that were not able to address all source categories due to data gaps and missing input information. Quality of the data used is indicated in the basin-specific tables above, and needs to be considered when applying the results of this ranking to other analyses.

April 2010 74

METHODOLOGIES

The methodologies used to develop the screening-level inventories, from which the GHG emissions source category rankings are derived, are described below in greater detail. For each of the source categories for which sufficient activity and other input data were available to conduct a GHG estimate for the screening-level inventories, a number of methodologies were evaluated for use in the GHG estimations. This section presents both a list of methodologies available for use in estimation of GHG emissions from the O&G E&P source categories considered in this analysis, and a more detailed discussion of the particular methodology used in the screening-level inventories presented above. The detailed discussion of the methodologies selected includes an analysis of current data availability and other factors considered in selecting methodologies for the screening-level inventories. Input data that are not basin-, region- or facility-specific are presented in quantitative form. The discussions of methodologies used in the screening-level inventories are not intended as a recommendation of a specific methodology for a source category, as part of a mandatory or voluntary reporting protocol. This discussion is intended to provide an indication of what type of data is currently typically available for estimation of GHG emissions for a particular source category, through measurements, engineering estimates or typical activity data collected for field operations. Additional measurement techniques or estimation methods may be considered further by state/provincial regulatory agencies in the course of developing GHG reporting regulations for this sector. The final section of this report provides an analysis of the draft EPA GHG reporting regulation, with a specific focus on the methodologies recommended by the draft regulation for GHG emissions estimation from oil and gas source categories. Table 30 below presents the GHG emissions source categories considered in the ranking analysis with a description of the methodologies considered for estimation of GHG emissions for each of these source categories in the basins, regions, or production types considered, ranked by the uncertainty of the methodology from least to greatest. Note that uncertainty of the methodologies was not quantitatively defined, but rather uses engineering judgment. A more detailed quantitative analysis of uncertainty is not within the scope of this effort. For each source category, the methodology selected for estimating emissions from this source category in the screening-level inventories is described in more detail below. It should be noted that some methodologies may require that the type of control be taken into consideration. For example, not all well-completion or well workover completion is vented but rather flared. In such cases the methodology for flares should be used for estimated GHG emissions. Another example would be the fact that not all gas is treated through dehydrators. Additionally, all Title V still vents are controlled to at least 95% under EPA MACT regulations. On May 4-5, 2009 the Technical Workgroup (TWG) for the Exploration & Production and Natural Gas Gathering & Processing Greenhouse Gas (GHG) Accounting Protocol project held a Project meeting at the Grand Hyatt Hotel in Denver, Colorado. The main topics of the meeting were review of the DRAFT Task 2 Significant Sources Report, and charting the path forward to completion of the Task 3 final O&G E&P Reporting Protocol. A summary of the comments on the methodologies is contained in Appendix A.

April 2010 75

Table 30. Summary of all methodologies considered for estimation of emissions from the source categories considered in the screening-level inventories and source category rankings.

Methodologies Source Category CO2 CH4 N2O References

Combustion Categories

Metered fuel consumption rate, fuel gas composition analysis to determine carbon content of fuel, assumed fuel carbon fraction oxidized to CO2

1.

Source test – measured engine activity data, measured CH4 concentrations through GC, FTIR, NDIR techniques.

Source test – measured engine activity data, measured N2O concentrations through GC, FTIR, NDIR techniques.

1(API, 2004)

Estimated fuel consumption using brake-specific fuel consumption (BSFC) factor for engine or estimated engine efficiency factor2, measured or estimated engine activity (e.g. hp, load factor), carbon content of fuel, assumed fuel carbon fraction oxidized to CO2, or estimated fuel carbon content based on fuel type3.

Measured or estimated engine activity data (e.g. hp, load factor) and emissions from Continuous Emissions Monitoring (CEMS)

Metered fuel consumption, or estimated fuel consumption using engine BSFC, measured or estimated engine activity data (e.g. hp, load factor), heating value of fuel based on fuel type, and volumetric- or energy-based N2O emissions factor4.

2(API, 2004) 3(TCR, 2008) 4(API, 2004)

Measured or estimated engine activity data (e.g. hp, load factor), engine operating hours, engine efficiency factor, and energy-based CO2 emissions factor5.

Metered fuel consumption or estimated fuel consumption using engine BSFC, heating value of fuel based on fuel type, and volumetric- or energy-based CH4 emissions factor6.

5(API, 2004) 6(API, 2004)

Reciprocating internal combustion engines – NG-fired compressors at gas processing plants, large compressor stations (“Permitted Compressors”)

Measured or estimated engine activity data (e.g. hp, load factor), engines hours and brake-specific CO2 emissions factor7.

Measured or estimated engine activity data (e.g. hp, load factor), brake-specific total organic gas (TOG) emissions factor and speciation data including CH4

8.

7(USEPA, 2005a) 8(CARB, 2008)

Reciprocating internal combustion engines – NG-fired compressors at wellheads and lateral compressor stations (“Unpermitted Compressors”)

Same as “Permitted Compressors” above



Artificial lift engines Same as “Permitted Compressors” above



April 2010 76

Methodologies Source Category CO2 CH4 N2O References Miscellaneous Engines Same as “Permitted

Compressors” above Same as “Permitted Compressors” above


Electric generators at gas processing plants, large compressor stations (“Permitted Generators”)




Metered fuel consumption rate for all rig engines combined, typical fuel carbon content for diesel fuel, assumed fuel carbon fraction oxidized to CO2.

Source test – measured engine activity data, measured CH4 concentrations through mobile emissions measurement system (GC, FTIR, NDIR techniques).

Source test – measured engine activity data, measured N2O concentrations through mobile emissions measurement system (GC, FTIR, NDIR techniques).

Estimated fuel consumption using engine BSFC for each rig engine, measured or estimated engine activity (e.g. hp, load factor) for each rig engine, carbon content of fuel, assumed fuel carbon fraction oxidized to CO2

9.

Metered fuel consumption or estimated fuel consumption using engine BSFC for each rig engine, heating value of diesel fuel, and volumetric- or energy-based CH4 emissions factor10.

Metered fuel consumption or estimated fuel consumption using engine BSFC for each rig engine, heating value of diesel fuel, and volumetric- or energy-based N2O emissions factor11.

9(USEPA, 2005a) 10(API, 2004) 11(API, 2004)

Drill Rigs

Measured or estimated engine activity data (e.g. hp, load factor), and brake-specific CO2 emissions factor12.


13.

12(USEPA, 2005a) 13(CARB, 2008)

Workover rigs Same as Drill Rigs above Same as Drill Rigs above Same as Drill Rigs above

CBM pump engines Same as Drill Rigs above Same as Drill Rigs above Same as Drill Rigs above

Salt water disposal engines Same as Drill Rigs above Same as Drill Rigs above Same as Drill Rigs above

Off-shore platform supply boats

Metered fuel consumption rate of marine engine, typical fuel carbon content for diesel fuel, assumed fuel carbon fraction oxidized to CO2.



April 2010 77

Methodologies Source Category CO2 CH4 N2O References Estimated fuel consumption

using engine BSFC, measured or estimated engine activity (e.g. hp, load factor), carbon content of fuel, assumed fuel carbon fraction oxidized to CO2

14.

Metered fuel consumption or estimated fuel consumption using engine BSFC, heating value of diesel fuel, and volumetric- or energy-based CH4 emissions factor15.

Metered fuel consumption or estimated fuel consumption using engine BSFC, heating value of diesel fuel, and volumetric- or energy-based N2O emissions factor16.

14(USEPA, 2003) 15(API, 2004) 16(API, 2004)

Measured or estimated engine activity data (e.g. hp, load factor), and brake-specific CO2 emissions factor-17.


18.

17(USEPA, 2003) 18(CARB, 2008)

CEMs or Metered fuel consumption rate, fuel gas composition analysis to determine carbon content of fuel, assumed fuel carbon fraction oxidized to CO2.

Source test – measured heater/boiler activity data, measured CH4 concentrations through GC, FTIR, NDIR techniques or CEMs

Source test – measured heater/boiler activity data, measured N2O concentrations through GC, FTIR, NDIR techniques.

Estimated fuel consumption rate using heater/boiler specifications, cycling time, usage, and measured or estimated carbon content of fuel, assumed fuel carbon fraction oxidized to CO2.

Metered fuel consumption rate (energy basis), energy-based CH4 emissions factor for heater/boiler type19.

Metered fuel consumption rate (energy basis), energy-based N2O emissions factor for heater/boiler type20.

19(USEPA, 1998) 20(USEPA, 1998)

External combustion – NG-fired heaters and boilers at gas processing plants, large compressor stations (“Permitted Heaters/Boilers”)

Metered or estimated fuel consumption rate (energy basis), energy-based CO2 emissions factor21.

Estimated fuel consumption rate (energy basis), energy-based CH4 emissions factor for heater/boiler type22.

Estimated fuel consumption rate (energy basis), energy-based N2O emissions factor for heater/boiler type23.

21(API, 2004) 22(API, 2004) 23(API, 2004)

External combustion – NG-fired heaters and boilers at wellheads or in well site equipment (“Unpermitted Heaters/Boilers”)

Same as “Permitted Heaters/Boilers” above.



In-situ flaring emissions testing using emissions probe and analysis by GC/MS system, metered flare inlet fuel flow rate, and measured flare inlet fuel composition analysis24. Use engineering estimates?

In-situ flaring emissions testing using emissions probe and analysis by GC/MS system, metered flare inlet fuel flow rate, and measured flare inlet fuel composition analysis25.


24(Strosher, 1996) 25(Strosher, 1996) 26(Strosher, 1996)

Flaring – including flaring at gas processing plants and large compressor stations (“Permitted Flares”)

Metered flare inlet fuel flow General emissions factors per General emissions factors 27(API, 2004)

April 2010 78


rate, fuel composition analysis to determine carbon content of fuel, assumed fuel carbon fraction oxidized to CO2, assumed flare destruction efficiency27.

unit gas or oil produced, or emissions factor per unit of liquid hydrocarbon flared28.

per unit gas or oil produced, or emissions factor per unit of liquid hydrocarbon flared29.

28(API, 2004) 29(API, 2004)

Use engineering estimates for volume of gas, general emissions factors per unit gas or oil produced, or emissions factor per unit of liquid hydrocarbon flared30.

30(API, 2004)

Metered fuel consumption rate, fuel gas composition analysis to determine carbon content of fuel, assumed fuel carbon fraction oxidized to CO2.



Estimated turbine fuel input rate (energy-basis) using turbine power rating and turbine efficiency factor, energy-based CO2 emissions factor31.

Measured or estimated turbine activity data (e.g. power, load factor) and emissions from Continuous Emissions Monitoring (CEMS) or Parametric Emissions Monitoring (PEMS) systems.

Estimated turbine fuel input rate (energy-basis) using turbine power rating and turbine efficiency factor, energy-based N2O emissions factor32.

31(API, 2004) 32(API, 2004)

Centrifugal internal combustion engines – NG-fired turbines at gas processing plants, large compressor stations (“Permitted NG Turbines”) and Offshore Platforms

Estimated turbine fuel input rate (energy-basis) using turbine power rating and turbine efficiency factor, energy-based CH4 emissions factor33.

33(API, 2004)

Venting Categories

Direct measurement of CO2 concentrations and flashing/working & breathing loss volumes from tanks (volume flow rate measurements and IR or GC/MS for CO2 concentration if present in the gas)

Direct measurement of CH4 concentrations and flashing/working & breathing loss volumes from tanks (volume flow rate measurements and IR or GC/MS for CH4 concentration)

Condensate and oil tanks – flashing and working and breathing losses

Flashing and working & Flashing and working & 34(API, 2004)

April 2010 79


breathing losses estimation using modeling software (e.g. E&P TANKS), requires tank configuration, API gravity and Reid vapor pressure (RVP) of liquid, composition of liquid, separator and atmospheric pressure and temperature, production rate of liquid to tanks34.

breathing losses estimation using modeling software (e.g. E&P TANKS), requires tank configuration, API gravity and Reid vapor pressure of liquid, composition of liquid, separator and atmospheric pressure and temperature, production rate of liquid to tanks35.

35(API, 2004)

Process simulation software (e.g. HYSYS) to model flashing and working & breathing losses36.


36(Aspen, 2009) 37(Aspen, 2009)

Correlation equations (e.g. Vasquez-Beggs equation), API gravity of liquid, separator pressure and temperature, specific gravity of flash gas, measured or estimated CO2 content of flash gas, production rate of liquid to tanks38.

Correlation equations (e.g. Vasquez-Beggs equation), API gravity of liquid, separator pressure and temperature, specific gravity of flash gas, measured or estimated CH4 content of flash gas, production rate of liquid to tanks39.

38(API, 2004) 39(API, 2004)

Production rate of liquid to tanks and general emissions factors per unit liquid production40.


40(API, 2004) 41(API, 2004)

Direct measurement of gas consumption rate by pneumatic device type using gas flow meters upstream and downstream of device, measured or estimated CO2 content of gas42.

Direct measurement of gas consumption rate by pneumatic device type using gas flow meters upstream and downstream of device, measured or estimated CH4 content of gas43.

42(USEPA, 1996a) 43(USEPA, 1996a)

Measured gas consumption rates by pneumatic device type from vendor data, measured or estimated CO2 content of gas.

Measured gas consumption rates by pneumatic device type from vendor data, measured or estimated CH4 content of gas.

Pneumatic devices

Emissions factor by pneumatic device type, measured or

Emissions factor by pneumatic device type, measured or

44(USEPA, 1996a) 45(USEPA, 1996a)

April 2010 80


estimated CO2 content of gas44.

estimated CH4 content of gas45.

Direct measurement of gas consumption rate by pneumatic pump type using gas flow meters, measured or estimated CO2 content of gas46.

Direct measurement of gas consumption rate by pneumatic pump type using gas flow meters, measured or estimated CH4 content of gas47.

46(USEPA, 1996a) 47(USEPA, 1996a)

Measured gas consumption rates by pneumatic pump type from vendor data, measured or estimated CO2 content of gas.

Measured gas consumption rates by pneumatic pump type from vendor data, measured or estimated CH4 content of gas.

Pneumatic pumps

Emissions factor per unit of fluid pumped by pneumatic pump type (piston, diaphragm or average), measured or estimated CO2 content of gas48.

Emissions factor per unit of fluid pumped by pneumatic pump type (piston, diaphragm or average), measured or estimated CH4 content of gas49.

48(USEPA, 1996a) 49(USEPA, 1996a)

Metered volumetric gas flow rate during well completion, duration of venting, measured or estimated CO2 content of gas during venting.

Metered volumetric gas flow rate during well completion, duration of venting, measured or estimated CH4 content of gas during venting.

Well completion venting

Gas volume vented during well completion estimated using engineering flow calculations, measured or estimated CO2 content of gas during venting50. Gas volume vented may be calculated from the pressure drop across a choke point in the well.

Gas volume vented during well completion estimated using engineering flow calculations, measured or estimated CH4 content of gas during venting51.

50(API, 2004) 51(API, 2004)

Metered volumetric gas flow rate during well recompletion, duration of venting, measured or estimated CO2 content of gas during venting.

Metered volumetric gas flow rate during well recompletion, duration of venting, measured or estimated CH4 content of gas during venting.

Well recompletion venting (well workovers)

Gas volume vented during well completion estimated using engineering flow calculations,

Gas volume vented during well completion estimated using engineering flow calculations,

52(API, 2004) 53(API, 2004)

April 2010 81


measured or estimated CO2 content of gas during venting52. Volume estimated based on reservoir surface pressure, pressure tubing volume and size of stimulation.

measured or estimated CH4 content of gas during venting53. Volume estimated based on reservoir surface pressure, pressure tubing volume and size of stimulation.

Gas or oil well average volume vented per well workover, measured or estimated CO2 content of gas during venting54.

Gas or oil well average volume vented per well workover, measured or estimated CH4 content of gas during venting55.

54(API, 2004) 55(API, 2004)

Metered volumetric gas flow rate during well blowdown, duration of venting, measured or estimated CO2 content of gas during venting56.

Metered volumetric gas flow rate during well blowdown, duration of venting, measured or estimated CH4 content of gas during venting57.

56(API, 2004) 57(API, 2004)

Well blowdowns

Gas volume vented during well blowdown estimated using engineering flow calculations (assumed to be isentropic flow of an ideal gas through a nozzle), measured or estimated CO2 content of gas during venting58. Gas volume estimations may be made by using a transient pressure analysis across an orifice at the end of the vent line58.

Gas volume vented during well completion estimated using engineering flow calculations (assumed to be isentropic flow of an ideal gas through a nozzle), measured or estimated CH4 content of gas during venting59.

58(CAPP, 2002) 59(CAPP, 2002)

Direct measured volume of gas vented during compressor startup or shutdown, measured or estimated CO2 content of vented gas.

Direct measured volume of gas vented during compressor startup or shutdown, measured or estimated CH4 content of vented gas.

Estimated volume of gas vented during compressor startup or shutdown (estimated based on internal volume of compressor vented during event), measured or estimated CO2 content of vented gas60.

Estimated volume of gas vented during compressor startup or shutdown (estimated based on internal volume of compressor vented during event), measured or estimated CH4 content of vented gas61.

60(API, 2004) 61(API, 2004)

Compressor startups and shutdowns

Emissions factors per startup or shutdown event, measured

Emissions factors per startup or shutdown event, measured or

62(API, 2004) 63(API, 2004)

April 2010 82


or estimated CO2 content of gas62.

estimated CH4 content of gas63.

Measured volumetric flow rate and CO2 content of gas vented (measured at dehydrator still vent) per unit throughput of gas to the dehydrator.

Measured volumetric flow rate and CH4 content of gas vented (measured at dehydrator still vent) per unit throughput of gas to the dehydrator.

Estimated CO2 emissions per unit of gas throughput to the dehydrator using GRI GLYCalc (requires wet gas flow rate, wet gas temperature and pressure, use of gas-driven glycol pump, wet and dry gas water content, glycol flow rate, use of stripping gas and temperature and pressure of flash tank if used)64.

Estimated CH4 emissions per unit of gas throughput to the dehydrator using GRI GLYCalc (requires wet gas flow rate, wet gas temperature and pressure, use of gas-driven glycol pump, wet and dry gas water content, glycol flow rate, use of stripping gas and temperature and pressure of flash tank if used)65.

64(GRI, 2009) 65(GRI, 2009)

Dehydrators (still vent emissions)

Use of general dehydrator still vent emissions factors per unit of gas throughput to the dehydrator, measured or estimated CO2 content of gas66.

Use of general dehydrator still vent emissions factors per unit of gas throughput to the dehydrator, measured or estimated CH4 content of gas67.

66(API, 2004) 67(API, 2004)

Fugitive Categories Direct measurement of CO2 emissions from leaking component using sample bagging and GC/MS analysis68.

Direct measurement of CH4 emissions from leaking component using sample bagging and GC/MS analysis69.

68(USEPA, 1996b) 69(USEPA, 1996b)

Scaling of volumetric CH4 emissions measured using high-volume flow sampler, using measured ratio of CO2/CH4 volumetric content of gas.

Direct measurement of CH4 volumetric emissions using high-volume flow sampler.

Fugitive emissions from gas processing plants, large compressor stations (“Permitted Fugitives”)

Screening value measurement using portable gas analyzer, mass emissions rate of total organic carbon (TOC) using

Screening value measurement using portable gas analyzer, mass emissions rate of total organic carbon (TOC) using

70(USEPA, 1996b) 71(USEPA, 1996b)

April 2010 83


screening value and EPA correlation equations by component and service type, measured or estimated ratio of CO2 to TOC in the gas stream70.

screening value and EPA correlation equations by component and service type, measured or estimated CH4 fraction of TOC in the gas stream71.

Average TOC emissions factors by component and service type, number of components, measured or estimated ratio of CO2 to TOC in the gas stream72.

Average TOC emissions factors by component and service type, number of components, measured or estimated CH4 fraction of TOC in the gas stream73.

72(USEPA, 1995) 73(USEPA, 1995)

Fugitive emissions from wellhead components (“Unpermitted Fugitives”)

Direct measurement of CO2 emissions from leaking component using sample bagging and GC/MS analysis74.


74(USEPA, 1996b) 75(USEPA, 1996b)



Screening value measurement using portable gas analyzer, mass emissions rate of total organic carbon (TOC) using screening value and EPA correlation equations by component and service type, measured or estimated ratio of CO2 to TOC in the gas stream76.

Screening value measurement using portable gas analyzer, mass emissions rate of total organic carbon (TOC) using screening value and EPA correlation equations by component and service type, measured or estimated CH4 fraction of TOC in the gas stream77.

76(USEPA, 1996b) 77(USEPA, 1996b)

Average TOC emissions factors by component and service type, measured or estimated ratio of CO2 to TOC in the gas stream78.

Average TOC emissions factors by component and service type, measured or estimated CH4 fraction of TOC in the gas stream79.

