2007 Oil and Gas 

Industry Survey 

Results

Final Report

December 2011

Final 2007 Oil and Gas Industry Survey Results

i

State of California

California Environmental Protection Agency

Air Resources Board

2007 Oil and Gas Industry Survey Results

Final Report

December 2011

Principal Author:

Stephanie Lee

Reviewed and Approved By:

James F. Nyarady, Manager

Strategy Evaluation Section

Floyd Vergara, Chief

Alternative Fuels Branch 

Richard Corey, Chief

Stationary Source Division

This report has been reviewed and approved for publication by the Air Resources Board 

(ARB). Approval does not signify that the contents reflect the views and policies of the 

ARB, nor does mention of any company constitute endorsement. This report is a direct 

reflection of the California process and equipment survey (for calendar year 2007) 

submitted by the companies that responded to the “ARB Oil and Gas Industry Survey” 

conducted in 2009.
Final 2007 Oil and Gas Industry Survey Results

ii

Acknowledgements

The 2007 ARB Oil and Gas Industry Survey and this report were developed with the 

assistance of the following ARB staff:

Nancy Adams

Joseph Fischer

Luis Leyva

Camille McCallion

Sarah Penfield 

Minh Pham

Edgar Vidrio

Glen Villa

We would like to extend our appreciation to the following trade associations for 

facilitating discussion among industry and governmental representatives:

Western States Petroleum Association (WSPA)

California Independent Producers Association (CIPA)

Independent Oil Producers’ Agency (IOPA)

We would also like to thank those industry representatives that met with ARB staff to 

share specific technical information and all the respondents that completed the survey.
Final 2007 Oil and Gas Industry Survey Results

iii

Table of Contents

Glossary......................................................................................................ix

Executive Summary .................................................................................................. ES-1

Chapter 1 – Survey Development ................................................................................1-1

Chapter 2 – General Information..................................................................................2-1

Chapter 3 – Overview of Total California Emissions ....................................................3-1

Chapter 4 – Wells.........................................................................................................4-1

Chapter 5 – Electricity Generation and Use .................................................................5-1

Chapter 6 – Vapor Recovery........................................................................................6-1

Chapter 7 – Combustion Equipment ............................................................................7-1

Chapter 8 – Components .............................................................................................8-1

Chapter 9 – Automated Control Devices ......................................................................9-1

Chapter 10 – Inspection and Maintenance.................................................................10-1

Chapter 11 – Natural Gas Dehydrators......................................................................11-1

Chapter 12 – Natural Gas Sweetening and Acid Gas Removal .................................12-1

Chapter 13 – Other Natural Gas Processing..............................................................13-1

Chapter 14 – Total Natural Gas Processing Emissions..............................................14-1

Chapter 15 – Natural Gas Compressors ....................................................................15-1

Chapter 16 –Pipeline Pigging and Natural Gas Gathering Pipelines..........................16-1

Chapter 17 – Separators ............................................................................................17-1

Chapter 18 – Crude Oil Sumps and Pits ....................................................................18-1

Chapter 19 – Crude Oil Storage Tanks ......................................................................19-1

Chapter 20 – Overview of California Emissions from Crude Oil Production, 

Processing, and Storage.......................................................................20-1

Chapter 21 – Overview of California Emissions from Dry Natural Gas Production, 

Processing, and Storage.......................................................................21-1

Appendix A : 2007 Oil and Gas Industry Survey ..........................................................A-1

Appendix B : Emission Calculation Methodologies and Corresponding Emission 

Factors....................................................................................................B-1

Appendix C : Site Visits and Meetings......................................................................... C-1

Appendix D : Internal Combustion Engine Use Categories......................................... D-1

Appendix E : Separator Type Categories.....................................................................E-1
Final 2007 Oil and Gas Industry Survey Results

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List of Tables and Figures

Chapter 1 – Survey Development

Table 1-1: Site Visits and Meetings..............................................................................1-2

Chapter 2 – General Information

Table 2-1: Number of Facilities by Business Type .......................................................2-2

Table 2-2: Number of Facilities by Primary Business Type..........................................2-3

Table 2-3: Crude Oil Totals ..........................................................................................2-4

Table 2-4: Natural Gas Totals ......................................................................................2-5

Table 2-5: Global Warming Potentials..........................................................................2-5

Chapter 3 – Overview of Total California Emissions

Table 3-1: Total California 2007 Emissions (Metric Tons/Year) ...................................3-1

Table 3-2: Total California Emissions by Primary Business Type ................................3-2

Table 3-3: Total California Emissions by Air District (Metric Tons/Year) ......................3-2

Table 3-4: Combustion Emissions by Combustion Type (Metric Tons/Year) ...............3-3

Table 3-5: Combustion Emissions by Primary Business (Metric Tons/Year)................3-3

Table 3-6: Vented Emissions by Source Type (Metric Tons/Year)...............................3-4

Table 3-7: Vented Emissions by Primary Business Type (Metric Tons/Year) ..............3-4

Table 3-8: Fugitive Emissions by Source Type (Metric Tons/Year)..............................3-5

Table 3-9: Fugitive Emissions by Primary Business Type (Metric Tons/Year) .............3-5

Table 3-10: Total California Emissions by CO2e Range (Metric Tons/Year) ................3-6

Table 3-11: Total California Combustion Emissions by CO2e Range...........................3-6

Table 3-12: Total California Vented Emissions by CO2e Range (Metric Tons/Year)....3-6

Table 3-13: Total California Fugitive Emissions by CO2e Range .................................3-6

Chapter 4 – Wells

Table 4-1: Number of Crude Oil Active Wells and Well Cellars by API Range.............4-2

Table 4-2: Number of Natural Gas Active Wells and Well Cellars................................4-2

Table 4-3: Number of Crude Oil New Wells Drilled, Well Completions, Well Workovers 

and Well Cleanups by API Range...............................................................4-2

Table 4-4: Number of Natural Gas New Wells Drilled, Well Completions, Well 

Workovers, and Well Cleanups...................................................................4-2

Table 4-5: Emissions of Crude Oil Wells by API Range (Metric Tons/Year) ................4-3

Table 4-6: Emissions of Natural Gas Wells (Metric Tons/Year) ...................................4-3

Table 4-7: Emissions of Crude Oil Well Cellars by API Range (Metric Tons/Year)......4-3

Table 4-8: Emissions of Crude Oil Well Workovers by API Range...............................4-4

Table 4-9: Emissions of Natural Gas Well Workovers (Metric Tons/Year) ...................4-4

Table 4-10: Emissions of Crude Oil Well Cleanups by API Range...............................4-4

Table 4-11: Emissions of Natural Gas Well Cleanups (Metric Tons/Year) ...................4-4

Chapter 5 – Electricity Generation and Use

Table 5-1: Electricity by Primary Business (Metric Tons/Year).....................................5-1
Final 2007 Oil and Gas Industry Survey Results

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Chapter 6 – Vapor Recovery

Table 6-1: Number of Vapor Recovery Units by Type..................................................6-1

Table 6-2: Vapor Recovery Combustion Emissions by Type (Metric Tons/Year).........6-2

Table 6-3: Carbon Adsorber Vented Emissions (Metric Tons/Year).............................6-2

Table 6-4: Vapor Recovery Combustion Emissions by Use (Metric Tons/Year) ..........6-3

Table 6-5: Number of Combustion Vapor Recovery Units by Size...............................6-3

Chapter 7 – Combustion Equipment

Table 7-1: External Combustion Emissions by Equipment Type (Metric Tons/Year) ...7-2

Table 7-2: Age of External Combustion Units ..............................................................7-3

Table 7-3: Internal Combustion Emissions by Equipment Type (Metric Tons/Year) ....7-3

Table 7-4: Age of Internal Combustion Units................................................................7-4

Table 7-5: Combustion Emissions of Internal Combustion Engines by Use.................7-4

Table 7-6: Combustion Emissions of Internal Combustion Engines by Type ...............7-5

Table 7-7: Turbine Combustion Emissions by Use (Metric Tons/Year)........................7-5

Table 7-8: Turbine Combustion Emissions by Cycle Type (Metric Tons/Year) ............7-6

Table 7-9: Cogeneration Combustion Emissions by Type (Metric Tons/Year).............7-6

Table 7-10: Combustion Emissions by Combustion Type (Metric Tons/Year) .............7-7

Table 7-11: Combustion Emissions by Primary Business (Metric Tons/Year)..............7-7

Table 7-12: Combustion Emissions by Fuel Type (Metric Tons/Year) .........................7-8

Chapter 8 – Components

Table 8-1: Number of Components by Service Type ...................................................8-1

Table 8-2: Fugitive Emissions of Components by Primary Business Type...................8-2

Table 8-3: Fugitive Emissions of Components by Service Type ..................................8-2

Table 8-4: Fugitive Emissions of Components by Type (Metric Tons/Year).................8-3

Table 8-5: Fugitive Emissions of Natural Gas Components by Type ...........................8-3

Table 8-6: Fugitive Emissions of Light Crude1 Components by Type...........................8-4

Table 8-7: Fugitive Emissions of Heavy Crude1 Components by Type ........................8-4

Chapter 9 – Automated Control Devices

Table 9-1: Vented Emissions of Automated Control Devices by Primary Business .....9-2

Table 9-2: Vented Emissions of Automated Control Devices by Type .........................9-2

Chapter 10 – Inspection and Maintenance

Table 10-1: Number of Facilities Utilizing each Leak Threshold.................................10-1

Chapter 11 – Natural Gas Dehydrators

Table 11-1: Vented Emissions of Natural Gas Dehydrators by Type .........................11-2

Table 11-2: Fugitive Emissions of Natural Gas Dehydrators by Type ........................11-2

Table 11-3: Volume of Natural Gas Dehydrators by Type..........................................11-2

Table 11-4: Total Emissions of Natural Gas Dehydrators (Metric Tons/Year)............11-3

Table 11-5: Natural Gas Dehydrators Percent on Vapor Recovery............................11-3

Table 11-6: Natural Gas Dehydrators Types of Vapor Recovery ...............................11-3
Final 2007 Oil and Gas Industry Survey Results

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Chapter 12 – Natural Gas Sweetening and Acid Gas Removal

Table 12-1: Vented Emissions of Natural Gas AGR Units by Type............................12-2

Table 12-2: Fugitive Emissions of Natural Gas AGR Units by Type...........................12-2

Table 12-3: Total Emissions of Natural Gas AGR Units (Metric Tons/Year) ..............12-3

Table 12-4: Natural Gas AGR Units Percent on Vapor Recovery ..............................12-3

Table 12-5: Natural Gas AGR Units Types of Vapor Recovery..................................12-3

Chapter 13 – Other Natural Gas Processing

Table 13-1: Emissions of Other Natural Gas Processing Units by Type ....................13-1

Table 13-2: Other Natural Gas Processing Units Percent on Vapor Recovery ..........13-2

Chapter 14 – Total Natural Gas Processing Emissions

Table 14-1: Total California Emissions (Metric Tons/Year) ........................................14-1

Table 14-2: Natural Gas Processing Emissions by Type (Metric Tons/Year).............14-1

Chapter 15 – Natural Gas Compressors

Table 15-1: Number of Compressors by Type ...........................................................15-1

Figure 15-1: Reciprocating Compressor.....................................................................15-2

Figure 15-2: Centrifugal Compressor.........................................................................15-2

Figure 15-3: Rotary Compressor................................................................................15-2

Table 15-2: Number of Primary Drivers by Type ........................................................15-3

Table 15-3: Number of Starters by Type ....................................................................15-3

Table 15-4: Startup and Blowdown Volumes .............................................................15-3

Table 15-5: Natural Gas Compressor Startup Vented Emissions (Metric Tons/Year) 15-4

Table 15-6: Natural Gas Compressor Blowdown Vented Emissions..........................15-4

Table 15-7: Natural Gas Compressor Fugitive Seal Emissions (Metric Tons/Year)...15-4

Table 15-8: Total Emissions of Natural Gas Compressors (Metric Tons/Year)..........15-5

Table 15-9: Compressor Emissions by Primary Business (Metric Tons/Year) ...........15-5

Table 15-10: Total Emissions of Natural Gas Compressors by Type.........................15-5

Table 15-11: Total Emissions of Natural Gas Compressors by Primary Driver..........15-6

Table 15-12: Total Emissions of Natural Gas Compressors by Age ..........................15-6

Table 15-13: Usage of Natural Gas Compressors by Age .........................................15-7

Chapter 16 –Pipeline Pigging and Natural Gas Gathering Pipelines

Table 16-1: Miles of Natural Gas Gathering System Pipelines by Primary Business 

Type........................................................................................................16-1

Table 16-2: Natural Gas Gathering System Pipeline Maintenance Activity Volumes .16-2

Table 16-3: Pigging Operations..................................................................................16-2

Table 16-4: Natural Gas Vented Emissions from Gathering Pipeline Maintenance

and Pigging Operations (Metric Tons/Year)............................................16-2

Table 16-5: Natural Gas Fugitive Emissions from Gathering Pipelines

(Metric Tons/Year) ..................................................................................16-3

Chapter 17 – Separators

Table 17-1: Number of Separators by Primary Business Type ..................................17-1
Final 2007 Oil and Gas Industry Survey Results

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Table 17-2: Total Emissions of Separators (Metric Tons/Year)..................................17-2

Table 17-3: Fugitive Emissions of Separators by Type (Metric Tons/Year)................17-2

Table 17-4: Fugitive Emissions of Separators by Subtype (Metric Tons/Year) ..........17-3

Table 17-5: Separator Units by Type Percent on Vapor Recovery.............................17-3

Table 17-6: Separator Units by Subtype Percent on Vapor Recovery .......................17-4

Table 17-7: Separator Units by Types of Vapor Recovery .........................................17-4

Chapter 18 – Crude Oil Sumps

Table 18-1: Fugitive Emissions of Sumps/Pits by Type (Metric Tons/Year)...............18-1

Table 18-2: Fugitive Emissions of Sumps/Pits by Air District (Metric Tons/Year).......18-2

Table 18-3: Sumps/Pits by Percent on Vapor Recovery ............................................18-2

Table 18-4: Sumps/Pits by Types of Vapor Recovery................................................18-3

Chapter 19 – Crude Oil Storage Tanks

Table 19-1: Total Emissions of Storage Tanks (Metric Tons/Year)............................19-2

Table 19-2: Fugitive Emissions of Storage Tanks by Type (Metric Tons/Year)..........19-2

Table 19-3: Fugitive Emissions of Storage Tanks by Subtype (Metric Tons/Year).....19-2

Table 19-4: Storage Tanks by Type Percent on Vapor Recovery ..............................19-3

Table 19-5: Storage Tanks by Subtype Percent on Vapor Recovery .........................19-3

Table 19-6: Storage Tanks by Types of Vapor Recovery...........................................19-3

Chapter 20 – Overview of California Emissions from Crude Oil Production, 

Processing, and Storage

Table 20-1: Crude Oil Emissions (Metric Tons/Year) .................................................20-1

Table 20-2: Crude Oil Emissions by Primary Business Type (Metric Tons/Year).......20-1

Table 20-3: Crude Oil Total Emissions by CO2e Range (Metric Tons/Year) ..............20-2

Table 20-4: Crude Oil Combustion Emissions by CO2e Range..................................20-2

Table 20-5: Crude Oil Vented Emissions by CO2e Range (Metric Tons/Year)...........20-2

Table 20-6: Crude Oil Fugitive Emissions by CO2e Range (Metric Tons/Year)..........20-3

Table 20-7: Average Total CO2e Emissions per Barrel Crude Oil Produced..............20-4

Table 20-8: Average Combustion CO2e Emissions per Barrel Crude Oil Produced...20-4

Table 20-9: Average Vented CO2e Emissions per Barrel Crude Oil Produced ..........20-5

Table 20-10: Average Fugitive CO2e Emissions per Barrel Crude Oil Produced .......20-5

Chapter 21 – Overview of California Emissions from Dry Natural Gas Production, 

Processing, and Storage

Table 21-1: Natural Gas Emissions (Metric Tons/Year) .............................................21-1

Table 21-2: Natural Gas Emissions by Primary Business Type (Metric Tons/Year)...21-1

Table 21-3: Total Natural Gas Emissions by CO2e Range (Metric Tons/Year) ..........21-2

Table 21-4: Natural Gas Combustion Emissions by CO2e Range (Metric Tons/Year)21-2

Table 21-5: Natural Gas Vented Emissions by CO2e Range (Metric Tons/Year).......21-2

Table 21-6: Natural Gas Fugitive Emissions by CO2e Range (Metric Tons/Year)......21-2

Table 21-7: Average Total CO2e Emissions per MSCF Natural Gas Produced .........21-3

Table 21-8: Average Combustion CO2e Emissions per MSCF Natural Gas ..............21-4

Table 21-9: Average Vented CO2e Emissions per MSCF Natural Gas Produced......21-4

Table 21-10: Average Fugitive CO2e Emissions per MSCF Natural Gas Produced...21-4
Final 2007 Oil and Gas Industry Survey Results

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Final 2007 Oil and Gas Industry Survey Results

ix

Glossary

Term Definition

AB 32 Assembly Bill 32, The California Global Warming Solutions Act 

of 2006 (Stats. 2006, ch. 488)

Active Wells Wells that are producing crude oil or natural gas throughout the 

year

AGR Unit Acid Gas Removal Unit. These units remove sulfur or CO2 from 

natural gas streams.

Air District An air pollution control district (APCD) or air quality 

management district (AQMD)

API Gravity A scale used to reflect the specific gravity (SG) of a fluid such 

as crude oil, water, or natural gas. The API gravity is calculated 

as [(141.5/SG) - 131.5], where SG is the specific gravity of the 

fluid at 60°F 

ARB California Air Resources Board

Automated Control 

Device

A device that uses compressed gas or air to affect mechanical 

motion. Commonly referred to as pneumatic devices. 

Automated Control 

Device Actuator

A device that accurately locates the valve plug in a position 

dictated by the control signal.

Automated Control 

Device Controller

Positions its movable part (a plug, ball or vane) relative to the 

stationary seat of the valve.

Board California Air Resources Board

BTU British Thermal Unit

CEC California Energy Commission

CEIDARS ARB’s California Emission Inventory Development and 

Reporting System Database

Centrifugal 

Compressor

Centrifugal compressors increase the pressure of natural gas by 

centrifugal action, employing rotating movement of the drive 

shaft. 
Final 2007 Oil and Gas Industry Survey Results

x

Term Definition

CH4 Methane

CHP Combined Heat and Power

CIPA California Independent Petroleum Association

CNG Compressed natural gas

CO2 Carbon dioxide

CO2e Carbon dioxide equivalents

Cogeneration An integrated system that produces electric energy and useful 

thermal energy. Synonymous with combined heat and power.

Combined Cycle 

Turbine

A turbine that generates electricity and the waste heat of which 

is used to make steam. The steam is then used to generate 

electricity through a steam turbine or injected into a geological 

formation to increase production. 

Combined Heat and 

Power

An integrated system that produces electric energy and useful 

thermal energy. Synonymous with cogeneration. 

Combustion Emission Greenhouse gas emission occurring during the exothermic 

reaction of a fuel with oxygen

Compressor Any machine for raising the pressure of a natural gas stream by 

drawing in low pressure natural gas and discharging 

significantly higher pressure natural gas 

Dehydrator Equipment that removes water from a natural gas stream by 

passing it over glycol or a desiccant.

DOGGR Department of Conservation’s Division of Oil, Gas, and 

Geothermal Resources

Dry Gas Natural gas produced from a gas well without associated crude 

oil

EIA The US Department of Energy’s Energy Information 

Administration

EOR Enhanced oil recovery
Final 2007 Oil and Gas Industry Survey Results

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Term Definition

External Combustion

Engine

An engine where an internal fluid is heated by an external heat 

source

FAR IPCC Fourth Assessment Report

Four-Stroke Engine An engine in which the piston completes four separate strokes, 

intake, compression, power, and exhaust, during two separate 

revolutions of the engine's crankshaft.

Fracturing Fracturing uses high pressure pumps to increase fluid pressure 

at the bottom of a well. This fluid pressure cracks the formation 

and proppants such as sand or walnut hulls are injected into the 

newly formed crevices to keep them open when the fluid 

pressure is removed. 

Fractionation The process of separating natural gas liquids into their 

constituent liquid products.

Fugitive Emission Unintentional release of greenhouse gas vapors to the 

atmosphere

Gas Injection EOR The method of injecting a gas such as natural gas, nitrogen, or 

carbon dioxide into a geological formation to increase crude oil 

production

GHG Greenhouse Gas

GWP Global warming potential. This is the amount of radiative

forcing a particular compound has compared to CO2

H2S Hydrogen Sulfide

Heater/Treater Oil/water separators that use heat to expedite the separation 

process

Heavy Crude Crude oil with an API gravity of 10 to 20

HHV Higher Heating Value

I&M Program Inspection and Maintenance Program

Internal Combustion 

Engine

An engine where fuel is burned inside a combustion chamber. 

The expansion of the gas applies direct force to a component of 
Final 2007 Oil and Gas Industry Survey Results

xii

Term Definition

the engine such as a piston or turbine blade. 

IOPA Independent Oil Producers’ Agency

IPCC United Nation’s Intergovernmental Panel on Climate Change

Lean Burn Engine Engines that may operate up to the lean flame extinction limit, 

with exhaust oxygen levels of 12 percent or greater. The air to 

fuel ratios of lean-burn engines range from 20:1 to 50:1 and are

typically higher than 24:1. The exhaust excess oxygen levels of 

lean-burn engines are typically around 8 percent, ranging from 4 

to 17 percent.

Light Crude Crude oil with an API gravity of 20 to 30

N2O Nitrous oxide

Natural Gas 

Gathering Pipelines

Small natural gas pipelines located on a production facility that 

route natural gas

PD Protected data. In this survey report, data values that do not 

represent at least three companies. 

PERP Portable Equipment Registration Program

Pipeline Pig A device sent down a pipeline to clean or inspect the pipeline.

Pits Open pits that are used for oil/water separation or for 

emergency containment.

Production Facility Facility that extracts crude oil and/or natural gas

Reboiler Units that heat glycol to remove water, or heat amine to remove 

acid gas. 

Reciprocating 

Compressor

Reciprocating compressors increase the pressure of natural gas 

by positive displacement, employing linear movement of a shaft 

driving a piston in a cylinder. 

Rich Burn Engine Engines that operate near the stoichiometric air-to-fuel ratio 

(16:1) with exhaust excess oxygen levels less than 4 percent 

(typically closer to 1 percent)
Final 2007 Oil and Gas Industry Survey Results

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Term Definition

ROG Reactive Organic Gas

Rotary Compressor Rotary compressors have blades or a cylinder that rotate off 

center to compress the natural gas. Synonymous with screw 

compressors.

SAR IPCC Second Assessment Report

Screw Compressor Screw compressors have blades or a cylinder that rotate off 

center to compress the natural gas. Synonymous with rotary 

compressors.

Separator Separators split the fluids that come out of a well by gravity, 

heat, or both. 

Simple Cycle Turbine A turbine that generates electricity and does not utilize the 

waste heat.

Specific Gravity The ratio of the density of a substance to the density of a 

reference substance. The reference substance is generally 

water.

Steam Generator Equipment that produces steam using an external heat source

Sump Open pit that is used for oil/water separation or for emergency 

containment.

TAR IPCC Third Assessment Report

Thermal EOR The method of injecting steam into a geological formation to 

increase crude oil production

TOG Total Organic Gas

Turbine An internal combustion engine where the force from the 

combustion chamber moves a blade rather than a piston.

Two-Stroke Engine In a 2-stroke engine, the air-to-fuel charge is injected with the 

piston near the bottom of the power stroke. The intake ports are 

then covered or closed, and the piston moves to the top of the 

cylinder, compressing the charge. Following ignition and 

combustion, the power stroke starts with the downward 

movement of the piston. As the piston reaches the bottom of the 

power stroke, exhaust ports or valves are opened to exhaust, or 
Final 2007 Oil and Gas Industry Survey Results

xiv

Term Definition

scavenge, the combustion products, and a new air-to-fuel 

charge is injected.

Ultra-Heavy Crude Crude oil with an API gravity of less than 10

Ultra-Light Crude Crude oil with an API gravity of greater than 30

US EPA United States Environmental Protection Agency

Vapor Recovery Equipment located at the source of potential gas emissions to 

the atmosphere that is used for collecting and routing the gas 

back into the process as a product and/or fuel or for destruction.

Vented Emission Intentional release of greenhouse gas vapors to the atmosphere

Waterflood EOR The method of injecting water into a geological formation to 

increase crude oil production.

Well Cellars Lined or unlined pits around one or more wells that: (a) allow 

access to the wellhead components for servicing, or (b) contain 

intermittent flows of crude oil or water during an emergency or 

from drilling and petroleum production processes.

Well Cleanups Well maintenance activities that include fracturing or removing 

fluids to increase production.

Well Completions The final step to bringing a newly drilled well into production.

Well Workovers The process of performing major maintenance or remedial 

treatments on an oil or gas well.

WSPA Western States Petroleum Association
Executive Summary Final 2007 Oil and Gas Industry Survey Results

ES-1

Executive Summary

On September 27, 2006, Governor Schwarzenegger signed Assembly Bill 32 (AB 32), 

the California Global Warming Solutions Act of 2006 (Núñez, Statutes of 2006, chapter 

488). AB 32 establishes a comprehensive program of regulatory and market 

mechanisms to achieve real, cost-effective, quantifiable reductions of greenhouse 

gases (GHG). AB 32 charges the Air Resources Board (ARB) as the agency 

responsible for monitoring and regulating many GHG emission sources to reduce 

California’s GHG emissions to 1990 levels by 2020. 

Among the measures that the ARB staff is considering to help reach this AB 32 goal is a 

measure to reduce GHG emissions from crude oil and natural gas production, 

processing, and storage operations. In order for staff to determine the potential GHG 

emission reductions, the technical feasibility, and the cost-effectiveness of any potential 

control measure, the ARB staff conducted a survey of the crude oil and natural gas 

industry to improve estimates of GHG emissions in California from these operations. 