78(USEPA, 1995) 79(USEPA, 1995)

April 2010 84

Methodology Discussion The methodologies presented in Table 30 for all source categories considered in the screening-level inventories are discussed in further detail below. For each source category, the selected methodology is presented, including a discussion of input data to the methodology, the criteria for selection of the methodology, and a qualitative discussion of limitations to the methodology or alternative methodologies. It should be noted that specific calculation methods to be used for mandatory reporting will be fine-tuned during the rule development process. Permitted Compressor Engines The compressor engine source category includes “permitted” compressors using reciprocating internal combustion engines. Permitted compressors refer to large compressor engines located at central gas processing plants or large compressor stations. CO2 Emissions Estimation Methodology CO2 emissions for permitted compressor engines were estimated based on available data, which varied by state or region. If available permit data contained information on the metered fuel consumption of the engine, CO2 emissions were estimated using Equation (1):

Equation (1) 62.220412

443.379

0.1 22 annualOCgasfuelCO t

CgCOgffMW

scfmolelbQE ×⎟⎟

⎠

⎞⎜⎜⎝

⎛−−

××××⎟⎟⎠

⎞⎜⎜⎝

⎛ −×= &

where:

2COE is the annual emissions of CO2 per permitted compressor engine [tonne/yr]

fuelQ& is the metered fuel flow rate [scf/hr] MWgas is the molecular weight of the combusted natural gas (assumed to be 17.4 lb/lb-mole where a specific fuel composition is not known) [lb/lb-mole] fC is the mass fraction of carbon in the fuel fO is the fraction of fuel carbon oxidized to CO2 (assumed to be 1.0 for all combustion emissions estimates) tannual is the annual hours of usage of the engine (hr/yr)

If fuel consumption data was not available, CO2 emissions were estimated by using an assumed engine efficiency factor, and a CO2 emissions factor on an energy basis, according to Equation (2): Equation (2) annualCOeCO tEFfLFHPE ××××=

22

where:

2COE is the annual emissions of CO2 per permitted compressor engine [tonne/yr] HP is the rated horsepower of the permitted compressor engine [hp] LF is the load factor of the permitted compressor engine (assumed to be 0.75 for all permitted compressor engine calculations) fe is the energy-basis conversion factor for the engine (assumed to be 7858 for a NG internal combustion engine) [BTU/hp-hr]

April 2010 85

2COEF is the emissions factor of CO2 on an energy basis assuming the higher heating value (HHV) of the fuel [tonne/BTU] tannual is the annual hours of usage of the engine (hr/yr)

CH4 Emissions Estimation Methodology CH4 emissions for permitted compressor engines were also estimated based on available data. If available permit data contained information on the metered fuel consumption of the engine, CH4 emissions were estimated using Equation (3): Equation (3) annualCHfuelCH tEFHHVQE ×××=

44&

where:

4CHE is the annual emissions of CH4 per permitted compressor engine [tonne/yr]

fuelQ& is the metered fuel flow rate [scf/hr] HHV is the measured higher heating value of the fuel [BTU/scf]

4CHEF is the emissions factor of CH4 on an energy basis assuming the HHV of the fuel [tonne/BTU] tannual is the annual hours of usage of the engine (hr/yr)

If fuel consumption data were not available, CH4 emissions were estimated using engine power data similar to Equation (2) above: Equation (4) annualCHeCH tEFfLFHPE ××××=

44

where:

4CHE is the annual emissions of CH4 per permitted compressor engine [tonne/yr] HP is the rated horsepower of the permitted compressor engine [hp] LF is the load factor of the permitted compressor engine (assumed to be 0.75 for all permitted compressor engine calculations) fe is the energy-basis conversion factor for the engine (assumed to be 7858 for a NG internal combustion engine) [BTU/hp-hr]

4CHEF is the emissions factor of CH4 on an energy basis assuming the higher heating value (HHV) of the fuel [tonne/BTU] tannual is the annual hours of usage of the engine (hr/yr)

N2O Emissions Estimation Methodology N2O emissions for permitted compressor engines were also estimated based on available data. If available permit data contained information on the metered fuel consumption of the engine, N2O emissions were estimated using Equation (5): Equation (5) annualONfuelON tEFHHVQE ×××=

22&

where:

April 2010 86

ONE2

is the annual emissions of N2O per permitted compressor engine [tonne/yr]


ONEF2

is the emissions factor of N2O on an energy basis assuming the HHV of the fuel [tonne/BTU] tannual is the annual hours of usage of the engine (hr/yr)

If fuel consumption data were not available, N2O emissions were estimated using engine power data similar to Equation (2) above: Equation (6) annualONeON tEFfLFHPE ××××=

22

where:

ONE2

is the annual emissions of N2O per permitted compressor engine [tonne/yr] HP is the rated horsepower of the permitted compressor engine [hp] LF is the load factor of the permitted compressor engine (assumed to be 0.75 for all permitted compressor engine calculations) fe is the energy-basis conversion factor for the engine (assumed to be 7858 for a NG internal combustion engine) [BTU/hp-hr]

ONEF2

is the emissions factor of N2O on an energy basis assuming the higher heating value (HHV) of the fuel [tonne/BTU] tannual is the annual hours of usage of the engine (hr/yr)

Discussion Permitted compressor engines were treated as a separate source category for the basin-specific rankings presented above, because the data available for use in estimating GHG emissions for these sources differs from wellhead compressors. Compressor engines located at large facilities which are permitted generally are more extensively metered and their specifications more extensively detailed. The preferred methodology of those listed above for CO2, CH4, and N2O emissions estimation is to use metered fuel consumption rate data for individual engines, if this information is available. Permits were obtained for permitted engines in New Mexico, Utah and Colorado that were used to develop emissions estimates for permitted compressors. This includes permits administered by state agencies and EPA (for large sources on tribal land). While all of these permits contained data on engine rated horsepower, not all permits provided data on metered fuel consumption rates. However it is expected that fuel metering is conducted at gas processing plants and large compressor stations, so this data could be available for use in GHG emissions estimates. For all engines, emissions factors were selected for rich- or lean- burn engines as appropriate to the engine type. The engine type was indicated in some permits, for others the NOx emissions were used as a surrogate to determine whether the engine was rich- or lean-burn. The WRAP Phases I, II and III criteria pollutant inventories used to generate many of the basin and production type screening-level inventories collected detailed information on produced gas composition, including produced gas HHV and the carbon fraction of the gas (WRAP, 2005; WRAP, 2007; WRAP, 2008). Where this was not available, a standard HHV of natural gas was used (API, 2004). Emissions factors for CO2, CH4 and N2O on an energy basis were obtained from the API Compendium. Data on engine load factors were obtained as part of the WRAP Phases I, II and III inventories, but showed high variability from engine to engine, and were not available for many engines (WRAP, 2005; WRAP,

April 2010 87

2007; WRAP, 2008). Based on the data collected, this analysis assumed that permitted compressor engines were operating at a 75% load, but more information could be gathered to refine this assumption for estimation of GHG emissions from a specific engine.

April 2010 88

Unpermitted Compressor Engines Unpermitted compressors refer to small, distributed compressors using natural gas-fired reciprocating internal combustion engines, usually located at the wellhead or at lateral compressor stations. CO2 Emissions Estimation Methodology CO2 emissions for unpermitted compressor engines were estimated using an assumed engine efficiency factor, and a CO2 emissions factor on an energy basis, according to Equation (7): Equation (7) annualCOeCO tEFfLFHPE ××××=

22

where:

2COE is the annual emissions of CO2 per unpermitted compressor engine [tonne/yr] HP is the rated horsepower of the unpermitted compressor engine [hp] LF is the load factor of the unpermitted compressor engine (assumed to be 0.50 for all unpermitted compressor engine calculations) fe is the energy-basis conversion factor for the engine (assumed to be 7858 for a NG internal combustion engine) [BTU/hp-hr]

2COEF is the emissions factor of CO2 on an energy basis assuming the higher heating value (HHV) of the fuel [tonne/BTU] tannual is the annual hours of usage of the engine (hr/yr)

CH4 Emissions Estimation Methodology CH4 emissions for unpermitted compressor engines were estimated using engine power data similar to Equation (7) above: Equation (8) annualCHeCH tEFfLFHPE ××××=

44

where:

4CHE is the annual emissions of CH4 per unpermitted compressor engine [tonne/yr] HP is the rated horsepower of the unpermitted compressor engine [hp] LF is the load factor of the unpermitted compressor engine (assumed to be 0.50 for all unpermitted compressor engine calculations) fe is the energy-basis conversion factor for the engine (assumed to be 7858 for a NG internal combustion engine) [BTU/hp-hr]

4CHEF is the emissions factor of CH4 on an energy basis assuming the higher heating value (HHV) of the fuel [tonne/BTU] tannual is the annual hours of usage of the engine (hr/yr)

N2O Emissions Estimation Methodology N2O emissions for unpermitted compressor engines were estimated using engine power data similar to Equation (7) above:

April 2010 89

Equation (8) annualONeON tEFfLFHPE ××××=22

where:

ONE2

is the annual emissions of N2O per unpermitted compressor engine [tonne/yr] HP is the rated horsepower of the unpermitted compressor engine [hp] LF is the load factor of the unpermitted compressor engine (assumed to be 0.50 for all unpermitted compressor engine calculations) fe is the energy-basis conversion factor for the engine (assumed to be 7858 for a NG internal combustion engine) [BTU/hp-hr]

ONEF2

is the emissions factor of N2O on an energy basis assuming the higher heating value (HHV) of the fuel [tonne/BTU] tannual is the annual hours of usage of the engine (hr/yr)

Discussion Unpermitted compressor engine CO2, CH4, and N2O emissions estimates were conducted similar to permitted engines, except that for these small engines fuel metering data is generally unavailable. In the San Juan Basin in New Mexico, wellhead compressor engines are used extensively and represent a significant GHG emissions source category. In other basins or for other production types, they may be used less extensively and therefore not be a significant GHG emissions source category. Typically the only data available for these engines is the rated horsepower, and an indication of whether the engine is rich- or lean-burn. However, load factor is another important parameter in the GHG emissions estimates for these engines. The load factor of wellhead compressor engines may vary significantly with field pressure and the engine size. For this analysis, a single load factor of 0.50 was used but site-specific data could be collected or engineering estimates based on field pressures could be used to generate a more refined estimate of the load factor of wellhead compressors. Emissions factors for these estimates were taken from the API Compendium (API, 2004).

April 2010 90

Permitted NG Turbines The permitted NG turbine source category includes large turbines operating at gas processing plants, large compressor stations, and for power generation and compression on off-shore platforms in California. The methodologies for CO2, CH4 and N2O emissions estimates for turbines used for compression and power generation are described separately below. CO2 Emissions Estimation Methodology CO2 emissions for permitted NG turbine compressors were estimated based on available data, which varied by state or region. If available permit data contained information on the metered fuel consumption of the turbine, CO2 emissions were estimated using Equation (9):

Equation (9) 62.220412

443.379

0.1 22 annualOCgasfuelCO t

CgCOgffMW

scfmolelbQE ×⎟⎟

⎠

⎞⎜⎜⎝

⎛−−

××××⎟⎟⎠

⎞⎜⎜⎝

⎛ −×= &

where:

2COE is the annual emissions of CO2 per permitted compressor engine [tonne/yr]

fuelQ& is the metered fuel flow rate [scf/hr] MWgas is the molecular weight of the combusted natural gas (assumed to be 17.4 lb/lb-mole where a specific fuel composition is not known) [lb/lb-mole] fC is the mass fraction of carbon in the fuel fO is the fraction of fuel carbon oxidized to CO2 (assumed to be 1.0 for all combustion emissions estimates) tannual is the annual hours of usage of the engine (hr/yr)

If fuel consumption data was not available, CO2 emissions for NG turbine compressors were estimated by using an assumed engine efficiency factor, and a CO2 emissions factor on an energy basis, according to Equation (10): Equation (10) annualCOeCO tEFfLFHPE ××××=

22

where:

2COE is the annual emissions of CO2 per permitted NG turbine compressor [tonne/yr] HP is the rated horsepower of the permitted NG turbine compressor [hp] LF is the load factor of the permitted NG turbine compressor (assumed to be 0.75 for all permitted NG turbine compressor calculations) fe is the energy-basis conversion factor for the turbine (assumed to be 10379 for a NG turbine) [BTU/hp-hr]

2COEF is the emissions factor of CO2 on an energy basis assuming the higher heating value (HHV) of the fuel [tonne/BTU] tannual is the annual hours of usage of the turbine (hr/yr)

For turbines used for power generation (California off-shore platforms), CO2 emissions were estimated based on the power rating of the turbine, according to Equation (11):

April 2010 91

Equation (11) annualCOCO tEFPE ××=22

where:

2COE is the annual emissions of CO2 per permitted NG turbine generator [tonne/yr] P is the rated power of the permitted NG turbine generator [MW]

2COEF is the emissions factor of CO2 on an energy basis [tonne/MW-hr] tannual is the annual hours of usage of the turbine (hr/yr)

CH4 Emissions Estimation Methodology CH4 emissions for permitted NG turbine compressors were also estimated based on available data. If available permit data contained information on the metered fuel consumption of the turbine, CH4 emissions were estimated using Equation (12): Equation (12) annualCHfuelCH tEFHHVQE ×××=

44&

where:

4CHE is the annual emissions of CH4 per permitted NG turbine compressor [tonne/yr]


4CHEF is the emissions factor of CH4 on an energy basis assuming the HHV of the fuel [tonne/BTU] tannual is the annual hours of usage of the turbine (hr/yr)

If fuel consumption data were not available, CH4 emissions were estimated using turbine power data similar to Equation (10) above: Equation (13) annualCHeCH tEFfLFHPE ××××=

44

where:

4CHE is the annual emissions of CH4 per permitted NG turbine compressor [tonne/yr] HP is the rated horsepower of the permitted NG turbine compressor [hp] LF is the load factor of the permitted NG turbine compressor (assumed to be 0.75 for all permitted NG turbine compressor calculations) fe is the energy-basis conversion factor for the turbine (assumed to be 10379 for a NG turbine compressor) [BTU/hp-hr]

4CHEF is the emissions factor of CH4 on an energy basis assuming the higher heating value (HHV) of the fuel [tonne/BTU] tannual is the annual hours of usage of the turbine (hr/yr)

For turbines used for power generation (California off-shore platforms), CH4 emissions were estimated based on the power rating of the turbine, according to Equation (14): Equation (14) annualCHCH tEFPE ××=

44

April 2010 92

where: 4CHE is the annual emissions of CH4 per permitted NG turbine generator [tonne/yr]

P is the rated power of the permitted NG turbine generator [MW] 4CHEF is the emissions factor of CH4 on an energy basis [tonne/MW-hr]

tannual is the annual hours of usage of the turbine (hr/yr) N2O Emissions Estimation Methodology N2O emissions for permitted NG turbine compressors were also estimated based on available data. If available permit data contained information on the metered fuel consumption of the turbine, N2O emissions were estimated using Equation (15): Equation (15) annualONfuelON tEFHHVQE ×××=

22&

where:

ONE2

is the annual emissions of N2O per permitted NG turbine compressor [tonne/yr]


ONEF2

is the emissions factor of N2O on an energy basis assuming the HHV of the fuel [tonne/BTU] tannual is the annual hours of usage of the turbine (hr/yr)

If fuel consumption data were not available, N2O emissions were estimated using engine power data similar to Equation (10) above: Equation (16) annualONeON tEFfLFHPE ××××=

22

where:

ONE2

is the annual emissions of N2O per permitted NG turbine compressor [tonne/yr] HP is the rated horsepower of the permitted NG turbine compressor [hp] LF is the load factor of the permitted NG turbine compressor (assumed to be 0.75 for all permitted NG turbine compressor calculations) fe is the energy-basis conversion factor for the turbine (assumed to be 10379 for a NG turbine compressor) [BTU/hp-hr]

ONEF2

is the emissions factor of N2O on an energy basis assuming the higher heating value (HHV) of the fuel [tonne/BTU] tannual is the annual hours of usage of the turbine (hr/yr)

For turbines used for power generation (California off-shore platforms), N2O emissions were estimated based on the power rating of the turbine, according to Equation (17): Equation (17) annualONON tEFPE ××=

22

where:

ONE2

is the annual emissions of N2O per permitted NG turbine generator [tonne/yr]

April 2010 93

P is the rated power of the permitted NG turbine generator [MW] ONEF

2 is the emissions factor of N2O on an energy basis [tonne/MW-hr]

tannual is the annual hours of usage of the turbine (hr/yr) Discussion Natural gas-fired turbines used as compressors in gas processing facilities and large compressor stations as well as turbines used as generators on California off-shore platforms are generally considered permitted sources, in that they exceed emissions thresholds requiring permits in most of the U.S. states covered in this geographic domain. Therefore detailed specifications, including fuel consumption rates for turbine compressors and power generation rates for turbine generators, are available through the permit data. Where this information was available, it is the preferred method for estimating GHG emissions. Some permits for large compressor stations and processing plants did not have fuel consumption data available, in which case the power rating of the turbine, an assumed load factor, and energy-based emissions factors from the API Compendium were used (API, 2004). It is assumed that load factor data could be obtained more precisely for individual turbines which would refine the emissions factor-based GHG estimate, however this approach would only be useful to improve the GHG estimate if fuel metering is not feasible. Permits for California off-shore platforms did contain data on fuel consumption rates for turbine compressors and power generation capacity for turbine generators and this information was used (Snyder, 2009). In addition, fuel composition (carbon fraction) and fuel HHV was provided for these platforms. For other basins and production types, the WRAP Phases I, II and III inventories were used to provide fuel carbon fraction and HHV for cases where fuel metering data was available for a turbine (WRAP, 2005; WRAP, 2007; WRAP, 2008).

April 2010 94

Permitted Heaters and Boilers Permitted heaters and boilers refer to external combustion devices at gas processing plants, and large compressor stations. Similar to permitted compressor engines, these facilities are typically required to file for a permit through a state agency or through the EPA (for sources on tribal land), and are treated as a separate source category for this analysis because of the greater level of detailed information available from the permits. This category can include steam boilers, heaters used in a variety of gas processing steps, reboilers used in dehydration and acid gas removal, and any other application of a heater or boiler at a large permitted facility. CO2 Emissions Estimation Methodology CO2 emissions for permitted heaters/boilers were estimated based on available data, which varied by state or region. For some of the permits, metered fuel consumption rates of the heaters/boilers were indicated, and CO2 emissions were estimated using Equation (18): Equation (18)

62.220412

443.379

0.1 22

ctCg

COgffMWscfmolelbQE annualOCgasfuelCO ××⎟⎟

⎠

⎞⎜⎜⎝

⎛−−

××××⎟⎟⎠

⎞⎜⎜⎝

⎛ −×= &

where:

2COE is the annual emissions of CO2 per permitted heater/boiler [tonne/yr]

fuelQ& is the metered fuel flow rate [scf/hr] MWgas is the molecular weight of the natural gas (assumed to be 17.4 lb/lb-mole where a specific fuel composition is not known) [lb/lb-mole] fC is the mass fraction of carbon in the fuel fO is the fraction of fuel carbon oxidized to CO2 (assumed to be 1.0 for all combustion emissions estimates) tannual is the annual hours of usage of the heater (hr/yr) c is the cycling fraction of the heater (if the heater uses cycling to maintain a set point temperature)

If fuel consumption data was not available, CO2 emissions were estimated by using the heater rating, the HHV of the gas, and a CO2 emissions factor on a fuel volume basis, according to Equation (19): Equation (19)

62.220412

443.379

0.1 22

ctCg

COgffMW

scfmolelb

HHVQE annualOCgas

firingCO ××⎟⎟

⎠

⎞⎜⎜⎝

⎛−−

××××⎟⎟⎠

⎞⎜⎜⎝

⎛ −×⎟⎟⎠

⎞⎜⎜⎝

⎛=

&

where:

2COE is the annual emissions of CO2 per permitted heater/boiler [tonne/yr]

firingQ& is the specified firing rate of the heater/boiler [MMBTU/hr] HHV is the higher heating value of the fuel [MMBTU/scf] MWgas is the molecular weight of the natural gas (assumed to be 17.4 lb/lb-mole where a specific fuel composition is not known) [lb/lb-mole]

April 2010 95

fC is the mass fraction of carbon in the fuel fO is the fraction of fuel carbon oxidized to CO2 (assumed to be 1.0 for all combustion emissions estimates) tannual is the annual hours of usage of the heater (hr/yr) c is the cycling fraction of the heater (if the heater uses cycling to maintain a set point temperature)

CH4 Emissions Estimation Methodology CH4 emissions for permitted heaters/boilers were also estimated based on available data. If available permit data contained information on the metered fuel consumption of the heater/boiler, CH4 emissions were estimated using Equation (20): Equation (20) 62.2204

44 annualCHfuelCH tEFQE ××= & where:

4CHE is the annual emissions of CH4 per permitted heater/boiler [tonne/yr]

fuelQ& is the metered fuel flow rate [MMSCF/hr]

4CHEF is the emissions factor of CH4 on a volumetric basis [lb/MMSCF] tannual is the annual hours of usage of the engine (hr/yr)

If fuel consumption data were not available, CH4 emissions were estimated using the specified firing rate of the heater/boiler, the HHV of the gas, and a CH4 emissions factor on a volume basis, according to Equation (21):

Equation (21) ( )61062.220444

××××⎟⎟⎠

⎞⎜⎜⎝

⎛= ctEFHHV

QE annualCHfiring

CH

&

where:

4CHE is the annual emissions of CH4 per permitted heater/boiler [tonne/yr]

firingQ& is the specified firing rate of the heater/boiler [MMBTU/hr] HHV is the higher heating value of the fuel [MMBTU/scf]

4CHEF is the emissions factor of CH4 on a volumetric basis [lb/MMSCF] tannual is the annual hours of usage of the engine (hr/yr) c is the cycling fraction of the heater (if the heater uses cycling to maintain a set point temperature)

N2O Emissions Estimation Methodology N2O emissions for permitted heaters/boilers were also estimated based on available data. If available permit data contained information on the metered fuel consumption of the heater/boiler, N2O emissions were estimated using Equation (22): Equation (22) 62.2204

22 annualONfuelON tEFQE ××= &

April 2010 96

where:

ONE2

is the annual emissions of N2O per permitted heater/boiler [tonne/yr]

fuelQ& is the metered fuel flow rate [MMSCF/hr]

ONEF2

is the emissions factor of N2O on a volumetric basis [lb/MMSCF] tannual is the annual hours of usage of the engine (hr/yr)

If fuel consumption data were not available, N2O emissions were estimated using the specified firing rate of the heater/boiler, the HHV of the gas, and a N2O emissions factor on a volume basis, according to Equation (23):

Equation (23) ( )61062.220422

××××⎟⎟⎠

⎞⎜⎜⎝

⎛= ctEFHHV

QE annualONfiring

ON

&

where:

ONE2

is the annual emissions of N2O per permitted heater/boiler [tonne/yr]


ONEF2

is the emissions factor of N2O on a volumetric basis [lb/MMSCF] tannual is the annual hours of usage of the engine (hr/yr) c is the cycling fraction of the heater (if the heater uses cycling to maintain a set point temperature)

Discussion The preferred methodology for estimating CO2, CH4, and N2O emissions from permitted heaters/boilers is to use a metered fuel consumption rate of the device. For permitted sources, this data is often collected and documented in the permit. CO2 emissions could then be determined based on fuel consumption, the carbon content of the fuel and assumed complete fuel carbon oxidation to CO2. CH4 and N2O emissions were estimated using emissions factors on a volume basis, from EPA’s AP-42 emissions factors for external combustion sources, and an estimate of the volume of fuel combusted (USEPA, 1998). Fuel composition and heating value were obtained from the WRAP Phases I, II and III studies for various basins and production types (WRAP, 2005; WRAP, 2007; WRAP, 2008). Fuel characteristics are typically available at the large facility level for each of the various gas streams in use at the facility. However, these units are often fired with field gas and therefore fuel is not tracked as closely since it is not subject to royalty payments. Heater/boiler cycling refers to periodic cycling of the firing of a device in order to maintain a set-point temperature. If a heater/boiler is configured to cycle the cycling fraction must be determined to account for actual firing hours, separately from an overall estimate of the usage hours. Data on estimated cycling fractions were collected as part of the WRAP Phases I, II and III studies, and were obtained either from manufacturer specifications or observation (WRAP, 2005; WRAP, 2007; WRAP, 2008). Note that if fuel metering is used, the cycling fraction does not need to be determined.

April 2010 97

Unpermitted Heaters and Boilers Unpermitted heaters and boilers refer to external combustion devices at gas and oil wellheads. These typically include separator and tank heaters, reboilers used in field dehydrators or field amine units, or any other wellhead application for a heater or boiler. These heaters were treated as a separate source category for purposes of the screening-level inventories for some basins to distinguish them from permitted heaters/boilers (for which more detailed information is usually available). Site-specific data on unpermitted heaters/boilers is limited and therefore limits the number of applicable methodologies for CO2, CH4 and N2O emissions estimation. CO2 Emissions Estimation Methodology Fuel consumption data was typically not available for unpermitted heaters/boilers, and therefore CO2 emissions were only estimated by using the heater rating, the HHV of the gas, and a CO2 emissions factor on a fuel volume basis, according to Equation (24): Equation (24)

62.220412

443.379

0.1 22

ctCg

COgffMWscfmolelb

HHVQE annualOCgas

firingCO ××⎟⎟

⎠

⎞⎜⎜⎝

⎛−−

××××⎟⎟⎠

⎞⎜⎜⎝

⎛ −×⎟⎟⎠

⎞⎜⎜⎝

⎛=

&

where:

2COE is the annual emissions of CO2 per unpermitted heater/boiler [tonne/yr]

firingQ& is the specified firing rate of the heater/boiler [MMBTU/hr] HHV is the higher heating value of the fuel [MMBTU/scf] MWgas is the molecular weight of the natural gas (assumed to be 17.4 lb/lb-mole where a specific fuel composition is not known) [lb/lb-mole] fC is the mass fraction of carbon in the fuel fO is the fraction of fuel carbon oxidized to CO2 (assumed to be 1.0 for all combustion emissions estimates) tannual is the annual hours of usage of the heater (hr/yr) c is the cycling fraction of the heater (if the heater uses cycling to maintain a set point temperature)

CH4 Emissions Estimation Methodology CH4 emissions were estimated similar to CO2 emissions, using the specified firing rate of the heater/boiler, the HHV of the gas, and a CH4 emissions factor on a volume basis, according to Equation (25):

Equation (25) ( )61062.220444

××××⎟⎟⎠

⎞⎜⎜⎝

⎛= ctEFHHV

QE annualCHfiring

CH

&

where:

4CHE is the annual emissions of CH4 per unpermitted heater/boiler [tonne/yr]


April 2010 98

4CHEF is the emissions factor of CH4 on a volumetric basis [lb/MMSCF] tannual is the annual hours of usage of the engine (hr/yr) c is the cycling fraction of the heater (if the heater uses cycling to maintain a set point temperature)

N2O Emissions Estimation Methodology N2O emissions were estimated similar to CO2 emissions, using the specified firing rate of the heater/boiler, the HHV of the gas, and a N2O emissions factor on a volume basis, according to Equation (26):

Equation (26) ( )61062.220422

××××⎟⎟⎠

⎞⎜⎜⎝

⎛= ctEFHHV

QE annualONfiring

ON

&

where:

ONE2

is the annual emissions of N2O per unpermitted heater/boiler [tonne/yr]


ONEF2

is the emissions factor of N2O on a volumetric basis [lb/MMSCF] tannual is the annual hours of usage of the engine (hr/yr) c is the cycling fraction of the heater (if the heater uses cycling to maintain a set point temperature)

Discussion Unpermitted heaters/boilers are used extensively in the basins and production types considered in the screening-level inventories used for the ranking analysis. These devices, located at gas and oil wellheads, are not typically fuel-metered and therefore the preferred methodology for the permitted heaters/boilers would not be feasible for these devices. The primary information on these heaters is the specified firing rate of the heater, the annual usage (including seasonal variations), and potentially an estimate of the cycling of the heater. Therefore the CO2 emissions estimation methodology used in this analysis was based on estimating fuel consumption through the firing rate of the heater, fuel carbon fraction and HHV of the fuel. However, these units are often fired with field gas and therefore fuel is not tracked as closely since it is not subject to royalty payments. For CH4 and N2O the same AP-42 emissions factors were used as for permitted heaters/boilers (USEPA, 1998).

April 2010 99

Artificial Lift Engines Artificial lift engines (pumpjacks) used at oil wellheads for increasing bottom-hole pressure to help lift liquids to the surface are either electric or gas-fired. For much of the geographic domain of this analysis, the WRAP Phases I, II and III studies have indicated that field electrification is rare, and therefore artificial lift engines would be gas-fired. In some of the California regions, particularly the Southern California region, in which oil wells are sometimes located in urban areas it is likely that artificial lift engines would be electrified. Manitoba has a very large percentage of the wells electrified, even in very rural settings. This is primarily a result of the availability of abundant and inexpensive electricity. It should also be noted that these units are often fired with field gas and therefore fuel is not tracked as closely since it is not subject to royalty payments. Methodologies If the prime mover of the pump is a gas-fired engine, the methodologies for estimating CO2, CH4 and N2O emissions are identical to those of unpermitted compressor engines. These pumps typically use casing gas, or associated gas as the fuel, so the fuel-specific parameters for associated gas would be inputs for these methodologies. Discussion Similar to unpermitted compressor engines, data from fuel consumption metering was not available for purposes of estimating GHG emissions for artificial lift engines. However, engine horsepower and annual usage was available for most of the basins and production types for which the WRAP Phases I, II and III studies were used (WRAP, 2005; WRAP, 2007; WRAP, 2008). Similar to unpermitted compressor engines, the load factor of artificial lift engines is often unknown or uncertain. This analysis assumed a 50% load factor for artificial lift engines, similar to unpermitted compressor engines. The load factor requires can be estimate based either on field pressure, or engine RPM and is expected to vary over time.

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Drill Rigs The drilling rig source category considers combustion-generated GHG emissions from the drilling rig itself, including all engines used in the rig. A single drilling rig may contain from 3 – 7 or more engines, including draw works, mud pump, and generator engines. This source category was treated separately from workover rig engines, which are discussed below. This source category does not include vented emissions associated with well drilling, or completion activities such as fracing but does include exploratory drilling. CO2 Emissions Estimation Methodology If fuel consumption data was available, CO2 emissions for drill rigs were estimated using the fuel consumption rate and the HHV of diesel fuel, according to Equation (27): Equation (27) wellCOdieselfuelCO tEFHHVQE ××××=

22ρ&

where:

2COE is the emissions of CO2 per well for a drilling rig [tonne/well]

fuelQ& is the fuel consumption rate of the entire drilling rig during well drilling [gal/hr] ρdiesel is the density of diesel fuel (assumed to be 7.09 lb/gal) [lb/gal] HHV is the higher heating value of the diesel fuel [BTU/lb]

2COEF is the emissions factor of CO2 on an energy basis assuming the higher heating value (HHV) of the fuel [tonne/BTU] twell is the hours of drilling rig operation for a single well drilling event (hr/well)

If fuel consumption data was not available, the CO2 emissions were estimated using the BSFC of the diesel engine to estimate fuel consumption, according to Equation (28): Equation (28) ∑ ×××××=

iiwellCOiiCO tEFHHVBSFCLFHPE ,22

where:

2COE is the emissions of CO2 per well for a drilling rig [tonne/well] HPi is the horsepower of engine i on the drilling rig [hp] LFi is the load factor of engine i on the drilling rig BSFC is the brake specific fuel consumption of engine i on the drilling rig [lb-fuel/hp-hr] HHV is the higher heating value of the diesel fuel [BTU/lb]

2COEF is the emissions factor of CO2 on an energy basis assuming the higher heating value (HHV) of the fuel [tonne/BTU] twell is the hours of operation of engine i on the drilling rig for a single well drilling event (hr/well)

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CH4 Emissions Estimation Methodology CH4 emissions for drill rigs were estimated similar to CO2 emissions. If fuel consumption data was available, emissions were estimated using the fuel consumption rate and the HHV of diesel fuel, according to Equation (29): Equation (29) wellCHdieselfuelCH tEFHHVQE ××××=

44ρ&

where:

4CHE is the emissions of CH4 per well for a drilling rig [tonne/well]

fuelQ& is the fuel consumption rate of the entire drilling rig during well drilling [gal/hr] ρdiesel is the density of diesel fuel (assumed to be 7.09 lb/gal) [lb/gal] HHV is the higher heating value of the diesel fuel [BTU/lb]

4CHEF is the emissions factor of CH4 on an energy basis assuming the higher heating value (HHV) of the fuel [tonne/BTU] twell is the hours of drilling rig operation for a single well drilling event (hr/well)

If fuel consumption data was not available, the CH4 emissions were estimated using the BSFC of the diesel engine to estimate fuel consumption, according to Equation (30): Equation (30) ∑ ×××××=

iiwellCHiiCH tEFHHVBSFCLFHPE ,44

where:

4CHE is the emissions of CH4 per well for a drilling rig [tonne/well] HPi is the horsepower of engine i on the drilling rig [hp] LFi is the load factor of engine i on the drilling rig BSFC is the brake specific fuel consumption of engine i on the drilling rig [lb-fuel/hp-hr] HHV is the higher heating value of the diesel fuel [BTU/lb]

4CHEF is the emissions factor of CH4 on an energy basis assuming the higher heating value (HHV) of the fuel [tonne/BTU] twell is the hours of operation of engine i on the drilling rig for a single well drilling event (hr/well)

N2O Emissions Estimation Methodology N2O emissions for drill rigs were estimated similar to CO2 emissions. If fuel consumption data was available, emissions were estimated using the fuel consumption rate and the HHV of diesel fuel, according to Equation (31): Equation (31) wellONdieselfuelON tEFHHVQE ××××=

22ρ&

where:

ONE2

is the emissions of N2O per well for a drilling rig [tonne/well]

fuelQ& is the fuel consumption rate of the entire drilling rig during well drilling [gal/hr]

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ρdiesel is the density of diesel fuel (assumed to be 7.09 lb/gal) [lb/gal] HHV is the higher heating value of the diesel fuel [BTU/lb]

ONEF2

is the emissions factor of N2O on an energy basis assuming the higher heating value (HHV) of the fuel [tonne/BTU] twell is the hours of drilling rig operation for a single well drilling event (hr/well)

If fuel consumption data was not available, the N2O emissions were estimated using the BSFC of the diesel engine to estimate fuel consumption, according to Equation (32): Equation (32) ∑ ×××××=

iiwellONiiON tEFHHVBSFCLFHPE ,22

where:

ONE2

is the emissions of N2O per well for a drilling rig [tonne/well] HPi is the horsepower of engine i on the drilling rig [hp] LFi is the load factor of engine i on the drilling rig BSFC is the brake specific fuel consumption of engine i on the drilling rig [lb-fuel/hp-hr] HHV is the higher heating value of the diesel fuel [BTU/lb]

ONEF2

is the emissions factor of N2O on an energy basis assuming the higher heating value (HHV) of the fuel [tonne/BTU] twell is the hours of operation of engine i on the drilling rig for a single well drilling event (hr/well)

Discussion The methodologies presented above were used to estimate GHG emissions from well drilling for a single drilling event. Drilling rig emissions per well were scaled to a basin-level or region-level using the number of drilling events (spuds) in the basin or region for a particular year. Engine activity data was obtained from the WRAP Phases I, II and III studies, which have examined drilling rigs and their activity extensively (WRAP, 2005; WRAP, 2007; WRAP, 2008). Where fuel consumption data was available, this is the preferred methodology for estimating CO2, CH4, and N2O emissions. Fuel consumption is usually determined through a fuel meter on the common fuel tank serving the entire drilling rig. Where fuel consumption data was not available, multiple rig configurations – number of engines by type, horsepower of engine by type – were considered in the screening-level inventories to derive an average or representative configuration for purposes of the emissions estimates. It should be noted that there is uncertainty associated with drilling rig load factors, as these are expected to vary significantly by engine type and over the period of drilling. Where load factor information was available specific to a rig and drilling event, this was used, otherwise drilling rig engines were assumed to operate at a 53% load consistent with previous WRAP studies (WRAP, 2005; WRAP, 2007; WRAP, 2008). Emissions factors on an energy basis for CO2, CH4 and N2O from diesel fuel combustion were obtained from the API Compendium, as well as the HHV of diesel fuel (API, 2004). The methodologies described below assume that all drilling rigs use diesel as the primary fuel. It should be noted that some natural gas-fired drilling rigs are in use.

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Workover Rigs Workover rigs refer to rigs with diesel-fired engines used to perform major maintenance on a well, including removing and replacing the tubing string, or re-completing a well. Generally workover rigs have less total horsepower than drilling rigs, and often are equipped with only a single engine acting as the prime mover for all workover rig functions, although multiple-engine configurations are also used. Methodologies The methodologies for estimating CO2, CH4 and N2O emissions are identical to those of drilling rigs, with the exception that a summation over the engines on the rig is not necessary if the workover rig is equipped with only a single engine. Similar to drill rigs, the majority of workover rigs use diesel as the primary fuel. Discussion Workover rig data was obtained from the WRAP Phases I, II and III studies, similar to drill rigs (WRAP, 2005; WRAP, 2007; WRAP, 2008). Most of the data obtained on workover rigs was focused on rig configurations, and data on fuel consumption per well workover was not typically available. The methodology more commonly used in the development of the screening-level inventories for workover rigs used the BSFC of the engine rather than measured fuel consumption data. Similar to drill rigs, workover rigs are expected to have variable load factors during a well workover and there is greater uncertainty about workover rig load factors than those of drilling rigs. Generally the workover rigs were assumed to have a load factor of 53% for purposes of the screening-level inventories, consistent with WRAP studies.

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Flaring Emissions from flaring were estimated for the basins and production types considered in the screening-level inventories. For purposes of this analysis, this included flaring of flash gas from condensate/oil tanks, well completion venting, and dehydrators. Although flaring is used as a control technique for a variety of processes, the methodology for flaring GHG emissions estimates is identical for the different processes considered in the screening-level inventories. CO2 Emissions Estimation Methodology For purposes of the screening-level inventories, the flared gas volumes were provided for a number of different source categories or processes for which flaring is used. CO2 emissions were estimated using the volume of gas flared, and the flare gas carbon fraction, according to Equation (33):

Equation (33) 62.220412

443.379

0.1 22 ⎟⎟

⎠

⎞⎜⎜⎝

⎛−−

×××××⎟⎟⎠

⎞⎜⎜⎝

⎛ −×=

CgCOgfffMW

scfmolelbQE OflareCgasfuelCO

&

where:

2COE is the emissions of CO2 from flaring of a process or source category [tonne/yr]

fuelQ& is the flare inlet gas volume for the process or source category flared [scf/yr] MWgas is the molecular weight of the natural gas (assumed to be 17.4 lb/lb-mole where a specific fuel composition is not known) [lb/lb-mole] fC is the mass fraction of carbon in the fuel fO is the fraction of fuel carbon oxidized to CO2 (assumed to be 1.0 for all combustion emissions estimates) fflare is the destruction efficiency of the flaring (assumed to be 0.98 for purposes of this analysis)

CH4 Emissions Estimation Methodology Emissions of CH4 from flaring arise from uncombusted flare gas, which is assumed to be 2% of the flared gas by mass (API, 2004). However, for purposes of this analysis, the vented gas from the process or source category was already estimated, with flaring treated as a control measure with a 98% control efficiency. Thus no separate CH4 emissions estimate was conducted for the flared gas. CH4 may be a minor species in the total hydrocarbon emissions from the combustion process in the flare, but no data exists that separates CH4 emissions from combustion and uncombusted CH4 from the flare inlet gas. N2O Emissions Estimation Methodology N2O emissions from flaring were a relatively minor component of total CO2(e) emissions from flaring. Emissions of N2O from flaring were estimated for each basin or production type using general emissions factors on a unit production basis from the API Compendium (API, 2004), according to Equation (34): Equation (34) ONON EFPE

22×=

April 2010 105

where:

ONE2

is the emissions of N2O from flaring of a process or source category [tonne/yr] P is the production of gas or oil in a basin or region or for a production type in this analysis [MMSCF-gas/yr or 1000bbl-oil/yr]

ONEF2

is the emissions factor of N2O per unit production [tonne/MMSCF-gas or tonne/1000bbl]

Discussion Flaring emissions estimations in the screening-level inventories depended highly on the available data gathered as part of the WRAP Phases I, II and III studies on the volume of vented gas flared from various processes (WRAP, 2005; WRAP, 2007; WRAP, 2008). This estimate contains a significant level of uncertainty, but a field-level reporting could provide more detailed and accurate flared gas volumes from the source categories and processes for which flaring is used. For purposes of this analysis, flaring volume data was obtained for flaring of well completion venting, dehydrators, and condensate/oil tanks. Flared gas volumes were estimated based on the vented volume estimates for the source categories that were flared, which are discussed more below in the venting categories. Not all equipment in a source category was equipped with flares, so the fraction of equipment with flares was an input variable to determining the total flared gas volume for a given process. The fraction of equipment equipped with flares was one of the activity parameters determined through the WRAP Phases I, II and III studies (WRAP, 2005; WRAP, 2007; WRAP, 2008).

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Supply Boats This source category is specific to California off-shore platforms and is in the list of significant source categories for off-shore platforms based on the rankings presented above. This refers to combustion emissions from supply boats servicing California off-shore platforms. CO2 Emissions Estimation Methodology Fuel consumption data for supply boats was available, and CO2 emissions were estimated using the fuel consumption data and the HHV of diesel fuel, according to Equation (35): Equation (35)

22 COdieselfuelCO EFHHVQE ×××= ρ where:

2COE is the emissions of CO2 for supply boats at a representative off-shore platform [tonne/platform]

fuelQ is the total annual fuel usage by supply boats at the platform [gal/yr] ρdiesel is the density of diesel fuel (assumed to be 7.09 lb/gal) [lb/gal] HHV is the higher heating value of the diesel fuel [BTU/lb]

2COEF is the emissions factor of CO2 on an energy basis assuming the higher heating value (HHV) of the fuel [tonne/BTU]

CH4 Emissions Estimation Methodology Similar to the CO2 emissions estimation, fuel consumption data for supply boats was used to estimate CH4 emissions, according to Equation (36):

Equation (36) 44 1000 CH

fuelCH EFQE ×⎟

⎠⎞

⎜⎝⎛=

where:

4CHE is the emissions of CH4 for supply boats at a representative off-shore platform [tonne/platform]

fuelQ is the total annual fuel usage by supply boats at the platform [gal/yr]

4CHEF is the emissions factor of CH4 on a fuel volume basis [tonne/1000gal] N2O Emissions Estimation Methodology Similar to the CO2 emissions estimation, fuel consumption data for supply boats was used to estimate N2O emissions, according to Equation (37):

Equation (37) ONfuel

ON EFQE22 1000 ×⎟

⎠⎞

⎜⎝⎛=

where:

April 2010 107

ONE2

is the emissions of N2O for supply boats at a representative off-shore platform [tonne/platform]

fuelQ is the total annual fuel usage by supply boats at the platform [gal/yr]

ONEF2

is the emissions factor of N2O on a fuel volume basis [tonne/1000gal] Discussion Supply boat GHG emissions were estimated using measured fuel volumes reported as part of the permits for the off-shore platforms included as part of this analysis. Permit data was obtained for a single off-shore platform in the jurisdiction of the Santa Barbara APCD, and was assumed to be representative of this activity for all off-shore platforms (Snyder, 2009).