In February 2009, the 2007 Oil and Gas Industry Survey was mailed out to crude oil and 

natural gas production, processing, and storage facilities in California. The survey was 

completed by 325 companies representing over 1,600 facilities and approximately 97 

percent of the 2007 crude oil and natural gas production in California. 

Emissions were calculated using equipment information from the survey and commonly 

used emission equations and emission factors listed in Appendix B of this report. Total 

emissions for equipment covered under this survey are estimated to be 18.8 million 

metric tons of CO2e. Combustion sources (equipment burning fuel for energy) account 

for 87 percent of the total CO2e emissions. The remaining 13 percent of the CO2e 

emissions, or about 2.4 million metric tons of CO2e, come from vented and fugitive 

sources, which are, respectively, intentional and unintentional releases of gases to the 

atmosphere.

In August 2011, staff released a draft of this survey results report for public comment. 

Staff has finalized this report based on the subsequent comments received, which 

resulted in the addition of a Glossary, minor text changes to improve clarity, and the 

inclusion of the survey cover letter and survey instructions in Appendix A. As 

mentioned above, staff intends to use the data in this report to explore the development 

of a control measure to reduce GHG emissions from crude oil and natural gas 

production, processing, and storage
.
Chapter 1 Final 2007 Oil and Gas Industry Survey Results

1-1

Chapter 1 – Survey Development

Background

On September 27, 2006, Governor Schwarzenegger signed Assembly Bill 32 (AB 32), 

the California Global Warming Solutions Act of 2006 (Núñez, Statutes of 2006, chapter 

488). This law required the reduction of greenhouse gas (GHG) emissions to 1990 

levels by 2020. 

AB 32 designated the California Air Resources Board (ARB or Board) as the lead 

agency for implementing AB 32 and mapped out major milestones for achieving this 

goal. ARB met the first milestones in 2007 by developing a list of discrete early action 

measures, assembling an inventory of historic emissions, establishing GHG reporting 

requirements, and setting the 2020 emissions limit. 

In November 2007, ARB published the 1990 – 2004 California GHG inventory. The oil 

and gas production sector, as well as the natural gas transmission and distribution 

pipeline system, were identified as large sources of GHG emissions. In late 2007, a 

team of staff was assembled to evaluate potential reductions from these sectors. 

Among the measures that the ARB staff is developing to help reach the AB 32 goal of 

reducing GHG emissions to 1990 levels by 2020 is one potential measure to reduce 

emissions from the crude oil and natural gas production, processing, and storage

sector. This report provides the results of the 2007 survey of emissions from the crude 

oil and natural gas production, processing, and storage sector (2007 Oil and Gas 

Industry Survey). 

Development of the 2007 Oil and Gas Industry Survey

In April 2008, ARB staff held a public workshop to discuss preliminary concepts for 

reducing greenhouse gases from the oil and gas production, transmission and 

distribution, and refinery sectors. Attendees were encouraged to sign up to be part of 

industry workgroups. After that workshop, the sector was split into three discrete 

sections: an oil and gas production section, a natural gas transmission and distribution 

section, and a refinery section. 

Ultimately, the oil and gas production sector contained the following types of facilities:

o Crude oil extraction;

o Natural gas extraction;

o Natural gas storage;

o Crude oil processing not including refineries;

o Natural gas processing including gas plants;

o Crude oil pipelines; and

o Crude oil tank farms not including tank farms at refineries.
Chapter 1 Final 2007 Oil and Gas Industry Survey Results

1-2

The natural gas transmission and distribution sector contained:

o Natural gas transmission pipelines;

o Natural gas distribution pipelines;

o Natural gas compressor stations; and

o Natural gas metering stations.

The refinery sector included only crude oil refineries. 

In the months preceding the April 2008 public workshop, staff gathered available data 

from ARB’s California Emission Inventory Development and Reporting System 

(CEIDARS) database, local air district permit data, and a small amount of individual 

company data. It was concluded that the quality and uniformity of the data were not 

robust enough to support regulation development. Staff then proposed surveying the 

sector to create a current baseline inventory. 

To create a comprehensive survey that could be used to create a robust GHG 

emissions inventory for the oil and gas production sector, staff determined that 

research, industry and air district meetings, and site visits were necessary. To that end, 

staff spent the next 10 months educating themselves and developing a survey in 

cooperation with the industry, industry trade groups, and local air districts (Table 1-1). 

Appendix A is a copy of the survey, and Appendix B lists the calculation methods and 

emission factors used to estimate emissions. Appendix C contains a more detailed 

version of Table 1-1. 

Table 1-1: Site Visits and Meetings 

Date Action

April 2008 • Staff held public workshop.

• Industry and district working groups created.

May 2008 to 

January 2009

• Staff met with the Western States Petroleum Association 

(WSPA), California Independent Petroleum Association 

(CIPA), Independent Oil Producers’ Agency (IOPA), and air 

district staff.

• Staff toured over twenty oil and gas facilities.

• Staff developed a draft survey and worked with the industry 

and district working groups to revise.

• Staff developed general instructions for completing the 

survey and electronic templates.

February 19, 

2009

• ARB staff mailed out the Oil and Gas Industry Survey.

March 26, 2009 • Staff traveled to Bakersfield to conduct a training seminar for 

filling out the survey.

February to 

August 2009

• Survey responses were due on April 30, 2009.

• Survey database was developed and surveys uploaded as 
Chapter 1 Final 2007 Oil and Gas Industry Survey Results

1-3

they came in.

• Staff answered questions from the industry about the survey.

• Extensive follow-up with facilities that responded began after 

the April 30 due date. 

• By August, the majority of surveys were received.

• Staff toured several oil and gas facilities.

September to 

December 2009

• Staffed contacted non-respondents to the survey.

• Remaining surveys received and uploaded.

December 8, 

2009

• Staff conducted a workshop detailing preliminary results from 

the survey.

January to March 

2010

• Staff worked with industry to answer questions about facility 

emissions. 

• Staff checked data for quality and followed up with facilities.

March 18, 2010 • Survey data were frozen.

April to May 2010 • Staff developed survey data and emission summaries.

• Staff worked with industry working group on emission 

summaries.

June 2010 to 

January 2011

• Draft survey report developed.

April 2011 to 

June 2011

• Draft survey report reviewed by district and industry working 

groups.

August 2011 • Draft survey report released for public comment.

The 2007 Oil and Gas Industry Survey

This report presents the results from the 2007 Oil and Gas Industry Survey conducted 

by ARB to estimate greenhouse gas emissions in California. This survey was a onetime collection of data intended to accurately quantify operations and processes needed 

to estimate greenhouse gas emissions. The survey pertained to all upstream crude oil 

and natural gas facilities regardless of the size of operation.

For the purpose of this survey, upstream crude oil and natural gas facilities include:

Oil or Natural Gas Extraction Facilities: any facility that extracts crude oil, natural 

gas, or both crude oil and natural gas.

Processing Facilities: any facility that processes crude oil or natural gas for use 

or distribution. This survey does not include refineries.

Crude Oil Transmission Facilities: crude oil pipelines or crude oil bulk loading 

operations. This includes ship, truck, or rail car loading facilities.
Chapter 1 Final 2007 Oil and Gas Industry Survey Results

1-4

Storage Facilities: any facility that stores crude oil or natural gas, including

underground natural gas storage facilities. This survey excludes crude oil tank 

farms located on refinery premises.

Additional facilities or operations covered under this survey include:

Drilling or Workover Companies: any owner of drilling or workover rigs that 

performed well services on crude oil or natural gas facilities. 

Cogeneration Plants/Combined Heat and Power: any facility that produced 

electricity and thermal energy for use at a crude oil extraction or storage facility.

Produced Water Disposal: any facility that stored produced water from crude oil 

or natural gas extraction or storage facilities.

Some companies considered the data provided in the survey to be trade secret and 

confidential. To address this concern, but still allow the publishing of survey results, 

ARB implemented the historical practice of concealing all data values that did not 

represent at least three companies, otherwise known as the “Three Company Rule.” In 

addition, this report contains summarized survey data, rather than lists of individual 

survey responses to further protect confidentiality. Every effort was made to reveal as 

much of the survey data as possible without compromising the “Three Company Rule.” 

However, instances did arise where it was necessary to conceal certain portions of the 

survey results. Throughout this report the term “Protected Data” (or PD) is used to 

reflect that compliance with the “Three Company Rule” could not be satisfied and the 

data were concealed to protect company confidentiality.
Chapter 2 Final 2007 Oil and Gas Industry Survey Results

2-1

Chapter 2 – General Information

Survey Response

The 2007 Oil and Gas Industry Survey was sent out to 1,429 companies. ARB received 

over 750 surveys, representing 389 companies from our original mailing list. Of the 

remaining 1,040 companies, 960 names were removed due to the following reasons:

o The company was out of business,

o The company had merged or been bought by another, or

o The company was not in the crude oil or natural gas business.

The remaining 80 companies did not respond. Thus, there was an 83 percent response 

rate for relevant companies. The response rate is probably even greater assuming 

many of the 80 nonresponsive companies fall into one of the three removal categories 

above.

This report details the results of this equipment and process survey. The total number 

of companies that completed the survey was 325. This number is smaller than the 389 

companies listed on our mailing list due to several companies being listed with multiple 

addresses.

In the tables that follow, it should be noted that the percentages reported may not add to 

100 percent due to rounding and that percentages that round to less than one percent 

are shown as zero percent.

The unique nature of crude oil and natural gas extraction added complexity to assigning 

emissions to a company. Many companies have multiple fields, with multiple facilities. 

To accommodate this, ARB allowed the company to list a company name, a facility

location, and a facility identification number (ID). The facility location was generally the 

field or lease name and the facility ID was generally an air district identification number. 

In both cases, the facility location and facility ID were defined by contiguous property 

boundaries. As a result, 325 companies representing 1,379 facility locations, and 1,632 

facility IDs in 17 air districts across California completed the survey. For the remainder 

of this report, the term “facility” will be used for facility ID.

Table 1 of the 2007 Oil and Gas Industry Survey required companies to fill out general 

information about each facility and facility location. This included business type. Table 

2-1 lists the number of facilities by business type. Because facilities were allowed to list 

multiple business types for one facility, the total number of facilities by business type is 

larger than the total number of facilities that completed the survey.

The business type “other” includes the following self-reported facility types:

o CNG compression and marketing

o Cogeneration
Chapter 2 Final 2007 Oil and Gas Industry Survey Results

2-2

o Combined heat and power

o Electricity generation

o Portable heating 

o Water disposal

o Vapor recovery services.

Table 2-1: Number of Facilities by Business Type

Type Number

Onshore Crude 668

Offshore Crude 17

Onshore Natural Gas 786

Offshore Natural Gas 8

Natural Gas Storage 11

Natural Gas Processing 282

Crude Pipeline 111

Crude Storage 258

Crude Processing 92

PERP1 Equipment Owner 60

Other 54

Totals: 2,347

1. PERP = Portable Equipment Registration Program

Throughout the remainder of this report, the term “primary business” will be used. This 

term is used to assign emissions for a particular facility to its primary business. Primary 

business type was assigned to each facility using the following list in this order:

o Onshore crude oil production

o Offshore crude oil production

o Onshore natural gas production

o Offshore natural gas production

o Natural gas storage facility

o Natural gas processing

o Crude oil pipeline

o Crude oil storage

o Crude oil processing

o PERP equipment owner

o Other

The above list shows the order in which a primary business was assigned to each 

facility. Thus, a facility listing the business types “onshore crude”, “natural gas 

processing”, and “crude storage” would have “onshore crude” designated as its primary 

business. 

Table 2-2 shows the number of facilities by primary business type. Crude storage and 

crude processing were combined to protect confidential data.
Chapter 2 Final 2007 Oil and Gas Industry Survey Results

2-3

Table 2-2: Number of Facilities by Primary Business Type

Type Number

Onshore Crude Production 668

Offshore Crude Production 16

Onshore Natural Gas Production 703

Offshore Natural Gas Production 0

Natural Gas Storage 10

Natural Gas Processing 17

Crude Pipeline 65

Crude Processing and Storage 42

PERP Equipment Owner 58

Other 53

Totals: 1,632

California Production

Table 2 of the 2007 Oil and Gas Industry Survey required companies to fill out their 

production for each facility location. This table asked for the number of 

o active wells, 

o well cellars, 

o new wells drilled,

o workovers that required tubing removal,

o well cleanups (also known as liquid unloading), and

o well completions.

The production type was also required. California crude oil production was reported by 

the American Petroleum Institute (API) gravity range. API gravity measures how heavy 

or light a petroleum product is compared to water. The lower the API gravity number, 

the heavier the petroleum product is compared to water. Thus, companies filled out the 

above list by type of production: 

o dry gas production (referred to as Produced Natural Gas in the survey),

o natural gas storage,

o ultra-heavy (API < 10) crude oil production, 

o heavy (API 10 - 20) crude oil production ,

o light (API 20 - 30) crude oil production, and 

o ultra-light (API > 30) crude oil production.

Table 2 of the 2007 Oil and Gas Industry Survey also gathered production volume, the 

composition of the natural gas produced, the volume of crude oil transported, and the 

miles of crude oil pipeline.

Crude oil and natural gas extraction is a large industry in California. In 2007, California 

produced 243 million barrels of crude oil, making it the fourth largest producer of 

domestic crude oil (DOGGR, 2008; EIA, 2009b). This production accounts for 38 

percent of the total crude oil delivered to California refineries. The other sources of 
Chapter 2 Final 2007 Oil and Gas Industry Survey Results

2-4

crude oil delivered to California refineries are 45 percent foreign, 16 percent Alaskan, 

and one percent from gulf coast states (CEC, 2010). 

The 2007 Annual Report of the State Oil and Gas Supervisor stated that 58 percent of 

California’s 2007 crude oil production was extracted through enhanced oil recovery 

(EOR) techniques (DOGGR, 2008). EOR techniques include thermal, waterflood, and 

gas injection. Thermal EOR injects steam into the formation, waterflood EOR injects 

water into the formation, and gas injection EOR injects natural gas, nitrogen, or carbon 

dioxide into the formation. Of the production that was recovered through EOR 

techniques, 68 percent used thermal, 27 percent used waterflood, and 5 percent used 

gas injection techniques (DOGGR, 2008). 

The crude oil production reported under ARB’s 2007 Oil and Gas Industry Survey 

represents 96 percent of California’s total production. Table 2-3 lists the California 

crude oil production reported in the 2007 Oil and Gas Industry Survey by API range. 

There were 882,953,716 barrels of crude oil transported through 6,799 miles of pipeline. 

This total includes California production and imported crude oil. The amount of crude oil 

transported through crude oil pipelines is greater than the 639,189,000 barrels delivered 

to refineries (CEC, 2010) because many crude oil extraction facilities listed crude oil 

transport from their facility to one of the major pipeline companies. Thus, some crude 

oil transport was counted twice.

Table 2-3: Crude Oil Totals

Type

Barrels Crude Oil 

Produced

Percent of Total 

Production Reported

Ultra-Heavy Oil (API <10) 614,683 0%

Heavy Oil (API 10 - 20) 156,304,520 67%

Light Oil (API 20 - 30) 61,524,698 26%

Ultra-Light Oil (API >30) 15,649,398 7%

Totals: 234,093,299

Natural gas production and natural gas storage have very similar processes. Natural 

gas production extracts virgin natural gas that is then processed and sold. Natural gas 

storage takes clean, processed gas from pipelines or large producers and injects it into 

a geological formation for storage. The gas is then removed at a later date when 

needed. 

There are discrepancies between the amounts of natural gas produced that was 

reported to the Energy Information Administration (EIA), the Department of 

Conservation Division of Oil, Gas, and Geothermal (DOGGR), and the 2007 Oil and 

Gas Industry survey. According to the EIA Natural Gas 2007 Annual Report (EIA, 

2009a), these discrepancies may be due to the way operators fill out their reports. The 

amount of natural gas extracted that was reported to EIA was 339 billion cubic feet (EIA, 

2009a). This amount is larger than the 312 billion cubic feet reported to DOGGR 

(DOGGR, 2008). The amount reported in the 2007 Oil and Gas Industry survey is 

shown in Table 2-4 and is larger than both the EIA and DOGGR numbers. However, if 
Chapter 2 Final 2007 Oil and Gas Industry Survey Results

2-5

the amount combusted onsite is subtracted from the amount produced, the amount 

available becomes similar to the EIA number.

Table 2-4: Natural Gas Totals

Type

MSCF1 Natural 

Gas Produced

MSCF Natural Gas 

Combusted

MSCF Natural Gas 

Available to Consumers

Associated Gas 291,115,743 54,465,754 236,649,989

Dry Gas 99,211,175 4,623,503 94,587,672

Totals: 390,326,918 59,089,257 331,237,661

1. MSCF is 1000 standard cubic feet 

In 2007, 2,326 billion cubic feet of natural gas were delivered to California consumers 

(EIA, 2009a). This includes gas used in residential, commercial, and industrial

applications; vehicular fuel; and electric power generation. According to the 2007 Oil 

and Gas Industry survey, California produced 14 percent of the total natural gas used in 

state. The remaining 86 percent came in through interstate transmission pipelines 

crossing the border at Arizona, Nevada, and Oregon (EIA, 2009a).

California withdrew 211 billion cubic feet of gas from natural gas storage facilities in 

2007. The storage numbers include in-state production and imported natural gas.

Global Warming Potentials

The 2007 Oil and Gas Industry Survey collected comprehensive equipment and process 

data for the California crude oil and natural gas industry. The data from the survey are

used to calculate greenhouse gas (GHG) emissions. The major GHG compounds 

emitted from this sector are carbon dioxide (CO2), methane (CH4), and nitrous oxide 

(N2O). Carbon dioxide equivalents (CO2e) are calculated by multiplying the mass of the 

GHG compound by its global warming potential (GWP). GWP numbers are the amount 

of radiative forcing a particular compound has compared to CO2. GWP numbers are 

published by the Intergovernmental Panel on Climate Change (IPCC) in their 

Assessment Reports. Table 2-5 lists the GWP for CO2, CH4, and N2O from the Second, 

Third, and Fourth IPCC Assessment Reports (IPCC 2007, 2001, and 1995).

Table 2-5: Global Warming Potentials

CO2 CH4 N2O

Second Assessment Report (SAR) 1 21 310

Third Assessment Report (TAR) 1 23 296

Fourth Assessment Report (FAR) 1 25 298

ARB’s and US EPA’s Mandatory GHG Reporting rules both use the SAR to calculate 

emissions. To remain consistent with both of these programs, all the CO2e calculations 

in this report use the SAR GWP numbers.

Chapter 3 of this report gives an overview of the total emissions calculated from the 

2007 Oil and Gas Industry Survey. Chapters 4 through 19 go through the emissions 

calculated from each table of the survey. The remaining chapters of the report total the 

emissions for oil production and natural gas production separately. 
Chapter 2 Final 2007 Oil and Gas Industry Survey Results

2-6

References

CEC (2010). California Energy Commission. Oil Supply Sources to California 

Refineries. 

http://www.energyalmanac.ca.gov/petroleum/statistics/crude_oil_receipts.html. 

July 2010.

DOGGR (2008). California Department of Conservation Division of Oil, Gas, and

Geothermal Resources. 2007 Annual Report of the State Oil and Gas 

Supervisor. 2008.

EIA (2009a). U.S. Energy Information Administration. Natural Gas Annual 2007. 

January 2009.

EIA (2009b). U.S. Energy Information Administration. U.S. Crude Oil, Natural Gas, and 

Natural Gas Liquids Reserves 2007 Annual Report. February 2009.

IPCC (2007). Solomon, S., D. Qin, M. Manning, Z. Chen, M. Marquis, K.B. Averyt, M. 

Tignor and H.L. Miller (eds.). Contribution of Working Group I to the Fourth 

Assessment Report of the Intergovernmental Panel on Climate Change. 

Cambridge University Press, Cambridge, United Kingdom and New York, NY, 

USA. 2007.

IPCC (2001). Houghton, J.T., Y. Ding, D.J. Griggs, M. Noguer, P.J. van der Linden, X. 

Dai, K. Maskell, C.A. Johnson (eds.). Contribution of Working Group I to the 

Third Assessment Report of the Intergovernmental Panel on Climate Change. 

Cambridge University Press, Cambridge, United Kingdom and New York, NY, 

USA. 2001.

IPCC (1995). Houghton, J.T., L.G. Meira Filho, B.A. Callander, N. Harris, A. Kattenberg 

and K. Maskell (eds.). Contribution of Working Group I to the Second 

Assessment Report of the Intergovernmental Panel on Climate Change. 

Cambridge University Press, Cambridge, United Kingdom and New York, NY, 

USA. 1995.
Chapter 3 Final 2007 Oil and Gas Industry Survey Results

3-1

Chapter 3 – Overview of Total California Emissions

Total Emissions

This chapter combines the emissions from all equipment surveyed in the 2007 Oil and 

Gas Industry Survey. These emissions do not include extrapolated emissions for 

equipment not covered by the survey. The emissions were calculated using equipment 

information from the survey and the emission equations and emissions factors listed in 

Appendix B. Table 3-1 shows the total California statewide emissions for the crude oil 

and natural gas sector for the equipment covered by the survey in 2007. Combustion 

sources are equipment burning fuel for energy. Vented emissions are intentional 

releases of vapors to the atmosphere. Fugitive emissions are unintentional releases of 

vapors to the atmosphere. The majority of the total CO2e emissions in California are 

from combustion sources. Only 13 percent of the CO2e emissions come from vented or 

fugitive sources. 

Table 3-1: Total California 2007 Emissions (Metric Tons/Year)

Type CO2 CH4 N2O CO2e

Percent of 

Total CO2e

Combustion 16,073,395 10,836 314 16,398,268 87%

Vented 48,432 24,880 0 570,922 3%

Fugitive 270,815 73,551 0 1,815,393 10%

Totals: 16,392,641 109,267 314 18,784,582

Table 3-2 lists the total CO2e emissions by primary business type. Primary business 

type is defined in Chapter 2. The business type “other” includes the following selfreported facility types:

o CNG compression and marketing

o Cogeneration

o Combined heat and power

o Electricity generation

o Portable heating 

o Water disposal

o Vapor recovery services

The facility types “crude processing” and “crude storage” were combined to protect 

confidential company data. The facility types “onshore crude production” and “other”

account for 42 percent of the total number of facilities for this sector. However, they 

emit 83 percent of the total CO2e for the state. The remaining 58 percent of the facilities 

account for only 17 percent of the emissions. 
Chapter 3 Final 2007 Oil and Gas Industry Survey Results

3-2

Table 3-2: Total California Emissions by Primary Business Type

 (Metric Tons/Year)

Type

Number 

of 

Facilities CO2 CH4 N2O CO2e

Percent

of Total 

CO2e

Onshore Crude Production 668 9,784,578 136,839 888,158 10,809,576 58%

Other 53 4,616,047 53 8,512 4,624,612 25%

Natural Gas Processing 17 879,601 5,102 400,160 1,284,863 7%

Natural Gas Storage 10 226,569 276,484 176,004 679,058 4%

Onshore Natural Gas 

Production 703 218,910 117,835 210,879 547,624 3%

Crude Processing and 

Storage 42 346,952 15,940 44,347 407,239 2%

Offshore Crude Production 16 104,272 16,708 65,232 186,213 1%

PERP Equipment Owner 58 148,825 1,960 4,793 155,577 1%

Crude Pipeline 65 72,515 0 17,306 89,821 0%

Totals: 1,632 16,398,268 570,922 1,815,393 18,784,582

Total Emissions by Air District

Crude oil and natural gas operations are found in 17 air pollution control districts 

(APCD) and air quality management districts (AQMD) in California. Total CO2e 

emissions for each air district are shown in Table 3-3. Several companies had a facility 

that was located in more than one air district. In those cases, the CO2e emissions for 

that facility were split equally between each air district. This resulted in the total number 

of facilities being larger than the 1,632 facilities that reported in the survey. About three 

quarters of the statewide total CO2e emissions for these operations occur in the San 

Joaquin Valley APCD.

Table 3-3: Total California Emissions by Air District (Metric Tons/Year)

Air District Number of Facilities CO2e

Percent of Total 

CO2e

San Joaquin Valley APCD 456 14,191,599 76%

South Coast AQMD 265 1,619,949 9%

Santa Barbara County APCD 63 1,503,930 8%

Monterey Bay Unified APCD 19 498,249 3%

Ventura County APCD 83 304,936 2%

Sacramento Metro AQMD 155 133,043 1%

Yolo/Solano AQMD 200 106,460 1%

Glenn County APCD 79 91,584 0%

Feather River AQMD 69 85,569 0%

Bay Area AQMD 68 65,979 0%

San Luis Obispo County APCD 4 64,785 0%

Colusa County APCD 119 62,195 0%

Tehama County APCD 47 27,684 0%

Butte County AQMD PD PD PD

North Coast Unified AQMD PD PD PD

No District 4 806 0%

San Diego County APCD PD PD PD

Totals: 1,637 18,784,582
Chapter 3 Final 2007 Oil and Gas Industry Survey Results

3-3

Total Emissions by Combustion, Vented, and Fugitive Sources

Table 3-4 lists the total combustion emissions by source type. The majority of the CO2e 

emissions are from steam generators, combined heat and power units, and turbines.

Table 3-4: Combustion Emissions by Combustion Type (Metric Tons/Year)

Type CO2 CH4 N2O CO2e

Percent of 

Total CO2e

Steam Generator 6,658,156 2,973 115 6,756,167 41%

Combined Heat and Power 3,568,017 612 7 3,583,006 22%

Turbine 2,731,036 835 153 2,796,035 17%

Internal Combustion Engine 1,004,624 4,537 16 1,104,754 7%

Cogeneration 930,377 15 2 931,185 6%

Flare 242,454 812 0 259,623 2%

Microturbine 232,240 581 17 249,584 2%

Thermal Oxidizer 216,378 80 0 218,155 1%

Boiler 140,240 245 0 145,454 1%

Heater 116,301 34 2 117,584 1%

Heater/Treater 115,607 47 2 117,226 1%

Incinerator 44,846 49 0 45,896 0%

Drill Rig 31,600 1 0 31,708 0%

Reboiler 17,466 15 0 17,782 0%

Workover Rig 13,300 1 0 13,345 0%

Vapor Recovery 10,681 0 0 10,690 0%

Other 72 0 0 73 0%

Totals: 16,073,395 10,836 314 16,398,268

Table 3-5 lists the total combustion emissions by primary business type. The primary 

business type “crude processing” and “crude storage” were combined to protect 

confidential company data. Table 3-5 shows that 88 percent of the emissions are from 

onshore crude production and the business type “other.” 