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Well Completion Venting Well completion venting refers to venting of a well after fracture stimulation and before the well is completed and begins production. This source category specifically addresses venting from the initial completion of a well. However, well recompletions would use a similar estimation methodology. CH4 Emissions Estimation Methodology CH4 emissions from well completion venting are estimated using the volume of gas vented and the methane fraction of that gas, according to Equation (38):

Equation (38) 62.22043.379

0.1444 CHCHventedCH fMW

scfmolelbQE ××⎟⎟

⎠

⎞⎜⎜⎝

⎛ −×= &

where:

4CHE is the emissions of CH4 from completion venting of a single well [tonne/well]

ventedQ& is the total volume of gas vented during well completed [scf/well]

4CHMW is the molecular weight of methane (16 lb/lb-mole) [lb/lb-mole]

4CHf is the molar fraction of methane in the vented gas CO2 Emissions Estimation Methodology The emissions estimation methodology for CO2 from well completions is similar to that of CH4, and is estimated if there is a significant quantity of CO2 in the vented gas, as shown in Equation (39):

Equation (39) 62.22043.379

0.1222 COCOventedCO fMW


⎠

⎞⎜⎜⎝

⎛ −×= &

where:

2COE is the emissions of CO2 from completion venting of a single well [tonne/well]

ventedQ& is the total volume of gas vented during well completed [scf/well]

2COMW is the molecular weight of CO2 (44 lb/lb-mole) [lb/lb-mole]

2COf is the molar fraction of CO2 in the vented gas Discussion The emissions per well estimated using Equations (38) and (39) above were scaled to the basin-level or regional level using data on the number of wells completed in the basin or region. Well completion venting of CH4 and CO2 is a potentially significant GHG emissions source category, particularly for wells which require fracture stimulation, in which venting durations can be extensive. The methodology above relies on an estimate of the volume of gas vented during completion. This is typically derived from engineering estimates based on a number of factors

April 2010 109

including the dimensions of the well bore and down-hole pressure, as well as the duration of the completion venting. There is uncertainty associated with this estimate if the volume of gas vented is not metered, and the vented volume can be very variable from basin to basin, or depending on the operating practices used by the well owner in the completion process. Gas metering during the completion venting phase is potentially technically complex, but more information would be needed to determine if it is feasible to meter this vented gas. The molar fractions of methane and CO2 are obtained either from gas composition analyses for well completion obtained as part of the activity data from the WRAP Phases I, II and III studies, or if this was not available it was assumed that the molar fractions were similar to production gas (WRAP, 2005; WRAP, 2007; WRAP, 2008). There is uncertainty associated with the gas molar fractions as well, primarily because the values of these molar fractions change with time during the completion venting process. The molar fractions are particularly variable if an inert gas was used to stimulate the well, and this is particularly true if the inert gas was CO2 in which case the CO2 molar fraction in the vented gas may vary considerably throughout the completion venting. Intermittent sampling of the vented gas is conducted to determine methane and inert gas concentrations for purposes of determining when to complete the well and bring it into production. These measurements could be used to better characterize the time-varying CH4 and CO2 molar fractions in the vented gas during completions. It should be noted that some well completions are controlled to prevent uncontrolled venting of gas. Controls include flaring of the gas, and the use of “green completions” (USEPA, 2005b). Green completion techniques capture the completion venting gas using 4-state separators to remove sand and fluid from the completion in order to produce pipeline-quality natural gas. Where flaring or green completions were indicated as controls through the data gathered from the WRAP studies, control factors were applied to revise the vented volume estimates.

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Well Blowdowns Well blowdowns refers to cleaning or unloading of a gas well to remove liquid buildup that reduces production rates. This process is used particularly in shallow, low-pressure gas wells such as CBM wells where down-hole pressure may not be sufficient to overcome a liquid buildup. During this process production gas is vented from the well to the atmosphere. CH4 Emissions Estimation Methodology CH4 emissions from well blowdowns are estimated using the volume of gas vented and the methane fraction of that gas, according to Equation (40):

Equation (40) 62.22043.379

0.1444 CHCHventedCH fMW


⎠

⎞⎜⎜⎝

⎛ −×= &

where:

4CHE is the emissions of CH4 from a single blowdown venting event [tonne/blowdown]

ventedQ& is the total volume of gas vented during a well blowdown [scf/blowdown]


4CHf is the molar fraction of methane in the vented gas CO2 Emissions Estimation Methodology The emissions estimation methodology for CO2 from well blowdowns is similar to that of CH4, and is estimated if there is a significant quantity of CO2 in the vented gas, as shown in Equation (41):

Equation (41) 62.22043.379

0.1222 COCOventedCO fMW


⎠

⎞⎜⎜⎝

⎛ −×= &

where:

2COE is the emissions of CO2 from a single blowdown venting event [tonne/blowdown]

ventedQ& is the total volume of gas vented during a well blowdown [scf/blowdown]


2COf is the molar fraction of CO2 in the vented gas Discussion Well blowdowns can be a significant GHG emissions source category particularly for low reservoir energy/depleted tight sand gas fields and to a lesser degree in CBM operations. For these production types, activity data was collected on the number of blowdowns within a basin or region, and the gas volume vented during a blowdown as part of the WRAP Phases I, II and III studies. The vented gas volume during a blowdown is typically an engineering estimate, and can be estimated using assumptions of isentropic flow of an ideal gas through a nozzle (CAPP,

April 2010 111

2002). This estimate requires information on the gas wellhead temperature and pressure, the dimensions of the vent pipe, and some gas properties. The molar fractions of CH4 and CO2 in the vented gas were assumed to be the same as for production gas, and were also obtained as part of the WRAP studies. It should be noted that control techniques have been investigated and utilized to reduce venting emissions from blowdowns (USEPA, 2006). Some of these practices are in use in the geographic domain of this analysis.

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Condensate/Oil Tanks This source category refers to flashing and working & breathing losses from condensate and oil tanks. Flashing refers to emissions of gas from a hydrocarbon liquid which experiences a large pressure drop (usually from the surface separator pressure to an atmospheric tank as the liquid is produced from a well). The liquids can include both primary crude oil and condensate produced from a primary gas well. Working and breathing losses occur as a result of loading and unloading of a tank (working losses) or diurnal temperature changes (breathing or standing losses). CH4 Emissions Estimation Methodology CH4 emissions from condensate and oil tank flashing were estimated using the production throughput of oil or condensate to the tank, and a throughput-based emissions factor, according to Equation (42): Equation (42) 62.2204

44 ,CHflashingCH EFPE ×= where:

4CHE is the condensate or oil tank flashing emissions of CH4 for a basin or region [tonne/yr] P is the total annual production of condensate or oil stored in tanks [bbl/yr]

4,CHflashingEF is the emissions factor of methane from condensate or oil tank flashing [lb/bbl] CH4 emissions from condensate and oil tank working & breathing losses were estimated using the production throughput of oil or condensate to the tank, and a throughput-based emissions factor, according to Equation (43): Equation (43) 62.2204

44 ,/ CHbreathingworkingCH EFPE ×= where:

4CHE is the condensate or oil tank working and breathing loss emissions of CH4 for a basin or region [tonne/yr] P is the total annual production of condensate or oil stored in tanks [bbl/yr]

4,/ CHbreathingworkingEF is the emissions factor of methane from condensate or oil tank working and breathing losses [lb/bbl]

Emissions of CO2 from this source category were not evaluated. Discussion Emissions factors for methane emissions from flashing and working & breathing losses from condensate and oil tanks were derived primarily from using the E&P TANKS software (API, 2004). Detailed information on tank configuration, condensate or oil composition, separator pressure and temperature, API gravity and RVP of condensate or oil and tank throughput were gathered as part of the WRAP Phases I, II and III studies (WRAP, 2005; WRAP, 2007; WRAP, 2008). This data was collected at the field level, from a number of production areas within a basin and used to characterize basin-wide average or representative tank information. This data

April 2010 113

was used to develop VOC emissions factors on a throughput basis (lb/bbl) for tanks in the basin using the TANKS software, separately for flashing and for working & breathing losses. For purposes of the screening-level inventories and ranking analysis, the VOC emissions factors were used to derive CH4 emissions factors by multiplying by an estimated ratio of CH4 concentration to VOC concentration in the flash gas. This is not as accurate as developing CH4 emissions factors directly using E&P TANKS, but direct CH4 emissions factors from E&P TANKS can be readily derived using the same input data as described above.

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Dehydrators This source category refers to liquid desiccant dehydrators, primarily glycol dehydrators, in use at wellheads as well as at central gas processing facilities. This category focuses on venting emissions from dehydrators, rather than combustion emissions associated with dehydrator reboilers (which are covered under the heaters/boilers source category). CH4 Emissions Estimation Methodology Vented CH4 emissions from dehydrators were estimated using a simplified emissions factor approach, according to Equation (44): Equation (44)

44 ,CHdehyCH EFPE ×= where:

4CHE is the dehydrator venting emissions of CH4 for a basin or region [tonne/yr] P is the total annual production of gas in the basin or region (all of which is assumed to be processed through dehydrators) [MMSCF/yr]

4,CHdehyEF is the emissions factor of methane from dehydrator venting [tonne/MMSCF] CO2 Emissions Estimation Methodology Vented CO2 emissions from dehydrators were estimated using the same simplified emissions factor for methane scaled with the ratio of CO2 concentration in the gas to CH4 concentration in the gas, according to Equation (45):

Equation (45) ⎟⎟⎠

⎞⎜⎜⎝

⎛××=

4

2

42 ,CH

COCHdehyCO f

fEFPE

where:

2COE is the dehydrator venting emissions of CO2 for a basin or region [tonne/yr] P is the total annual production of gas in the basin or region (all of which is assumed to be processed through dehydrators) [MMSCF/yr]

4,CHdehyEF is the emissions factor of methane from dehydrator venting [tonne/MMSCF]

2COf is the mass fraction of CO2 in the vented gas

4CHf is the mass fraction of CH4 in the vented gas Discussion A very simplified approach was used to estimate dehydrator vented CH4 emissions, relying on generalized emissions factors per unit of production gas processed in the dehydrator (API, 2004). This analysis assumed that all gas in the basin, region or for a production type (with the exception of California off-shore) would require dehydration. Although activity data on dehydrators were collected for both field units at the wellhead and larger dehydrators at gas processing plants through the WRAP Phases I, II and III studies, this data could not be used to

April 2010 115

tractably estimate the dehydrator emissions (WRAP, 2005; WRAP, 2007; WRAP, 2008). The preferred methodology for estimating dehydrator CH4 and CO2 emissions would be either through direct measurement (for large dehydrators at permitted facilities), or through use of modeling software like GRI GLYCalc (for smaller distributed dehydrators) (GRI, 2009). Similar to the WRAP studies, representative or average conditions would be needed for dehydrators at a field to be used as inputs to GLYCalc. It should be noted that for some basins, flaring of dehydrator still vent emissions were indicated from the WRAP studies. Where this was indicated, a control factor of 98% was applied to the CH4 emissions from the fraction of total production that was processed by flare-equipped dehydrators in that basin.

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Pneumatic Devices This source category refers to gas-actuated devices used to regulate flow at gas and oil wellheads (and to a limited extent at gas processing facilities). The gas used to pneumatically actuate these devices is generally the production gas for wellhead pneumatic devices. These devices include pressure and temperature controllers, positioners, and liquid level controllers. Gas-driven (pneumatic) pumps are not included in this source category and are described below in more detail in a separate source category. CH4 Emissions Estimation Methodology Vented CH4 emissions from pneumatic devices are estimated using the bleed rates of gas from the devices by device type, and the methane fraction of the vented gas, according to Equation (46):

Equation (46) 62.22043.379

0.1444 ,∑ ×××⎟⎟

⎠

⎞⎜⎜⎝

⎛ −××=

iannualCHCHibleediCH tfMW

scfmolelbQNE &

where:

4CHE is the total pneumatic device venting emissions of CH4 for a basin or region [tonne/yr] Ni is the number of devices of type i in the basin or region

ibleedQ ,& is the bleed rate of gas from device type i [scf/hr]


4CHf is the molar fraction of methane in the gas tannual is the annual usage of the pneumatic devices (assumed to be 8760 hr/yr) [hr/yr]

CO2 Emissions Estimation Methodology Vented CO2 emissions from pneumatic devices are estimated identically to the CH4 emissions, according to Equation (47):

Equation (47) 62.22043.379

0.1222 ,∑ ×××⎟⎟

⎠

⎞⎜⎜⎝

⎛ −××=

iannualCOCOibleediCO tfMW

scfmolelbQNE &

where:

2COE is the total pneumatic device venting emissions of CO2 for a basin or region [tonne/yr] Ni is the number of devices of type i in the basin or region

ibleedQ ,& is the bleed rate of gas from device type i [scf/hr]


2COf is the molar fraction of CO2 in the gas tannual is the annual usage of the pneumatic devices (assumed to be 8760 hr/yr) [hr/yr]

April 2010 117

Discussion Detailed pneumatic device counts by type were obtained as part of the WRAP Phases I, II and III studies for the basins and production types covered in this analysis (WRAP, 2005; WRAP, 2007; WRAP, 2008). These were used to characterize typical or representative oil and gas well configurations in terms of the number of devices by device type at a representative well. Total well counts by type were then used to estimate the total number of pneumatic devices by type. The WRAP studies indicated the extent to which low-bleed pneumatic devices were used (rather than traditional high-bleed pneumatic devices) or if devices were run on compressed air, another inert gas, or were electrified. Where manufacturer-specific pneumatic devices were identified, manufacturer provided bleed rates were used for those devices. Otherwise general bleed rates were used obtained from an EPA/GRI study (USEPA, 1996a). Gas composition analyses from the WRAP studies for the various basins and production types included in this analysis were used to determine the molar fractions of methane and CO2 in the production gas. Where this data was unavailable, the molar fraction of methane in production gas was generally assumed to be 78.8%, with no CO2 content. Pneumatic devices are used less frequently at gas processing plants, as these plants are often electrified or have a source of compressed air available. It should be noted that some states in the Rocky Mountain region have adopted regulations requiring the use of low-bleed pneumatic devices. Oil and gas companies have begun to implement low-bleed pneumatic devices into field operations in some of the Rocky Mountain states.

April 2010 118

Pneumatic Pumps This source category refers to gas-actuated pumps used to inject chemicals into wells, particularly methanol injection at gas wells to prevent freezing and condensate formation at wellheads and pipelines during cold weather. Pressurized produced natural gas is used as the actuating gas for these pneumatic pumps, and some of this gas is vented during pneumatic actuation. CH4 Emissions Estimation Methodology Vented CH4 emissions from pneumatic pumps are estimated using the bleed rates of gas from the pumps, and the methane fraction of the vented gas, according to Equation (48):

Equation (48) 62.22043.379

0.1444 annualCHCHconsCH VfMW

scfmolelbQE ×××⎟⎟

⎠

⎞⎜⎜⎝

⎛ −×=

where:

4CHE is the total pneumatic pump venting emissions of CH4 for a basin or region [tonne/yr]

consQ& is the gas consumption from a pneumatic pump per unit of fluid pumped [scf/gal]


4CHf is the molar fraction of methane in the gas Vannual is the annual total volume of fluid pumped per pneumatic pump [gal/yr]

CO2 Emissions Estimation Methodology If present in the gas in significant quantities, vented CO2 emissions from pneumatic pumps are estimated identically to methane emissions, according to Equation (49):

Equation (49) 62.22043.379

0.1222 annualCOCOconsCO VfMW

scfmolelbQE ×××⎟⎟

⎠

⎞⎜⎜⎝

⎛ −×=

where:

2COE is the total pneumatic pump venting emissions of CO2 for a basin or region [tonne/yr]

consQ& is the gas consumption from a pneumatic pump per unit of fluid pumped [scf/gal]


2COf is the molar fraction of CO2 in the gas Vannual is the annual total volume of fluid pumped per pneumatic pump [gal/yr]

Discussion Activity information on the usage of pneumatic pumps and the types of pumps used (including manufacturer specific data) was collected as part of the WRAP Phases I, II and III studies (WRAP, 2005; WRAP, 2007; WRAP, 2008). Gas consumption rates were obtained from manufacturer specifications, or an average of various manufacturer-specified consumption rates

April 2010 119

were used if a specific make/model of pneumatic pump could not be identified. Activity information on the usage of the pumps was collected as part of the WRAP studies and was averaged together to determine a representative or typical annual usage of the pumps in terms of total volume of fluid pumped. Production gas composition analyses were used to determine CH4 and CO2 molar fractions in the gas, or if not available the gas was assumed to have a 78.8% CH4 molar fraction and no CO2 content.

April 2010 120

Permitted Fugitives This source category refers to fugitive emissions from leaking components at gas processing plants or large compressor stations that would be permitted sources in the basins and regions covered in the geographic domain of this analysis. Fugitive emissions from wellhead components are treated as a separate source category (described below). It should be noted that the permitted fugitives source category does not include fugitive emissions from gas or oil pipelines in field operations, for which activity data was not obtained for purposes of this analysis. CH4 Emissions Estimation Methodology Fugitive emissions of CH4 from large permitted facilities were obtained from the permits for these facilities that were gathered as part of previous studies (discussed further below). The permit analysis for a facility used a variety of methodologies for estimating fugitive emissions from these facilities. The primary criterion for the selection of a methodology was whether the facility was required to estimate actual emissions as part of an emissions inventory process. If so, fugitive emissions were sometimes measured or screening values were measured and a correlation approach was used to determine fugitive emissions. If no emissions inventory was conducted for the facility, the fugitive emissions estimate in the permit data was assumed to be from a methodology using component counts and an assumed fugitive emissions rate by component and service type (gas, light oil, heavy oil, water/oil). If bagged sample measurements were made of a leaking component, this technique would provide direct estimates of the fugitive mass emissions rate of gas from the components sampled (USEPA, 1995). The EPA screening value and correlation approach was sometimes used if an emissions inventory analysis was conducted for a facility. The correlation approach requires measurement of a screening value for a leaking component (typically a concentration measurement of total organic carbon at the leak point), and use of correlation equations by component type to determine the mass emissions rate of fugitive gas (EPA, 1996b). The emissions of CH4 are estimated for components for which bagged sample measurements or screening value measurements have been taken according to Equation (50):

Equation (50) 62.22044

4 ,,∑∑ ×⎟⎟⎠

⎞⎜⎜⎝

⎛×=

i jannual

TOC

CHjifugitiveCH t

ff

QE &

where:

4CHE is the total fugitive emissions of CH4 for a facility [tonne/yr]

jifugitiveQ ,,& is the measured or estimated fugitive mass emissions rate of gas from component i

in service type j (using direct measurement or correlation equations) [lb-TOC/hr] 4CHf is the mass fraction of CH4 in the gas stream

TOCf is the mass fraction of total organic carbon species in the gas stream tannual is the annual usage of the component [hr/yr]

If mass emissions rates of gas were not measured directly (through bag sampling) or were not estimated using EPA correlation equations, the fugitive emissions of CH4 are estimated using

April 2010 121

average emissions factors (USEPA, 1995) by component type and service type and gas speciation data, according to Equation (51):

Equation (51) 62.22044

4 ,,∑∑ ×⎟⎟⎠

⎞⎜⎜⎝

⎛×=

i jannual

TOC

CHjifugitiveCH t

ff

QE &

where:


jifugitiveQ ,,& is the average fugitive mass emissions rate of gas from component i in service

type j [lb-TOC/hr] 4CHf is the mass fraction of CH4 in the gas stream


CO2 Emissions Estimation Methodology The CO2 emissions estimation methodology is identical to that of CH4, and also depends on the availability of measured or estimated fugitive mass emissions rates from leaking components. The corresponding methodologies for fugitive CO2 emissions from leaking components are presented in Equations (52) and (53), for measured or estimated mass emissions rates from bag samples or correlation equations and for average mass emissions rates, respectively:

Equation (52) 62.22042

2 ,,∑∑ ×⎟⎟⎠

⎞⎜⎜⎝

⎛×=

i jannual

TOC

COjifugitiveCO t

ff

QE &

where:

2COE is the total fugitive emissions of CO2 for a facility [tonne/yr]

jifugitiveQ ,,& is the measured or estimated fugitive mass emissions rate of gas from component i

in service type j (using direct measurement or correlation equations) [lb-TOC/hr] 2COf is the mass fraction of CO2 in the gas stream


Equation (53) 62.22042

2 ,,∑∑ ×⎟⎟⎠

⎞⎜⎜⎝

⎛×=

i jannual

TOC

COjifugitiveCO t

ff

QE &

where: 2COE is the total fugitive emissions of CO2 for a facility [tonne/yr]


type j [lb-TOC/hr] 2COf is the mass fraction of CO2 in the gas stream


April 2010 122

Discussion Fugitive emissions estimates using bag sampling are considered accurate measurements of the mass emissions rate of gas from a leaking component, but generally are not feasible to conduct for all components in a large facility which can have many separate gas streams and a large number of components of various types in various service types. The correlation equation methodology, combined with screening value measurements, provides an approach to estimating the mass emissions rates from leaking components. The average emissions factor approach is considered the most uncertain of these methodologies for fugitive emissions estimates. It should also be noted that a more streamlined direct measurement methodology for fugitive equipment leaks may be possible through the use of a high-volume flow sampler. This type of device would allow for more rapid direct measurements of mass emissions rates from leaking components at a large facility such as a gas processing plant or central compressor station. Gas speciation was not available for the screening-level inventories’ fugitive emissions estimates for most of the permitted facilities, and therefore it was conservatively assumed that the gas streams at the leak points would all contain production gas with a molar methane content of 78.8% and no CO2 content.