Table 3-5: Combustion Emissions by Primary Business (Metric Tons/Year)

Type CO2 CH4 N2O CO2e

Percent of 

Total CO2e

Onshore Crude Production 9,601,843 6,069 178 9,784,578 60%

Other 4,579,058 161 108 4,616,047 28%

Natural Gas Processing 832,060 2,173 6 879,601 5%

Crude Processing and Storage 334,290 580 2 346,952 2%

Natural Gas Storage 200,225 1,126 9 226,569 1%

Onshore Natural Gas Production 204,801 620 4 218,910 1%

PERP Equipment Owner 148,048 19 1 148,825 1%

Offshore Crude 101,521 78 4 104,272 1%

Crude Pipeline 71,548 9 3 72,515 0%

Totals: 16,073,395 10,836 314 16,398,268
Chapter 3 Final 2007 Oil and Gas Industry Survey Results

3-4

Table 3-6 lists the total vented emissions by source type. The type “natural gas 

gathering pipelines” only includes the venting from maintenance activities. These 

pipelines do not include natural gas transmission and distribution pipelines. Natural gas 

dehydrators and automated control devices account for 61 percent of the total vented 

emissions in California. 

Table 3-6: Vented Emissions by Source Type (Metric Tons/Year)

Type CO2 CH4 CO2e

Percent of 

Total CO2e

Dehydrators 308 10,829 227,721 40%

Automated Control Devices 161 5,727 120,434 21%

Compressor Blowdowns 172 3,238 68,165 12%

Natural Gas Gathering Pipelines 2,659 2,490 54,940 10%

Well Workovers 645 2,116 45,085 8%

Sweetening/Acid Gas Removal 44,160 19 44,559 8%

Well Cleanups 219 327 7,082 1%

Compressor Startups 4 69 1,462 0%

Carbon Adsorbers 0 54 1,131 0%

Natural Gas Gathering Pipeline Pigging 104 5 211 0%

Storage Tank Degassing 0 5 109 0%

Separator Degassing 0 1 24 0%

New Wells Drilled 0 0 0 0%

Totals: 48,432 24,880 570,922

Table 3-7 lists the total vented emissions by primary business type. The primary 

business type “crude processing” and “crude storage” were combined to protect 

confidential company data. Table 3-7 shows that 93 percent of the total vented 

emissions in California are from the primary business types “natural gas storage”, 

“onshore crude production”, and “onshore natural gas production”.

Table 3-7: Vented Emissions by Primary Business Type (Metric Tons/Year)

Type CO2 CH4 CO2e

Percent of 

Total CO2e

Natural Gas Storage 384 13,148 276,484 48%

Onshore Crude Production 30,308 5,073 136,839 24%

Onshore Natural Gas Production 127 5,605 117,835 21%

Offshore Crude Production 84 792 16,708 3%

Crude Processing and Storage 15,867 4 15,940 3%

Natural Gas Processing 1,649 164 5,102 1%

PERP Equipment Owner 10 93 1,960 0%

Other 2 2 53 0%

Crude Pipeline 0 0 0 0%

Totals: 48,432 24,880 570,922
Chapter 3 Final 2007 Oil and Gas Industry Survey Results

3-5

Table 3-8 lists the total fugitive emissions by source type. The type “natural gas 

gathering pipeline” only includes the fugitive emissions from the gathering system 

pipelines. These pipelines do not include natural gas transmission and distribution 

pipelines. Natural gas processing equipment and compressor seals account for 80 

percent of the total fugitive emissions in California that are covered by this survey.

Table 3-8: Fugitive Emissions by Source Type (Metric Tons/Year)

Type CO2 CH4 CO2e

Percent of 

Total CO2e

Sweetening/Acid Gas Removal 145,414 14,640 452,847 25%

Compressor Seals 2,025 17,679 373,274 21%

Other Natural Gas Processing 104,457 12,099 358,528 20%

Dehydrators 16,682 11,336 254,741 14%

Storage Tanks 1,084 11,501 242,594 13%

Well Cellars 0 2,154 45,225 2%

Wellheads 559 2,032 43,228 2%

Natural Gas Gathering Pipelines 327 867 18,541 1%

Components 256 811 17,283 1%

Sumps 0 264 5,552 0%

Separators 11 170 3,578 0%

Totals: 270,815 73,551 1,815,393

Table 3-9 lists the total fugitive emissions by primary business type. The primary 

business type “crude processing” and “crude storage” were combined to protect 

confidential company data. This table shows that the primary business types “onshore 

crude production” and “natural gas processing” account for 71 percent of the total 

fugitive emissions.

Table 3-9: Fugitive Emissions by Primary Business Type (Metric Tons/Year)

Type CO2 CH4 CO2e

Percent of 

Total CO2e

Onshore Crude Production 25,974 41,056 888,158 49%

Natural Gas Processing 177,461 10,605 400,160 22%

Onshore Natural Gas Production 408 10,022 210,879 12%

Natural Gas Storage 29 8,380 176,004 10%

Offshore Crude Production 46,296 902 65,232 4%

Crude Processing and Storage 20,509 1,135 44,347 2%

Crude Pipeline 77 820 17,306 1%

Other 37 404 8,512 0%

PERP Equipment Owner 24 227 4,793 0%

Totals: 270,815 73,551 1,815,393

Total Emissions by CO2e Range

Total CO2e emissions were calculated for each facility. All facilities were then 

categorized into ranges of CO2e emissions. Table 3-10 lists the number of facilities in 

each range and the total CO2e emissions for all the facilities in that range. Ninety-four 

percent of the facilities in this sector account for only 5 percent of the total emissions 

while 2.5 percent of the facilities account for 85 percent of the emissions. 
Chapter 3 Final 2007 Oil and Gas Industry Survey Results

3-6

Table 3-10: Total California Emissions by CO2e Range (Metric Tons/Year)

Range 

(CO2e per Facility)

Number of 

Facilities CO2e

Percent of Total 

CO2e

< 10,000 1,533 960,769 5%

10,000 to 25,000 29 471,512 3%

25,000 to 50,000 19 693,382 4%

50,000 to 100,000 10 726,316 4%

100,000 to 500,000 32 6,251,485 33%

> 500,000 9 9,681,118 52%

Totals: 1,632 18,784,582

Tables 3-11, 3-12, and 3-13 list the number of facilities and total CO2e emissions for 

combustion, vented, and fugitive sources. These tables mirror Table 19-11 in that the 

majority of the emissions come from a small fraction of the total number of facilities. 

Table 3-11: Total California Combustion Emissions by CO2e Range

 (Metric Tons/Year)

Range

(CO2e per Facility)

Number of 

Facilities CO2e

Percent of Total 

CO2e

< 10,000 1,549 544,783 3%

10,000 to 25,000 25 398,589 2%

25,000 to 50,000 17 629,251 4%

50,000 to 100,000 7 547,906 3%

100,000 to 500,000 26 4,867,300 30%

> 500,000 8 9,410,440 57%

Totals: 1,632 16,398,268

Table 3-12: Total California Vented Emissions by CO2e Range (Metric Tons/Year)

Range

(CO2e per Facility)

Number of 

Facilities CO2e

Percent of Total 

CO2e

<1,000 1,588 102,520 18%

1,000 to 5,000 32 63,978 11%

5,000 to 10,000 4 28,043 5%

10,000 to 25,000 4 62,736 11%

> 25,000 4 313,645 55%

Totals: 1,632 570,922

Table 3-13: Total California Fugitive Emissions by CO2e Range

(Metric Tons/Year)

Range 

(CO2e per Facility)

Number of 

Facilities CO2e

Percent of Total 

CO2e

< 1,000 1,505 204,824 11%

1,000 to 5,000 99 180,392 10%

5,000 to 10,000 9 64,619 4%

10,000 to 25,000 7 98,901 5%

> 25,000 12 1,266,656 70%

Totals: 1,632 1,815,393
Chapter 4 Final 2007 Oil and Gas Industry Survey Results

4-1

Chapter 4 – Wells

Wells are essential to extracting crude oil and natural gas from geological formations. 

These wells have emissions from the site of the well as well as from maintenance 

activities. Table 2 of the 2007 Oil and Gas Industry Survey required companies to fill 

out the number of

o active wells, 

o well cellars, 

o new wells drilled,

o workovers that required tubing removal,

o well cleanups (also known as liquid unloading), and

o well completions.

Active wells are wells that are producing crude oil or natural gas throughout the year. 

Well cellars are lined or unlined pits around one or more wells that: (a) allow access to 

the wellhead components for servicing, or (b) contain intermittent flows of crude oil or 

water during an emergency or from drilling and petroleum production processes. 

Well completions are the final step to bringing a newly drilled well on to production. In 

some cases, a new well will be completed in a different reporting period than when the 

well was drilled. Thus, the number of well completions for crude oil in 2007 is larger 

than the number of wells drilled in that same year. 

Well workovers are the process of performing major maintenance or remedial 

treatments on an oil or gas well. This can be done with the production tubing remaining 

in place or being removed. The number of well workovers listed in Tables 4-3 and 4-4 

only include workovers that required tubing removal. 

Well cleanups are well maintenance activities that included fracturing or removing fluids 

to increase production. Fracturing uses high pressure pumps to increase fluid pressure 

at the bottom of the well. This fluid pressure cracks the formation and proppants such 

as sand or walnut hulls are injected into the newly formed crevices to keep them open 

when the fluid pressure is removed. This increases the flow of the crude oil or natural 

gas. Fluid removal is a natural gas well maintenance activity that removes built up 

fluids from the well to increase natural gas production. 

Table 4-1 lists the number of crude oil active wells and well cellars by API range. Table 

4-2 lists the number of active wells and well cellars for natural gas.
Chapter 4 Final 2007 Oil and Gas Industry Survey Results

4-2

Table 4-1: Number of Crude Oil Active Wells and Well Cellars by API Range

Type

Number of 

Active Wells 

Number of 

Well Cellars

Ultra-Heavy Oil (API <10) 47 22

Heavy Oil (API 10 - 20) 36,619 7,461

Light Oil (API 20 - 30) 14,261 4,998

Ultra-Light Oil (API >30) 1,323 2,168

Totals: 52,250 14,649

Table 4-2: Number of Natural Gas Active Wells and Well Cellars

Type

Number of 

Active Wells 

Number of Well 

Cellars

Dry Gas 1,397 491

Natural Gas Storage 372 337

Totals: 1,769 828

Table 4-3 lists the number of new wells drilled, well completions, well workovers, and 

well cleanups reported in the survey by API range. Table 4-4 lists the number of new 

wells drilled, well completions, well workovers, and well cleanups for natural gas. 

Table 4-3: Number of Crude Oil New Wells Drilled, Well Completions, Well 

Workovers and Well Cleanups by API Range

Type

Number of 

New Wells 

Drilled

Number of 

Well 

Completions

Number of 

Well 

Workovers

Number of 

Well Cleanups

Ultra-Heavy Oil (API <10) 0 0 0 0

Heavy Oil (API 10 - 20) 1,197 1,399 12,889 956

Light Oil (API 20 - 30) 763 732 5,424 1,977

Ultra-Light Oil (API >30) 175 187 599 187

Totals: 2,135 2,318 18,912 3,120

Table 4-4: Number of Natural Gas New Wells Drilled, Well Completions, Well 

Workovers, and Well Cleanups

Type

Number of New 

Wells Drilled

Number of Well 

Completions

Number of Well 

Workovers

Number of Well 

Cleanups

Dry Gas 162 142 304 86

Natural Gas Storage PD PD PD PD

Totals: PD PD PD PD

Emissions

Emissions for wells and their maintenance activities are detailed in this section. 

Emissions from active wells and well cellars are categorized as fugitive emissions. 

Fugitive emissions are unintentional emission leaks. Emissions from well workovers 

and well cleanups are vented emissions. Vented emissions are intentional emission 

leaks. All CO2 and CH4 values are multiplied by their corresponding GWP (1 for CO2

and 21 for CH4) to get the CO2e number.
Chapter 4 Final 2007 Oil and Gas Industry Survey Results

4-3

Active Wells

The emissions of CO2 and CH4 are calculated using emission factors multiplied by the 

number of active wells. The calculations and emission factors are detailed in 

Appendix B.

Table 4-5 lists the number of wells and the calculated emissions by API range. 

Table 4-6 lists the number of wells and calculated emissions for natural gas. In 2007, 

there were 59,856 wells producing crude oil and 1,540 active dry gas wells (DOGGR, 

2008). Thus, 87 percent of the actively producing crude oil wells and 91 percent of the 

actively producing dry gas wells in California were reported in the survey. 

Table 4-5: Emissions of Crude Oil Wells by API Range (Metric Tons/Year)

Type

Number of 

Active Wells CO2 CH4 CO2e

Percent of 

Total CO2e

Ultra-Heavy Oil (API <10) 47 0 0 4 0%

Heavy Oil (API 10 - 20) 36,619 66 155 3,327 9%

Light Oil (API 20 - 30) 14,261 459 1,415 30,163 83%

Ultra-Light Oil (API >30) 1,323 19 139 2,932 8%

Totals: 52,250 543 1,709 36,427

Table 4-6: Emissions of Natural Gas Wells (Metric Tons/Year)

Type

Number of 

Active Wells CO2 CH4 CO2e

Percent of 

Total CO2e

Dry Gas 1,397 14 253 5,321 78%

Natural Gas Storage 372 1 70 1,479 22%

Totals: 1,769 16 323 6,801

Well Cellars

The emissions of CO2 and CH4 are calculated using emission factors multiplied by the 

number of well cellars. The calculations and emission factors are detailed in Appendix 

B.

Table 4-7 lists the number of well cellars and their emissions by crude oil API. Emission 

factors for natural gas well cellars do not exist at this time.

Table 4-7: Emissions of Crude Oil Well Cellars by API Range (Metric Tons/Year)

Type

Number of 

Well Cellars CH4 CO2e

Percent of 

Total CO2e

Ultra-Heavy Oil (API <10) 22 3 58 0%

Heavy Oil (API 10 - 20) 7,461 933 19,585 43%

Light Oil (API 20 - 30) 4,998 850 17,843 39%

Ultra-Light Oil (API >30) 2,168 369 7,740 17%

Totals: 14,649 2,154 45,225
Chapter 4 Final 2007 Oil and Gas Industry Survey Results

4-4

Drilling and Maintenance

GHG emissions can be calculated from well drilling and maintenance activities. At this 

time, there are emission calculations for CO2 and CH4 emissions from well workovers 

and cleanups but not for new wells drilled and well completions. The emissions are 

calculated using the number of workovers or cleanups, the percent CO2 and CH4 in the 

associated or dry gas, and emission factors. These calculations are detailed in 

Appendix B. 

Tables 4-8 through 4-11 list the calculated emissions for well workovers and well 

cleanups. As these tables show, well workovers account for the majority of the CO2e 

emissions from well maintenance activities.

Table 4-8: Emissions of Crude Oil Well Workovers by API Range

(Metric Tons/Year)

Type

Number of Well 

Workovers CO2 CH4 CO2e

Percent of 

Total CO2e

Ultra-Heavy Oil (API <10) 0 0 0 0 0%

Heavy Oil (API 10 - 20) 12,889 405 1,428 30,403 69%

Light Oil (API 20 - 30) 5,424 225 575 12,303 28%

Ultra-Light Oil (API >30) 599 9 65 1,374 3%

Totals: 18,912 639 2,069 44,080

Table 4-9: Emissions of Natural Gas Well Workovers (Metric Tons/Year)

Type

Number of Well 

Workovers CO2 CH4 CO2e

Percent of 

Total CO2e

Dry Gas 304 6 46 970 PD

Natural Gas Storage PD PD PD PD PD

Totals: PD PD PD PD

Table 4-10: Emissions of Crude Oil Well Cleanups by API Range

(Metric Tons/Year)

Type

Number of 

Well Cleanups CO2 CH4 CO2e

Percent of 

Total CO2e

Ultra-Heavy Oil (API <10) 0 0 0 0 0%

Heavy Oil (API 10 - 20) 956 103 90 1,993 29%

Light Oil (API 20 - 30) 1,977 113 201 4,327 64%

Ultra-Light Oil (API >30) 187 3 21 442 7%

Totals: 3,120 219 312 6,762

Table 4-11: Emissions of Natural Gas Well Cleanups (Metric Tons/Year)

Type

Number of 

Well Cleanups CO2 CH4 CO2e

Percent of 

Total CO2e

Dry Gas 86 0 14 292 PD

Natural Gas Storage PD PD PD PD PD

Totals: PD PD PD PD
Chapter 5 Final 2007 Oil and Gas Industry Survey Results

5-1

Chapter 5 – Electricity Generation and Use

Many crude oil and natural gas facilities often produce their own electricity. This is done 

using generators, cogeneration units, or combined heat and power units. Many of the 

cogeneration units and combined heat and power units are used to generate steam as 

well as electricity. 

Table 3 of the 2007 Oil and Gas Industry Survey required facilities to report the amount 

of electricity generated onsite, exported, and purchased. Table 5-1 lists the total 

electricity by primary business type. Twenty-four terra-watt hours (Twh) of electricity 

was generated by facilities through generators, cogeneration units, or combined heat 

and power units. Sixty percent of the generated electricity was used on site, with the 

remainder exported to either the grid or other facilities. Crude oil and natural gas 

facilities purchased 17 Twh of electricity in 2007. This is nine percent of the 200 Twh of 

electricity that was purchased by non-residential customers (CEC, 2007). 

Table 5-1: Electricity by Primary Business (Metric Tons/Year)

Type

Generated

(MWh)

Used

(MWh)

Exported

(MWh)

Purchased

(MWh)

Onshore Crude Production 15,564,710 14,259,805 1,304,905 17,183,986

Offshore Crude Production 81,739 81,739 0 69,056

Onshore Natural Gas Production PD PD PD PD

Natural Gas Storage 7,729 7,729 0 27,976

Natural Gas Processing 49,037 18,078 30,959 60,393

Crude Pipeline 19,202 5,195 14,007 194,877

Crude Processing PD PD PD PD

Crude Storage 0 0 0 67,270

PERP Equipment Owner PD PD PD PD

Other 8,472,167 152,854 8,319,313 7,888

Totals: 24,582,599 14,910,228 9,672,371 17,676,795

The business type “other” includes the following self-reported facility types:

o CNG compression and marketing

o Cogeneration

o Combined heat and power

o Electricity generation

o Portable heating 

o Water disposal

o Vapor recovery services.
Chapter 5 Final 2007 Oil and Gas Industry Survey Results

5-2

References

CEC (2007). California Energy Commission. 2007 Non-Residential Electricity 

Consumption by County. http://www.ecdms.energy.ca.gov/elecbycounty.aspx. 

2007.
Chapter 6 Final 2007 Oil and Gas Industry Survey Results

6-1

Chapter 6 – Vapor Recovery

Vapor recovery is the process of collecting vapors so their emissions to the atmosphere

are substantially reduced. Vapor recovery equipment collects or converts these vapors. 

Table 4 of the 2007 Oil and Gas Industry Survey collected information about four types 

of vapor recovery units. These include flares, incinerators, thermal oxidizers, and 

carbon adsorbers. Flares, incinerators, and thermal oxidizers convert vapors while 

carbon adsorbers collect them. In the oil and gas production sector, these units are 

also used to convert or collect natural gas that is not of good enough quality to enter a 

natural gas transmission pipeline or that is stranded, and which would otherwise be 

emitted to the atmosphere. 

Table 4 of the Oil and Gas Industry Survey collected the following information about 

each facility’s vapor recovery units.

o Type

• Flare, incinerator, thermal oxidizer, or carbon adsorber

o Use

• Vapor recovery or emergency were choices on the survey

• Some facilities added other uses such as gas disposal and planned 

flaring

o For flares, incinerators, and thermal oxidizers

• Size in btu/hr

• Throughput in scf 

• Combustion efficiency

• CH4 and CO2 content of the gas stream

• Carbon mole ratio

o For carbon adsorbers

• Size in cubic feet

• Throughput in scf

• Capture efficiency

• CH4 content of the gas stream

Table 6-1 lists the number of vapor recovery units by type. Flares represented the most 

common type. They account for 77 percent of the total number of vapor recovery units.

Table 6-1: Number of Vapor Recovery Units by Type

Type Number of Units

Flare 196

Thermal Oxidizer 19

Incinerator 23

Carbon Adsorbers 17

Totals: 255
Chapter 6 Final 2007 Oil and Gas Industry Survey Results

6-2

Emissions

Emissions from flares, incinerators, thermal oxidizers, and carbon adsorbers are 

detailed in this section. Emissions from flares, incinerators, and thermal oxidizers are 

categorized as combustion emissions from burning fuel. Emissions from carbon 

adsorbers are considered vented emissions. The emissions are calculated using fuel 

data supplied in the survey and are detailed in Appendix B. The CO2, CH4, and N2O 

emissions are multiplied by their corresponding GWP (1 for CO2, 21 for CH4, and 310 

for N2O) to get the CO2e value. 

Table 6-2 lists the combustion emissions from flares, incinerators, and thermal 

oxidizers. Some equipment types were combined from what was listed on individual 

surveys to protect confidential company data and to aggregate similar pieces of 

equipment. For example, incinerators, burners, and afterburners were combined into 

the category “incinerator.” This table shows that flares and thermal oxidizers have 

similar CO2e emissions even though there are 10 times as many flares as thermal 

oxidizers. This is because both flares and thermal oxidizers combusted similar volumes 

of gas. 

Table 6-2: Vapor Recovery Combustion Emissions by Type (Metric Tons/Year)

Type

Number of 

Units CO2 CH4 N2O CO2e

Percent 

of Total 

CO2e

Flare 196 242,454 812 0.4 259,623 50%

Thermal Oxidizer 19 216,378 80 0.3 218,155 42%

Incinerator 23 44,846 49 0.1 45,896 9%

Totals: 238 503,678 941 0.7 523,675

Table 6-3 lists the vented emissions from carbon adsorbers. The CO2e emissions from 

carbon adsorbers are a very small fraction of the total emissions from vapor recovery 

units. 

Table 6-3: Carbon Adsorber Vented Emissions (Metric Tons/Year)

Type

Number of 

Units CH4 CO2e

Carbon Adsorbers 17 54 1,131

Totals: 17 54 1,131

Table 6-4 lists the uses of flares, incinerators, and thermal oxidizers. All carbon 

adsorbers were used for vapor recovery. Some vapor recovery uses were combined 

from what was listed on individual surveys to protect confidential company data and to 

aggregate similar equipment uses. Below is a list of use categories and the types they 

represent.

o Unknown – unknown, not in use, and dormant

o Emergency – emergency, emergency and vapor recovery, planned and 

unplanned flaring, and standby
Chapter 6 Final 2007 Oil and Gas Industry Survey Results

6-3

o Gas Disposal – gas disposal, maintenance, tank degassing, fuel limited, and 

vapor recovery/gas disposal

As this table shows, vapor recovery is the dominant use. It accounts for 73 percent of 

the total CO2e emissions.

Table 6-4: Vapor Recovery Combustion Emissions by Use (Metric Tons/Year)

Type

Number of 

Units CO2 CH4 N2O CO2e

Percent 

of Total 

CO2e

Vapor Recovery 123 373,813 475 0.5 383,949 73%

Emergency 92 90,949 364 0.1 98,629 19%

Unknown 11 29,236 75 0.1 30,835 6%

Gas Disposal 12 9,680 28 0.0 10,262 2%

Totals: 238 503,678 941 0.7 523,675

Table 6-5 lists the combustion vapor recovery units by their rated size. It includes all 

flares, incinerators, and thermal oxidizers reported in the 2007 Oil and Gas Industry 

Survey. 

Table 6-5: Number of Combustion Vapor Recovery Units by Size

Range (MMBtu/Hr)

Number of 

Units

Percent 

of Total 

Unknown 26 11%

<5 84 35%

5 to 25 55 23%

25 to 100 17 7%

100 to 500 32 13%

500 to 1000 9 4%

>1000 15 6%

Totals: 238

Chapter 7 Final 2007 Oil and Gas Industry Survey Results

7-1

Chapter 7 – Combustion Equipment

Combustion equipment encompasses many different types of equipment that all burn a 

fuel for energy. The 2007 Oil and Gas Industry Survey collected information about two 

main categories of combustion equipment: external combustion units and internal 

combustion units. 

Table 5 of the Oil and Gas Industry Survey collected the following information about 

each facility’s combustion equipment.

o Type

• External 

 Boiler, steam generator, heater/treater, oil heater, glycol 

reboiler, or amine reboiler

 Facilities could also specify a type not listed above

• Internal combustion

 Reciprocating two-stroke or four-stroke and either lean or rich 

burn, combined heat and power, simple or combined cycle 

turbine, microturbine, drill rig, or workover rig,

 Facilities could also specify a type not listed above

o Use for internal combustion equipment

• Compressor, vapor recovery, crude oil pump, well pump, or water 

injection pump

• Facilities could also specify a use not listed above

o Fuel type

• Including volume, higher heating value (hhv), carbon weight percent, 

liquid fuel density, and gaseous fuel molecular weight as appropriate

o Manufacturer

o Model year

o Average load in HP, BTU, or MW

o Inspection frequency

o Permitting and PERP registration

Emissions

Emission calculations for combustion equipment are dependent on the information 

reported in the survey. Three methods are available to calculate CO2, CH4, and N2O. 

The first method uses a mass balance approach, the second uses equipment-specific 

emission factors, and the third method uses fuel-specific emission factors. The mass 

balance approach is used first if fuel composition was reported. If fuel composition was 

not reported, the equipment-specific emission factors are used. For combustion 

equipment emission calculations that could not utilize either the first or second method, 

fuel-specific emission factors were used. These equations and emission factors are 

detailed in Appendix B. The CO2, CH4, and N2O emissions are multiplied by their 

corresponding GWP numbers (1 for CO2, 21 for CH4, and 310 for N2O) to get the CO2e 

values.
Chapter 7 Final 2007 Oil and Gas Industry Survey Results

7-2

External Combustion

An external combustion engine is an engine where an internal fluid is heated by an 

external heat source. The most common types of external combustion units are steam 

generators and boilers. Some equipment types were combined from what was listed on 

individual surveys to protect confidential company data and to aggregate similar pieces 

of equipment. Below is a list of equipment categories and the types they represent:

o Boilers – boilers and locomotive boilers;

o Heaters – heaters, central process heaters, tank heaters, forced air 

furnaces, water heaters, hot water circulating heaters, line heaters, oil 

heaters, and process heaters; and

o Vapor Recovery – flares, incinerators, and thermal oxidizers that were

reported on Table 5 rather than Table 4 of the Oil and Gas Industry 

Survey.

Steam generators create steam that is injected into the geological formation to increase 

crude oil production. Cogeneration units produce steam for injection and electricity

generation. Heater/Treaters are oil/water separators that use heat to expedite the 

separation process. Reboilers include glycol and amine reboilers. These units heat 

glycol or amine to remove water in dehydrators and the acid gas in amine units. 

Table 7-1 lists the CO2, CH4, and N2O emissions from external combustion equipment. 

This table shows that the majority of the emissions are from steam generators. 

Table 7-1: External Combustion Emissions by Equipment Type (Metric Tons/Year)

Type

Number 

of Units CO2 CH4 N2O CO2e

Percent 

of Total 

CO2e

Steam Generator 587 6,658,156 2,973 115 6,756,167 83%

Cogeneration 34 930,377 15 2 931,185 12%

Boiler 132 140,240 245 0 145,454 2%

Heater 294 116,301 34 2 117,584 1%

Heater/Treater 371 115,607 47 2 117,226 1%

Reboiler 201 17,466 15 0 17,782 0%

Vapor Recovery 11 10,681 0 0 10,690 0%

Totals: 1,630 7,988,827 3,328 121 8,096,089

Table 7-2 lists the age of the external combustion equipment. The age of each unit was 

determined from the model year. As this table shows, 80 percent of the units did not 

have a reported model year. Of the remaining units, most are 5 to 10 years old.
Chapter 7 Final 2007 Oil and Gas Industry Survey Results

7-3

Table 7-2: Age of External Combustion Units

Type

< 5 

Years

5 – 10 

Years

10 – 20 

Years

20 – 30 

Years

>30 

Years Unknown Total

Boiler 3 28 4 15 1 81 132

Cogeneration 0 0 0 0 0 34 34

Heater 1 30 3 4 6 250 294

Heater/Treater 11 61 5 21 5 268 371

Reboiler 5 50 5 7 5 129 201

Steam Generator 10 11 1 25 0 540 587

Vapor Recovery 0 4 1 0 0 6 11

Totals: 30 184 19 72 17 1,308 1,630

Internal Combustion

An internal combustion engine is an engine where fuel is burned inside a combustion 

chamber. The expansion of the gas applies direct force to a component of the engine 

such as a piston or turbine blade. Some equipment types were combined from what 

was listed on individual surveys to protect confidential company data and to aggregate 

similar pieces of equipment. Below is a list of equipment categories and the types they 

represent:

o Other – generators, pumps, accumulators, and welders; and

o Turbines – turbines, turbines – combined cycle, turbines – simple cycle, 

and turbines – combined heat and power.

Table 7-3 lists the combustion emissions for internal combustion engines. The type 

“internal combustion engines” encompasses all the general use reciprocating engines. 

The type “combined heat and power” and turbines together account for 82 percent of 

the emissions. The term “combined heat and power” is interchangeable with the term 

“cogeneration” listed above in “external combustion”. Such units produce electricity and 

useful heat. The heat is either used to create steam for injection into the geological 

formation or used to create more electricity. Combined heat and power units could be 

turbines or reciprocating engines. Facilities reported cogeneration and combined heat 

and power differently. Thus, they appear as both internal and external combustion.

Table 7-3: Internal Combustion Emissions by Equipment Type (Metric Tons/Year)

Type

Number 

of Units CO2 CH4 N2O CO2e

Percent 

of Total 

CO2e

Combined Heat and Power 23 3,568,017 612 7 3,583,006 46%

Turbine 64 2,731,036 835 153 2,796,035 36%

Internal Combustion Engine 2,698 1,004,624 4,537 16 1,104,754 14%

Microturbine 29 232,240 581 17 249,584 3%

Drill Rig 174 31,600 1 0 31,708 0%

Workover Rig 225 13,300 1 0 13,345 0%

Other 77 72 0 0 73 0%

Totals: 3,290 7,580,889 6,567 193 7,778,505
Chapter 7 Final 2007 Oil and Gas Industry Survey Results

7-4

Table 7-4 lists the age of internal combustion units by type. Almost half of the units did 

not have a reported model year in their survey; thus, their ages are unknown. 

Table 7-4: Age of Internal Combustion Units

Type

< 5 

Years

5 – 10 

Years

10 – 20 

Years

20 – 30 

Years

>30 

Years Unknown Total

Combined Heat and Power 0 4 13 1 5 0 23

Drill Rig 123 11 10 17 12 1 174

Internal Combustion Engine 347 362 92 240 180 1,477 2,698

Microturbine 2 0 0 0 0 27 29

Other 22 0 0 0 0 55 77

Turbine 1 6 7 16 3 31 64

Workover Rig 24 63 34 4 100 0 225

Totals: 519 446 156 278 300 1,591 3,290

Internal Combustion Engines

The type category “internal combustion engines” was reported on Table 5 of the 2007 

Oil and Gas Industry Survey as reciprocating engines. Many internal combustion 

engine uses were combined from what was listed on individual surveys to protect 

confidential company data and to aggregate similar equipment uses. Appendix D lists 

the use categories and the types they represent.

Table 7-5 lists the combustion emissions by use. The use “unknown” accounts for 

equipment where a use was not specified on the survey. The use “pump” is separate 

from “crude oil pump” and “water pump” as it was not indicated on the survey which kind 

of pump it is. Cogeneration is listed here as a use for a reciprocating engine. As stated 

above, cogeneration units can be either reciprocating engines or turbines. 

Table 7-5: Combustion Emissions of Internal Combustion Engines by Use

(Metric Tons/Year)

Use

Number 

of Units CO2 CH4 N2O CO2e

Percent 

of Total 

CO2e

Compressor 693 714,295 4,200 13 806,644 73%

Crude Oil Pump 722 103,846 224 1 108,786 10%

Power Generation 229 54,000 41 0 54,997 5%

Well Servicing 297 53,181 3 0 53,360 5%

Water Pump 49 27,619 51 0 28,778 3%

Unknown 96 20,856 5 0 20,986 2%

Pump 297 14,796 1 0 14,841 1%

Miscellaneous 189 9,440 1 0 9,482 1%

Cogeneration 17 5,254 13 0 5,534 1%

Crane 36 915 0 0 919 0%

Air Compressor 35 277 0 0 278 0%

Emergency Services 38 145 0 0 149 0%

Totals: 2,698 1,004,624 4,537 16 1,104,754

Compressors account for the majority of the emissions for internal combustion engines. 

They emit 73 percent of the internal combustion engine CO2e emissions. Crude oil 
Chapter 7 Final 2007 Oil and Gas Industry Survey Results

7-5

pumps account for the next highest percentage. The remaining 17 percent of the 

emissions are distributed among the remaining ten use categories.

Table 7-6 lists combustion emissions by rich burn, lean burn, two-stroke, or four-stroke. 

Survey respondents did not report the type for about half of the units. Of the remaining 

units for which a type was not specified, 66 percent are rich burn, four-stroke engines. 

Rich burn two-stroke engines are the least common. 

Table 7-6: Combustion Emissions of Internal Combustion Engines by Type

(Metric Tons/Year)

Type

Number 

of Units CO2 CH4 N2O CO2e

Percent 

of Total 

CO2e

Rich Burn Four-Stroke 914 378,030 828 3 396,392 36%

Rich Burn Two-Stroke 78 17,134 13 0 17,431 2%

Lean Burn Four-Stroke 284 395,947 3,279 10 467,823 42%

Lean Burn Two-Stroke 115 43,195 356 2 51,262 5%

Unknown 1,307 170,318 62 1 171,846 16%

Totals: 2,698 1,004,624 4,537 16 1,104,754

Turbines

Turbines are a type of internal combustion engine where the force from the combustion 

chamber moves a blade rather than a piston. Some turbine uses were combined from 

what was listed on individual surveys to protect confidential company data and to 

aggregate similar equipment uses. Below is a list of use categories and the types they 

represent:

o Cogeneration – cogeneration, electrical and steam generation, electrical 

and process heat generation;

o Electricity – electrical generation and power generation; and

o Other – compressors and pumps.

Table 7-7 lists the combustion emissions for turbines by use. Cogeneration accounts 

for 81 percent of the total emissions. 

Table 7-7: Turbine Combustion Emissions by Use (Metric Tons/Year)

Use

Number 

of Units CO2 CH4 N2O CO2e

Percent 

of Total 

CO2e

Cogeneration 46 2,207,183 791 125 2,262,524 81%

Electricity 6 308,823 22 21 315,810 11%

Other 12 215,029 22 7 217,701 8%

Totals: 64 2,731,036 835 153 2,796,035

Table 7-8 lists the combustion emissions from turbines by the type of cycles they use. 

Combined cycle turbines have a gas turbine that generates electricity, and the waste 

heat is used to make steam. The steam is then used to generate electricity through a 
Chapter 7 Final 2007 Oil and Gas Industry Survey Results

7-6

steam turbine or injected into the geological formation to increase production. Simple 

cycle turbines generate electricity in the same manner as combined cycle turbines. The 

difference is that the waste heat is not used to create steam for more electricity or useful 

steam. 

Some turbine cycle types were combined from what was listed on individual surveys to 

protect confidential company data: 

o Turbine Combined Cycle – turbine combine cycle and turbines-combined heat 

and power.

Table 7-8 shows that the majority of the emissions are from combined cycle turbines. 

Table 7-8: Turbine Combustion Emissions by Cycle Type (Metric Tons/Year)

Type

Number 

of Units CO2 CH4 N2O CO2e

Percent 

of Total 

CO2e

Turbine Combined Cycle 23 1,648,609 167 124 1,690,680 60%

Turbine 26 682,553 640 1 696,374 25%

Turbine Simple Cycle 15 399,873 28 27 408,981 15%

Totals: 64 2,731,036 835 153 2,796,035

Cogeneration

Cogeneration and combined heat and power are interchangeable terms. Both refer to 

engines that produce electricity and waste heat. In these categories, the waste heat is 

used to create steam. This steam is then injected into geological formations to increase 

crude oil production or used to create more electricity. 

Cogeneration and combined heat and power units were reported in the 2007 Oil and 

Gas Industry Survey in many different ways. Table 7-9 lists these units together in the 

manner they were reported. Two turbine types were combined from what was listed on 

individual surveys to protect confidential company data. The type “turbines combined 

cycle” and “turbines-combined heat and power” were combined under the type “turbine 

combined cycle.” 

Table 7-9: Cogeneration Combustion Emissions by Type (Metric Tons/Year)

Type

Number 

of Units CO2 CH4 N2O CO2e

Percent 

of Total 

CO2e

Combined Heat and Power 23 3,568,017 612 7 3,583,006 50%

Turbine Combined Cycle 19 1,642,198 153 124 1,683,882 24%

Cogeneration 34 930,377 15 2 931,185 13%

Turbine 23 563,939 638 1 577,654 8%

Turbine Simple Cycle 10 309,869 21 21 316,799 4%

Internal Combustion Engine 54 36,143 19 0 36,633 1%

Totals: 163 7,050,543 1,457 155 7,129,158
Chapter 7 Final 2007 Oil and Gas Industry Survey Results

7-7

Total Combustion Emissions

Table 7-10 lists the combustion emissions from equipment listed on both Tables 4 and 5 

of the Oil and Gas Industry Survey. It shows that the majority of the emissions are from 

external and internal combustion engines. Vapor recovery units, which include flares, 

thermal oxidizers, and incinerators, only account for 3 percent of the total combustion 

emissions from this sector. 

Table 7-10: Combustion Emissions by Combustion Type (Metric Tons/Year)

Type CO2 CH4 N2O CO2e

Percent of 

Total CO2e

External 7,988,827 3,328 121 8,096,089 49%

Internal 7,580,889 6,567 193 7,778,505 47%

Vapor Recovery 503,678 941 1 523,675 3%

Totals: 16,073,395 10,836 314 16,398,268

Table 7-11 lists the total combustion emissions by primary business type. This table 

shows that 88 percent of the emissions are from onshore crude production and the 

business type “other.” 

The business type “other” includes the following self-reported facility types:

•CNG compression and marketing,

•Cogeneration,

•Combined heat and power,

•Electricity generation,

•Portable heating, and

•Water disposal.

Table 7-11: Combustion Emissions by Primary Business (Metric Tons/Year)

Type CO2 CH4 N2O CO2e

Percent of 

Total CO2e

Onshore Crude Production 9,601,843 6,069 178 9,784,578 60%

Other 4,579,058 161 108 4,616,047 28%

Natural Gas Processing 832,060 2,173 6 879,601 5%

Crude Processing and Storage 334,290 580 2 346,952 2%

Natural Gas Storage 200,225 1,126 9 226,569 1%

Onshore Natural Gas Production 204,801 620 4 218,910 1%

PERP Equipment Owner 148,048 19 1 148,825 1%

Offshore Crude 101,521 78 4 104,272 1%

Crude Pipeline 71,548 9 3 72,515 0%

Totals: 16,073,395 10,836 314 16,398,268

Table 7-12 lists the total combustion emissions by fuel types. Natural gas accounts for 

99 percent of the total combustion emissions. Pipeline natural gas and associated gas 

are the top two of all the natural gas fuels.
Chapter 7 Final 2007 Oil and Gas Industry Survey Results

7-8

Table 7-12: Combustion Emissions by Fuel Type (Metric Tons/Year)

Type

Volume 

Combusted

(mscf or gal) CO2 CH4 N2O CO2e

Percent 

of Total 

CO2e

Pipeline Quality Gas 202,096,976 11,313,493 3,718 231 11,463,292 70%

Associated Gas 54,465,754 3,424,822 5,740 71 3,567,473 22%

Waste Gas 17,656,611 886,192 619 5 900,899 5%

Dry Gas 4,623,503 252,638 749 4 269,709 2%

Diesel 18,195,581 180,052 8 2 180,688 1%

Landfill Gas 332,047 14,007 0 0 14,014 0%

Propane 419,638 1,748 0 0 1,750 0%

Gasoline 47,081 433 0 0 435 0%

LPG 1,400 8 0 0 8 0%

Totals: 16,073,395 10,836 314 16,398,268
Chapter 8 Final 2007 Oil and Gas Industry Survey Results

8-1

Chapter 8 – Components

In the 2007 Oil and Gas Industry Survey, Table 6 asked for counts of components by 

service type. Service type was natural gas, light crude oil (API >20), and heavy crude 

oil (API <20). Facilities were asked to report counts of the following component types:

o Components 1 inch and above 

• Manual valves, flanges, connectors, open-ended lines, and threaded 

components; and

o Other components

• Pump seals, pressure relief valves, bursting discs, diaphragms, 

hatches, meters, polished rod stuffing boxes, sight glasses, loading 

arms, and dump lever arms.

Table 8-1 lists the number of components by service type that was reported. The 

service type “natural gas” includes dry gas, associated gas, and gas storage. This table 

shows that the total number of all components is fairly equally distributed throughout the 

three service types.

Table 8-1: Number of Components by Service Type

Type Natural Gas

Light Crude 

(API >20)

Heavy Crude 

(API <20) Total

Manual Valves 471,916 963,565 1,401,237 3,370,968

Connectors 1,006,166 633,749 370,274 1,037,533

Threaded Components 992,715 260,939 321,321 979,792

Flanges 348,579 244,296 531,380 2,157,844

Pump Seals 8,049 8,441 35,174 15,318

Pressure Relief Valves 16,754 7,293 5,670 45,540

Meters 8,997 3,327 4,820 27,661

Diaphragms 5,142 3,687 3,942 18,354

Hatches 5,043 2,410 3,614 12,273

Sight Glasses 2,983 1,825 2,740 7,548

Dump Lever Arm 2,963 995 9,608 7,251

Polished Rod Stuffing Boxes 1,925 515 1,337 4,815

Bursting Discs 1,354 1,543 1,114 16,790

Open-ended Lines 5,639 195 334 1,724

Loading Arms 547 137 175 1,018

Totals: 2,878,772 2,132,917 2,692,740 7,704,429

Emissions

Components are connections from which vapors could leak. Emissions from 

components are considered fugitive emissions because these connections are not 

designed to intentionally leak. CO2 and CH4 emissions are calculated using emission 

factors and total component counts and are detailed in Appendix B. The CO2 and CH4,

emissions are multiplied by their corresponding GWP numbers (1 for CO2 and 21 for 

CH4) to get the CO2e values.
Chapter 8 Final 2007 Oil and Gas Industry Survey Results

8-2

Table 8-2 lists the fugitive emissions by primary business type. The business type 

“other” includes the following self-reported facility types:

o CNG compression and marketing,

o Cogeneration,

o Combined heat and power,

o Electricity generation,

o Portable heating,

o Water disposal, and

o Vapor recovery services.

This table shows that the majority of the number of components and the total CO2e are 

from onshore crude production. This business type includes both oil and associated 

natural gas components. It accounts for 76 percent of the emissions and 82 percent of 

the number of components.

Table 8-2: Fugitive Emissions of Components by Primary Business Type

(Metric Tons/Year)

Type

Number of 

Units CO2 CH4 CO2e

Percent of 

Total CO2e

Onshore Crude 6,339,732 232 617 13,198 76%

Natural Gas Processing 738,279 8 69 1,457 8%

Onshore Natural Gas 195,062 1 34 712 4%

Crude Processing PD PD PD PD PD

Offshore Crude 231,733 7 28 604 3%

Natural Gas Storage 47,486 0 12 245 1%

Crude Pipeline 69,612 1 10 216 1%

Crude Storage 25,586 1 6 130 1%

Other PD PD PD PD PD

Totals: 7,704,429 256 811 17,283

Table 8-3 lists the fugitive emissions by service type. Natural gas components account 

for 40 percent of the CO2e emissions. The emissions are relatively evenly distributed 

among natural gas, heavy crude, and light crude service.

Table 8-3: Fugitive Emissions of Components by Service Type

(Metric Tons/Year)

Type

Number of 

Units CO2 CH4 CO2e

Percent of 

Total CO2e

Natural Gas 2,878,772 68 324 6,866 40%

Heavy Crude 2,692,740 160 263 5,680 33%

Light Crude 2,132,917 29 224 4,737 27%

Totals: 7,704,429 256 811 17,283

Table 8-4 lists the fugitive emissions by type of component. Connectors, manual valves, 

flanges, and threaded components account for 83 percent of the emissions. They also 

account for 98 percent of the total number of components.
Chapter 8 Final 2007 Oil and Gas Industry Survey Results

8-3

Table 8-4: Fugitive Emissions of Components by Type (Metric Tons/Year)

Type

Number of 

Units CO2 CH4 CO2e

Percent of 

Total CO2e

Connectors 3,370,968 44 239 5,063 29%

Manual Valves 1,037,533 44 152 3,234 19%

Flanges 979,792 99 141 3,057 18%

Threaded Components 2,157,844 37 142 3,008 17%

Pump Seals 15,318 8 50 1,060 6%

Polished Rod Stuffing Boxes 45,540 10 26 561 3%

Pressure Relief Valves 27,661 4 21 453 3%

Meters 18,354 3 13 274 2%

Hatches 12,273 2 8 180 1%

Sight Glasses 7,548 1 6 117 1%

Diaphragms 7,251 1 6 117 1%

Dump Lever Arm 4,815 1 3 68 0%

Open-ended Lines 16,790 1 2 47 0%

Bursting Discs 1,724 0 1 31 0%

Loading Arms 1,018 0 1 14 0%

Totals: 7,704,429 256 811 17,283

Tables 8-5 through 8-7 list the fugitive emissions by type of component and service 

type. 

Table 8-5: Fugitive Emissions of Natural Gas Components by Type

(Metric Tons/Year)

Type

Number of 

Units CO2 CH4 CO2e

Percent of 

Total CO2e

Manual Valves 471,916 21 81 1,720 25%

Connectors 1,006,166 15 59 1,263 18%

Threaded Components 992,715 9 58 1,237 18%

Flanges 348,579 9 48 1,014 15%

Pump Seals 8,049 6 42 893 13%

Pressure Relief Valves 16,754 2 13 267 4%

Meters 8,997 2 7 139 2%

Diaphragms 5,142 1 4 87 1%

Hatches 5,043 1 4 79 1%

Sight Glasses 2,983 0 2 50 1%

Dump Lever Arm 2,963 1 2 44 1%

Polished Rod Stuffing Boxes 1,925 0 1 30 0%

Bursting Discs 1,354 0 1 25 0%

Open-ended Lines 5,639 1 1 13 0%

Loading Arms 547 0 0 8 0%

Totals: 2,878,772 68 324 6,866
Chapter 8 Final 2007 Oil and Gas Industry Survey Results

8-4

Table 8-6: Fugitive Emissions of Light Crude1 Components by Type

(Metric Tons/Year)

Type

Number of 

Units CO2 CH4 CO2e

Percent of 

Total CO2e

Connectors 963,565 7 75 1,588 34%

Threaded Components 633,749 7 46 978 21%

Flanges 260,939 5 42 877 19%

Manual Valves 244,296 5 31 665 14%

Polished Rod Stuffing Boxes 8,441 1 8 159 3%

Pressure Relief Valves 7,293 1 7 151 3%

Pump Seals 3,327 1 6 123 3%

Meters 3,687 1 3 73 2%

Hatches 2,410 0 2 48 1%

Sight Glasses 1,825 0 2 36 1%

Diaphragms 995 0 1 18 0%

Dump Lever Arm 515 0 0 9 0%

Open-ended Lines 1,543 0 0 4 0%

Bursting Discs 195 0 0 4 0%

Loading Arms 137 0 0 2 0%

Totals: 2,132,917 29 224 4,737

1. Light Crude is crude oil with an API gravity greater than 20.

Table 8-7: Fugitive Emissions of Heavy Crude1 Components by Type

(Metric Tons/Year)

Type

Number of 

Units CO2 CH4 CO2e

Percent of 

Total CO2e

Connectors 1,401,237 22 104 2,212 39%

Flanges 370,274 85 51 1,166 21%

Manual Valves 321,321 18 40 849 15%

Threaded Components 531,380 21 37 794 14%

Polished Rod Stuffing Boxes 35,174 9 17 372 7%

Meters 5,670 1 3 62 1%

Hatches 4,820 1 3 53 1%

Pump Seals 3,942 1 2 43 1%

Pressure Relief Valves 3,614 1 2 35 1%

Sight Glasses 2,740 0 1 31 1%

Open-ended Lines 9,608 0 1 30 1%

Dump Lever Arm 1,337 0 1 14 0%

Diaphragms 1,114 0 1 12 0%

Loading Arms 334 0 0 4 0%

Bursting Discs 175 0 0 2 0%

Totals: 2,692,740 160 263 5,680

1. Heavy Crude is crude oil with an API gravity less than 20.
Chapter 9 Final 2007 Oil and Gas Industry Survey Results

9-1

Chapter 9 – Automated Control Devices

Table 7 of the 2007 Oil and Gas Industry Survey asked facilities to report the number of 

automated control devices. Automated control devices are also commonly referred to 

as pneumatic devices. Facilities were asked to report the following information about 

their automated control devices:

o Controllers 

• Gas, electric, or air actuated

• Continuous bleed, intermittent bleed, low bleed, or no bleed

• Number on gas recovery, and

o Actuators

• Gas, electric, or air actuated

• Piston valve, hydraulic valve, or turbine valve operator

• Number on gas recovery.

Emissions

Emissions from automated control devices are considered vented emissions as these 

devices are designed to leak. CO2 and CH4 emissions from automated control devices 

are calculated by multiplying the number of devices by an emission factor; those 

calculations are detailed in Appendix B. The number of each type of device used to 

calculate emissions is the total number of devices minus the number on gas recovery. 

Devices on gas recovery capture the gas used to actuate. The CO2 and CH4 emissions 

are multiplied by their corresponding GWP numbers (1 for CO2 and 21 for CH4) to get 

the CO2e values. 

Table 9-1 lists the vented emissions by primary business type. The business type 

“other” includes the following self-reported facility types:

o Cogeneration,

o Combined heat and power,

o Electricity generation,

o Portable heating,

o Water disposal, and

o Vapor recovery services.

This table shows that the majority of the vented emissions are from automated control 

devices found in onshore natural gas production facilities. However, these facilities 

account for only 3 percent of the total number of devices in California. Onshore crude 

oil production facilities have 79 percent of the number of automated control devices but 

account for only 4 percent of the emissions.
Chapter 9 Final 2007 Oil and Gas Industry Survey Results

9-2

Table 9-1: Vented Emissions of Automated Control Devices by Primary Business

Type (Metric Tons/Year)

Type

Number of 

Units CO2 CH4 CO2e

Percent of 

Total CO2e

Onshore Natural Gas 2,526 88 5,056 106,267 88%

Natural Gas Storage 2,585 2 380 7,984 7%

Onshore Crude 57,549 69 253 5,378 4%

Natural Gas Processing 832 1 36 764 1%

Offshore Crude 6,197 0 2 35 0%

Crude Storage PD PD PD PD PD

Crude Pipeline 2,517 0 0 0 0%

Crude Processing PD PD PD PD PD

Other 109 0 0 0 0%

Totals: 72,861 161 5,727 120,434

Table 9-2 lists the vented emissions by type of automated control device. This table 

also lists the total number of devices and the number on gas recovery. Several facilities 

listed electric and air controllers and actuators on gas recovery. We are assuming that 

controllers and actuators that are either air or electrically actuated do not have any 

emissions associated with them. Continuous bleed and intermittent bleed controllers 

account for 99 percent of the vented emissions from this category. However, they only 

account for 2 percent of the total number of devices.