April 2010 123

Unpermitted Fugitives This source category refers to fugitive emissions from component leaks at wellheads. These are components such as valves, flanges, compressors (if wellhead compressors are used), and others that are part of a typical wellhead infrastructure. This source category does not include fugitive emissions from pipelines. These fugitive emissions are typically not permitted by state or federal regulatory agencies, and thus are described as “unpermitted” fugitives. CH4 Emissions Estimation Methodology Unpermitted fugitive emissions of CH4 from gas and oil wellheads were estimated only using average mass emissions rates and gas speciation, according to Equation (54):

Equation (54) 62.22044

4 ,,∑∑ ×⎟⎟⎠

⎞⎜⎜⎝

⎛×=

i jannual

TOC

CHjifugitiveCH t

ff

QE &

where:



type j [lb-TOC/hr] 4CHf is the mass fraction of CH4 in the gas stream


CO2 Emissions Estimation Methodology Unpermitted fugitive emissions of CO2 from gas and oil wellheads were estimated if there was a significant CO2 content in the gas, and used a methodology identical to that of methane, according to Equation (55):

Equation (55) 62.22042

2 ,,∑∑ ×⎟⎟⎠

⎞⎜⎜⎝

⎛×=

i jannual

TOC

COjifugitiveCO t

ff

QE &

where:

2COE is the total fugitive emissions of CO2 for a facility [tonne/yr]


type j [lb-TOC/hr] 2COf is the mass fraction of CO2 in the gas stream


April 2010 124

Discussion Fugitive emissions from wellhead components at oil and gas wells were estimated only using average emissions mass rates by component type and service type (USEPA, 1995). The data gathered as part of the WRAP Phases I, II, and III studies allowed for a characterization of a typical oil and gas well configuration, including the number of components by type and service (WRAP, 2005; WRAP, 2007; WRAP, 2008). From this data a population of components was developed for each basin region, or production type considered in this analysis and the average emissions mass rate approach described in Equations (54) and (55) were used. Measurement data was not available for wellhead fugitive emissions estimates. The gas composition used to estimate CH4 and CO2 fugitive emissions were either obtained from the WRAP studies or the gas was assumed to be a standard production gas with 78.8% molar content and no CO2 content.

April 2010 125

OVERVIEW OF EPA MANDATORY GHG REPORTING RULE

On March 10th 2009 in response to the FY2008 Consolidated Appropriations Act, EPA proposed a rule requiring mandatory reporting of greenhouse gas (GHG) emissions from large sources in the U.S. The rule proposes suppliers of fossil fuels or industrial GHGs, manufacturers of vehicles and engines, and facilities that emit 25,000 metric tons or more per year of GHG emissions submit annual reports to the EPA. Some industrial and upstream activities will be required to report emissions even if below 25,000 metric ton threshold. The rule is designed to gather data both from upstream fuel suppliers and downstream emitters. Background In developing the rule, the EPA drew on pre-existing protocols and methods from numerous groups, particularly The Climate Registry’s general reporting protocol, the California Air Resources Board’s mandatory reporting regulation and the EPA national Acid Rain Program. The EPA estimates 85-90% of total national US GHG emissions (across 13,200 facilities) are covered under the draft rule. Timeframes The EPA will collect accurate and comprehensive emissions data beginning January 1, 2010 with the first reports submitted to EPA by March 31, 2011. Vehicle and engine manufacturers will begin reporting for model year 2011. GHG’s Reported The gases covered by the proposed rule are carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), hydrofluorocarbons (HFC), perfluorocarbons (PFC), sulfur hexafluoride (SF6), and other fluorinated gases including nitrogen trifluoride (NF3) and hydrofluorinated ethers (HFE). Data Aggregation The EPA proposes reporting at a facility level. The proposed definition of “facility” assumes common ownership or control and parallels the EPA’s current approach for criteria pollutants, which is subject to some degree of interpretation. Data is to be disaggregated by source, fuel category and GHG. Data also must be reported for individual units, processes, activities and operations. The proposed rule states: “Facility means any physical property, plant, building, structure, source, or stationary equipment located on one or more contiguous or adjacent properties in actual physical contact or separated solely by a public roadway or other public right-of-way and under common ownership or common control, that emits or may emit any greenhouse gas.” De Minimis

A number of existing GHG reporting programs contain “de minimis” provisions. The goal of a de minimis provision is to avoid imposing excessive reporting costs on minor emission points that can be burdensome or infeasible to monitor. Depending on the program, the reporter is

April 2010 126

allowed to either not report a subset of emissions (e.g., 2 to 5 percent of facility-level emissions) or use simplified calculation methods for de minimis sources. EPA recognizes the potential burden of reporting emissions for smaller sources but has not explicitly included a de minimis exclusion in the rule as there are several aspects of the rule which, in EPA’s view, address the de minimis concern:

only those facilities over the established thresholds would be required to report and smaller facilities would not be subject to the program

for those facilities subject to the rule, only emissions from those source categories for which methods are provided would be reported and methods are not proposed for what are typically smaller sources of emissions (e.g., coal piles on industrial sites)

because some facilities subject to the rule could still have some relatively small sources, the proposal includes simplified emissions estimation methods for smaller sources, where appropriate e.g. small stationary combustion units could use default emission factors and heat rate to estimate emissions, and no fuel measurements would be required.

EPA requests comment on whether this approach to smaller sources of emissions is appropriate or if they should include some type of de minimis provision. Record Keeping The owners and operators subject to the reporting rule must preserve their annual GHG emissions reports and certain specified records for at least five years. The proposed list of records to be compiled and retained is lengthy. The list includes:

(a) the data used to calculate the GHG emissions for each unit, operation, process, and activity, categorized by fuel or material type;

(b) the results of any required fuel analysis (e.g., to determine carbon content) and quality assurance tests for fuel flow meters, where applicable;

(c) documentation of the data collection process for emissions collections; (d) the GHG emissions calculations and methods; (e) any facility operating data or process information used for the GHG emissions

calculations; and (f) any log book documenting changes to the GHG accounting method or instrumentation

critical to the GHG emissions calculation. A written quality assurance performance plan for compiling the GHG emissions data must also be prepared and preserved. In addition, records must be kept on the identity and responsibilities of key facility personnel involved in the GHG reporting process. Reporting Certification and Violations The reports would be submitted electronically, in a format to be specified by the Administrator after publication of the final rule. The EPA plan to adapt existing facility reporting programs to accept GHG emissions data and are developing a new electronic data reporting system for source categories or suppliers for which it is not feasible to use existing reporting mechanisms.

April 2010 127

Every annual report must be certified, under penalty of law, by a designated representative with primary responsibility for obtaining the emissions data. The EPA proposes that the designated representative shall be an individual having responsibility for the overall operation of a facility or activity, or someone with overall responsibility for environmental matters. The designation must be reflected in an agreement binding on the facility’s owners and operators. A completed certificate of representation listing all owners and operators for a given facility (or supply operation) apparently must be docketed with the EPA. The receipt of such a representation certificate will apparently be a pre-condition to the filing of an annual GHG emissions report. The proposed rule states that a violation may include, without limitation, failure to report emissions, failure to collect the underlying data, failure to calculate emissions based on the required methodology, and failure to carry out any combustion emissions monitoring or testing that might be required. Each day of non-compliance is a separate violation. Owners and operators subject to the rule must preserve annual GHG reports and certain specified records for at least five years. The proposed rule would make any reporting violation a violation of the CAA which may lead to civil and administrative penalties of up to $37,500 per day, per violation. The EPA plans to publicly disseminate GHG reporting data and to share data with the states. State Reporting Pre-Emption The EPA’s proposal would not expressly pre-empt any state reporting program requirements. Facilities subject to both federal and state GHG reporting rules will need to take particular care in preparing their submissions to ensure that data is consistently reported even though the reporting categories may not always be congruent. Verification There is no third party verification proposed and EPA will be responsible for verifying the data submitted. EPA estimates the average cost of reporting under the proposed rule would be approximately $0.04 per metric ton.

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SPECIFIC IMPLICATIONS TO THE OIL AND GAS EXPLORATION AND PRODUCTION INDUSTRY

Issues relevant to the Oil and Gas industry are addressed in four primary sections: subpart C, General Stationary Fuel Combustion Sources; subpart W, Oil and Natural Gas “Systems;” subpart NN, Suppliers of Natural Gas and NGLs; and subpart PP, Suppliers of Carbon Dioxide. Oil and Gas facilities will typically need to check both subparts C and W to determine if they are required to report emissions. Subpart NN will apply to certain gas plants that distribute NGL products into the market. Subpart PP only applies to suppliers of CO2, but it will be relevant for any oil and gas facilities that receive purchased CO2 to understand the suppliers’ reporting obligations. A detailed discussion of each of these subparts is provided below. The following discussion also considers, where appropriate, the sources and the source ranking results in earlier chapters of this report and how they may be impacted by the proposed reporting rule. Table 31 is a an initial attempt to match up the oil and gas GHG source types listed in the Task 1 report with the sources that could be subject to the reporting requirements of the rule. The table rules out mobile source reporting, and any fugitive or process emission source types not specifically covered in the proposed rule. For the remaining sources potentially subject to the rule, no attempt has been made to distinguish operated sources versus contractor emission sources. Regarding contractor emissions, the proposed rule appears to be silent on the issue. The standard definition of “facility” provided in the proposed rule can be used to determine whether contractor emissions should be reported or not. Table 31. Cross Reference of Oil and Gas Source Categories with Mandatory Reporting Rule Elements

Source Category Potentially Covered in Rule (if facility is above threshold)/Rule Subpart

Well testing Yes/W Exploratory drilling Yes/C Completion activities (non-venting) Yes/C Completion venting Yes/W Drill mud degassing No Drill rigs Yes/C Workover rigs Yes/C (But not if mobile source) Miscellaneous I.C engines Yes/C Glycol dehydrators Yes/C Flares/incinerators Yes/W (flares) C (incinerators) Heavy-duty trucks No Medium-duty trucks No Light-duty trucks No Light-duty automobiles No Offshore Support and Seismic Vessels (OSV) No Helicopters (Offshore) No Artificial lift engines (pumpjacks) Yes/C Oil well tanks Yes/W Oil well truck loading No Pneumatic devices Yes/W Oil well fugitives Yes/W Chemical injection pumps Yes/W

April 2010 129

Source Category Potentially Covered in Rule (if facility is above threshold)/Rule Subpart

Vapor recovery unit (VRU) engines Yes/C Heaters Yes/C Boilers Yes/C Cogen Units (EOR) Yes/C Miscellaneous Engines Yes/C Process heat/steam imports No Salt-water disposal (SWD) engines Yes/C Gas actuated pumps Yes/C Landfarms No Central power plant turbines (offshore) Yes/C Central power plant IC Engines (offshore) Yes/C Converted Diesel ship engines (offshore) Yes/C Tankers in Floating Production, Storage, and Offloading Systems – FPSO (Offshore)

Yes/W

Coke gasification unit Yes/C or W Hydrogen production unit Yes/C or W Primary upgrading coke unit Yes/C or W Gas well condensate tanks Yes/W Gas well truck loading No Gas well fugitives Yes/W Compressor start-ups and shutdowns Yes/C Miscellaneous gas-fired heaters or boilers Yes/C Dehydrators Yes/C Amine units Yes/C or W – possibly PP if CO2 gas is captured Well blowdowns Yes/W Compressor blowdowns Yes/W Lateral/wellhead compressor engines Yes/C CBM pump engines Yes/C Gas actuated pumps Yes/W Gas well and plant truck loading No Gas pipeline fugitives Yes/W Water treatment facilities (evaporative ponds) No Gas processing plant fugitives Yes/W Acid gas removal systems Yes/C or W – possibly PP if CO2 gas is

captured Boilers/Steam generators Yes/C Gas turbines Yes/C Vessel blowdowns Yes/W Pipeline blowdowns Yes/W Haulers and dumptrucks No Bulldozers No Scrapers No Blasthole Drills No Explosive loading trucks No Front end loaders No Hydraulic excavators No Mobile cranes, forklifts, maintenance and supply trucks, road graders, etc.

No

April 2010 130

SUBPART C - GENERAL STATIONARY FUEL COMBUSTION SOURCES

Stationary fuel combustion sources are devices that combust solid, liquid, or gaseous fuel generally for the purposes of producing electricity, generating steam, or providing useful heat or energy for industrial, commercial, or institutional use, or reducing the volume of waste by removing combustible matter. Stationary fuel combustion sources include, but are not limited to, boilers, combustion turbines, engines, incinerators, and process heaters. Emergency generators with a permit issued by state or local air pollution control agency are excluded. Facilities that contain stationary fuel combustion units, but not any other covered sources are not required to report if total stationary combustion emissions are <25,000 MT CO2e or if their total maximum rated heat input capacity for all stationary fuel combustion units is less than 30 mmBtu/hr. The rule requires CO2, CH4, and N2O to be reported. EPA is proposing to not require reporting of emissions from portable equipment or generating units designated as emergency generators in a permit issued by a state or local air pollution control agency. The EPA is requesting comments on whether or not a permit should be required for these emergency generators. Wastewater Treatment Only facilities operating wastewater treatment systems with emissions of 25,000 mtCO2e (i.e., anthropogenic CO2, CH4, and N2O emissions generated at a wastewater treatment system minus CH4 combusted) would be required to report their emissions. Electricity Generation Electricity generation is only applicable if there is on-site stationary combustion such as a co-generation unit that is selling electricity to the grid. Emergency generators are specifically excluded from reporting. There are some oil and gas fields with cogeneration plants that sell electricity to the grid, and these cogeneration plants are subject to stationary combustion requirements as outlined in the Rule, below. When drafting the Rule, the EPA considered requiring reporting of electricity reporting, but decided not to exclude it, at least initially. EPA has requested further comment on this issue during the public comment period. Mobile Sources The rule focuses on upstream sources with all vehicle and engine manufacturers, except small businesses or small-volume manufacturers required to report emissions. However, the EPA is taking comment on the possibility of vehicle fleet operations reporting.

April 2010 131

Reporting Thresholds For each segment in the petroleum and natural gas industry as amenable to a reporting program, four thresholds were considered for emissions reporting as applicable to an individual facility; 1,000 metric tons of CO2 equivalent (mtCO2e) per year, 10,000 mtCO2e, 25,000 mtCO2e, and 100,000 mtCO2e. A threshold analysis was then conducted on each segment to determine which level of threshold was most suitable for each industry segment. CH4, CO2, and N2O emissions from each segment were included in the threshold analysis. Table 32 provides the details of the threshold analysis at all threshold levels for the different segments in the oil and gas industry. Table 32. Threshold Analysis for the Oil and Gas Industry Segments.

Monitoring Requirements

For stationary combustion sources, owners are required to use the methodologies in the rule to calculate the GHG emissions, except for electricity generating units that are subject to the Acid Rain Program. EPA already collects CO2 emissions data from electricity generating units in the Acid Rain Program, which combust the vast majority of coal consumed in the U.S. annually4. 4 The Acid Rain program was implemented in two phases with an objective to reduce annual SO2 emissions by 10 million tons below 1980 levels. Phase I began in 1995 and affected mostly coal-burning electric utility plants located in eastern and Midwestern states. Phase II, which began in the year 2000, tightened the annual emissions limits imposed on these large, higher emitting plants and also set restrictions on smaller, cleaner plants fired by coal, oil, and gas

Emissions Covered Facilities Covered

Source Category

Threshold Level

Total National

Emissions

Number of

Facilities

Process Emissions mtCO2e/

yr

Combustion CO2

Emissions mt/yr

Total Emissions mtCO2e/yr Percent Number Percent

100,000 10,162,179 2,525 2,931,777 204,408 3,136,185 31% 4 0.2%

25,000 10,162,179 2,525 3,969,694 1,168,382 5,138,076 51% 50 2%

10,000 10,162,179 2,525 4,678,145 2,095,741 6,773,885 67% 156 6%

Offshore Petroleum and Natural Gas Production Facilities 1,000 10,162,179 2,525 5,951,766 3,831,730 9,783,496 96% 1,021 40%

100,000 50,211,548 566 21,581,714 17,459,840 39,041,555 78% 125 22% 25,000 50,211,548 566 26,006,801 21,493,174 47,499,976 95% 287 51% 10,000 50,211,548 566 27,113,211 21,094,641 49,207,852 98% 394 70%

Onshore Natural Gas Processing Facilities 1,000 50,211,548 566 28,038,416 22,173,132 50,211,548 100% 566 100%

100,000 73,198,355 1,944 1,589,418 11,833,992 30,200,243 41% 216 11% 25,000 73,198,355 1,944 4,749,993 36,032,206 63,835,288 87% 874 45% 10,000 73,198,355 1,944 5,480,135 41,670,038 71,359,167 97% 1,311 67%

Onshore Natural Gas Transmission Facilities 1,000 73,198,355 1,944 5,682,533 43,163,746 73,177,746 100% 1,659 85%

100,000 11,719,044 398 3,262,598 2,003,351 5,265,948 45% 35 9% 25,000 11,719,044 398 6,120,836 3,758,410 9,879,247 84% 131 33% 10,000 11,719,044 398 6,800,178 4,175,550 10,975,728 94% 197 49%

Underground Natural Gas Storage Facilities 1,000 11,719,044 398 7,250,309 4,451,947 11,702,256 100 346 87%

100,000 1,956,435 157 469,981 167,496 637,477 33% 3 2% 25,000 1,956,435 157 1,338,416 332,001 1,670,427 85% 29 18% 10,000 1,956,435 157 1,504,228 356,085 1,860,314 95% 39 25%

LNG Storage Facilities

1,000 1,956,435 157 1,549,469 390,734 1,940,203 99% 54 34% 100,000 1,896,626 5 813,899 1,081,254 1,895,153 99.9% 4 80% 25,000 1,896,626 5 813,899 1,081,254 1,895,153 99.9% 4 80% 10,000 1,896,626 5 813,899 1,081,254 1,895,153 99.9% 4 80%

LNG Import Facilities

1,000 1,896,626 5 814,531 1,082,095 1,896,626 100% 5 100%

Note: Totals may not add exactly due to rounding

April 2010 132

Methodologies for measuring stationary combustion emissions are classified according to methodological complexity using a four-tier system. A direct measurement (CEMS) approach would be a Tier 4 method and require the most rigorous monitoring. Tiers 3 and 2 could be defined by measurement strategies using a combination of direct fuel measurement and the application of a combination of fuel-specific factors. The least rigorous tier, Tier 1, could be met by using quarterly fuel consumption records combined with default factors. The most stringent emissions calculation methods will apply to large stationary combustion units (above 250 mmBtu/hr rating) that are fired with solid fuels and that have existing CEMS equipment. This is due to the complexity of monitoring solid fuel consumption and the heterogeneous nature of solid fuels. The next level of methodological stringency applies to large stationary combustion units (above 250 mmBtu/hr rating) that are fired with liquid or gaseous fuels. The stringency of the methods reflects the homogenous nature of these fuels and the ability to monitor fuel consumption more precisely. However, in cases where there is greater heterogeneity in the fuels (e.g., refinery fuel gas) more frequent analyses of liquid and gaseous fuels is required. For smaller combustion units (250 mmBtu/hr rating or less), EPA is proposing to allow the use of more simplified emissions calculation methods that rely on relationships between the heat content of the fuel (a generally known parameter) and the CO2 emission factor associated with the fuel’s characteristics. Table 33 details when each of the four reporting tiers will be required. Table 33. Four-Tiered Approach for Calculating CO2 Emissions from Stationary Combustion Sources.

Combustion Unit Size Additional Requirement (s) Methodological

Tier Requireda

Solid Fossil Fuel (e.g., Coal)

- Unit has operated more than 1,000 hours a yearb

- Unit has existing, certified gas monitors or stack gas volumetric flow rate monitor (or both); and - Facility has an established monitoring infrastructure and meets specific QA/QC requirements.

4 > 250 mmBtu/hour

- Unit does not meet conditions above. 3 - Unit operates more than 1,000 hours a yearb - Unit has existing, certified CO2 or O2 concentration monitor and stack gas volumetric flow rate monitor; and - Facility has an established monitoring infrastructure and meets specific QA/QC requirements.

4

- Unit does not meet conditions above. - Monthly measured HHV is available. 2

≤ 250 mmBtu/hour

- Unit does not meet conditions above. - Monthly measured HHV is not available 1

Gaseous Fossil Fuel (e.g., Natural Gas)

> 250 mmBtu/hour None 3

- Monthly measured HHV is available 2 ≤ 250 mmBtu/hour - Monthly measured HHV is not available 1

April 2010 133

Combustion Unit Size Additional Requirement (s) Methodological

Tier Requireda

Fossil Liquid Fuel (e.g., Diesel)

> 250 mmBtu/hour None 3

- Monthly measured HHV is available 2 ≤ 250 mmBtu/hour - Monthly measured HHV is not available 1

Biomass or Biomass-Derived Fuels (e.g., wood)

All Sizes - EPA has provided a default CO2 emission factor and a default heating value for the fuel. 1

All Sizes - EPA has provided a default CO2 emission factor for specific fuel to be used with that fuel’s measured heating value.

2

All Sizes - EPA has not provided a default CO2 emission factor for specific fuel to be used with that fuel’s measured heating value

3

MSW

- Unit has operated more than 1,000 hours a yearb - Unit has existing, certified gas monitors or stack gas volumetric flow rate monitor (or both); and - Facility has an established monitoring infrastructure and meets specific QA/QC requirements.

4 > 250 tons MSW/day

- Unit does not meet conditions above. 2 - Unit operates more than 1,000 hours a yearb - Unit has existing, certified CO2 concentration monitor and stack gas volumetric flow rate monitor; and - Facility has an established monitoring infrastructure and meets specific QA/QC requirements.