Table 9-2: Vented Emissions of Automated Control Devices by Type

(Metric Tons/Year)

Type

Number 

of Units

Number 

on Gas 

Recovery CO2 CH4 CO2e

Percent 

of Total 

CO2e

Controllers

Continuous Bleed 1,151 2 89 4,915 103,298 86%

Intermittent Bleed 405 24 69 760 16,019 13%

Low Bleed 50 0 2 46 969 1%

No Bleed 1,054 0 0 0 0 0%

Electric Controller 6,391 384 0 0 0 0%

Air Controller 7,995 599 0 0 0 0%

Actuators

Piston Valve Operator 1,030 111 0 1 15 0%

Hydraulic Valve Operator 136 0 1 6 131 0%

Turbine Valve Operator 3 0 0 0 1 0%

Electric Actuator 6,205 18 0 0 0 0%

Air Actuator 48,441 643 0 0 0 0%

Totals: 72,861 1,781 161 5,727 120,434
Chapter 10 Final 2007 Oil and Gas Industry Survey Results

10-1

Chapter 10 – Inspection and Maintenance 

Many air districts in California require crude oil and natural gas facilities to routinely 

inspect their fugitive components. Table 8 of the 2007 Oil and Gas Industry Survey 

collected information about each facility’s inspection and maintenance program (I&M). 

The following information were requested:

o Whether or not the facility follows an I&M program;

o District rule number governing the I&M program; and

o Leak Threshold.

An I&M program is a routine that a facility follows to inspect components for vapor 

leaks. Many air districts require facilities to inspect their components a specific number 

of times per year. They will also designate a leak threshold to test against. A 

component leaking above the threshold or below the threshold will determine how long 

the facility has to repair the leak. Components with a higher leak rate generally must be 

repaired sooner than ones with a lower leak rate.

 

Of the 1,632 facilities that completed the survey, 602 have an I&M program, 566 do not 

have an I&M program, and 470 did not complete Table 9 of the survey. Table 10-1 lists 

the number of facilities utilizing each leak threshold. Many facilities have more than one 

leak threshold they test against depending on the type of component. Thus, the total 

number of facilities listed in Table 10-1 will add up to more than the total 602 facilities 

with an I&M program.

Table 10-1: Number of Facilities Utilizing Each Leak Threshold

Leak Threshold Number of Facilities

0 – 500 ppm 247

500 – 1,000 ppm 217

1,000 – 2,000 ppm 146

2,000 – 10,000 ppm 166

10,000 – 50,000 ppm 145

> 50,000 ppm 60

Chapter 11 Final 2007 Oil and Gas Industry Survey Results

11-1

Chapter 11 – Natural Gas Dehydrators

Natural gas dehydrators remove water from gas streams by passing natural gas through 

glycol or over a desiccant material. Table 9 of the 2007 Oil and Gas Industry Survey 

(Appendix A) collected process information about natural gas dehydrators. Facilities

were asked to report the following information:

o Type

• Glycol or dessicant

• Facilities could also specify a type not listed above;

o Average natural gas composition

• Percent CH4, H2S, CO2 for input and output streams

• Higher heating value (HHV) in btu for input and output streams;

o Input and output volume in standard cubic feet;

o Quantity of liquids removed in tons/year;

o For glycol units

• Circulation rate (gal/hr)

• Average flash tank pressure (psia)

• Average contactor pressure (psia)

• Whether a gas assisted pump, electric pump, stripping gas, or a flash 

separator was used;

o For desiccant units

• Volume of dehydrator (ft3

)

• Pressure (psig)

• Percent of packed vessel volume that is natural gas

• Frequency of desiccant replacement (days); and

o For all units’ vapor recovery system

• Type

 Flare, incinerator, collection system

 Facilities could also specify a type not listed above

• Control efficiency.

Emissions

Dehydrators have combustion, vented, and fugitive emissions. Combustion emissions 

were calculated from Table 5 of the 2007 Oil and Gas Industry Survey and are listed 

under “reboiler” emissions in Chapter 7 of this report. Vented and fugitive emissions are 

summarized here. 

There are two methods for calculating vented emissions from dehydrators and one 

method for calculating fugitive. The first venting method is for glycol units. It uses 

process information to calculate venting losses. The second venting method is for 

desiccant units. It calculates vented emissions based on replacement of the desiccant 

material. The third method calculates the fugitive emissions using a mass balance 

approach. Appendix B details the calculations for all three methods. The CO2 and CH4
Chapter 11 Final 2007 Oil and Gas Industry Survey Results

11-2

emissions are adjusted by the vapor recovery efficiency and then multiplied by their 

corresponding GWP numbers (1 for CO2 and 21 for CH4) to get the CO2e values.

Table 11-1 lists the vented emissions by type of dehydrator. Some equipment types 

were combined from what was listed on individual surveys to protect confidential 

company data and to aggregate similar pieces of equipment. Below is a list of 

equipment categories and the types they represent:

o Desiccant – desiccant and scrubber dehydrators; and

o Chiller – gas chiller, methanol chiller, low temperature separation, and 

refrigeration dehydrators.

Glycol dehydrators make up 85 percent of the dehydrators in California and are 

responsible for almost all the CO2e emissions.

 

Table 11-1: Vented Emissions of Natural Gas Dehydrators by Type

(Metric Tons/Year)

Type

Number of 

Units CO2 CH4 CO2e

Percent of 

Total CO2e

Glycol 261 308 10,829 227,719 100%

Desiccant 41 0.01 0.09 1.94 0%

Chiller 6 0.00 0.00 0.00 0%

Totals: 308 308 10,829 227,721

Table 11-2 lists the fugitive emissions by type of dehydrator. Again, glycol dehydrators 

emit the vast majority of the CO2e emissions reported in this survey.

Table 11-2: Fugitive Emissions of Natural Gas Dehydrators by Type

(Metric Tons/Year)

Type

Number of 

Units CO2 CH4 CO2e

Percent of 

Total CO2e

Glycol 261 16,682 10,802 243,517 96%

Chiller 6 0 534 11,224 4%

Desiccant 41 0 0 0 0%

Totals: 308 16,682 11,336 254,741

Table 11-3 lists the total input volume for each dehydrator type. This volume includes 

natural gas, water, and other impurities. As indicated, nearly the entire input volume is 

moved through glycol dehydrators.

Table 11-3: Volume of Natural Gas Dehydrators by Type

Type Volume (MSCF) Percent of Total 

Glycol 701,123,262 100%

Desiccant 1,338,428 0%

Chiller 1,119,742 0%

Totals: 703,581,432
Chapter 11 Final 2007 Oil and Gas Industry Survey Results

11-3

Table 11-4 lists the combustion, vented, and fugitive emissions from all natural gas 

dehydrators. The combustion emissions are from Table 5 of the 2007 Oil and Gas 

Industry Survey and were calculated using the methods detailed in Chapter 7 of this 

report. This table shows that vented and fugitive CO2e emissions make up the majority 

of the emissions from this category. 

Table 11-4: Total Emissions of Natural Gas Dehydrators (Metric Tons/Year)

Type CO2 CH4 N2O CO2e

Percent of 

Total CO2e

Combustion 14,093 14 0 14,406 3%

Vented 308 10,829 0 227,721 46%

Fugitive 16,682 11,336 0 254,741 51%

Totals: 31,083 22,180 0 496,868

Table 11-5 lists the number of dehydrators that have vapor recovery units. Less than 

50 percent of the glycol dehydrators have vapor recovery units. Overall, only 44 

percent of all the dehydrators reported in this survey have vapor recovery units. 

Table 11-5: Natural Gas Dehydrators Percent with Vapor Recovery

Type Number of Units

Number on Vapor 

Recovery

Type-Specific 

Percent on Vapor 

Recovery

Glycol 261 125 48%

Chiller 6 5 83%

Desiccant 41 5 12%

Totals: 308 135 44%

Table 11-6 lists the types of vapor recovery units used on dehydrators. Some vapor 

recovery types were combined from what was listed on individual surveys to protect 

confidential company data and to aggregate similar pieces of equipment. Below is a list 

of equipment categories and the types they represent:

o Flare – flares and emergency flares;

o Combustion Unit – burn lines, burners, reboilers, and turbines; and 

o Collection System – compressors, collection systems, and carbon 

adsorbers.

Table 11-6: Natural Gas Dehydrators Types of Vapor Recovery

Type Number of Units Percent of Total

None 173 56%

Collection System 77 25%

Combustion Unit 25 8%

Incinerator 17 6%

Flare 11 4%

Thermal Oxidizer 5 2%

Totals: 308

Chapter 12 Final 2007 Oil and Gas Industry Survey Results

12-1

Chapter 12 – Natural Gas Sweetening and Acid Gas Removal

Natural gas sweetening and acid gas removal units (AGR) remove sulfur and CO2 from 

the gas streams. Table 10 of the Oil and Gas Industry Survey collected process 

information about AGR units. Facilities were asked to report the following information:

o Type

• Solid and non-solid material (Specific types listed in Appendix A)

• Facilities could also specify a type not listed;

o Average natural gas composition

• Percent CH4, H2S, CO2 for input and output streams

• Higher heating value (HHV) in btu for input and output streams;

o Input and output volume in standard cubic feet;

o Quantity of liquids removed in tons/year;

o CO2 removal

• Total CO2 removed (tons/year)

• Amount vented (tons/year)

• Amount incinerated (tons/year)

• Amount captured (tons/year);

o For solid material units

• Volume of unit (ft3)

• Pressure (psig)

• Percent of packed vessel volume that is natural gas

• Frequency of material replacement (days); and

o For all units’ vapor recovery system

• Type

 Flare, incinerator, collection system

 Facilities could also specify a type not listed above

• Control efficiency.

Emissions

Natural gas sweetening and AGR units have combustion, vented, and fugitive 

emissions. Combustion emissions were calculated from Table 5 of the Oil and Gas 

Industry Survey and are listed under “reboiler” emissions in Chapter 7 of this report. 

Vented and fugitive emissions are summarized here. 

Vented emissions are only calculated for replacing the solid material in solid material 

AGR units. Fugitive emissions are calculated using a mass balance approach for both 

solid and non-solid material units. See Appendix B for detailed calculations. The CO2

and CH4 emissions are adjusted by the vapor recovery efficiency and then multiplied by 

their corresponding GWP numbers (1 for CO2 and 21 for CH4) to get the CO2e values.

Table 12-1 lists the vented emissions by type of AGR unit. These emissions contain the 

calculated vented emissions from solid material replacement as well as the reported 
Chapter 12 Final 2007 Oil and Gas Industry Survey Results

12-2

vented CO2 values. Some equipment types were combined from what was listed on 

individual surveys to protect confidential company data and to aggregate similar pieces 

of equipment. Below is a list of equipment categories and the types they represent:

o Sulfa – sulfa scrubs, sulfa treats, sulfurchecks, soluroxes, and sulfide 

scavengers; and

o Other – triazine, claus process, grace membrane, contactor, liquid redox, 

lo-cat, molecular gate.

This table shows that the majority of the vented CO2e emissions are from amine AGR 

units.

Table 12-1: Vented Emissions of Natural Gas AGR Units by Type

(Metric Tons/Year)

Type

Number of 

Units CO2 CH4 CO2e

Percent of 

Total CO2e

Amine 19 44,138 0 44,138 99%

Other 8 2 16 349 1%

Sulfa 38 19 3 72 0%

Totals: 65 44,160 19 44,559

Table 12-2 lists the fugitive emissions by type of AGR unit. As listed above for 

Table 12-1, the same categories were combined to protect confidential company data 

and to aggregate similar pieces of equipment. This table shows that fugitive emissions 

are more spread out among the three categories. Here, 65 percent of the fugitive CO2e 

emissions are from the “other” category. The remaining 35 percent is split between 

amine units and sulfa units.

Table 12-2: Fugitive Emissions of Natural Gas AGR Units by Type

(Metric Tons/Year)

Type

Number of 

Units CO2 CH4 CO2e

Percent of 

Total CO2e

Other 8 65,366 10,832 292,844 65%

Amine 19 57,294 1,575 90,373 20%

Sulfa 38 22,755 2,232 69,630 15%

Totals: 65 145,414 14,640 452,847

Table 12-3 lists the combustion, vented, and fugitive emissions from all natural gas 

AGR units. The combustion emissions are from Table 5 of the 2007 Oil and Gas 

Industry Survey and were calculated using the methods detailed in Chapter 7 of this 

report. This table shows that fugitive CO2e emissions make up the majority of the 

emissions from this category.
Chapter 12 Final 2007 Oil and Gas Industry Survey Results

12-3

Table 12-3: Total Emissions of Natural Gas AGR Units (Metric Tons/Year)

Type CO2 CH4 N2O CO2e

Percent of 

Total CO2e

Combustion 3,373 0 0 3,377 1%

Vented 44,160 19 0 44,559 9%

Fugitive 145,414 14,640 0 452,847 90%

Totals: 192,947 14,659 0 500,783

Table 12-4 lists the number of AGR units that have vapor recovery units. Overall, 75 

percent of all the AGR units in California have vapor recovery units. 

Table 12-4: Natural Gas AGR Units Percent on Vapor Recovery

Type Number of Units

Number on Vapor 

Recovery

Type-Specific 

Percent on Vapor 

Recovery

Amine 19 11 58%

Other 8 5 63%

Sulfa 38 33 87%

Totals: 65 49 75%

Table 12-5 lists the types of vapor recovery units used on AGR units. Some vapor 

recovery types were combined from what was listed on individual surveys to protect 

confidential company data and to aggregate similar pieces of equipment. Below is a list 

of equipment categories and the types they represent:

o Combustion Unit – boilers, heater/treaters, steam generators, and 

combustion equipment;

o Collection System – compressors and collection systems.

Table 12-5: Natural Gas AGR Units Types of Vapor Recovery

Type Number of Units Percent of Total

Collection System 30 46%

None 16 25%

Combustion Unit 10 15%

Flare PD PD

Incinerator PD PD

Thermal Oxidizer PD PD

Totals: 65

Chapter 13 Final 2007 Oil and Gas Industry Survey Results

13-1

Chapter 13 – Other Natural Gas Processing 

Other natural gas processing includes all other units that process natural gas but are 

not dehydrators (Chapter 10) or AGR units (Chapter 11). Table 11 of the Oil and Gas 

Industry Survey collected information about these units. The following information was 

requested from each facility:

o Type

• Fractionation, nitrogen removal, mercury removal

• Facilities could list a type not listed above;

o Average natural gas composition

• Percent CH4, H2S, CO2 for input and output streams

• Higher heating value (HHV) in btu for input and output streams;

o Input and output volume in standard cubic feet;

o Quantity of liquids removed in tons/year; and

o For all units’ vapor recovery system

• Type

 Flare, incinerator, collection system

 Facilities could also specify a type not listed above

• Control efficiency.

Emissions

Emissions of CO2 and CH4 from natural gas processing units are calculated using a 

mass balance approach. This calculation is detailed in Appendix B. Because a mass 

balance approach calculates the total vapor loss, determining whether they are vented 

emissions or fugitive emissions or both is not possible. Thus, emissions from these 

units are categorized as fugitive. The CO2 and CH4 emissions are adjusted by the 

vapor recovery efficiency and then multiplied by their corresponding GWP numbers (1 

for CO2 and 21 for CH4) to get the CO2e values.

Table 13-1 lists the emissions of the natural gas processing units by type. This table 

shows that almost all the emissions from this category come from fractionation units. 

Table 13-1: Emissions of Other Natural Gas Processing Units by Type

(Metric Tons/Year)

Type

Number 

of Units CO2 CH4 CO2e

Percent of 

Total CO2e

Fractionation 5 104,457 12,096 358,472 100%

Liquefied Petroleum Gas Extraction PD PD PD PD PD

Denitrification PD PD PD PD PD

Scrubber PD PD PD PD PD

Totals: 14 104,457 12,099 358,528

Table 13-2 lists the number of natural gas processing units with vapor recovery by type 

of unit. This table shows that nearly all fractionation units have vapor recovery and that,
Chapter 13 Final 2007 Oil and Gas Industry Survey Results

13-2

overall, 93 percent of the natural gas processing units have vapor recovery. Collection 

systems and flares are used as vapor recovery for these natural gas processing units.

Table 13-2: Other Natural Gas Processing Units Percent on Vapor Recovery

Type Number of Units

Number on Vapor 

Recovery

Type-Specific 

Percent on Vapor 

Recovery

Fractionation 5 5 100%

LPG Extraction PD PD PD

Scrubber PD PD PD

Denitrification PD PD PD

Totals: 14 13 93%
Chapter 14 Final 2007 Oil and Gas Industry Survey Results

14-1

Chapter 14 – Total Natural Gas Processing Emissions 

This chapter combines the emissions from the various natural gas processing 

equipment discussed in previous chapters. This includes dehydrators (Chapter 11), 

natural gas sweetening and acid gas removal units (Chapter 12), and other natural gas 

processing (Chapter 13). 

Table 14-1 lists the total California emissions from natural gas processing. As shown, 

fugitive emissions account for 79 percent of the total emissions from this category. 

Table 14-1: Total California Emissions (Metric Tons/Year)

Type CO2 CH4 N2O CO2e

Percent of 

Total CO2e

Combustion 17,465 0 0 17,482 1%

Vented 44,467 10,848 0 272,280 20%

Fugitive 266,554 38,074 0 1,066,116 79%

Totals: 328,487 48,923 0 1,355,878

Table 14-2 lists the total natural gas processing emissions by type. This table shows 

that all three major types of natural gas processing contribute almost equally to the total 

emissions from this category.

Table 14-2: Natural Gas Processing Emissions by Type (Metric Tons/Year)

Type CO2 CH4 N2O CO2e

Percent of 

Total CO2e

Dehydration 31,083 22,166 0 496,567 37%

Sweetening/Acid Gas Removal 192,947 14,659 0 500,783 37%

Other Processing 104,457 12,099 0 358,528 26%

Totals: 328,487 48,923 0 1,355,878

Chapter 15 Final 2007 Oil and Gas Industry Survey Results

15-1

Chapter 15 – Natural Gas Compressors 

Natural gas compressors compress natural gas to higher pressures and lower volumes. 

Table 12 of the 2007 Oil and Gas Industry Survey required facilities to provide the 

following information about their compressors:

o Type

• Centrifugal, reciprocating, rotary

• Facilities could specify a type not listed above;

o For centrifugal

• Number of wet seals and dry seals;

o For reciprocating

• Number of cylinders;

o Primary driver type

• Electric, turbine, piston engine, or integral;

o Starter type

• Natural gas expansion, instrument air expansion, electric, or hydraulic

• Facilities could specify a type not listed above;

o Manufacturer;

o Model year;

o Annual usage (hours);

o Inspection frequency;

o Maintenance frequency;

o Discharge pressure (psia);

o Discharge temperature (°F);

o Idle pressure (psia);

o For blowdowns

• Number

• Volume of natural gas vented, flared, or recovered; and

o For startups

• Number

• Volume of natural gas vented, flared, or recovered.

Table 15-1 lists the number of compressors by type. Some compressor types were 

combined from what was listed on individual surveys to protect confidential company 

data and to aggregate similar pieces of equipment. The compressor type “rotary” 

contain the types rotary, rotary vane, screw, and vane.

Table 15-1: Number of Compressors by Type

Type

Number of 

Compressors

Centrifugal 47

Reciprocating 911

Rotary 97

Unknown 16

Totals: 1,071
Chapter 15 Final 2007 Oil and Gas Industry Survey Results

15-2

Figure 15-1: Reciprocating Compressor

Figures 15-1 through 15-3 shows the compression 

chambers for each type of compressor.

Reciprocating compressors increase the pressure 

of natural gas by positive displacement, employing 

linear movement of a shaft driving a piston in a 

cylinder. 

Figure 15-2: Centrifugal Compressor

Centrifugal compressors increase the 

pressure of natural gas by centrifugal 

action, employing rotating movement of the 

drive shaft.

Rotary and screw compressors have blades 

or a cylinder that rotate off center to 

compress the natural gas. 

Figure 15-3: Rotary Compressor
Chapter 15 Final 2007 Oil and Gas Industry Survey Results

15-3

Each compressor type can have a different driver, which is the engine that drives the 

compressor. The driver could be electric, turbine, piston engine, or integral. Integral 

compressors are unique in that the compressor is integrated into the engine design. 

Essentially the two cannot be separated. Table 15-2 lists the number of compressors 

by type of compressor and primary driver.

Table 15-2: Number of Primary Drivers by Type

Type Electric Integral Piston Engine Turbine Total

Centrifugal 18 PD 24 PD 47

Reciprocating 313 PD 516 PD 911

Rotary 83 PD 14 PD 97

Unknown 16 PD 0 PD 16

Totals: 430 PD 554 PD 1,071

Compressor starters also vary across the different types of compressors. Some natural 

gas compressor starters use natural gas expansion. These starters use high-pressure 

natural gas expanded across the starter to initiate the startup of the engine. The gas is 

then either vented to the atmosphere or recovered back into the sales line or routed to a 

flare. Table 15-3 lists the number of compressors by type of compressor and starters.

Table 15-3: Number of Starters by Type

Type Electric

Gas Expansion -

Instrument Air

Gas Expansion -

Natural Gas Total

Centrifugal 20 0 27 47

Reciprocating 367 52 492 911

Rotary 86 PD PD 97

Unknown 16 PD PD 16

Totals: 489 54 528 1,071

Compressor blowdowns are the depressurization of the compressor. The natural gas in 

the compressor chamber is either vented to atmosphere, flared, or recovered and piped 

back into the system. Table 15-4 lists the volumes of natural gas that are flared, 

recovered, or vented for both compressor blowdowns and natural gas expansion 

startups. 

Table 15-4: Startup and Blowdown Volumes

Type

Flared 

(mcsf)

Recovered 

(mscf)

Vented 

(mscf)

Startup 821 42 4,196

Blowdown 9,835 26,246 189,062

Totals: 10,657 26,288 193,259

Emissions

Natural gas compressors have combustion, vented, and fugitive emissions. 

Combustion emissions were calculated from Table 5 of the 2007 Oil and Gas Industry 

Survey. They are included with the types of internal combustion engines listed in 

Chapter 7 of this report. Vented and fugitive emissions are calculated here.
Chapter 15 Final 2007 Oil and Gas Industry Survey Results

15-4

Vented emissions are calculated from the volumes of gas released from startups and 

blowdowns. Fugitive emissions are calculated from the number and type of compressor 

seals, the hours of operation and seal-specific emission factors. These calculations are 

detailed in Appendix B. The CO2 and CH4, emissions are multiplied by their 

corresponding GWP numbers (1 for CO2 and 21 for CH4) to get the CO2e values.

Table 15-5 lists the vented emissions from natural gas compressor startups, and 

Table 15-6 lists the vented emissions from blowdowns. The majority of the emissions 

come from reciprocating compressors. The compressor type “unknown” encompasses 

survey responses where “other” was checked but the type was not specified.

Table 15-5: Natural Gas Compressor Startup Vented Emissions (Metric Tons/Year)

Type CO2 CH4 CO2e

Percent of 

Total CO2e

Reciprocating 4 68 1,438 98%

Rotary 0.08 0.87 18 1%

Centrifugal 0.01 0.26 6 0%

Unknown 0 0 0 0%

Totals: 4 69 1,462

Table 15-6: Natural Gas Compressor Blowdown Vented Emissions

(Metric Tons/Year)

Type CO2 CH4 CO2e

Percent of 

Total CO2e

Reciprocating 170 3,210 67,578 99%

Centrifugal 0 17 358 1%

Rotary 1 11 229 0%

Unknown 0 0 0 0%

Totals: 172 3,238 68,165

Table 15-7 lists the fugitive emissions from compressor seals. Again, reciprocating 

compressors account for the majority of the CO2e emissions for this category.

Table 15-7: Natural Gas Compressor Fugitive Seal Emissions (Metric Tons/Year)

Type CO2 CH4 CO2e

Percent of 

Total CO2e

Reciprocating 1,797 16,871 356,096 95%

Rotary 200 451 9,661 3%

Centrifugal 28 357 7,517 2%

Unknown 0 0 0 0%

Totals: 2,025 17,679 373,274

Table 15-8 lists the combustion, vented, and fugitive emissions from all natural gas 

compressor units. The combustion emissions are from Table 5 of the Oil and Gas 

Industry Survey (Appendix A) and are categorized under internal combustion engines 

and turbines in Chapter 7 of this report. This table shows that combustion CO2e 

emissions make up the majority of the emissions from this category while fugitive CO2e 

account for the majority of the remaining 34 percent.
Chapter 15 Final 2007 Oil and Gas Industry Survey Results

15-5

Table 15-8: Total Emissions of Natural Gas Compressors (Metric Tons/Year)

Type CO2 CH4 N2O CO2e

Percent of 

Total CO2e

Combustion 782,515 4,210 19 876,891 66%

Vented 176 3,307 0 69,627 5%

Fugitive 2,025 17,679 0 373,274 28%

Totals: 784,716 25,196 19 1,319,792

Table 15-9 shows the total compressor emissions by primary business type. These 

numbers include combustion, vented, and fugitive emissions. The business type “other” 

includes the following self-reported facility types:

o CNG compression and marketing,

o Cogeneration,

o Combined heat and power,

o Electricity generation,

o Portable heating ,

o Water disposal, and

o Vapor recovery services.

Table 15-9: Compressor Emissions by Primary Business (Metric Tons/Year)

Type CO2 CH4 N2O CO2e

Percent of 

Total CO2e

Onshore Natural Gas 186,766 9,960 3 396,957 30%

Natural Gas Processing 289,705 4,449 5 384,674 29%

Natural Gas Storage 188,601 5,002 9 296,357 22%

Onshore Crude 116,310 4,506 2 211,517 16%

Offshore Crude 179 793 0 16,915 1%

PERP Equipment Owner PD PD PD PD PD

Crude Processing PD PD PD PD PD

Crude Pipeline PD PD PD PD PD

Other PD PD PD PD PD

Totals: 784,716 25,196 19 1,319,792

Table 15-10 lists the total compressor emissions by type of compressor. Reciprocating 

compressors account for 89 percent of the total CO2e emissions as well as 85 percent 

of the total number of compressors.

Table 15-10: Total Emissions of Natural Gas Compressors by Type

(Metric Tons/Year)

Type

Number 

of Units CO2 CH4 N2O CO2e

Percent of 

Total CO2e

Reciprocating 911 664,407 24,168 13 1,176,006 89%

Centrifugal 47 110,038 535 6 123,155 9%

Rotary 97 10,272 492 0 20,631 2%

Unknown 16 0 0 0 0 0%

Totals: 1,071 784,716 25,196 19 1,319,792
Chapter 15 Final 2007 Oil and Gas Industry Survey Results

15-6

Table 15-11 lists the total compressor emissions by type of primary driver. Piston 

engines and integral compressors account for 85 percent of total CO2e emissions. 

Table 15-11: Total Emissions of Natural Gas Compressors by Primary Driver

(Metric Tons/Year)

Type

Number 

of Units CO2 CH4 N2O CO2e

Percent of 

Total CO2e

Piston Engine 554 414,579 15,200 6 735,647 56%

Integral 81 281,453 4,687 7 382,146 29%

Electric 430 1,154 5,164 0 109,591 8%

Turbine 6 87,530 145 6 92,408 7%

Totals: 1,071 784,716 25,196 19 1,319,792

Table 15-12 lists the total compressor emissions by type and age of the compressor. 

Sixty percent of the total emissions from this category are from reciprocating 

compressors that are over 30 years old or for which the age is unknown. 

Table 15-12: Total Emissions of Natural Gas Compressors by Age

(Metric Tons/Year)

Age

Number 

of Units CO2 CH4 N2O CO2e

Percent of 

Total CO2e

Reciprocating

Unknown 403 124,541 10,093 2 337,201 26%

< 5 Years 70 82,080 1,773 1 119,592 9%

5 - 10 Years 61 53,533 2,040 1 96,708 7%

10 - 20 Years 43 33,173 986 0 53,991 4%

20 - 30 Years 131 57,271 2,899 2 118,655 9%

> 30 Years 203 313,809 6,379 7 449,859 34%

Centrifugal

Unknown 9 206 149 0 3,335 0%

< 5 Years PD PD PD PD PD PD

5 - 10 Years 0 0 0 0 0 0%

10 - 20 Years 16 8,407 155 0 11,713 1%

20 - 30 Years PD PD PD PD PD PD

> 30 Years PD PD PD PD PD PD

Rotary

Unknown 44 3,082 255 0 8,451 1%

< 5 Years 34 6,856 41 0 7,733 1%

5 - 10 Years PD PD PD PD PD PD

10 - 20 Years 6 77 29 0 679 0%

20 - 30 Years 8 16 165 0 3,491 0%

> 30 Years PD PD PD PD PD PD

Unknown

Unknown 16 0 0 0 0 0%

Totals: 1,071 784,716 25,196 19 1,319,792
Chapter 15 Final 2007 Oil and Gas Industry Survey Results

15-7

Table 15-3 lists the total number of hours and the average daily usage for each 

compressor type. This table shows that reciprocating compressors account for the 

majority of the hours of use.

Table 15-13: Usage of Natural Gas Compressors by Age

Age

Number 

of Units Total 

Hours

Average 

Daily 

Hours

Reciprocating

Unknown 403 2,400,079 16

< 5 Years 70 399,935 16

5 - 10 Years 61 296,475 13

10 - 20 Years 43 292,492 19

20 - 30 Years 131 773,125 16

> 30 Years 203 1,155,998 16

Subtotals: 911 5,318,104 16

Centrifugal

Unknown 9 71,430 22

< 5 Years PD PD PD

5 - 10 Years 0 0 0

10 - 20 Years 16 69,074 12

20 - 30 Years PD PD PD

> 30 Years PD PD PD

Subtotals: 47 280,131 16

Rotary

Unknown 44 299,080 19

< 5 Years 34 256,124 21

5 - 10 Years PD PD PD

10 - 20 Years 6 51,943 24

20 - 30 Years 8 61,320 21

> 30 Years PD PD PD

Subtotals: 97 682,396 19

Unknown

Unknown 16 140,160 24

Subtotals: 16 140,160 24

Totals: 1,062 6,349,360 16

Chapter 16 Final 2007 Oil and Gas Industry Survey Results

16-1

Chapter 16 –Pipeline Pigging and Natural Gas Gathering Pipelines

Pipelines are used to transport crude oil and natural gas around the facility and 

throughout the state. This chapter only includes information about natural gas gathering 

system pipelines and pipeline pigging operations for both crude oil and natural gas. It 

does not include natural gas transmission or distribution pipelines. Table 13 of the 2007

Oil and Gas Industry Survey required facilities to provide the following information about 

their pipelines:

o Length of natural gas gathering system pipelines;

o Maintenance activities for natural gas gathering system pipelines; 

• Type and volume of natural gas vented, flared, or recovered; and

o Pigging operations

• Number of crude oil and natural gas launchers and receivers 

• Number of types each launcher and receiver was opened

• If launcher or receiver was purged with inert gas prior to being opened.

Pipelines in a natural gas gathering system are pipes of various sizes that move natural 

gas around the facility. They move the natural gas to combustion units, gas processing 

units, or to compressors to be put into transmission lines. Table 16-1 lists the number 

of miles of natural gas gathering system pipelines by primary business type. The 

business type “other” includes the following self-reported facility types:

o CNG compression and marketing,

o Cogeneration,

o Combined heat and power,

o Electricity generation,

o Portable heating ,

o Water disposal, and 

o Vapor recovery services.

Table 16-1: Miles of Natural Gas Gathering System Pipelines by 

Primary Business Type

Primary Business

Miles of Natural Gas 

Gathering System Pipeline

Natural Gas Processing 1,124

Onshore Natural Gas 626

Onshore Crude 321

Natural Gas Storage 169

Offshore Crude 54

Crude Processing PD

Other PD

Totals: 2,295
Chapter 16 Final 2007 Oil and Gas Industry Survey Results

16-2

Maintenance activities of these natural gas gathering systems encompass repairs or 

improvements that are done to the pipelines. These activities often result in natural gas 

being vented to the atmosphere. Table 16-2 lists the volumes of natural gas that were 

vented, recovered, or flared due to pipeline maintenance activities.

Table 16-2: Natural Gas Gathering System Pipeline Maintenance Activity Volumes

Type

Flared 

(mscf)

Recovered 

(mscf)

Vented 

(mscf)

Pipeline Gas 2,002 628,149 3,962

Associated Gas 349,193 1,379,138 180,340

Dry Gas 1,902 2,367,936 75

Totals: 353,097 4,375,223 184,377

Pigging refers to sending a device (a “pig”) through a pipeline to clean it. Pigging is 

used in both crude oil and natural gas pipelines. The natural gas pig launchers and 

receivers are pressurized with natural gas. This gas is either purged with an inert gas 

prior to opening, or the gas is vented to atmosphere. Table 16-3 lists the number of pig 

launchers/receivers and the number of openings.

Table 16-3: Pigging Operations

Type

Number of 

Launchers/Receivers

Number of 

Openings

Crude Oil 786 989

Natural Gas 146 1,417

Totals: 932 2,406

Emissions

Vented emissions are calculated from the amount of gas vented from natural gas 

gathering system maintenance activities, and the number of natural gas pigging 

operations. These are multiplied with an emission factor to yield emission estimates. 

No emission factor is available for crude oil pigging. Fugitive emissions are calculated 

from the miles of natural gas pipeline and an emission factor. These calculations are 

detailed in Appendix B. The CO2 and CH4 emissions are multiplied by their 

corresponding GWP numbers (1 for CO2 and 21 for CH4) to get the CO2e values.

Table 16-4 lists the vented emissions from the natural gas gathering system 

maintenance activities and natural gas pigging operations. As shown, pipeline 

maintenance activities account for almost all of the vented emissions from pipelines. 

Table 16-4: Natural Gas Vented Emissions from Gathering Pipeline Maintenance 

and Pigging Operations (Metric Tons/Year)

Type CO2 CH4 CO2e

Percent of 

Total CO2e

Natural Gas Pipelines 2,659 2,490 54,940 100%

Natural Gas Pigging 104 5 211 0%

Totals: 2,763 2,495 55,151
Chapter 16 Final 2007 Oil and Gas Industry Survey Results

16-3

Table 16-5 lists the fugitive emissions from natural gas pipelines. 

Table 16-5: Natural Gas Fugitive Emissions from Gathering Pipelines

(Metric Tons/Year)

Type CO2 CH4 CO2e

Percent of 

Total CO2e

Natural Gas Pipelines 327 867 18,541 100%

Totals: 327 867 18,541

Chapter 17 Final 2007 Oil and Gas Industry Survey Results

17-1

Chapter 17 – Separators

Separators are used to split the fluids that come out of a well. In crude oil fields, this 

fluid can be made of crude oil, natural gas, water, and other contaminants. In natural 

gas fields, this fluid can contain natural gas, water, and other contaminants. Table 14 of 

the 2007 Oil and Gas Industry Survey gathered information about separators. Facilities 

were required to submit the following information about their separators:

o Type

• Free water knockout, heater/treater, horizontal separator, vertical 

separator, flow splitter, wemco, emulsion treater, or condensate tank

• Facilities could also specify a type not listed above;

o Subtype

• Bolted or welded;

o Size;

o Number of degassing events;

o Throughput in barrels crude oil per year or scf of natural gas per year;

o Crude oil API;

o Reactive organic gas (ROG) and total organic gas (TOG) emissions in 

tons/year

• For working, breathing, and flashing losses

• Average concentration of CH4 and CO2 in the vapor losses;

o Whether the separator had an access hatch or pressure relief valve

• Were they counted in the components from Table 6 of the 2007 Oil and 

Gas Industry Survey;

o Vapor recovery system type

• Flare, incinerator, collection system, or none

• Facilities could also specify a type not listed above; and

o Vapor recovery system control efficiency.

Table 17-1 lists the number of separators by primary business type. The business type 

“crude processing” and “crude pipeline” were combined to protect confidential company 

data. 

Table 17-1: Number of Separators by Primary Business Type

Primary Business Number of Separators

Onshore Crude 3,228

Onshore Natural Gas 891

Natural Gas Processing 379

Natural Gas Storage 75

Offshore Crude 40

Crude Processing and Pipeline 5

Totals: 4,618
Chapter 17 Final 2007 Oil and Gas Industry Survey Results

17-2

Emissions

Vented emissions are calculated from separator degassing events. This is where the 

separator is completely emptied of fluids and opened to atmosphere for cleaning or 

repair. Fugitive emissions are calculated from the total organic gas emissions from 

working, breathing, and flashing losses and the head space vapor concentrations. 

These equations are detailed in Appendix B. The CO2 and CH4 emissions are adjusted 

by the vapor recovery efficiency and then multiplied by their corresponding GWP 

numbers (1 for CO2 and 21 for CH4) to get the CO2e values.

Table 17-2 lists the total vented and fugitive emissions from separators as reported in 

the survey. As shown, almost all of the emissions are fugitive. 

Table 17-2: Total Emissions of Separators (Metric Tons/Year)

Type CO2 CH4 CO2e

Percent of 

Total CO2e

Vented 0 1 24 1%

Fugitive 11 170 3,578 99%

Totals: 11 171 3,602

Table 17-3 lists the fugitive emissions by type of separator. For approximately 90 

percent of the separators reported, a value for ROG or TOG was not reported. Thus, 

emissions from separators are most likely underestimated. Ongoing source testing may 

improve emissions estimates and will be incorporated in the final draft of this report. 

Some separator types were combined from what was listed on individual surveys to 

protect confidential company data and to aggregate similar equipment uses. Appendix 

E lists the categories and the types they represent. 

Table 17-3: Fugitive Emissions of Separators by Type (Metric Tons/Year)

Type

Number of 

Units CO2 CH4 CO2e

Percent of 

Total CO2e

Separator 715 0 68 1,435 40%

Shipping Tank 88 5 54 1,139 32%

Wash Tank 188 1 15 319 9%

Vertical Separator 604 1 14 288 8%

Produced Water Tank 130 1 8 160 4%

Crude Oil Separator 37 1 7 140 4%

Wemco 65 0 3 61 2%

Free Water Knockout 297 0 1 19 1%

Settling tanks 10 0 0 7 0%

Heater/Treater 309 0 0 5 0%

Stage Separator 88 0 0 2 0%

Horizontal Separator 1,046 0 0 1 0%

Condensate tank 81 0 0 0 0%

Gas Separator 102 0 0 0 0%

Surge Tank 9 0 0 0 0%

Scrubber 257 0 0 0 0%

Trap Separator 90 0 0 0 0%

Well Tester 502 0 0 0 0%

Totals: 4,618 11 170 3,578
Chapter 17 Final 2007 Oil and Gas Industry Survey Results

17-3

Seventy-two percent of the emissions come from the categories “separator” and 

“shipping tank”. The majority of separators in the category “separator” were not 

reported by a specific type. Shipping tanks are tanks that should have been listed on 

Table 16 of the 2007 Oil and Gas Industry Survey but were instead listed on Table 15. 

Table 17-4 lists the fugitive emissions by subtype of separator. Bolted separators 

account for 57 percent of the emissions but only 12 percent of the total number. The

subtype “unknown” is the next largest contributor to the total fugitive emissions. 

Table 17-4: Fugitive Emissions of Separators by Subtype (Metric Tons/Year)

Type

Number of 

Units CO2 CH4 CO2e

Percent of 

Total CO2e

Bolted 537 9 97 2,044 57%

Unknown 2,062 1 68 1,423 40%

Welded 1,999 0 5 111 3%

Both PD PD PD PD PD

None PD PD PD PD PD

Poly PD PD PD PD PD

Riveted PD PD PD PD PD

Totals: 4,618 11 170 3,578

Table 17-5 lists the number of separator units with vapor recovery by type of separator. 

This table shows that, overall, 70 percent of separators have vapor recovery.

Table 17-5: Separator Units by Type Percent on Vapor Recovery

Type Number of Units

Number on Vapor 

Recovery

Percent on Vapor 

Recovery

Scrubber 257 257 100%

Settling tanks 10 10 100%

Well Tester 502 500 100%

Surge Tank 9 8 89%

Stage Separator 88 78 89%

Gas Separator 102 90 88%

Wemco 65 56 86%

Trap Separator 90 74 82%

Horizontal Separator 1,046 819 78%

Free Water Knockout 297 209 70%

Condensate tank 81 52 64%

Heater/Treater 309 196 63%

Crude Oil Separator 37 23 62%

Vertical Separator 604 325 54%

Produced Water Tank 130 68 52%

Shipping Tank 88 43 49%

Separator 715 349 49%

Wash Tank 188 66 35%

Totals: 4,618 3,223 70%

Table 17-6 lists the number of separator units with vapor recovery by subtype of 

separator. For both the welded and bolted subtype, about 50 percent have vapor 
Chapter 17 Final 2007 Oil and Gas Industry Survey Results

17-4

recovery. The subtype “unknown” has 96 percent with vapor recovery. The 

percentages for the remaining subtypes are not shown due to protected data. 

Table 17-6: Separator Units by Subtype Percent with Vapor Recovery

Type Number of Units

Number with

Vapor Recovery

Percent with 

Vapor Recovery

Unknown 2,062 1,975 96%

Bolted 537 275 51%

Welded 1,999 966 48%

Both PD PD PD

Riveted PD PD PD

None PD PD PD

Poly PD PD PD

Totals: 4,618 3,223 70%

Table 17-7 lists the types of vapor recovery units used on separators. Some vapor 

recovery types were combined from what was listed on individual surveys to protect 

confidential company data and to aggregate similar pieces of equipment. Below is a list 

of equipment categories and the types they represent:

o Flare – flares, flares/collection systems, flares/collection 

systems/combustion equipment;

o Combustion Unit – steam generators, pump engines, oil heaters, gas 

plants, and boilers; and

o Collection System – compressors, collection systems, disposal wells, 

pressure vessels, fuel gas systems, and carbon adsorbers.

This table shows that 65 percent of the total number of separators uses a collection 

system for vapor recovery. Four percent send the vapors directly to a flare, incinerator, 

or combustion unit. The remaining 30 percent have no vapor recovery unit.

Table 17-7: Separator Units by Types of Vapor Recovery

Type Number of Units Percent of Total

Collection System 3,019 65%

None 1,405 30%

Flare 105 2%

Incinerator 55 1%

Combustion Unit 34 1%

Totals: 4,618
Chapter 18 Final 2007 Oil and Gas Industry Survey Results

18-1

Chapter 18 – Crude Oil Sumps and Pits

Crude oil sumps and pits are open pits that are used for oil/water separation or for 

emergency containment. Table 15 of the 2007 Oil and Gas Industry Survey gathered 

information about sumps and pits. Facilities were required to submit the following 

information about their sump/pits:

o Level

• Primary, secondary, tertiary;

o Crude oil API;

o Number of days in use;

o Dimensions

• Area and depth;

o Vapor recovery system type

• Flare, incinerator, collection system, cover, or none

• Facilities could also specify a type not listed above; and

o Vapor recovery system control efficiency.

Primary sumps/pits contain crude oil emulsions straight from the well. The liquids have 

not gone through any separation. Secondary sumps/pits contain emulsions that have 

gone through separation and thus contain mostly water and very little crude oil. Tertiary 

sumps/pits are primarily water.

Emissions 

Fugitive emissions from sumps/pits are calculated using emission factors based on the 

type, area, and the days of use of the sump. These equations are detailed in 

Appendix B. The CO2 and CH4 emissions are adjusted by the vapor recovery efficiency 

and then multiplied by their corresponding GWP numbers (1 for CO2 and 21 for CH4) to 

get the CO2e values.

Table 18-1 lists the fugitive emissions by type of sump/pit. About half the emissions are 

from primary sumps/pits. The remaining half is split between secondary and tertiary 

sumps/pits.

 

Table 18-1: Fugitive Emissions of Sumps/Pits by Type (Metric Tons/Year)

Type

Number of 

Sumps CH4 CO2e

Percent of 

Total CO2e

Primary 62 128 2,678 48%

Secondary 94 80 1,674 30%

Tertiary 94 57 1,200 22%

Totals: 250 264 5,552

Table 18-2 lists the fugitive emissions by type of sump/pit for each air district. Only 

seven air districts contain sump/pits. Most of the CO2e emissions from sumps/pits are 

in the San Joaquin Valley and Santa Barbara County air districts.
Chapter 18 Final 2007 Oil and Gas Industry Survey Results

18-2

Table 18-2: Fugitive Emissions of Sumps/Pits by Air District (Metric Tons/Year)

Air District Type

Number of 

Sumps CH4 CO2e

Bay Area AQMD Secondary PD PD PD

Monterey Bay Unified APCD Secondary PD PD PD

Santa Barbara County APCD

Primary 36 76 1,587

Secondary 29 39 826

Tertiary 15 2 40

South Coast AQMD

Primary PD PD PD

Secondary 27 1 18

Tertiary 34 0 5

San Joaquin Valley APCD

Primary 14 46 971

Secondary 18 18 372

Tertiary 30 55 1,151

San Luis Obispo County APCD Tertiary PD PD PD

Ventura County APCD

Primary PD PD PD

Secondary 17 5 100

Tertiary 14 0 4

Totals: 250 264 5,552

Table 18-3 lists the number of sumps/pits with vapor recovery. Less than 20 percent of 

the primary sumps/pits have vapor recovery. Overall, only 50 percent of all sumps/pits 

have vapor recovery. 

Table 18-3: Sumps/Pits by Percent on Vapor Recovery

Type Number of Units

Number on Vapor 

Recovery

Percent on Vapor 

Recovery

Primary 62 12 19%

Secondary 88 75 80%

Tertiary 94 38 40%

Totals: 250 125 50%

Table 18-4 lists the types of vapor recovery used on sumps/pits. Some vapor recovery 

types were combined from what was listed on individual surveys to protect confidential 

company data and to aggregate similar pieces of equipment. Below is a list of 

equipment categories and the types they represent:

o Collection System – compressors, collection systems, tanks, and carbon 

adsorbers; and

o Cover – covers, covers and pressure relief devices, and covers and 

activated carbon.

This table shows most of the sumps/pits that have vapor recovery use either a cover or 

a collection system. The remaining sumps/pits have no vapor recovery.
Chapter 18 Final 2007 Oil and Gas Industry Survey Results

18-3

Table 18-4: Sumps/Pits by Types of Vapor Recovery

Type Number of Units Percent of Total

None 125 50%

Cover 73 29%

Collection System 48 19%

Flare PD PD

Incinerator PD PD

Totals: 250

Chapter 19 Final 2007 Oil and Gas Industry Survey Results

19-1

Chapter 19 – Crude Oil Storage Tanks

Crude oil storage tanks store crude oil before it’s transported to a refinery for 

processing. They can be located on crude oil extraction sites, at tank farms, along 

pipelines, or at the refinery. Table 16 of the 2007 Oil and Gas Industry Survey collected 

information about crude oil storage tanks. Storage tanks at refineries were not included. 

Facilities were required to submit the following information about their tanks:

o Type

• Fixed roof, internal floating roof, external floating roof, or open top roof;

o Subtype

• Bolted or welded;

o Size in barrels;

o Number of degassing events;

o Average crude oil API gravity;

o Reactive organic gas (ROG) and total organic gas (TOG) emissions in 

tons/year

• For working, breathing, and flashing losses

• Average concentration of CH4 and CO2 in the vapor losses;

o Whether the storage tank had an access hatch or pressure relief valve

• Were they counted in the components from Table 6 of the 2007 Oil and 

Gas Industry Survey;

o For floating roof tanks only

• Deck leg height in feet

• Tank diameter in feet

• Primary seal type

• Secondary seal type;

o Vapor recovery system type

• Flare, incinerator, collection system, or none

• Facilities could also specify a type not listed above; and

o Vapor recovery system control efficiency.

Emissions

Vented emissions are calculated from storage tank degassing events. This is where the 

storage tank is completely emptied of fluids and opened to atmosphere for cleaning or 

repair. Fugitive emissions are calculated from the total organic gas emissions from 

working, breathing, and flashing losses and the head space vapor concentrations. 

These equations are detailed in Appendix B. The CO2 and CH4 emissions are adjusted 

by the vapor recovery efficiency and then multiplied by their corresponding GWP 

numbers (1 for CO2 and 21 for CH4) to get the CO2e values.

Table 19-1 lists the total vented and fugitive emissions from storage tanks. As shown, 

nearly all of the emissions are fugitive.
Chapter 19 Final 2007 Oil and Gas Industry Survey Results

19-2

Table 19-1: Total Emissions of Storage Tanks (Metric Tons/Year)

Type CO2 CH4 CO2e

Percent of 

Total CO2e

Vented 0 5 109 0%

Fugitive 1,084 11,501 242,594 100%

Totals: 1,084 11,506 242,703

Table 19-2 lists the fugitive emissions by tank type. Most of the emissions are from 

fixed roof storage tanks. Fixed roof tanks also account for 94 percent of the total 

number of storage tanks in California. Approximately 65 percent of the storage tanks 

reported did not have a value reported for ROG or TOG. Thus, emissions for storage 

tanks are most likely underestimated. Ongoing source testing may improve emissions 

estimates and will be incorporated in the final draft of this report.

Table 19-2: Fugitive Emissions of Storage Tanks by Type (Metric Tons/Year)

Type

Number of 

Units CO2 CH4 CO2e

Percent of 

Total CO2e

Fixed Roof 3,417 993 9,795 206,683 85%

Internal Floating Roof 34 71 1,492 31,396 13%

External Floating Roof 138 18 193 4,063 2%

Open Top Roof 37 2 16 348 0%

Unknown 13 0 5 105 0%

Totals: 3,639 1,084 11,501 242,594

Table 19-3 lists the fugitive emissions by subtype. Bolted tanks account for 80 percent 

of the total fugitive emissions and 61 percent of the total number of storage tanks.

Table 19-3: Fugitive Emissions of Storage Tanks by Subtype (Metric Tons/Year)

Type

Number of 

Units CO2 CH4 CO2e

Percent of 

Total CO2e

Bolted 2,220 937 9,239 194,960 80%

Welded 694 141 1,463 30,874 13%

Unknown 653 5 785 16,480 7%

Riveted PD PD PD PD PD

Steel PD PD PD PD PD

Poly PD PD PD PD PD

Open Top PD PD PD PD PD

Totals: 3,639 1,084 11,501 242,594

Table 19-4 lists the number of storage tanks that have vapor recovery by the type of 

tank. As shown, less than half of the fixed roof tanks have vapor recovery. Floating 

roof tanks, both internal and external, are considered a type of vapor recovery system 

for a storage tank. They typically will not have an additional vapor recovery system. 

Overall, only 45 percent of all the storage tanks have vapor recovery units.
Chapter 19 Final 2007 Oil and Gas Industry Survey Results

19-3

Table 19-4: Storage Tanks by Type Percent with Vapor Recovery

Type Number of Units

Number with

Vapor Recovery

Percent with

Vapor Recovery

Unknown 13 10 77%

Fixed Roof 3,417 1,579 46%

Internal Floating Roof 34 10 29%

External Floating Roof 138 40 29%

Open Top Roof 37 9 24%

Totals: 3,639 1,648 45%

Table 19-5 lists the number of storage tanks that have vapor recovery by subtype. Sixty 

percent of the welded tanks and 44 percent of the bolted tanks have vapor recovery 

units.