4 ≤ 250 tons MSW/day

- Unit does not meet conditions above. 2 a Minimum tier level to be used by reporters. Reporters required to use Tier 1, 2 or 3 have the option to use a higher tier methodology. b Hours of operation in any year since 2005. Tier 4 The most rigorous calculation method, Tier 4, requires owners and operators to calculate the annual CO2 mass emissions from all fuels combusted in a unit, by using quality-assured data from continuous emission monitoring systems (CEMS). According to the EPA, the Tier 4 calculation method is required for units which have a maximum rated heat input capacity greater than 250 mmBtu/hr, (or in the case of Municipal Solid Waste or MSW combustion greater than 250 tons per day of MSW), has operated for more than 1,000 hours in any calendar year since 2005 and has installed CEMS monitoring equipment as required by 40 CFR, part 75 or an applicable State continuous monitoring program. It appears the EPA has identified that existing CEMS stacks without monitors will need to install the CO2 monitors before January 1, 2011. If monitors are in place and certified by January 1, 2010, the Tier 4 Calculation Methodology shall be used. If not installed the owner or operator

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shall use the Tier 3 Calculation Methodology in 2010 and Tier 4 methodologies starting January 1, 2011. This tier requires a CO2 concentration monitor and a stack gas volumetric flow rate monitor (if not already installed) to capture emissions data at hourly intervals and convert to CO2 mass emission rates in metric tons per hour. Two equations are provided for monitoring on a wet and dry basis. If the CO2 concentration is measured on a dry basis, a correction for the stack gas moisture content is required. The owner or operator should continually monitor stack gas moisture content using an acceptable monitoring system (as used for SO2 monitoring under the Acid Rain Program) or use default moisture percentages which are provided in the rule (coal, wood and natural gas fuel types only). For dry monitoring, the subpart also provides a moisture correction to be applied to wet-basis equation for each unit operating hour. If the effluent gas stream monitored by the CEMS consists solely of combustion products and if only fuels that are listed in the rule (coal, petroleum coke, tire derived fuel, oil, natural gas, propane, butane and wood) are combusted in the unit, an oxygen (O2) concentration monitor may be used in lieu of a CO2 concentration monitor to determine the hourly CO2 concentration The calculations (and recommended factors for inclusion in calculations) must be undertaken using equations provided in appendix F to part 75 of the chapter Operating Hour Each hourly CO2 mass emission rate is multiplied by the operating time to convert it from metric tons per hour to metric tons. The operating time is the fraction of the hour during which fuel is combusted (e.g., the unit operating time is 1.0 if the unit operates for the whole hour and is 0.5 if the unit operates for 30 minutes in the hour). For common stack configurations, the operating time is the fraction of the hour during which effluent gases flow through the common stack. The hourly CO2 mass emissions are then summed over the entire calendar year. Biogenic Fuel (or Biomass-Derived Fuel) The subpart defines biomass as non-fossilized and biodegradable organic material originating from plants, animals and microorganisms, including products, by-products, residues and waste from agriculture, forestry and related industries as well as the non-fossilized and biodegradable organic fractions of industrial and municipal wastes, including gases and liquids recovered from the decomposition of non-fossilized and biodegradable organic material. If both biogenic fuel and fossil fuel are combusted during the year, the owner or operator must determine the biogenic CO2 mass emissions separately. The subpart provides a number of alternatives for measuring biomass derived fuel including the use of Tier 1 equations (provided that Tier 4 is not required and the waste fits the definition of biomass derived fuel (not MSW). If CEMS are used and if both fossil fuel and biogenic fuel (except for MSW) are combusted in the unit during the reporting year, the subpart provides an equation for fossil fuels to determine the annual biogenic CO2 mass emissions. For a unit that combusts MSW, the owner or operator shall use specific methods provided in the sub-part to determine the relative proportions of biogenic and non-biogenic CO2 emissions

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Tier 3 The EPA proposed rule provides a set of fairly standard emission summary equations including for natural gas combustion. The important issues pertaining to Tier 3 reporting include frequency of sampling and maintenance of the monitoring equipment. The required frequency for carbon content determinations for Tier 3 reporting is monthly for natural gas, as well as for liquid and solid fuels. Monthly molecular weight determinations are also required for all gaseous fuels. Daily determinations for other non-standard gaseous fuels (e.g., refinery gas, process gas, etc.) will be required. The EPA is also proposing that a facility may use the Tier 3 calculation methodology to calculate facility-wide CO2 emissions (rather than unit-by-unit emissions) if the same gaseous fuel is used across the facility and a common direct measurement of fuel consumed is available (e.g., a natural gas meter at the facility gate). So several combustion devices that are supplied natural gas from a common meter can apparently be combined for reporting purposes. Regarding meter maintenance and accuracy, Tier 3 will require direct measurement of the amount of fuel combusted, using calibrated fuel flow meters. The EPA rule proposes that all Tier 3 oil and gas flow meters would have to be calibrated prior to the first reporting year. These fuel flow meters are required to be recalibrated either annually or at the minimum frequency specified by the manufacturer. The EPA has provided specific equations for owners and operators to calculate the annual CO2 mass emissions for three-fuel types combusted in a unit: solid, liquid and gas. Data on the measurements of fuel carbon content, molecular weight, and the quantity of fuel combusted is required to complete the equations. In applying the gas equations, the CO2 mass emissions are calculated only for those days on which the gaseous fuel is combusted during the reporting year. This includes natural gas and other gaseous fuels (e.g., refinery gas or process gas). Tier 2 The Tier 2 calculation methodology would require that the HHVs of each fuel combusted would be measured monthly. EPA is proposing that the Tier 2 method be used by units with heat input capacities of 250 mmBtu/hr or less, combusting fuels for which EPA has provided default CO2 emission factors in the proposed rule – including natural gas, diesel, gasoline, jet fuel, and specified types of biomass. Fuel consumption would be based on company records. Regarding accuracy of fuel measurement, the rule specifies in part 98.34 that the owner or operator will need to document the procedures used to ensure the accuracy of the estimates of fuel usage including, but not limited to, calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and the technical basis for these estimates shall be provided. No frequency of calibration is mentioned until Tier 3 reporting is required and annual calibration (or more frequently if recommended by manufacturer) is required. Tier 1

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Under Tier 1, the annual CO2 mass emissions will be calculated using the quantity of each type of fuel combusted during the year, in conjunction with fuel specific default CO2 emission factors and default Highest Heating Values (HHVs). The rule provides an equation for this calculation. The amount of fuel combusted would be determined from company records. The default CO2 emission factors and HHVs are national-level default factors. The Tier 1 method may be used by any small unit if EPA has provided the fuel specific HHV and emission factors in proposed 40 CFR part 98, subpart C (includes natural gas, diesel, gasoline, jet fuel, and specified types of biomass). However, if the owner or operator already performs fuel sampling and analysis on a monthly (or more frequent) basis to determine the HHV and other properties of the fuel, or if monthly HHV data are provided by the fuel supplier, Tier 1 could not be used but instead Tier 2 (or a higher tier) would have to be used. For both Tier 1 and 2 reporting, owners and operators will need to maintain documentation of the procedures used to maintain the monitoring equipment, along with an estimation of the accuracy. It appears that there is no specific accuracy requirement. The proposed rule also states that if a facility contains two or more units (e.g., boilers or combustion turbines) that have a combined maximum rated heat input capacity of 250 mmBtu/hr or less, the owner or operator may report the combined emissions for the group of units in lieu of reporting separately the GHG emissions from the individual units. If the combined maximum rated heat input capacity of the units is above this level, each unit’s emissions must be separately detailed in the annual report. Methane and Nitrous Oxide CH4 and N2O emissions are also required to be reported from stationary combustion. For units subject to the requirements of the Acid Rain Program and for other units monitoring and reporting heat input on a year-round basis according to 40 CFR part 75.10(c) and 75.64, an equation is provided. For all other units, separate equations and procedures are provided to calculate the annual CH4 and N2O emissions. Monitoring Quality Assurance and Control For units using the following calculation methodologies, records must include both company records and a detailed explanation of how company records are used to estimate the following:

Fuel consumption, when using Tier 1 and 2 Fuel consumption, when using Tier 3 and solid fuel is combusted Fossil fuel consumption when the owner or operator of a unit that uses CEMS to quantify

CO2 emissions and that combusts fossil and biogenic fuels separately reports the biogenic portion

The owner or operator must document procedures used to ensure the accuracy of the estimates of fuel usage and the estimated accuracy of measurements made with any devices must also be recorded. Procedures for Estimating Missing Data

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When a quality-assured value of a required parameter is unavailable, EPA allows a substitute data value for the missing parameter to be used in the calculations. For units subject to requirements of the Acid Rain Program, applicable procedures shall be followed for CO2 concentration, stack gas flow rate, fuel flow rate, gross calorific value, and fuel carbon content For units not subject to the requirements of the Acid Rain Program, and when Tier 1, 2, 3, or 4 calculations are used, substitution is performed as follows:

For each missing value of the heat content, carbon content, or molecular weight of the fuel, and for each missing value of CO2 concentration and percent moisture, the substitute data will be the average of the quality assured values of that parameter immediately preceding and following the missing data incident.

For missing records of stack gas flow rate, fuel usage, and sorbent usage, the substitute data value shall be the best available estimate based on all available process data. All procedures for making these estimates must be documented.

Data Aggregation For stationary combustion operations, the aggregation of data is required beyond facility-level data. The rule requires annual GHG emissions reports to disclose unit-level or process-level emissions data and emissions verification information. At a unit-level, the owner or operator will be required to report:

Unit ID number Code representing the type of unit Maximum rated heat input capacity of the unit in mmBtu/hr Each type of fuel combusted in the unit during the report year Calculated CO2, CH4, and N2O emissions for each type of fuel combusted, expressed in

native unites and mtCO2e Method used to calculate CO2 emissions for each type of fuel combusted CEMS, LME methodologies, as applicable Calculated CO2 emissions from sorbent Total GHG emissions from the unit for the reporting year for all fuel types in mtCO2e

However, the rule does provide some alternatives to simplify unit-level reporting. The EPA will allow reporting of the above data (with slight variations) for: 1) aggregations of small units that have a combined maximum rated heat input of ≥250 MMBtu/hr 2) monitored common stack i.e. flue gases from two or more stationary combustion units at a facility are discharged through a common stack and 3) common pipe configurations i.e. two or more oil-fired or gas-fired stationary combustion units at a facility combust the same type of fuel and that fuel is fed to the individual units through a common supply line or pipe (provided a calibrated fuel flow meter is used). However, if these alternatives are not feasible, the above information is required on an individual basis,

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Record Keeping In reviewing subpart C of the rule, owners and operators of stationary combustion will be required to maintain very detailed and specific record keeping requirements for at least 5 years. This includes:

A list of all units, operations, processes, and activities for which GHG emission were calculated

The data used to calculate the GHG emissions for each unit, operation, process, and activity, categorized by fuel or material type including results of analyses for HHV and carbon content, CEMS certification and quality assurance tests and development of site-specific emissions factors.

Documentation of the process used to collect the necessary data for the GHG emissions calculations.

The GHG emissions calculations and methods used. All emission factors used for the GHG emissions calculations. Any facility operating data or process information used for the GHG emission

calculations. Names and documentation of key facility personnel involved in calculating and reporting

the GHG emissions. The annual GHG emissions reports. A log-book, documenting procedural changes to the GHG emissions accounting methods

and changes to the instrumentation critical to GHG emissions calculations. Missing data computations. A written quality assurance performance plan Fuel consumption, when Tier 1 and Tier 2 Calculation Methodologies are used. Fuel consumption, when solid fuel is combusted and the Tier 3 Calculation Methodology

is used. Fossil fuel consumption, when the owner or operator of a unit that uses CEMS to

quantify CO2 emissions and that combusts both fossil and biogenic fuels separately reports the biogenic portion of the total annual CO2 emissions.

Procedures used to ensure the accuracy of the estimates of fuel usage and sorbent usage The EPA has proposed records shall be kept in an electronic or hard copy format and recorded in a form that is suitable for expeditious inspection and review. Verification EPA has included specific requirements for data and supplementary information to verify the reported emissions for stationary combustion facilities, depending on the calculation methodology used. As would be expected, it appears the more complex calculation methodologies require more detailed supplementary evidence to be provided. For Tier 1, owners and operators are required to report the total quantity of each type of fuel combusted during the reporting year only. For Tier 2, monthly fuels combustion quantities are to be reported as well as the annual number of required HHV determinations for each type of fuel, and certain other values and methods used in the provided equations must be reported (separate documentation is required specific to combustion of MSW).

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For Tier 3 monthly or daily fuel combustion quantities are required as well as the annual number of required carbon content determinations for each type of fuel, methods and dates and results of measurement taken and other values used in Tier 3 equations. For Tier 4, owners and operators are required to report the total number of source operating days and hours in the reporting year, which CEMS and quality assurance procedures have been selected. In addition other CEMS related data as detailed as daily CO2 emissions, dates and results of tests conducted and specific methods for MSW and biomass-derived fuel combustion will be required. The metrics required for fuel reporting include metric tons for solid fuels, gallons for liquid fuels, and scf for gaseous fuels and for HHV include mmBtu per short ton for solid fuels, mmBtu per gallon for liquid fuels, and mmBtu per scf for gaseous fuels. Finally, the EPA administrator or state or local pollution control agency will be also able to request additional detail from owners and operators (to be delivered within 7 days) on how company records are used to quantify fuel consumption for the various calculation methodologies.

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SUBPART W - OIL AND NATURAL GAS SYSTEMS In the context of this rule, fugitive emissions from the petroleum and natural gas industry are defined as unintentional equipment emissions and intentional or designed releases of CH4 and/or CO2 containing natural gas or hydrocarbon gas (not including combustion flue gas) from emissions sources including, but not limited to, open ended lines, equipment connections or seals to the atmosphere. CO2 emissions resulting from the combustion of natural gas in flares are also considered fugitive emissions. This definition is then fairly broad and includes emissions sometimes categorized as process emissions or flaring emissions. Facilities with fugitive emissions greater than 25,000 metric tons CO2e are required to report. The oil and natural gas systems facilities covered by this subpart of the rule are: offshore petroleum and natural gas production facilities, onshore natural gas processing facilities (including gathering/boosting stations), onshore natural gas transmission compression facilities, onshore natural gas storage facilities, LNG storage facilities, and LNG import facilities. These facilities are included in the rulemaking because EPA considers that they represent potentially significant emissions sources, facilities are easily defined, and major fugitive sources can be characterized by direct measurement or engineering estimation. Other sectors of the industry such as onshore petroleum and natural gas production, petroleum and natural gas pipeline segments, natural gas distribution and crude oil transportation are not required to report their fugitive emissions in this first draft of the rule. If the onshore operations of a company exceed the 25,000 tonnes CO2e per year for combustion devices, or have combustion devices with a heat capacity throughput higher than 30MMBtu/hr, emissions from these operations will have to be reported only under Subpart C. Fugitive emissions from petroleum refineries are part of the rulemaking process, but these emissions are addressed in the petroleum refinery section (Subpart Y) of the rule. Definition of Facility One important factor to decide who should report under this rule is the definition of facility. Some sectors of the industry don’t have clear physical boundaries and ownership structures that allow to easily identifying a facility. The onshore petroleum and natural gas production segment is a case in point. This sector is responsible for the largest share of fugitive CH4 and CO2 emissions from petroleum and natural gas industry (27 percent of total emissions), but is not proposed for inclusion because it is difficult to define a facility in this sector and correspondingly to determine who would be responsible for reporting. Due to the significance of fugitive emissions from onshore petroleum and natural gas production activities, EPA is considering requiring entities to report fugitive emissions from all onshore petroleum and natural gas production assets at the basin level. If such a basin-level facility definition is pursued, EPA would propose reporting of only the major fugitive emissions sources; such as, natural gas driven pneumatic valve and pump devices, well completion releases and flaring, well blowdowns, well workovers, crude oil and condensate storage tanks, dehydrator vent stacks, and reciprocating compressor rod packing. Under this scenario, EPA might suggest that all operators would be subject to reporting, possibly exempting small businesses, as defined

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by the Small Business Administration. In cases where more than one company jointly owns emissions sources, each company would report emissions equivalent to its portion of ownership. EPA is seeking comments on this approach. Another sector that is currently not included in the rule but where EPA is proposing an approach to define a facility is the natural gas distribution sector. Here, EPA would require each distribution company to report fugitive emissions at the corporate level. EPA is seeking comments on this and other ways of reporting fugitive emissions from the distribution sector. Reporting Thresholds Table 32 of this report provides the details of the threshold analysis for the oil and natural gas industry. A proposed threshold of 25,000 mtCO2e applied to only those emissions sources listed in Table 32 captures approximately 81 percent of fugitive CH4 and CO2 emissions from the entire oil and natural gas industry, while capturing only a small fraction of total facilities. EPA is aware of the fact that the proposed rule doesn’t indicate a particular threshold for detection above which emissions measurement is required and that this can be burdensome for reporting emissions. Therefore, EPA is proposing two approaches to determine this threshold. Refer to section W of the preamble (Outstanding Issues on Which We Seek Comments) for more details on this issue. Monitoring Requirements Operators must report fugitive CH4 and CO2 emissions in metric tons per year from the following sources: acid gas removal (AGR) vent stacks, blowdown vent stacks, centrifugal compressor dry seals, centrifugal compressor wet seals, compressor fugitive emissions, compressor wet seal degassing vents, dehydrator vent stacks, flare stacks, liquefied natural gas import and export facilities fugitive emissions, liquefied natural gas storage facilities fugitive emissions, natural gas driven pneumatic pumps, natural gas driven pneumatic manual valve actuator devices, natural gas driven pneumatic valve bleed devices, non-pneumatic pumps, offshore platform pipeline fugitive emissions, open-ended lines (OELs), pump seals, platform fugitive emissions, processing facility fugitive emissions, reciprocating compressor rod packing, storage station fugitive emissions, storage tanks, storage wellhead fugitive emissions, transmission station fugitive emissions. Operators or owners are required to detect fugitive emissions from the emission sources stated above and to quantify them using either direct measurement methods or engineering equations. Fugitive emissions from all sources at the facility, whether in operating condition or on standby, have to be monitored on an annual basis. Table 34 provides the proposed source specific monitoring methods and emissions quantification methods.

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Table 34. Source Specific Monitoring Methods and Emissions Quantification.

Emission Source Monitoring Method Type Emissions Quantification

Methods Acid Gas Removal Vent Stacks Engineering estimation Simulation software Blowdown Vent Stacks Engineering estimation Gas law and temperature,

pressure, and volume between isolation valves

Centrifugal Compressor Dry Seals

Direct Measurement 1) High volume sampler, or 2) Calibrated bag, or 3) Meter

Centrifugal Compressor Wet Seals


Compressor Fugitive Emissions Direct Measurement 1) High volume sampler, or 2) Calibrated bag, or 3) Meter

Dehydrator Vent Stacks Engineering estimation Simulation software Flare Stacks Engineering estimation and direct

measurement Velocity meter and mass/volume equations

Natural Gas Driven Pneumatic Pumps

1) Engineering estimation, or 2) direct measurement

1) Manufacture data and equipment counts, or 2) High volume sampler, or 3) Calibrated bag, or 4) Meter

Non-pneumatic Pumps Direct Measurement High volume sampler Offshore Platform Pipeline Fugitive Emissions

Direct Measurement High volume sampler

Open-ended Lines Direct Measurement 1) High volume sampler, or 2) Calibrated bag, or 3) Meter

Pump Seals Direct Measurement 1) High volume sampler, or 2) Calibrated bag, or 3) Meter

Facility Fugitive Emissions Direct Measurement High volume sampler Reciprocating Compressor Rod Packing


Storage Tanks 1) Engineering estimation, and direct measurement, or 2) Engineering estimation

1) Meter, or 2) Simulations software, or 3) Vasquez-Beggs Equation

The Technical Review of Significant Source Categories report that is part of this task, presents GHG source category rankings of CO2e emissions from oil and natural operations in the southern region of the San Juan Basin, New Mexico; Uinta Basin, Utah; and the offshore region of California. The results of the rankings (for EPA defined fugitive emissions only) are in Table 35.

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Table 35. GHG Source Category Ranking (Fugitive Emissions). Basin or Area State Source Category Contribution (%)

Well Completion Venting 17.75 Well Blowdowns 7.17 Flaring 1.22 San Juan (South) New Mexico

Wellhead Fugitives 1.10 Pneumatic Devices 32.15 Pneumatic Pumps 15.61 Uinta Basin Utah Wellhead Fugitives 4.09 Flaring 20.07 Offshore California Fugitives 16.08

It is important to notice that all the sources mentioned above are contributors to top 95% CO2e emissions in these particular basins. For the offshore facilities, fugitive emissions will have to be reported under the proposed rule if overall fugitives are greater than 25,000 tons. These rankings provide a rough indication that a number of offshore facilities will have to report under the Part W requirements. Direct Measurement The proposed rule states that direct measurement is mandatory unless there is a demonstrated and documented safety concern that prohibits the use of a direct measurement method or when the variable in the emissions magnitude on an annual basis is the number of times the source releases fugitive CH4 and CO2 emissions to the atmosphere, at which time engineering estimates can be applied. Infrared remote fugitives emissions detection instruments, organic vapor analyzers (OVAs), and toxic vapor analyzers (TVAs) must be used to conduct annual leak detection of fugitive emissions from all the sources included in the proposed rule. For direct measurement, EPA proposes that high volume samplers, meters (such as rotameters, turbine meters, hot wire anemometers, and others), and/or calibrated bags be designated for use. However, if fugitive emissions exceed the maximum range of the proposed monitoring instrument, the operator will be required to use a different instrument option that can measure larger magnitude emissions levels. Additional options for how to measure when the range of emissions measurement is an issue are discussed in the Oil and Natural Gas Systems Technical Support Document (EPA-HQ-OAR-2008-0508-0235). The rule specifies that the operator is required to use a high volume sampler to calculate emissions from the following sources: centrifugal compressor dry seals fugitive emissions; centrifugal compressor wet seals fugitive emissions, compressor fugitive emissions, LNG import and export facility fugitive emissions, LNG storage station fugitive emissions, non-pneumatic pumps fugitive emissions, open-ended lines (OELs) fugitive emissions, pump seals fugitive emissions, offshore platform pipeline fugitive emissions, platform fugitive emissions, processing facility fugitive emissions, reciprocating compressor rod packing fugitive emissions, storage station fugitive emissions, transmission station fugitive emissions, and storage wellhead fugitive emissions.