Table 19-5: Storage Tanks by Subtype Percent with Vapor Recovery

Type Number of Units

Number with

Vapor Recovery

Percent with

Vapor Recovery

Welded 694 415 60%

Bolted 2,220 970 44%

Unknown 653 208 32%

Steel PD PD PD

Poly PD PD PD

Riveted PD PD PD

Open Top PD PD PD

Totals: 3,639 1,648 45%

Table 19-6 lists the type of vapor recovery systems used on storage tanks. Some vapor 

recovery types were combined from what was listed on individual surveys to protect 

confidential company data and to aggregate similar pieces of equipment. Below is a list 

of equipment categories and the types they represent:

o Flare – flares, flares/collection systems, flares/collection 

systems/combustion equipment;

o Combustion Unit – boilers, gas plants, heaters, heater/treaters, and steam 

generators; and

o Collection System – collection system, carbon adsorber, compressor, and 

disposal well.

As shown, most of the storage tanks with vapor recovery utilize collection systems.

Table 19-6: Storage Tanks by Types of Vapor Recovery

Type Number of Units Percent of Total

None 2,019 55%

Collection System 1,313 36%

Flare 131 4%

Combustion Unit 61 2%

Incinerator 61 2%

Unknown 54 1%

Totals: 3,639

Chapter 20 Final 2007 Oil and Gas Industry Survey Results

20-1

Chapter 20 – Overview of California Emissions from Crude Oil 

Production, Processing, and Storage

Total Crude Oil Emissions

This chapter gives an overview of emissions from crude oil production, processing, and 

storage. This encompasses the primary business types: onshore crude production, 

offshore crude production, crude processing, crude storage, and crude pipelines. 

These categories account for 61 percent of California’s statewide GHG emissions from 

the oil and gas sector. As can be seen in Table 20-1, most of the emissions come from 

combustion sources. 

Table 20-1: Crude Oil Emissions (Metric Tons/Year)

Type CO2 CH4 N2O CO2e

Percent of 

Total CO2e

Combustion 10,109,202 6,737 186 10,308,317 90%

Vented 46,259 5,868 0 169,488 1%

Fugitive 92,856 43,914 0 1,015,044 9%

Totals: 10,248,318 56,519 186 11,492,849

The emissions in Table 20-1 do not include 13 cogeneration units that supply steam to 

oil fields but do not have any production associated with them. They were listed under 

the primary business type “other” and their emissions are included in Chapter 8 of this 

report.

Table 20-2 lists the combustion, vented, and fugitive emissions for crude oil facilities by 

primary business type. The primary business types crude oil processing and crude oil 

storage were combined to protect confidential data. Most of the emissions are from 

onshore crude oil production facilities. The remaining 6 percent of the emissions are 

from offshore production, processing, storage, and pipelines. 

Table 20-2: Crude Oil Emissions by Primary Business Type (Metric Tons/Year)

Type

Number of 

Facilities Combustion Vented Fugitive CO2e

Percent of 

Total CO2e

Onshore Crude 

Production 668 9,784,578 136,839 888,158 10,809,576 94%

Crude Processing 

and Storage 42 346,952 15,940 44,347 407,239 4%

Offshore Crude 

Production 16 104,272 16,708 65,232 186,213 2%

Crude Pipeline 65 72,515 0 17,306 89,821 1%

Totals: 791 10,308,317 169,488 1,015,044 11,492,849

Total CO2e emissions were calculated for each facility. The facilities were then 

categorized into ranges of CO2e emissions. Table 20-3 lists the number of facilities in 

each range and the total CO2e emissions for the facilities in that range. As this table 

shows, 84 percent of the emissions come from two percent of the facilities.
Chapter 20 Final 2007 Oil and Gas Industry Survey Results

20-2

Table 20-3: Crude Oil Total Emissions by CO2e Range (Metric Tons/Year)

Range 

(CO2e per Facility)

Number of 

Facilities CO2e

Percent of Total 

CO2e

< 10,000 729 419,662 4%

10,000 to 25,000 20 314,565 3%

25,000 to 50,000 14 521,735 5%

50,000 to 100,000 9 653,132 6%

100,000 to 500,000 13 2,914,583 25%

> 500,000 6 6,669,171 58%

Totals: 791 11,492,849

Tables 20-4, 20-5, and 20-6 list the number of facilities and total CO2e emissions for 

combustion, vented, and fugitive sources. These tables are similar to Table 20-3 in that 

the majority of the emissions come from a small fraction of the facilities. 

Table 20-4: Crude Oil Combustion Emissions by CO2e Range

 (Metric Tons/Year)

Range

(CO2e per Facility)

Number of 

Facilities CO2e

Percent of Total 

CO2e

< 10,000 742 337,672 3%

10,000 to 25,000 15 231,994 2%

25,000 to 50,000 12 454,116 4%

50,000 to 100,000 6 449,261 4%

100,000 to 500,000 11 2,379,080 23%

> 500,000 5 6,456,193 63%

Totals: 791 10,308,317

Tables 20-5 and 20-6 list the number of facilities and total CO2e emissions for vented 

and fugitive emissions separately. With the combustion emissions removed, the range 

of CO2e values is much smaller. The majority of the facilities fall in the “less than 1,000 

metric ton CO2e per year” range, while a small fraction of the facilities account for a 

majority of the GHG emissions. 

Table 20-5: Crude Oil Vented Emissions by CO2e Range (Metric Tons/Year)

Range

(CO2e per Facility)

Number of 

Facilities CO2e

Percent of Total 

CO2e

<1,000 776 17,152 10%

1,000 to 5,000 8 18,391 11%

5,000 to 10,000 PD PD PD

10,000 to 25,000 4 62,736 37%

> 25,000 PD PD PD

Totals: 791 169,488
Chapter 20 Final 2007 Oil and Gas Industry Survey Results

20-3

Table 20-6: Crude Oil Fugitive Emissions by CO2e Range (Metric Tons/Year)

Range 

(CO2e per Facility)

Number of 

Facilities CO2e

Percent of Total 

CO2e

< 1,000 734 76,445 8%

1,000 to 5,000 36 64,734 6%

5,000 to 10,000 7 51,487 5%

10,000 to 25,000 6 84,296 8%

> 25,000 8 738,083 73%

Totals: 791 1,015,044

Average Emissions per Barrel Produced

This section includes emissions from onshore and offshore crude production. A way to 

classify facilities is to determine their average total CO2e emissions per barrel of crude 

oil produced. This can be calculated in two ways, as a facility average and as a 

production-weighted average. 

Facility Average 

The average CO2e emissions per barrel of crude oil produced was calculated for each 

facility by dividing the facility’s total CO2e emissions by its total production. Those 

values were then averaged for each range of production, as a facility average and as a 

production-weighted average.

Avg. CO2e/bblrange = ∑[(CO2e/bblfacility)]range/number facilitiesrange

Production-Weighted Average

The average CO2e emissions per barrel of crude production was calculated by summing 

the total CO2e emissions for each range of production and dividing it by the total barrels 

produced in that range.

Avg. CO2e/bblrange = (total CO2erange)/(total bblrange)

The above calculations were done for total emissions and combustion, vented, and 

fugitive emissions separately. Table 20-7 shows the average CO2e emissions per 

barrel for total emissions. The range “not reported” includes facilities that listed 

themselves as crude production but did not fill out their crude oil production for 2007. 

Most of the CO2e emissions per barrel numbers are very close with the exception of the 

range 10,000 to 25,000. This range is skewed upwards due to facilities generating

electricity as well as producing crude oil. 
Chapter 20 Final 2007 Oil and Gas Industry Survey Results

20-4

Table 20-7: Average Total CO2e Emissions per Barrel Crude Oil Produced

(Metric Tons/Year)

Range 

(Barrels Crude Oil 

produced per Year)

Number of 

Facilities

Total Barrels 

of Crude Oil 

Produced Total CO2e

Facility 

Average CO2e 

per Barrel

Production 

Weighted 

Average CO2e 

per Barrel

Not Reported 88 Not Reported 358,452 N/A N/A

< 1,000 87 42,720 3,444 0.12 0.08

1,000 to 10,000 238 961,326 36,480 0.04 0.04

10,000 to 25,000 84 1,267,662 273,644 0.31 0.22

25,000 to 50,000 57 2,093,042 72,740 0.04 0.03

50,000 to 75,000 21 1,344,532 101,704 0.07 0.08

75,000 to 100,000 11 896,802 16,528 0.02 0.02

> 100,000 99 227,371,062 10,132,797 0.05 0.04

Totals: 684 233,977,146 10,995,789 0.08 0.05

Table 20-8 shows the average CO2e emissions per barrel for combustion emissions 

only. Most of the ranges are relatively similar except for the 10,000 to 25,000 range. 

Again, this is due to facilities generating electricity as well as producing crude oil.

Table 20-8: Average Combustion CO2e Emissions per Barrel Crude Oil Produced

(Metric Tons/Year)

Range 

(Barrels Crude Oil 

produced per Year)

Number of 

Facilities

Total Barrels 

of Crude Oil 

Produced Total CO2e

Facility 

Average CO2e 

per Barrel

Production 

Weighted 

Average CO2e 

per Barrel

Not Reported 88 Not Reported 178,993 N/A N/A

< 1,000 87 42,720 1,267 0.03 0.03

1,000 to 10,000 238 961,326 25,122 0.03 0.03

10,000 to 25,000 84 1,267,662 258,871 0.30 0.20

25,000 to 50,000 57 2,093,042 39,504 0.02 0.02

50,000 to 75,000 21 1,344,532 92,469 0.07 0.07

75,000 to 100,000 11 896,802 4,782 0.01 0.01

> 100,000 99 227,371,062 9,287,843 0.03 0.04

Totals: 684 233,977,146 9,888,850 0.06 0.04

Table 20-9 shows that vented CO2e emissions per barrel produced are relatively 

consistent for all ranges of production. 
Chapter 20 Final 2007 Oil and Gas Industry Survey Results

20-5

Table 20-9: Average Vented CO2e Emissions per Barrel Crude Oil Produced

(Metric Tons/Year)

Range 

(Barrels Crude Oil 

produced per Year)

Number 

of 

Facilities

Total Barrels of 

Crude Oil 

Produced

Total 

CO2e

Facility 

Average CO2e 

per Barrel

Production 

Weighted 

Average CO2e 

per Barrel

Not Reported 88 Not Reported 15,848 N/A N/A

< 1,000 87 42,720 113 0.0025 0.0027

1,000 to 10,000 238 961,326 1,846 0.0019 0.0019

10,000 to 25,000 84 1,267,662 1,312 0.0010 0.0010

25,000 to 50,000 57 2,093,042 2,213 0.0011 0.0011

50,000 to 75,000 21 1,344,532 1,616 0.0012 0.0012

75,000 to 100,000 11 896,802 381 0.0004 0.0004

> 100,000 99 227,371,062 130,218 0.0050 0.0006

Totals: 684 233,977,146 153,548 0.0019 0.0007

Table 20-10 shows the CO2e emissions per barrel for fugitive emissions only. The high 

average CO2e emission per barrel for the < 1,000 range is due to a number of facilities 

that produce less than 1 barrel of crude oil per day.

Table 20-10: Average Fugitive CO2e Emissions per Barrel Crude Oil Produced

(Metric Tons/Year)

Range 

(Barrels Crude Oil 

produced per Year)

Number 

of 

Facilities

Total Barrels of 

Crude Oil 

Produced

Total 

CO2e

Facility 

Average CO2e 

per Barrel

Production 

Weighted 

Average CO2e 

per Barrel

Not Reported 88 Not Reported 163,610 N/A N/A

< 1,000 87 42,720 2,064 0.088 0.048

1,000 to 10,000 238 961,326 9,512 0.011 0.010

10,000 to 25,000 84 1,267,662 13,461 0.010 0.011

25,000 to 50,000 57 2,093,042 31,023 0.017 0.015

50,000 to 75,000 21 1,344,532 7,619 0.005 0.006

75,000 to 100,000 11 896,802 11,366 0.011 0.013

> 100,000 99 227,371,062 714,736 0.011 0.003

Totals: 597 233,977,146 789,780 0.020 0.003

Chapter 21 Final 2007 Oil and Gas Industry Survey Results

21-1

Chapter 21 – Overview of California Emissions from Dry Natural Gas 

Production, Processing, and Storage

Total Natural Gas Emissions

This chapter gives an overview of natural gas production, processing, and storage. This 

encompasses the primary business types: onshore natural gas production, natural gas 

processing, and natural gas storage. These categories account for 13 percent of 

California’s statewide GHG emissions from the oil and gas sector. As can be seen in 

Table 21-1, about half of the emissions come from combustion sources and about a 

third come from fugitive sources.

Table 21-1: Natural Gas Emissions (Metric Tons/Year)

Type CO2 CH4 N2O CO2e

Percent of 

Total CO2e

Combustion 1,237,087 3,918 18 1,325,080 53%

Vented 2,160 18,917 0 399,421 16%

Fugitive 177,898 29,007 0 787,044 31%

Totals: 1,417,145 51,843 18 2,511,544

Table 21-2 lists the combustion, vented, and fugitive emissions for natural gas facilities. 

About half of the emissions come from natural gas processing. The remaining 

emissions are split almost equally between onshore gas production and natural gas 

storage.

Table 21-2: Natural Gas Emissions by Primary Business Type (Metric Tons/Year)

Type

Number 

of 

Facilities Combustion Vented Fugitive CO2e

Percent 

of Total 

CO2e

Natural Gas Processing 17 879,601 5,102 400,160 1,284,863 51%

Natural Gas Storage 10 226,569 276,484 176,004 679,058 27%

Onshore Natural Gas 703 218,910 117,835 210,879 547,624 22%

Totals: 730 1,325,080 399,421 787,044 2,511,544

“Natural gas processing” covers facilities that only process gas but do not extract gas. 

They are generally referred to as gas plants. Many extraction facilities have gas 

processing equipment onsite while others send their gas to gas plants. 

The CO2e emissions were calculated for each facility. The facilities were then 

categorized into ranges of CO2e emissions. Table 21-3 lists the number of facilities in 

each range and the CO2e emissions for the facilities in that range. As this table shows, 

about 76 percent of the emissions come from about one and a half percent of the 

facilities.
Chapter 21 Final 2007 Oil and Gas Industry Survey Results

21-2

Table 21-3: Total Natural Gas Emissions by CO2e Range (Metric Tons/Year)

Range 

(CO2e per Facility) Number of Facilities CO2e

Percent of Total 

CO2e

< 1,000 580 154,516 6%

1,000 to 5,000 117 227,760 9%

5,000 to 10,000 15 106,265 4%

10,000 to 25,000 7 107,584 4%

> 25,000 11 1,915,419 76%

Totals: 730 2,511,544

Table 21-4 lists the number of facilities in each range and the total combustion CO2e 

emissions for all the facilities in that range. Again, most of the emissions come from a 

small fraction of the facilities. Most of the facilities fall into the < 1,000 CO2e range.

Table 21-4: Natural Gas Combustion Emissions by CO2e Range (Metric Tons/Year)

Range 

(CO2e per Facility) Number of Facilities CO2e

Percent of Total 

CO2e

< 1,000 679 70,852 5%

1,000 to 5,000 31 67,690 5%

5,000 to 10,000 5 31,319 2%

10,000 to 25,000 8 117,233 9%

> 25,000 7 1,037,986 78%

Totals: 730 1,325,080

Tables 21-5 and 21-6 show the number of facilities and the total CO2e emissions for 

vented and fugitive sources separately. Information for two ranges is listed as “PD” to 

protect confidential data.

Table 21-5: Natural Gas Vented Emissions by CO2e Range (Metric Tons/Year)

Range

(CO2e per Facility) Number of Facilities CO2e

Percent of Total 

CO2e

<1,000 701 83,356 21%

1,000 to 5,000 24 45,587 11%

5,000 to 10,000 PD PD PD

10,000 to 25,000 0 0 0%

> 25,000 PD PD PD

Totals: 761 399,199

Table 21-6: Natural Gas Fugitive Emissions by CO2e Range (Metric Tons/Year)

Range 

(CO2e per Facility) Number of Facilities CO2e

Percent of Total 

CO2e

< 1,000 661 118,093 15%

1,000 to 5,000 62 112,640 14%

5,000 to 10,000 PD PD PD

10,000 to 25,000 PD PD PD

> 25,000 4 528,573 67%

Totals: 730 787,044
Chapter 21 Final 2007 Oil and Gas Industry Survey Results

21-3

Average Emissions per MSCF Produced

This section includes emissions from onshore and offshore natural gas production. A 

way to classify facilities is to determine their average total CO2e emissions per thousand 

cubic feet (mscf) of natural gas produced. This can be calculated in two ways. 

Facility Average 

The average CO2e emissions per mscf natural gas produced was calculated for each 

facility by dividing the facility’s total CO2e emissions by its total production. Those 

values were then averaged for each range of production.

Avg. CO2e/mscfrange = ∑[(CO2e/mscffacility)]range/number facilitiesrange

Production – Weighted Average

The average CO2e emissions per mscf natural gas production was calculated by 

summing the total CO2e emissions for each range of production and dividing it by the 

total mscf produced in that range.

Avg. CO2e/mscfrange = (total CO2erange)/(total mscfrange)

The above calculations were done for total emissions and combustion, vented, and 

fugitive emissions separately. Table 21-7 shows the average CO2e emissions per mscf

for total emissions. The range “not reported” includes facilities that listed themselves as 

natural gas production but did not fill out their natural gas production for 2007. 

Table 21-7 shows that most of the ranges have similar average CO2e emissions per 

mscf of natural gas produced except for the two lowest ranges. The “< 1,000 mscf”

range has several facilities that produce less than one mscf of natural gas. This 

artificially increases the CO2e emissions per mscf. The “1,000 to 50,000 mscf” range is 

larger than the remaining ranges due to several facilities with compressors onsite.

Table 21-7: Average Total CO2e Emissions per MSCF Natural Gas Produced

(Metric Tons/Year)

Range

(MSCF Natural Gas 

Produced per Year)

Number 

of 

Facilities

Total MSCF of 

Natural Gas 

Produced Total CO2e

Facility 

Weighted 

Average CO2e

per MSCF

Production 

Weighted 

Average CO2e

per MSCF

Not Reported 31 Not Reported 50,656 N/A N/A

< 1,000 57 5,196 1,023 25.438 0.197

1,000 to 50,000 329 9,181,032 202,829 0.052 0.022

50,000 to 250,000 242 34,859,306 252,624 0.007 0.007

250,000 to 500,000 35 10,830,889 27,687 0.003 0.003

> 500,000 9 13,178,870 12,805 0.001 0.001

Totals: 703 68,055,293 547,624 2.090 0.008
Chapter 21 Final 2007 Oil and Gas Industry Survey Results

21-4

Table 21-8 lists the average CO2e emissions per mscf natural gas produced for 

combustion emissions by range of production. Here, the bottom two ranges have 

higher CO2e per mscf values due to the reasons stated above for Table 21-7. 

Table 21-8: Average Combustion CO2e Emissions per MSCF Natural Gas

Produced (Metric Tons/Year)

Range

(MSCF Natural Gas 

Produced per Year)

Number 

of 

Facilities

Total MSCF of 

Natural Gas 

Produced Total CO2e

Facility 

Weighted 

Average CO2e

per MSCF

Production 

Weighted 

Average CO2e

per MSCF

Not Reported 31 Not Reported 36,316 N/A N/A

< 1,000 57 5,196 178 0.0056 0.0343

1,000 to 50,000 329 9,181,032 108,511 0.0227 0.0118

50,000 to 250,000 242 34,859,306 59,464 0.0018 0.0017

250,000 to 500,000 35 10,830,889 7,777 0.0008 0.0007

> 500,000 9 13,178,870 6,664 0.0003 0.0005

Totals: 703 68,055,293 218,910 0.0118 0.0032

Tables 21-9 and 21-10 detail the average CO2e emissions per mscf of natural gas 

produced for vented and fugitive emissions. In both these tables, the range “< 1,000 

mscf” range is higher due to several facilities producing less than one mscf of natural 

gas. 

Table 21-9: Average Vented CO2e Emissions per MSCF Natural Gas Produced

(Metric Tons/Year)

Range

(MSCF Natural Gas 

Produced per Year)

Number 

of 

Facilities

Total MSCF of 

Natural Gas 

Produced Total CO2e

Facility 

Weighted 

Average CO2e

per MSCF

Production 

Weighted 

Average CO2e

per MSCF

Not Reported 31 Not Reported 4,434 N/A N/A

< 1,000 57 5,196 609 1.0773 0.1172

1,000 to 50,000 329 9,181,032 30,316 0.0097 0.0033

50,000 to 250,000 242 34,859,306 71,806 0.0020 0.0021

250,000 to 500,000 35 10,830,889 6,308 0.0006 0.0006

> 500,000 9 13,178,870 4,361 0.0001 0.0003

Totals: 703 68,055,293 117,835 0.0926 0.0017

Table 21-10: Average Fugitive CO2e Emissions per MSCF Natural Gas Produced

(Metric Tons/Year)

Range

(MSCF Natural Gas 

Produced per Year)

Number 

of 

Facilities

Total MSCF of 

Natural Gas 

Produced Total CO2e

Facility 

Weighted 

Average CO2e

per MSCF

Production 

Weighted 

Average CO2e

per MSCF

Not Reported 31 Not Reported 9,907 N/A N/A

< 1,000 57 5,196 236 24.3552 0.0454

1,000 to 50,000 329 9,181,032 64,001 0.0196 0.0070

50,000 to 250,000 242 34,859,306 121,354 0.0037 0.0035

250,000 to 500,000 35 10,830,889 13,601 0.0013 0.0013

> 500,000 9 13,178,870 1,780 0.0001 0.0001

Totals: 703 68,055,293 210,879 1.9852 0.0031
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-1

Appendix A: 2007 Oil and Gas Industry Survey

California Air Resources Board

Oil and Gas Industry Survey
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-2
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-3
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-4
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-5

California Air Resources Board

Oil and Gas Industry Survey

For additional information related to this survey, please see 

accompanying 

General Instructions.

Reporting Year 2007

Table 1: Facility Description

Company Name:

Facility Name: Air District:

Address:

City: State: Zip:

Contact Person: Phone: Email:

Type of Business (Check all that apply)

 Onshore Crude Oil Production

 Offshore Crude Oil Production

 Onshore Natural Gas Production

 Offshore Natural Gas Production

 Natural Gas Storage Facility

 Natural Gas Processing 

 Crude Oil Pipeline

 Crude Oil Storage

 Crude Oil Processing

 PERP Equipment Owner2

 Other (Specify): _________________

Air District Facility ID1:

______________________

______________________

______________________

______________________

______________________

______________________

______________________

______________________

______________________

______________________

______________________

1. If your facility does not have an air district facility ID, please see instructions to create one. This code will be used 

in the remaining tables under “Air District Facility ID”.

2. Portable Equipment Registration Program (PERP).
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-6

California Air Resources Board

Oil and Gas Industry Survey

Reporting Year 2007

Table 2: Facility Production

Facility Name:

Box 1: Production

Number of:

Produced 

Natural 

Gas1

Natural 

Gas 

Storage

Ultra Heavy

Oil

API < 10°

Heavy Oil

API 

10° - 20°

Light Oil

API 

20° - 30°

Ultra Light 

Oil

API > 30°

Active Wells ________ ________ ________ ________ ________ ________

Well Cellars ________ ________ ________ ________ ________ ________

New Wells Drilled ________ ________ ________ ________ ________ ________

Workovers (Tubing Removal) ________ ________ ________ ________ ________ ________

Well Cleanups3 ________ ________ ________ ________ ________ ________

Well Completions ________ ________ ________ ________ ________ ________

Volume Produced (bbl) ________ ________ ________ ________ ________

Box 2: Associated or Produced Natural Gas Production2

Mole % 

Methane

Mole % 

CO2

Mole % 

H2S

Higher Heating 

Value (Btu)

Volume 

Produced (SCF)

Average Raw Gas Stream _________ _________ _________ _________ _________

Box 3: Crude Oil Transmission Pipeline (After LACT Unit)

Volume Transported

Barrels Crude Oil ____________________ Length (Miles) ___________________

1. Produced Natural Gas is gas extracted from a non-oil producing gas well. This category does not include 

associated gas. 

2. Associated Gas is gas produced with crude oil extraction. Box 2 is to be used for both associated and produced 

natural gas. 