5 Link to the document: http://www.epa.gov/climatechange/emissions/ghg_tsd.html

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If high volume samplers can’t capture all of the fugitive emissions, operators should use calibrated bags or meters such as rotameters, turbine meters, and others to measure the following fugitive emissions: open-ended lines (OELs), centrifugal compressor dry seals fugitive emissions, centrifugal compressor wet seals fugitive emissions, compressor fugitive emissions, pump seals fugitive emissions, reciprocating compressor rod packing fugitive emissions, and flare stacks and storage tanks (in this case operators should use meters in combination with engineering estimation methods to calculate fugitive emissions). In cases when is not safe to use calibrated bags or when the flow rate is too high, operators should use a hot wire anemometer calculate fugitive emissions from: centrifugal compressor wet seal, degassing vents and flares. Operators can choose the instrument to detect and to measure fugitive emissions from the choices provided in the rule that is best suited for their circumstance. Refer to section 98.234, subpart W of the proposed rule for details regarding how to choose the correct direct measurement method. Engineering Estimation

As mentioned above, engineering estimation methods can be applied only when direct measurement is not feasible. An exception to this rule are fugitive emissions coming from acid gas removal vents stacks, these emissions can’t be detected by the proposed direct measurement instruments included in this rule because these instruments mainly detect CH4 and the predominant constituent of these emissions is CO2. Therefore, there is no need to detect these emissions and there is a propose engineering estimation method included in this rule to calculate fugitive emissions coming from this source. For some sources, operators should direct measurement methods (infrared remote fugitives emissions detection instruments, OVAs and TVAs) to detect fugitive leak emissions and engineering estimation techniques to quantify these emissions. Operators can only use engineering estimation methods to calculate emissions from the following sources: acid gas removal vent stacks, natural gas driven pneumatic pumps, natural gas driven pneumatic manual valve actuator devices, natural gas driven pneumatic valve bleed devices, blowdown vent stacks, dehydrator vent stacks. A combination of engineering estimation method and direct measurement instruments should be used to calculate emissions from the following fugitive emissions sources: flare stacks, storage tanks, and compressor wet seal degassing vents. There are nine engineering estimation methods proposed in the rule, refer to section 98.233, subpart W for information on how to apply these methods. This section of the rule also includes equations for greenhouse gas (GHG) volumetric fugitive emissions and greenhouse gas (GHG) mass fugitive emissions. Procedures for Estimating Missing Data The proposed rule requires data collection for fugitive emission sources a minimum of once a year. If data are lost or an error occurs during fugitive emissions direct measurement, the

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operator should carry out the direct measurement a second time to obtain the relevant data point(s). Similarly, engineering estimates must account for relevant source counts and frequency of fugitive emissions releases throughout the year. There are no other provisions for missing data. Reporting Requirements Petroleum and natural gas facilities subject to the rule are required to report fugitive emissions on an annual basis. The reporting should be at a facility level with fugitive emissions being reported at the source type level. Fugitive emissions from each source type could be reported at an aggregated level. For example, a facility with multiple reciprocating compressors could report fugitive emissions from all reciprocating compressors as an aggregate number. It is important to note that fugitive emissions from all sources proposed for monitoring, whether in operating condition or on standby, have to be reported. Fugitive emissions resulting from standby sources have to be separately identified from the aggregate fugitive emissions and reported. Operators will be required to report the following information as part of the annual fugitive emissions reporting: fugitive emissions monitored at an aggregate source level for each reporting facility (assuming no carbon capture and transfer offsite), the quantity of CO2 captured for use and the end use (if known), fugitive emissions from standby sources, and activity data for each aggregate source type level. Additional data proposed to be reported to support verification are: engineering estimate of total component count, total number of compressors and average operating hours per year for compressors (if applicable), throughput per year (minimum, maximum and average), specification of the type of any control device used (including flares), and detection and measurement instruments used. For offshore petroleum and natural gas production facilities have to report: the number of connected wells, and whether they are producing. In the case of compressors, should report: total number of compressors and average operating hours per year. Record Keeping In addition to data requirements included in the General Provisions, the reporting facility should keep relevant information associated with the monitoring and reporting of fugitive emissions as follows; throughput of the facility when the fugitive emissions direct measurement was conducted, date(s) of measurement, detection and measurement instruments used, if any, results of the leak detection survey, and inputs and outputs to calculations or simulation software runs where the proposed monitoring method requires engineering estimation.

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SUBPART NN - SUPPLIERS OF NATURAL GAS AND NATURAL GAS LIQUIDS This subpart of the rule includes provisions affecting facilities and companies that introduce or supply natural gas and natural gas liquids (NGLs) into the economy, such as local natural gas distribution companies (LDCs) and natural gas processing plants. For the purpose of this particular report, this section only takes into account those issues proposed in rule related to natural gas processing plants. Natural gas processing plants must report the CO2 emissions that would result from the complete combustion or oxidation of the annual quantity of propane, butane, ethane, isobutane and the bulk of natural gas liquids (NGLs) sold or delivered for use off site. Combustion and other uses of natural gas are addressed in other subparts of the rule, such as subpart C (General Fuel Stationary Combustion Sources). Reporting Thresholds In developing the reporting threshold for LDCs and natural gas processors, EPA considered emissions-based thresholds of 1,000 mtCO2e, 10,000 mtCO2e, 25,000 mtCO2e and 100,000 mt CO2e per year. For natural gas suppliers, these thresholds are applied on the amount of CO2 emissions that would result from complete combustion or oxidation of the natural gas. Table 36 illustrates the NGL emissions and number of processing facilities that would be covered under these various thresholds. Table 36. Threshold Analysis for NGLs from Processing Plants.

Emissions Covered Facilities Covered Threshold Level mtCO2e/yr

Total National Emissions mtCO2e/yr

Total Number of Facilities

mtCO2e/yr Percent (%)

Number Percent (%)

1,000 164,712,077 566 164,704,346 100 466 82 10,000 164,712,077 566 164,704,207 100 400 71 25,000 164,712,077 566 163,516,733 99 347 61 100,000 164,712,077 566 157,341,629 96 244 43

EPA is not proposing a reporting threshold for natural gas processing plants. Each natural gas processing plant is already required to report the supply and disposition of NGLs monthly on EIA Form 816. Processing plants are also required to report the amounts of natural gas processed, NGLs produced, shrinkage of the natural gas from NGLs extraction, and the amount of natural gas used in processing on an annual basis on EIA Form 64A. Monitoring Methods Operators should report the amount of natural gas and NGLs produced or supplied to the economy annually, as well as the CO2 emissions that would result from the complete oxidation or combustion of this quantity of natural gas and NGLs. Facilities are required to report only CO2 emissions.

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Combustion of natural gas and NGLs may also lead to trace quantities of CH4 and N2O emissions. The proposed rule considers that the quantity of CH4 and N2O emissions are small, highly variable and dependent on technology and operating conditions in which the fuel is being consumed (unlike CO2). Therefore, operators are not required to report these emissions. When natural gas processing plants extract and separate individual components of NGLs, operators should report the carbon content of each individual component of the NGLs. In cases where raw NGLs are not separated, the processing plants should report the carbon content for raw NGLs. Natural gas processing plants can substitute their own values for carbon content provided they are developed according to nationally-accepted ASTM standards for sampling and analysis. The proposed rule includes two calculation methods to quantify the CO2e emissions and how these emissions should be monitored. Refer to section 98.403, subpart NN of the rule for details on these methodologies and monitoring requirements. Procedures for estimating missing data. Operators are required to have a complete record of all measured parameters used in the reporting of fuel volumes and in the calculations of CO2 mass emissions. Whenever a value is missing, a substitute data value must be calculated as specified in section 98.405, subpart NN of the rule. Operators should document and maintain records of the calculations of missing data. Reporting Requirements. The annual report for each natural gas processing plant must contain the following information: total annual quantity in barrels of NGLs (propane, natural butane, ethane, and isobutane, and all other bulk NGLs as a single category) produced for sale or delivery on behalf of others, and total annual CO2 mass emissions. Records Keeping In addition to the record keeping requirements included in the General Provisions section, operators must keep the following records: records of all daily meter readings and documentation to support volumes of natural gas and NGLs that are reported under this subpart, records documenting any estimates of missing metered data, calculations and worksheets used to estimate CO2 emissions for the volumes reported under this subpart, records related to the large end-users identified, and records relating to measured Btu content or carbon content.

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SUBPART PP- SUPPLIERS OF CARBON DIOXIDE Suppliers of CO2 include:

Facilities with production process units that capture and supply CO2 for commercial applications.

Facilities with CO2 production wells. Importers of bulk CO2, if total combined imports of CO2 and other GHGs exceed 25,000

tons of CO2 equivalent (CO2e) per year. Exporters of bulk CO2, if total combined exports of CO2 and other GHGs exceed 25,000

tons CO2e per year Entities that store CO2 through geologic sequestration or above ground storage; use CO2 in enhanced oil and gas recovery; transport or distribute CO2; purify, compress, or process CO2; or import or export CO2 in equipment are not included although EPA noted in the Preamble that significant sequestration can occur in EOR and subsurface storage applications. The result here is that CO2 suppliers apparently report all CO2 captured from production process units and extracted from production wells regardless of the destination of the CO2. Suppliers of CO2 will be required to calculate emissions quarterly by measuring the mass flow of gas and multiplying by the CO2 composition of the gas, as specified below:

For facilities with production process units or CO2 production wells that have mass flow meters installed to measure the volume of the CO2 captured or extracted, mass flow would be measured prior to any subsequent purification, processing, or compressing of the gas.

Facilities with production process units or CO2 production wells that do not have mass flow meters installed to measure the volume of the CO2captured or extracted would measure the mass flow of the CO2 transferred off site.

Importers or exporters of bulk CO2 would be required to use a mass flow meter to measure the volume of imported/exported CO2. If the CO2 importer does not have a mass flow meter installed to measure the volume imported, the measurements would be based on the volume of imported CO2 transferred off site or used in onsite processes. If a CO2 exporter does not have mass flow meters installed to measure the volume exported, the measurements would be based on the volume of CO2received for export.

CO2 composition would be measured quarterly. The proposal calls for facilities with production process units or CO2 production wells to report the following information at the facility level; importers and exporters would report the information at the corporate level:

Total annual mass of CO2 in metric tons. The weighted average composition of the CO2 stream captured, extracted, or transferred

in either gas, liquid, or solid forms. Annual amounts of CO2 transferred to the following end-use applications (if known):

o Food and beverage o Industrial and municipal water/wastewater treatment o Metal fabrication, including welding and cutting o Greenhouse uses for plant growth o Fumigants (e.g., grain storage) and herbicides

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o Pulp and paper o Cleaning and solvent use o Fire fighting o Transportation and storage of explosives o Enhanced oil and natural gas recovery o Long-term storage (sequestration) o Research and development

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PUBLIC COMMENT The public comment period is open for 60 days upon release on the Federal Register (not yet occurred) and the close of the comment period is likely to be at the end of May. There were two public hearings on April 6-7th in Arlington, Virginia and April 16th in Sacramento. Some public comments relevant to the oil & gas exploration and production industries included:

Mr. Scott (National Petrochemical and Refiners Association) suggested that the reporting burden could be further reduced by allowing the use of existing engineering estimation methodologies for source types for which these methodologies already exist and are in use for other reporting programs. Mr. Scott argued that it was unnecessary that EPA develop new estimation methodologies where such calculation protocols already exist, and that this just complicates the situation for those reporters facing the requirements of multiple programs.

Mr. Philip Marston (Denbury Resources), criticized the EPA for applying the assumption that all CO2 produced from geologic formations and transferred offsite for use in enhanced oil recovery is emitted. In reality, he said, much is recycled for reuse from one oil well to the next.

Mr. Jones (M.J. Bradley and The Clean Energy Group) felt that third-party verification is unnecessary given the authority provided to EPA to conduct site visits and to impose penalties, which will be sufficient reason for the owner to complete an accurate emissions report. Mr. Scott (National Petrochemical and Refiners Association) concurred that third-party verification would be an unnecessary and expensive requirement.

Mr. Scott (National Petrochemical and Refiners Association) expressed concern that the mandatory 60-day comment period is of insufficient length for stakeholders to appropriately digest the proposed rule and provide written comment. Mr. Scott argued that allowing more time for comment would be in EPA’s interest in order to get the rule right the first time, which he said is more important than to rush it. Further, the annual reporting timeline, including a March 31 deadline for reporting of the prior year’s emissions, is too tight. He suggested that a schedule more in alignment with those under other government reporting programs, such as the Toxic Release Inventory (which requires reporting in June), is more feasible.

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CONCLUSIONS The analyses presented in this report are aimed at providing guidance to the six WCI member states/provinces in the ongoing development of GHG reporting regulations for the O&G E&P sector. Specifically, this report provided four analyses that are intended to guide these regulatory processes:

(1) A characterization of the O&G production and production types occurring in various basins and regions in the six states/provinces that are part of the geographic domain of the analysis. This characterization is intended to inform the regulatory agencies at these states/provinces, and other interested readers of the production levels and types occurring so that these can be linked with the subsequent analysis of the most significant GHG emissions source categories operating in the various basins and regions of these states/provinces.

(2) Rankings of significant GHG emissions source categories for each of the basins and regions for which some activity data set was available from which to create rankings. The rankings were based on the development of screening-level inventories of GHG emissions from most major O&G E&P source categories, considering significance to be those categories contributing to the top 95% of GHG emissions in the basin or region. Where no data set was available for a basin or region, an analysis was conducted to create a similar ranking for a generic production type. The characterization of the production type in that basin or region (described above) would then be able to provide guidance on what may be the significant GHG emissions source categories in these basins or regions. Where activity data was not available for a screening-level estimate of GHG emissions for a particular source category, engineering judgment was used to indicate whether the source category may be significant for a basin, region or production type.

(3) A presentation and discussion of the methodologies available for estimating GHG emissions from the source categories analyzed in this report. The methodologies for significant source categories were discussed in greater detail, although in a primarily qualitative fashion, to provide information on the type of measured and estimated data currently available in these regions to estimate GHG emissions from various source categories. This information may be used to help guide states/provinces in determining what additional measurements or estimates may be desired in reporting GHG emissions for particular source categories.

(4) An analysis of the recently-released draft EPA GHG reporting regulation. Since some of the source categories covered in this draft EPA GHG reporting regulation are included in the O&G E&P source categories analyzed in this report, the details of the EPA regulation were analyzed to summarize and present the EPA reporting requirements in the draft regulation, and assess similarities and differences with the approaches discussed in the methodologies section.

The analyses presented here are intended for guidance purposes only, and also form an initial step in the development of the voluntary reporting protocol for this sector for The Climate Registry, which will be developed in Task 3 of this project.

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REFERENCES

API, 2004. “Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry,” Prepared for American Petroleum Institute (API), Prepared by URS Corporation, February.

Aspen, 2002. “HYSYS User’s Guide,” Aspen Technologies, Inc. Internet Address: http://www.aspentech.com/hysys

BC Oil and Gas Commission, 2009. Geographical Information Systems Data, British Columbia Oil and Gas Commission. Internet Address: http://www.ogc.gov.bc.ca/GIS.asp

CADOGGR, 2009. Online Mapping System (DOMS), State of California Department of Conservation Division of Oil Gas and Geothermal Resources (CADOGGR), March. Internet Address: http://www.conservation.ca.gov/dog/maps/Pages/index_map.aspx

CAPP, 2002. “Estimation of Flaring and Venting Volumes from Upstream Oil and Gas Facilities,” Canadian Association of Petroleum Producers (CAPP), May.

CAPP, 2004. “A National Inventory of Greenhouse Gas (GHG), Criteria Air Contaminant (CAC) and Hydrogen Sulphide (H2S) Emissions by the Upstream Oil and Gas Industry - Volume 3, Methodology for Greenhouse Gases,” Prepared by Canadian Association of Petroleum Producers (CAPP), September.

CAPP, 2009. “Statistical Handbook for Canada’s Upstream Petroleum Industry,” Prepared by Canadian Association of Petroleum Producers (CAPP), January.

CARB, 2008. “Speciation Profiles Used in ARB Modeling,” California Air Resources Board, May. Internet Address: http://www.arb.ca.gov/ei/speciate/speciate.htm

CARB, 2009. “Regulation for the Mandatory Reporting of Greenhouse Gas Emissions,” California Air Resources Board. Internet Address: http://www.arb.ca.gov/regact/2007/ghg2007/froghg.pdf

CENRAP, 2008. “Recommendations for Improvements to the CENRAP States’ Oil and Gas Emissions Inventories,” Prepared for Central States Regional Air Partnership (CENRAP), Prepared by ENVIRON International Corporation, November.

EIA, 2005. “Annual Energy Outlook with Projections to 2025 – Issues in Focus – Lower 48 Natural Gas Supply,” Prepared by U.S. Department of Energy, Energy Information Administration (EIA), DOE/EIA-0383(2005), January. Internet Address: http://www.eia.doe.gov/oiaf/archive/aeo04/issues_2.html

EIA, 2009. “Annual Energy Outlook 2009 with Projections to 2030,” Prepared by U.S. Department of Energy, Energy Information Administration (EIA), DOE/EIA-0383(2009), March. Internet Address: http://www.eia.doe.gov/oiaf/aeo/pdf/0383(2009).pdf

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Environment Canada, 2008. “National Inventory Report: Greenhouse Gas Sources and Sinks in Canada, 1990-2006,” May. Internet Address: http://www.ec.gc.ca/pdb/ghg/inventory_report/2006_report/2006_report_e.pdf

GRI, 2009. GRI-GLYCalc Version 4.0, Gas Research Institute. Internet Address: http://www.gastechnology.org/webroot/app/xn/xd.aspx?it=enweb&xd=10abstractpage%5C12352.xml

ITEP, 2005. Institute for Tribal Environmental Professionals, Private Communication.

M. EMPR, 2009. British Columbia Ministry of Energy, Mines and Petroleum Resources, Private Communication, March.

MB Petroleum Branch, 2009a. Manitoba Science, Technology, Energy and Mines – Petroleum Branch. Private Communication, March.

MB Petroleum Branch, 2009b. Geographic Information Systems Map Gallery, Manitoba Science, Technology, Energy and Mines – Petroleum Branch, March.

MTDNRC, 2009. Montana Online Oil and Gas Information System, Montana Department of Natural Resources and Conservation (MTDNRC), March. Internet Address: http://bogc.dnrc.state.mt.us/jdpintro.asp

NMED, 2006. “Ozone Precursors Emission Inventory for San Juan and Rio Arriba Counties, New Mexico,” Prepared for the New Mexico Environment Department (NMED), Prepared by ENVIRON International Corporation and Eastern Research Group (ERG), August.

NMOCD, 2009. Statistical Database on Production by Well, New Mexico Oil Conservation Division (NMOCD), March. Internet Address: http://www.emnrd.state.nm.us/OCD/Statistics.htm

Snyder, T., 2009. Santa Barbara County Air Pollution Control District (APCD), Private Communication, March.

TCR, 2008. “The Climate Registry General Reporting Protocol – Version 1.1,” Prepared by The Climate Registry (TCR), May. Internet Address: http://www.theclimateregistry.org/resources/protocols/general-reporting-protocol.php

USEPA, 1995. “Protocol for Equipment Leak Emissions Estimates,” U.S. Environmental Protection Agency, EPA-453/R-95-017, November.

USEPA, 1996a. “Methane Emissions from the Natural Gas Industry – Volume 12: Pneumatic Devices,” U.S. Environmental Protection Agency and Gas Research Institute, EPA-600/R-96-0801, June.

USEPA, 1996b. “Preferred and Alternative Methods for Estimating Fugitive Emissions from Equipment Leaks,” Prepared for U.S. Environmental Protection Agency, Prepared by Eastern Research Group (ERG), November.

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USEPA, 1998. “AP-42 Fifth Edition Volume I, Chapter 1: External Combustion Sources – Section 1.4 Natural Gas Combustion,” U.S. Environmental Protection Agency, July.

USEPA, 2003. “Final Regulatory Support Document: Control of Emissions from New Marine Compression-Ignition Engines at or Above 30 Liters per Cylinder,” U.S. Environmental Protection Agency, 420-R-03-004, January.

USEPA, 2005a. User’s Guide for the Final NONROAD2005 Model, U.S. Environmental Protection Agency, EPA420-R-05-013.

USEPA, 2005b. “Reduced Emissions Completions (Green Completions) – Lessons Learned from Natural Gas STAR,” U.S. Environmental Protection Agency, October. Internet Address: http://www.epa.gov/gasstar/documents/green_c.pdf

USEPA, 2006. “Installing Plunger Lift Systems in Gas Wells – Lessons Learned from Natural Gas STAR,” U.S. Environmental Protection Agency. Internet Address: http://www.epa.gov/gasstar/documents/ll_plungerlift.pdf

USEPA, 2009. “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007,” U.S. Environmental Protection Agency, April. Internet Address: http://epa.gov/climatechange/emissions/usinventoryreport.html

USEPA, 2009. "Mandatory Reporting of Greenhouse Gases; Proposed Rule," U.S. Environmental Protection Agency, 40 CFR Parts 86, 87, 89, et al., April.

USGS, 2008. “National Oil and Gas Assessment: Supporting Data” United States Geological Survey, Reston, VA. Internet address: http://energy.cr.usgs.gov/oilgas/noga/data.html

UTDOGM, 2009. LiveData Online Oil and Gas Information System, Utah Division of Oil, Gas and Mining (UTDOGM), March. Internet Address: http://oilgas.ogm.utah.gov/Data_Center/LiveData_Search/main_menu.htm

Villalvazo, L., 2009. San Joaquin Valley Air Pollution Control District (APCD), Private Communication, April.

WRAP, 2005. “Oil and Gas Emission Inventories for the Western States,” Prepared for Western Governors Association, Prepared by ENVIRON International Corporation, December.

WRAP, 2007. “WRAP Area Source Emissions Inventory Projections and Control Strategy Evaluation, Phase II,” Prepared for Western Governors Association, Prepared by ENVIRON International Corporation, September.

WRAP, 2008. “Joint Rocky Mountain Phase III Oil and Gas Emissions Inventory Project,” Prepared for Independent Petroleum Association of Mountain States (IPAMS) and Western Governors Association, Prepared by ENVIRON International Corporation and Buys & Associates Inc., July. Internet address: http://wrapair.org/forums/ogwg/PhaseIII_Inventory.html

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APPENDIX A

Annotated Table Summarizing Comments Received On Methodologies For Estimation of Emissions From The Source Categories at the

May 4-5, 2009 Technical WorkGroup Meeting

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Table A-1. Summary of all methodologies considered for estimation of emissions from the source categories considered in the screening-level inventories and source category rankings with written comments and comment at the TWG meeting in Denver, CO May 4-5 2009.

Methodologies Source Category

CO2 CH4 N2O Combined Comments

Metered fuel consumption rate, fuel gas composition analysis to determine carbon content of fuel, assumed fuel carbon fraction oxidized to CO2

1.



Estimated fuel consumption using brake-specific fuel consumption (BSFC) factor for engine or estimated engine efficiency factor2, measured or estimated engine activity (e.g. hp, load factor), carbon content of fuel, assumed fuel carbon fraction oxidized to CO2, or estimated fuel carbon content based on fuel type3.

Measured or estimated engine activity data (e.g. hp, load factor) and emissions from Continuous Emissions Monitoring (CEMS) or Parametric Emissions Monitoring (PEMS) systems.

Metered fuel consumption, or estimated fuel consumption using engine BSFC, measured or estimated engine activity data (e.g. hp, load factor), heating value of fuel based on fuel type, and volumetric- or energy-based N2O emissions factor4.

CEMs used for fuel measurement which includes a fuel meter. Use of PEMs (for methane) not recommended for any compressors either at large compressor stations or at wellhead compressors.

Reciprocating internal combustion engines – NG-fired compressors at gas processing plants, large compressor stations (“Permitted Compressors”)

Measured or estimated engine activity data (e.g. hp, load factor), engine efficiency factor, and energy-based CO2 emissions factor5.

Metered fuel consumption or estimated fuel consumption using engine BSFC, heating value of fuel based on fuel type, and volumetric- or energy-based CH4 emissions factor6.

Questions raised regarding the feasibility of metering fuel. By in large, compressor engines in the field do not have fuel meters. Most agreed that engines 500 hp and greater are metered. Very difficult to meter smaller engines due to large number of engines and cost. Estimates of cost were $6,000 to $7,000 to install and $2,000 to $3,000 to operate annually. Recommendation that operational data be used. Some producers use run time, throughput, differential pressure (to derive load), heat rate per hp-hr (mfgs specs) and fuel quality. However, manufacturers loads are based on pipeline quality gas determined on test stands. Additional method suggested is to measure CO2 or measure fuel volume and Carbon Content. CH4 and N2O are insignificant so suggested not to measure but use default emissions factors. Heating value (implying changes in composition of gas) does not change much within a field, so it is not recommended that this value needs to be measured frequently.

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8.

By and large, producers do not meter fuel flow in the field. For large permitted facilities there is generally data available but for smaller engines typical information includes hp, energy conversion or hp-hr rate, but fuel volume, load factor and CO2 emissions factors are not well known. For some older engines data such as name plate ratings are missing. In Wyoming, source testing is required for engines 200 hp and larger on an annual basis. Some pipeline companies use fuel sales data and allocate the data back to field operations in order to estimate the volume of fuel combusted, but the allocations are based on standard methods for all operations and are not considered to be very accurate. The proposed EPA rule requires engines rated at greater than 250 MMBtu/hr be metered. This represents very large engines (about 30,000 hp). Smaller engines, such as a 300 hp engine (4 MMBtu/hr), are far below the 30 MMBtuy/hr threshold for reporting combustion emissions by the proposed EPA rules. Suggested that there is likely a threshold below which meters might not be feasible.

Reciprocating internal combustion engines – NG-fired compressors at wellheads and lateral compressor stations (“Unpermitted Compressors”)




Artificial lift engines Same as “Permitted Compressors” above



Miscellaneous Engines Same as “Permitted Compressors” above



Electric generators at gas processing plants, large compressor stations (“Permitted Generators”)




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Metered fuel consumption rate for all rig engines combined, typical fuel carbon content for diesel fuel, assumed fuel carbon fraction oxidized to CO2.



Estimated fuel consumption using engine BSFC for each rig engine, measured or estimated engine activity (e.g. hp, load factor) for each rig engine, carbon content of fuel, assumed fuel carbon fraction oxidized to CO2

9.

Metered fuel consumption or estimated fuel consumption using engine BSFC for each rig engine, heating value of diesel fuel, and volumetric- or energy-based CH4 emissions factor10.

Metered fuel consumption or estimated fuel consumption using engine BSFC for each rig engine, heating value of diesel fuel, and volumetric- or energy-based N2O emissions factor11.

Written comment that there is very little venting associated with drilling rigs.

Drill Rigs



13.

Written comment that drilling rigs are portable and therefore do not fall into the EPA reporting scope

Workover rigs Same as Drill Rigs above Same as Drill Rigs above Same as Drill Rigs above CBM pump engines Same as Drill Rigs above Same as Drill Rigs above Same as Drill Rigs above Salt water disposal engines

Same as Drill Rigs above Same as Drill Rigs above Same as Drill Rigs above

Metered fuel consumption rate of marine engine, typical fuel carbon content for diesel fuel, assumed fuel carbon fraction oxidized to CO2.



Off-shore platform supply boats

Estimated fuel consumption using engine BSFC, measured or estimated engine activity (e.g. hp, load factor), carbon content of fuel, assumed fuel carbon fraction oxidized to CO2

14.

Metered fuel consumption or estimated fuel consumption using engine BSFC, heating value of diesel fuel, and volumetric- or energy-based CH4 emissions factor15.

Metered fuel consumption or estimated fuel consumption using engine BSFC, heating value of diesel fuel, and volumetric- or energy-based N2O emissions factor16.

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Measured or estimated engine activity data (e.g. hp, load factor), and brake-specific CO2 emissions factor-17.


18.


Source test – measured heater/boiler activity data, measured CH4 concentrations through GC, FTIR, NDIR techniques.

Source test – measured heater/boiler activity data, measured N2O concentrations through GC, FTIR, NDIR techniques.

Written suggestion to include CEMs for boilers and heaters

Estimated fuel consumption rate using heater/boiler specifications, cycling time, usage, and measured or estimated carbon content of fuel, assumed fuel carbon fraction oxidized to CO2.

Metered fuel consumption rate (energy basis), energy-based CH4 emissions factor for heater/boiler type19.

Metered fuel consumption rate (energy basis), energy-based N2O emissions factor for heater/boiler type20.

Written suggestion to include a methodology for both solid and liquid fuels

External combustion – NG-fired heaters and boilers at gas processing plants, large compressor stations (“Permitted Heaters/Boilers”)

Metered or estimated fuel consumption rate (energy basis), energy-based CO2 emissions factor21.

Estimated fuel consumption rate (energy basis), energy-based CH4 emissions factor for heater/boiler type22.

Estimated fuel consumption rate (energy basis), energy-based N2O emissions factor for heater/boiler type23.

Written comment that cycling rate is not included

External combustion – NG-fired heaters and boilers at wellheads or in well site equipment (“Unpermitted Heaters/Boilers”)




Flaring – including flaring at gas processing plants and large compressor stations (“Permitted Flares”)




Four types of flares are used; 1) post-fracture cleanup, new well completion, well workovers which are all temporary and not well designed, 2) temporary flares that are mobile for pipeline blowdowns, 3) stationary flaring at fixed facilities which are better designed and 4) emergency flares at stationary facilities. Majority of flares are for fracing and completion. Differences are the efficiencies and material combusted. For completion flaring it is more difficult to quantify the gas type. There are not commercial meters to handle purges and different flows that go to the flare. In-situ flare testing cannot be done and is technically not valid.

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Metered flare inlet fuel flow rate, fuel composition analysis to determine carbon content of fuel, assumed fuel carbon fraction oxidized to CO2, assumed flare destruction efficiency27.

General emissions factors per unit gas or oil produced, or emissions factor per unit of liquid hydrocarbon flared28.


Episodic flares at well blowdowns and completions-Literally 1000's of flares like this will make it difficult to measure.


Comments that flaring is also used extensively at oil/condensate tanks in the field, but these flares are sometimes referred to as combustors since they are designed differently from flares and are more controlled.




Recommend adding turbine generators for offshore platforms. Questions raised as to what data operators are currently collecting, what data is available, how you estimate fuel use and how you characterize the fuel. It was suggested that all you need for offshore platforms is one fuel meter and composition analysis.

Estimated turbine fuel input rate (energy-basis) using turbine power rating and turbine efficiency factor, energy-based CO2 emissions factor31.

Measured or estimated turbine activity data (e.g. power, load factor) and emissions from Continuous Emissions Monitoring (CEMS) or Parametric Emissions Monitoring (PEMS) systems.

Estimated turbine fuel input rate (energy-basis) using turbine power rating and turbine efficiency factor, energy-based N2O emissions factor32.

Centrifugal internal combustion engines – NG-fired turbines at gas processing plants, large compressor stations (“Permitted NG Turbines”)

Estimated turbine fuel input rate (energy-basis) using turbine power rating and turbine efficiency factor, energy-based CH4 emissions factor33.

Direct measurement of CO2 concentrations and flashing/working & breathing loss volumes from tanks (volume flow rate measurements and IR or GC/MS for CO2 concentration if present in the gas)

Direct measurement of CH4 concentrations and flashing/working & breathing loss volumes from tanks (volume flow rate measurements and IR or GC/MS for CH4 concentration)

This source category applies to atmospheric pressure tanks that receive hydrocarbon liquids from separators (large gun-barrel separators in oil wells, or in gas wells from small field separators). Some species that are in the liquid at high pressure go to gas phase when brought to atmospheric pressure. Some simulations exist to predict flashing emissions.

Condensate and oil tanks – flashing and working and breathing losses

Flashing and working & breathing losses estimation

Flashing and working & breathing losses estimation

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using modeling software (e.g. E&P TANKS), requires tank configuration, API gravity and Reid vapor pressure (RVP) of liquid, composition of liquid, separator and atmospheric pressure and temperature, production rate of liquid to tanks34.

using modeling software (e.g. E&P TANKS), requires tank configuration, API gravity and Reid vapor pressure of liquid, composition of liquid, separator and atmospheric pressure and temperature, production rate of liquid to tanks35.



Presentation by BP on HYSYS methodology. This is a large program, requires significant resources to run this software. Small/medium operators may not have the resources to use this. Gas, temperature, pressure, mass flow, liquid volume flow (molar flow in gas), set up the various components of the system. Model the flash vapor from the pressure drop into the tank. Configuration is totally customizable. Output produces flash vapor (speciated – VOC, CO2, methane). Reid showed an example of 1200 wells for which 18-19 samples were taken. End result is a set of regression equations, pressure-dependent lb/bbl condensate left in tank after flash. This process simulation is widely used in Wyoming and seems to work well. Inputs required are: pressure, temperature, and high-pressure liquid composition. Reid indicates that BP’s simulations are run in a constant-temperature mode (isothermal), results not highly dependent on temperature (much more so on pressure).

Correlation equations (e.g. Vasquez-Beggs equation), API gravity of liquid, separator pressure and temperature, specific gravity of flash gas, measured or estimated CO2 content of flash gas, production rate of liquid to tanks38.

Correlation equations (e.g. Vasquez-Beggs equation), API gravity of liquid, separator pressure and temperature, specific gravity of flash gas, measured or estimated CH4 content of flash gas, production rate of liquid to tanks39.

A new API compendium will provide a discussion on tank flashing which includes an analysis of various methods. These simulations can not be done for every well, so API section will discuss and show a range of flashing EFs (6.5-12.75 ton/yr), including also a Canadian EUB approach (24 ton/yr). The comparison includes Vasquez-Beggs, sampling from 1990’s project, simulations. API can extract a sample of these chapters prior to release and provide to the group. The API study focuses on crude oil tanks, not condensate tanks. Most producers currently use correlation equations to determine flashing emissions.

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In most areas of the country there are many small, remote tanks with low throughput and it will be very costly to measure or assess flashing emissions. This is not true in California where most tanks operated by large producers require VRUs to capture gas that is then sent to cogeneration units which in turn will be captured through the combustion of CO2 emissions. This may not be the case for smaller operators.

Direct measurement of gas consumption rate by pneumatic device type using gas flow meters upstream and downstream of device, measured or estimated CO2 content of gas42.

Direct measurement of gas consumption rate by pneumatic device type using gas flow meters upstream and downstream of device, measured or estimated CH4 content of gas43.

This category refers to gas-actuated devices like controllers and valves and use produced gas as the actuating gas. Some are now using compressed air in place of produced gas. Focus has been on controllers because they are the most prevalent devices and bleed more gas. Currently producers use emission factors from manufacturers’ data. The updated API compendium will summarize emission factors for production, processing and transmission. Typically there are 3 to 9 devices per well depending on whether dehydrators are used at the well site. Generally emission factors are available and match up well with manufacturers calculations but they must be corrected for the gas density to obtain accurate emissions.

Measured gas consumption rates by pneumatic device type from vendor data, measured or estimated CO2 content of gas.

Measured gas consumption rates by pneumatic device type from vendor data, measured or estimated CH4 content of gas.

Pneumatic devices

Emissions factor by pneumatic device type, measured or estimated CO2 content of gas44.

Emissions factor by pneumatic device type, measured or estimated CH4 content of gas45.

Difficulty in obtaining component counts. Many companies do not keep detailed drawings of individual wellhead configurations. Furthermore, this category applies to remote areas that do not have access to electricity or compressed are. Some suggested use of "typical" component counts for voluntary reporting but that we move slowly towards actually taking component counts.

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Direct measurement of gas consumption rate by pneumatic pump type using gas flow meters, measured or estimated CO2 content of gas46.

Direct measurement of gas consumption rate by pneumatic pump type using gas flow meters, measured or estimated CH4 content of gas47.

Written comment that the methodology should reflect the amount of liquid pumped not the bleed rate per time.

Measured gas consumption rates by pneumatic pump type from vendor data, measured or estimated CO2 content of gas.

Measured gas consumption rates by pneumatic pump type from vendor data, measured or estimated CH4 content of gas.

Pneumatic pumps

Emissions factor by pneumatic pump type (piston, diaphragm or average), measured or estimated CO2 content of gas48.

Emissions factor by pneumatic pump type (piston, diaphragm or average), measured or estimated CH4 content of gas49.

Metered volumetric gas flow rate during well completion, duration of venting, measured or estimated CO2 content of gas during venting.

Metered volumetric gas flow rate during well completion, duration of venting, measured or estimated CH4 content of gas during venting.

Need to have separators since you cannot meter liquids or solids. At least one producer uses orifice plate across the choke to estimate volume of gas vented. Questions raised as to the approach that should be used: Pressure drop or engineering estimates. Consensus that this needs to be followed up by the group.

Well completion venting

Gas volume vented during well completion estimated using engineering flow calculations, measured or estimated CO2 content of gas during venting50.


Written comment that ranking for well venting does not seem correct.

Well recompletion venting (well workovers)

Metered volumetric gas flow rate during well recompletion, duration of venting, measured or estimated CO2 content of gas during venting.

Metered volumetric gas flow rate during well recompletion, duration of venting, measured or estimated CH4 content of gas during venting.

Question arose whether well completion venting is the same as venting from workovers. If you go to refracs it is the same thing. Oil well workovers vs. gas well workovers need to be divided. Need to define the terms used. If you kill the well venting volume is very small. Generally, however, get a larger volume with well workovers.

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Gas volume vented during well completion estimated using engineering flow calculations, measured or estimated CO2 content of gas during venting52.


Once you open the well you will have venting. Many workovers may not involve releases. Acid simulation, frac blowback may result in venting but do not result in large volumes. Reservoir pressure, surface pressure, tubing volume and size of stimulation job will determine the volume vented. Gas composition is usually known. Will likely be a case-by-case evaluation due to all the variables.

Gas or oil well average volume vented per well workover, measured or estimated CO2 content of gas during venting54.

Gas or oil well average volume vented per well workover, measured or estimated CH4 content of gas during venting55.

Metered volumetric gas flow rate during well blowdown, duration of venting, measured or estimated CO2 content of gas during venting56.

Metered volumetric gas flow rate during well blowdown, duration of venting, measured or estimated CH4 content of gas during venting57.

Well venting for liquid unloading for tight sands occurs when production rate is low and liquids start building up in the well. One producer places an orifice at the end of a vent line and using a pressure transient analysis. Then determine volume per minute by counting minutes that the valve is open. The producer does this for the target formation (needs to be done for all three formation levels)

Well blowdowns

Gas volume vented during well blowdown estimated using engineering flow calculations (assumed to be isentropic flow of an ideal gas through a nozzle), measured or estimated CO2 content of gas during venting58.

Gas volume vented during well completion estimated using engineering flow calculations (assumed to be isentropic flow of an ideal gas through a nozzle), measured or estimated CH4 content of gas during venting59.

Compressor startups and shutdowns

Direct measured volume of gas vented during compressor startup or shutdown, measured or estimated CO2 content of vented gas.

Direct measured volume of gas vented during compressor startup or shutdown, measured or estimated CH4 content of vented gas.

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Estimated volume of gas vented during compressor startup or shutdown (estimated based on internal volume of compressor vented during event), measured or estimated CO2 content of vented gas60.

Estimated volume of gas vented during compressor startup or shutdown (estimated based on internal volume of compressor vented during event), measured or estimated CH4 content of vented gas61.

Emissions factors per startup or shutdown event, measured or estimated CO2 content of gas62.

Emissions factors per startup or shutdown event, measured or estimated CH4 content of gas63.

Measured volumetric flow rate and CO2 content of gas vented (measured at dehydrator still vent) per unit throughput of gas to the dehydrator.

Measured volumetric flow rate and CH4 content of gas vented (measured at dehydrator still vent) per unit throughput of gas to the dehydrator.

Written comment that measurement of vent stream very difficult

Estimated CO2 emissions per unit of gas throughput to the dehydrator using GRI GLYCalc (requires wet gas flow rate, wet gas temperature and pressure, use of gas-driven glycol pump, wet and dry gas water content, glycol flow rate, use of stripping gas and temperature and pressure of flash tank if used)64.

Estimated CH4 emissions per unit of gas throughput to the dehydrator using GRI GLYCalc (requires wet gas flow rate, wet gas temperature and pressure, use of gas-driven glycol pump, wet and dry gas water content, glycol flow rate, use of stripping gas and temperature and pressure of flash tank if used)65.

Dehydrators (still vent emissions)

Use of general dehydrator still vent emissions factors per unit of gas throughput to the dehydrator, measured or estimated CO2 content of gas66.

Use of general dehydrator still vent emissions factors per unit of gas throughput to the dehydrator, measured or estimated CH4 content of gas67.

Fugitive emissions from gas processing plants, large compressor stations (“Permitted Fugitives”)



April 2010 166







Written comment that component counts be included in methodology



Written suggestion to add use of advanced LDAR programs-screening decreases leaks


Direct measurement of CH4 emissions from leaking component using sample bagging and GC/MS analysis75

Sample bagging is not appropriate for wellhead fugitive emissions quantification.



Fugitive emissions from wellhead components (“Unpermitted Fugitives”)



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Written comment to state that equipment component counts were estimated not counted.

(Methodologies Not Included in Original Table)

This category refers to compressor seals. EPA interested in estimation of these fugitive emissions using either monitoring or estimation techniques using emission factors (page 16676 Subpart W). There are four categories: 1) Compressor wet seal degassing vents, 2) Compressor wet seal and dry seal emissions, 3) Compressor fugitive emissions and 4) reciprocating packing seals. Under EPA proposed rules both require annual leak detection measurements using emission factors. EPA indicates optical imaging camera can be used to identify leaks. For open ended lines, use a sample bagging method. Comment that compressors over 5 hp are already inspected for fugitives and no need for stack testing since everything is flared. EPA Natural Gas Star program indicates 50% of fugitive emissions from gas production are from compressors. Comment that oil fugitives much smaller. Concern that current emission factors (for example for centrifugal wet seals) have a very high error).

Compressor Station Fugitive Emissions

Many producers do not measure fugitives at E&P facilities, but have done measurements on pipelines and large turbines and reciprocating engines. Canada requires a leak detection and repair program and sometimes use high-volume flow sampler or Method 21 (OVA and screening value). Comment that there is a large threshold crossed between detecting a leak and then going out and sampling the device using bagging techniques. Difficult to do where there are several thousand field compressors. Another comment that it is more cost-effective to fix the leak than to measure and quantify the emissions. What is needed is the development of new emission factors.

Documents

Oil and Gas Exploration and Production Greenhouse Gas Protocol