3. Well cleanups are maintenance activities that include fracturing or removing fluids to increase production.
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-7

California Air Resources Board

Oil and Gas Industry Survey

Reporting Year 2007

Table 3: Facility Electrification 

Air District Facility ID:

Onsite Generated Electricity:

Amount Generated:

__________________ MWh

Amount Exported:

__________________ MWh

Amount Purchased:

_________________ MWh
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-8

California Air Resources Board

Oil and Gas Industry Survey

Reporting Year 2007

Table 4: Vapor Recovery and Flares

(Complete one for each piece of equipment)

Air District Facility ID:

Type:

 Flare

 Incinerator

 Thermal Oxidizer

 Carbon Adsorption

Use:

 Vapor Recovery

 Emergency

Flares, Thermal Oxidizers, and Incinerators Only Carbon Adsorbers Only:

Size (Btu/hr): ________________________ Size (ft3): _______________

Throughput (SCF): ________________________ Throughput (SCF): _______________

Combustion Efficiency: ________________________ Capture Efficiency: _______________

Avg. Composition (Mole %):

___________ % Methane ____________ % CO2

Avg. Composition (Mole %):

___________ % Methane 

Carbon Mole Ratio1 ________________

1. Please see instructions to calculate the carbon mole ratio.
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-9

California Air Resources Board

Oil and Gas Industry Survey

Reporting Year 2007

Table 5: Combustion Equipment 

(Complete one for each piece of equipment)

Air District Facility ID:

External Combustion Type:

 Boiler

 Steam Generator

 Heater/Treater

 Oil Heater

 Reboiler 

o Glycol

o Amine

 Other (Specify) 

_____________________

Internal Combustion Type:

Type:

 Reciprocating

o Rich Burn Two-Stroke

o Lean Burn Two-Stroke

o Rich Burn Four-Stroke

o Lean Burn Four-Stroke

 Combined Heat and Power 

 Turbine

o Simple Cycle

o Combined Cycle

 Microturbine

 Drill Rig

 Workover Rig

Use:

 Compressor

o ID1 ______________

 Vapor Recovery 

 Crude Oil Pump 

 Well Pump

 Water Injection Pump

 Other (Specify) 

_____________________

Manufacturer2: Fuel Type: Primary Secondary

Diesel  

Pipeline Quality Gas  

Model Year: Associated Gas  

Produced Gas  

Waste Gas  

Average Load (HP/BTU/MW): Landfill Gas  

Liquefied Petroleum Gas  

Propane  

Avg. Thermal Efficiency:

(Steam Generators and Turbine Engines)

Gasoline  

Other (Specify): ____________  

Annual Fuel Volume: (Gallons/SCF)

Inspection Frequency:

Instrument Test ______________

Visual Inspection ______________

Third Party ______________

Metered

Calculated

__________

__________

__________

__________

Avg. Higher Heating Value (Btu) __________ __________

Carbon Weight % __________ __________

Under Air District Permit? Liquid Fuel Density (lb/gal) __________ __________

 Yes  No

PERP4 Registered? Gaseous Fuel Molecular Weight3 __________ __________

 Yes  No

1. Create a unique ID number for each compressor engine. The number will be used in conjunction with Table 12. 

2. For external combustion, list the burner manufacturer. 

3. See instructions for calculation. 4. Portable Equipment Registration Program (PERP)
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-10

California Air Resources Board

Oil and Gas Industry Survey

Reporting Year 2007

Table 6: Component Counts1

Air District Facility ID:

Type: Number of Components by Product Type:

(1-inch and above):

Natural Gas Light Crude 

(API >20°)

Heavy Crude 

(API <20°)

 Manual Valves _________________ _________________ _________________

 Flanges _________________ _________________ _________________

 Connectors _________________ _________________ _________________

 Open-ended Lines _________________ _________________ _________________

 Threaded Components _________________ _________________ _________________

Other Components:

 Pump Seals _________________ _________________ _________________

 Pressure Relief Valves _________________ _________________ _________________

 Bursting Discs _________________ _________________ _________________

 Diaphragms _________________ _________________ _________________

 Hatches _________________ _________________ _________________

 Meters _________________ _________________ _________________

 Polished Rod Stuffing Boxes _________________ _________________ _________________

 Sight Glasses _________________ _________________ _________________

 Loading Arms _________________ _________________ _________________

 Dump Lever Arm _________________ _________________ _________________

1. If actual counts are not available please estimate. See instructions for details.
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-11

California Air Resources Board

Oil and Gas Industry Survey

Reporting Year 2007

Table 7: Automated Control Devices1

Air District Facility ID:

Controllers:

Gas Actuated Number:

Number on 

Gas Recovery2

Continuous Bleed ___________________ ___________________

Intermittent Bleed ___________________ ___________________

Low Bleed ___________________ ___________________

No Bleed3 ___________________

Electronically Actuated ___________________ ___________________

Air Actuated ___________________ ___________________

Actuators:

Gas Actuated

Piston Valve Operator ___________________ ___________________

Hydraulic Valve Operator ___________________ ___________________

Turbine Valve Operator ___________________ ___________________

Electronically Actuated ___________________ ___________________

Air Actuated ___________________ ___________________

1. If actual counts are unavailable, please estimate. 

2. Includes units connected to a vapor recovery system or vented back into a system.

3. A “No Bleed” controller is not connected to a gas recovery system.
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-12

California Air Resources Board

Oil and Gas Industry Survey

Reporting Year 2007

Table 8: Inspection and Maintenance Program1

(For Table 6 and 7)

Air District Facility ID:

Does your facility follow an Inspection and Maintenance (I&M) 

Program?

 Yes  No

District Rule # for I&M Program (If Applicable):

I&M Program Type:

Stratum: Leak Threshold 

(ppm):

 0 – 500 ppm _________________

 500 – 1,000 ppm _________________

 1,000 – 2,000 ppm _________________

 2,000 – 10,000 ppm _________________

 10,000 – 50,000 ppm _________________

 > 50,000 ppm _________________

Is this test data available electronically?  Yes  No (If yes, please submit electronically)

1. An Inspection and Maintenance Program is where the operator of a facility inspects their facility for leaks of organic 

gases and repairs the leaks.
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-13

California Air Resources Board

Oil and Gas Industry Survey

Reporting Year 2007

Table 9: Natural Gas Dehydration

(Complete one for each piece of equipment)

Air District Facility ID:

Type:

 Glycol  Desiccant  Other (Specify) ____________________

Avg. Natural Gas Composition (Mole %): Input Volume (SCF):

Input: Output:

_________ % Methane 

_________ % H2S 

_________ % CO2 

_________ % Methane 

_________ % H2S 

_________ % CO2 

Output Volume (SCF):

Volume of Liquids Removed (tons/year):

_________ HHV1 (Btu) _________ HHV1 (Btu)

For Glycol Units Only:

Gas Assisted Pump?  Yes  No

Glycol Circulation Rate (Gallons/Hour): ___________________

Electric Pump?  Yes  No

Average Flash Tank Pressure (PSIA): _____________________

Stripping Gas Used?  Yes  No

Average Contactor Pressure (PSIA): ______________________

Flash Separator?  Yes  No

For Desiccant Units Only:

Volume of Dehydrator (ft3): ________________ % of Packed Vessel Volume that is Natural Gas2: ____________

Vessel Pressure (PSIG): __________________ Frequency of Desiccant Replacement (days): _____________

Vapor Recovery System:

 Flare

 Incinerator

 Collection System

 None

 Other (Specify) ____________

Control Efficiency: _________%

1. HHV is Higher Heating Value.

2. See instructions.
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-14

California Air Resources Board

Oil and Gas Industry Survey

Reporting Year 2007

Table 10: Natural Gas Sweetening or Acid Gas Removal

(Complete one for each piece of equipment)

Air District Facility ID:

Type:

 Amine 

 Lo-Cat 

 Claus Process

 Morphysorb

 Sulfa Treat

 Iron Sponge

 Mol Sieve 

 Molecular Gate

 Grace Membranes

 Kvaerner Membrane

 Other (Specify) ______________

Avg. Natural Gas Composition (Mole %): Input Volume (SCF):

Input: Output:

_________ % Methane 

_________ % H2S 

_________ % CO2 

_________ % Methane 

_________ % H2S 

_________ % CO2 

Output Volume (SCF):

Volume of Liquids Removed (tons/year):

_________ HHV1 (Btu) _________ HHV1 (Btu)

CO2 Removal:

Total CO2 Removed (tons/year): _________________ Amount Incinerated (tons/year): _________________

Amount Vented (tons/year): _________________ Amount Captured (tons/year): _________________

For Units that Require Solid Material Replacement

Volume of Unit (ft3): ________________ % of Packed Vessel Volume that is Natural Gas2: ___________

Vessel Pressure (PSIG): __________________ Frequency of Material Replacement (days): _____________

Vapor Recovery System:

 Flare

 Incinerator

 Collection System

 None

 Other (Specify) ____________

Control Efficiency: _________%

1. HHV is Higher Heating Value.

2. See instructions.
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-15

California Air Resources Board

Oil and Gas Industry Survey

Reporting Year 2007

Table 11: Other Natural Gas Processing

(Complete one for each piece of equipment)

Air District Facility ID:

Unit Type:

 Fractionation

 Nitrogen Removal

 Mercury Removal

 Other (Specify) ___________

Avg. Natural Gas Composition (Mole %): Input Volume (SCF):

Input: Output:

_________ % Methane 

_________ % H2S 

_________ % CO2 

_________ % Methane 

_________ % H2S 

_________ % CO2 

Output Volume (SCF):

Volume of Liquids Removed (tons/year):

_________ HHV1 (Btu) _________ HHV1 (Btu)

Vapor Recovery System:

 Flare

 Incinerator

 Collection System

 Other (Specify) ____________

 None

Control Efficiency: _________%

1. HHV is Higher Heating Value.
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-16

California Air Resources Board

Oil and Gas Industry Survey

Reporting Year 2007

Table 12: Natural Gas Compressors 

(Complete one for each piece of equipment)

Air District Facility ID:

Type:

 Centrifugal

o # Wet Seals _________

o # Dry Seals _________

 Reciprocating

o # Cylinders _________

 Rotary

 Other (Specify) ___________

Primary Driver:

Compressor ID1 __________

Type:

 Electric

 Turbine

 Piston Engine

 Integral 

Starter Type (For Primary Driver):

 Gas Expansion

o Natural Gas

o Instrument Air

 Electric

 Hydraulic

 Other (Specify) 

____________

Manufacturer: Model Year: Annual Usage (Hours):

Inspection Frequency (Daily, Monthly, Annually, ect.): Maintenance Frequency2

:

Discharge Pressure (PSIA) Discharge Temperature (°F) Idle Pressure (PSIA)

Blow-downs:

Total Number: __________________

Total Volume of Gas for Blow-downs (SCF):

 Vented ______________

 Flared ______________

 Recovered ______________

 

Start-ups:

Total Number: _________________

Total Volume of Gas for Start-ups (SCF):

 Vented ______________

 Flared ______________

 Recovered ______________

1. Enter the compressor engine ID number from Table 5. If the compressor engine is electric, leave this field blank.

2. The maintenance frequency is the number of times the unit had to be disassembled to replace valves, seals, or 

packing.
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-17

California Air Resources Board

Oil and Gas Industry Survey

Reporting Year 2007

Table 13: Pipelines

Air District Facility ID:

Natural Gas:

Extraction Facility Gathering System (Prior to Gas Meter) Estimated Length (miles): _______________

Natural Gas Gathering System Maintenance Activites (SCF):

Pipeline Gas Associated Gas1 Produced Gas2

Vented __________________ __________________ __________________

Flared __________________ __________________ __________________

Recovered3 __________________ __________________ __________________

Pigging Operations:

Number of Launchers/Receivers Crude Oil _____________ Natural Gas _____________

Number of Launcher/Receiver Openings Crude Oil _____________ Natural Gas _____________

Are Launchers/Receivers Purged with Inert Gas Prior to Opening?  Yes  No

1. Associated Natural Gas is gas produced with crude oil extraction.

2. Produced Natural Gas is gas extracted from a gas well.

3. Recovered is any volume of gas that is not either vented or flared.
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-18

California Air Resources Board

Oil and Gas Industry Survey

Reporting Year 2007

Table 14: Crude Oil or Natural Gas Separation Units

(Complete one per piece of equipment)

Air District Facility ID:

Type:

 Free Water Knockout

 Heater/Treater

 Horizontal Separator

 Vertical Separator

 Flow Splitter

 Wemco

 Emulsion Treater

 Condensate Tank

 Other (Specify) 

_______________

Subtype:

 Bolted 

 Welded 

Size (Barrels/SCF):

Number of Degassing Events:

Throughput (Barrels/year or SCF/year):

Avg. Crude Oil API:

ROG (tons/year) TOG (tons/year) Components: 

Working Loss _________ _________

 

 Access Hatch

 Pressure Relief Valve

Breathing Loss _________ _________

Flashing Loss _________ _________ Are hatches and pressure relief valves included 

Avg. Methane _________ % Avg. CO2 _________ %

in Table 6?  Yes  No

Vapor Recovery System:

 Flare Control Efficiency: _________%

 Incinerator

 Collection System

 None

 Other (Specify) _________
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-19

California Air Resources Board

Oil and Gas Industry Survey

Reporting Year 2007

Table 15: Crude Oil Separation Sumps or Pits

(Complete one per piece of equipment)

Air District Facility ID:

Level:

 Primary

 Secondary

 Tertiary

Usage:

 Crude Oil API ____________

 Number of Days in Use ___________

Dimensions:

Area (Square Feet) __________________

Depth (Feet) __________________

Vapor Recovery System:

 Flare

 Incinerator

 Collection System

 Cover

 None

 Other (Specify) ________

Control Efficiency _________%
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-20

California Air Resources Board

Oil and Gas Industry Survey

Reporting Year 2007

Table 16: Crude Oil Storage Tanks

(Complete one per piece of equipment)

Air District Facility ID:

Type:

 Fixed Roof 

 Internal Floating Roof 

 External Floating Roof

 Open Top Roof

Subtype:

 Bolted Tank

 Welded Tank

Size (Barrels):

Number of Degassing Events:

Avg. Crude Oil API:

ROG (tons/year) TOG (tons/year) Components: 

Working Loss _________ _________

 

 Access Hatch

 Pressure Relief Valve

Breathing Loss _________ _________

Flashing Loss _________ _________ Are hatches and pressure relief valves included 

Avg. Methane _________ % Avg. CO2 _________ %

in Table 6?  Yes  No

Floating Roof Tanks Only:

Deck Leg Height (ft): ____________ Tank Diameter (ft): ____________

Primary Seal:

 Metallic Shoe

o Liquid Mounted

o Vapor Mounted

 Resilient Toroid

o Liquid Mounted

o Vapor Mounted

 Wiper

 Other (Specify) __________

Secondary Seal:

 Wiper 

 Resilient Toroid

o Liquid Mounted

o Vapor Mounted

 Other (Specify) __________

Vapor Recovery System:

 Flare Control Efficiency: _________%

 Incinerator

 Collection System

 None

 Other (Specify) _________
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-21

Oil & Natural Gas Industry Survey

General Instructions

Mailing Address:

California Air Resources Board

P.O. Box 2815

Sacramento, California 95812

Attention: SSD / Oil & Gas Survey

February 2009
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-22

Overview

The Oil & Natural Gas Industry Survey has been designed to improve our estimates of

greenhouse gas emissions in California. We are collecting data for the 2007 calendar 

year in order to accurately quantify equipment and operation processes. This survey is 

intended to be a one-time collection of information needed to develop a statewide 

inventory baseline. This survey is not being used as a compliance tool nor is it part of 

other mandatory reporting programs. This survey pertains to all upstream oil and natural 

gas facilities regardless of the size of the operation.

The following instructions have been provided to answer general questions pertaining to 

the individual survey tables. Since this survey covers a wide range of processes and 

operations, some companies may not need to complete every table.

Who should fill out this survey? Any owner or operator of the following facilities:

Oil or Natural Gas Extraction Facilities: includes any facility that extracts crude 

oil, natural gas, or both crude oil and natural gas.

Processing Facilities: includes any facility that processes crude oil or natural gas 

for use or distribution. This survey does not include refineries.

Crude Oil Transmission Facilities

loading operations. This includes ship, truck, or rail car loading facilities.

: includes crude oil pipelines or crude oil bulk

Storage Facilities: includes any facility that stores crude oil or natural gas, 

including underground natural gas storage facilities. This survey excludes crude 

oil tank farms that are located on refinery premises.

Submission Format. Paper forms, Microsoft Excel/Access files, or a combination of 

both paper and electronic files are acceptable. It is preferable to have all data submitted

electronically. We have staff available to provide assistance or answer questions via email or telephone.

Permitted and Non-Permitted Equipment. This survey covers both air district

permitted and non-permitted equipment and includes equipment that is registered under 

the Portable Equipment Registration Program (PERP). Therefore, this survey includes 

equipment that is moved more than once annually and includes non-air district 

permitted equipment that is below 50-horsepower in rating.

Questions? Please contact any of the following ARB staff for questions or assistance:

Stephanie Lee (916) 324-8024 sjlee@arb.ca.gov

Joseph Fischer (916) 445-0071 joseph.fischer@arb.ca.gov

Luis Leyva (916) 323-1079 lleyva@arb.ca.gov
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-23

General Instructions

Table 1: Facility Description

This survey and the Facility Description Table are to be completed one time per

geographically distinct facility (i.e., property boundary) by the entity that has operational

control of the equipment. Even though a single operator may oversee operations at 

multiple facilities, please complete one survey per geographically distinct facility in order 

for us to determine the locations of equipment and processes.

PERP Equipment Owners: In the case where a company owns and operates equipment 

that is portable (e.g., PERP registered equipment such as drill rigs, portable gas 

compressors) please use the company headquarters contact information as the facility 

description.

Inside a facility there may be different Facility ID numbers provided by the local air 

district (e.g., multiple gas plants). Please provide the facility ID number where indicated. 

In some cases, a Facility ID number may not be available and a generic number must 

be created. One way to create a unique ID number is by using the first two letters of the 

local air district where the facility is located and a number. For example, a facility 

located in San Joaquin Valley APCD could use “SJ1, SJ2, etc.”

Table 2: Facility Production

The Facility Production Table is designed to list active wells, production, and workover

information for the 2007 calendar year. Enter information in the corresponding 

categories. Indicate the number of new wells drilled, completions, and workovers for the 

facility. For well workovers, enter the number that required tubing removal only. The 

number that did not require tubing removal is not required. Well cleanups (also referred 

to as well unloading) include fluids removal or well fracturing, where in either case fluids 

are removed from the well.

There is a separate column listed for underground natural gas storage facilities. Some 

of these facilities may intermittently produce crude oil with the natural gas. For 

simplification, please enter the volume of oil intermittently produced from the gas wells 

in Box 1 under the Natural Gas Storage Column, and enter the total volume of natural 

gas extracted in Box 2. For all companies, please enter the average natural gas 

composition and volume in Box 2.

For crude oil transmission facilities, a section has been included for length of pipeline 

and barrels of crude oil transported. These facilities are located after a production 

facility’s LACT unit. A production facility does not enter information in Box 3.
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-24

Table 3: Facility Electrification

The Facility Electrification Table is designed to determine the level of electrification at 

crude oil and natural gas facilities. This information is important to understand the level 

of electrification within the sector. In some instances, a facility may generate or export 

its own electricity using Generators, Microturbines, Turbines, or Combined Heat and 

Power units. This includes electricity generated from standby or backup, on-site 

generators used in the event of power outages. Please indicate the amount of electricity 

generated, exported, and purchased. Estimated values are acceptable.

Table 4: Vapor Recovery and Flaring

Vapor recovery units consist of flares, thermal oxidizers, incinerators, and carbon 

adsorption units. These units control the release of hydrocarbons and may be designed 

for continuous or emergency operation. Table 4 is to be completed one time for each 

piece of equipment. In most cases, it may be easier to use one of the electronic 

templates.

Enter the throughput volume and rated size of the unit. For flares, enter the size in 

terms of btu/hour. For carbon adsorption units, enter the size in terms of the volume of 

the unit (height x diameter, etc.). In some cases the units are source tested for 

combustion or capture efficiency. If test data are available, please enter the efficiency 

where indicated.

For flares, thermal oxidizers, or incinerators, the average composition of the raw natural 

gas stream is required to enter the average gas composition and calculate the Carbon 

Mole Ratio. In many cases, a Gas Chromatograph (GC) analysis will have all of the 

values but the Carbon Mole Ratio must be calculated. If you are unsure on how to 

calculate these parameters, please call or submit a copy of a GC analysis and we will 

provide assistance. For convenience, the formula and a simplified example are shown 

below.

Carbon Mole Ratio = ��

mole % hydrocarbon

100 � ∗ Number carbons in hydrocarbon

The carbon mole ratio is calculated by adding up each of the mole percentages 

multiplied by the number of carbons in each species. The following is a simplified

example:

Species Mole %

Methane (CH4) 80

Ethane (C2H2) 15

Propane (C3H8) 5

In this example, the carbon mole ratio would be calculated as follows:

Carbon Mole Ratio = (80/100)*(1) + (15/100)*(2) + (5/100)*(3) = 1.25
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-25

Table 5: Combustion Equipment

Table 5 is to be completed one time for each piece of combustion equipment. In most 

cases, it may be easier to use one of the electronic templates. This table is designed to 

accommodate a wide variety of external and internal combustion equipment. List both 

air district and nonair district permitted equipment. The table also includes a box to 

indicate if the equipment is included in the Portable Equipment Registration Program 

(PERP).

The purpose of this survey is to perform an accurate statewide inventory baseline. 

Therefore, this survey includes equipment that is moved more than once annually and 

includes non-air district permitted equipment that is below 50-horsepower in rating.

We have provided examples from which to choose and the option to specify equipment 

not included as an example. For engines powering compressors, enter a unique ID 

number that will be used with the natural gas compressor table (Table 12). This number 

will link the primary driver engine with the natural gas compressor.

Enter the manufacturer name where indicated. For some external combustion units 

(e.g., steam generators) it is acceptable to enter the name of the burner manufacturer if 

no other information is available. Enter the inspection frequency and indicate the 

frequency that involves testing with instruments, visual inspections, and the use of a 

third-party tester. Estimated inspection frequencies are acceptable.

Fuel Type and Fuel Properties

Under fuel type, list the primary and, if necessary, the secondary fuel type and volume 

as metered or calculated. The average Higher Heating Value and Liquid Fuel Density 

may be entered as standard values. If available, it is preferred to have actual values. A 

Gas Chromatograph (GC) analysis will provide the values for you.

In many cases, a GC analysis will list values or allow figures to be computed. If you are

unsure on how to calculate these parameters, please call or submit a copy of a GC 

analysis and we will provide assistance. For convenience, the formula for Gaseous Fuel 

Molecular Weight is provided below.

Gaseous Fuel MW = 1

100 ∗���Mole %compound� ∗ �MWcompound��

Where:

Mole %compound = indicated on GC analysis

MWcompound = �Weightelement ∗ Coefficientelement

An example calculation for MWcompound : CH4 = (12*1) + (1*4) = 16
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-26

Table 6: Component Counts

Table 6 provides a means of organizing components by natural gas, heavy crude, and 

light crude oil. If the actual number of components is unknown for a facility, it is 

acceptable to estimate the number using an average number of components per unit 

and then multiply by the total number of similar units. Table 6 has been designed 

similarly to local air district inspection and maintenance (I&M) programs and should be 

completed in conjunction with Table 8.

Table 7: Automated Control Devices

Automated Control Devices (i.e., pneumatic devices) control the flow of fluids or gases. 

The devices may be connected to a central vapor recovery system or plumbed back into 

a natural gas system (gas recovery). Table 7 has been designed similarly to local air 

district inspection and maintenance (I&M) programs and should be completed in 

conjunction with Table 8.

Typically, a single unit consists of one or more components. For example, a controller is 

used to control an actuator and the actuator is used to operate a block or turbine valve. 

Intermittent bleed devices are the actuators that only emit when actuated. Low bleed 

devices are the controllers that continuously emit less than 6 scfh. Figure 1 shows the 

common components. For additional information, please refer to the manufacturer 

catalogue or look at the EPA Natural Gas Star web site for topics on pneumatic devices, 

such as http://www.epa.gov/gasstar/documents/ll_pneumatics.pdf

Due to design characteristics of the various units, indicate how many controllers and 

actuators are located at the facility and whether the devices are instrument air, gas, or 

electronically actuated. If the actual number of components is unknown for a facility, an 

estimated number of components are acceptable.

Figure 1. Typical Vee-Ball® Valves with Type 1052 Actuators and DVC6020 Digital Valve Controllers.

Controller Ball Valve

Actuator
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-27

Table 8: Inspection and Maintenance Program

An inspection and maintenance (I&M) program requires a facility operator to routinely 

screen for and repair leaks from equipment at their facility. Many facilities are required 

to comply with local air district I&M programs. Table 8 is designed to list how companies 

comply with the various requirements. Check the box or boxes that indicate the stratum 

range that the facility tests to. Indicate a different leak threshold should the facility test to 

a different level within the indicated stratum range.

In many cases oil and gas facilities store I&M data electronically. This data may be 

provided by a third-party tester, etc. If you have I&M data available in electronic format, 

submittal of the information would help prevent overestimating emissions or relying on 

national averages. Please submit electronic I&M program data in any Microsoft Excel or 

Access format. Submittal of hard copy data is not required.

Table 9: Natural Gas Dehydration

Natural Gas Dehydration units are used to remove moisture from a natural gas stream. 

The most common types are glycol and desiccant units. Please complete one table for 

each unit. In some cases, it may be simpler to use one of the electronic templates.

Enter the average input and output gas composition and enter the estimated volume of 

liquids removed for the 2007 calendar year. Indicate if the unit is connected to a vapor 

recovery system and if available, enter the control efficiency of the vapor recovery 

system.

For glycol units, there are fields provided for average circulation rate, pump type, and

stripping gas. Check each box and fill in the appropriate fields that apply. Similarly, a

separate box is included for desiccant units. For desiccant units, indicate the volume of 

the unit (height x diameter, etc.) and indicate the average remaining volume that exists 

after the unit is packed with desiccant (a typical value is 45 percent). If you can estimate 

a more precise percent packed volume value, please provide where indicated.

Table 10: Natural Gas Sweetening or Acid Gas Removal

Natural gas sweetening and acid gas removal units are used to condition gas for 

combustion or resale. Table 10 is designed to accommodate a large variety of units. In 

some cases all fields may not need to be completed. Please complete one table for 

each particular unit. It may be convenient to use one of the electronic templates.

Enter the average input and output gas composition. Enter the Higher Heating Value of 

the input and output gas streams (average values are acceptable).

In some units CO2 is mixed with waste gas and sent to an incinerator or vented. Indicate 

the method of CO2 disposal. For units that require regular solid material replacement, 

indicate the average remaining volume that exists after the unit is packed with material 
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-28

(a typical value is 45 percent). If you can estimate a more precise percent packed 

volume value, please enter the value where indicated.

Table 11: Other Natural Gas Processing

Table 11 is for listing other processing units used for removing natural gas liquids other 

than CO2, H2S, and water. Please complete one table for each particular unit. It may be

convenient to use one of the electronic templates.

Enter the average input and output gas composition and average volume of liquids 

removed. Indicate if the unit is connected to a vapor recovery system and list the 

estimated control efficiency of the vapor recovery system where indicated. In some 

cases it may be necessary to estimate total throughput.

Table 12: Natural Gas Compressors

Table 12 is designed to cover a variety of natural gas compressors. Please complete 

one table for each individual unit. This table should be completed using the unique 

compressor ID number from Table 5. This will link the compressor with the primary 

driver engine.

The primary types of compressors are reciprocating, centrifugal, rotary, and integral. In 

an integral unit, the primary driver engine and compressor are combined into a single 

unit. In other cases, the primary driver engine (internal combustion or turbine engine) 

are separated by a drive shaft.

For centrifugal units, indicate the type and number of wet or dry seals under the

corresponding seal type. Wet seals, also known as lubricated seals, use oil as a means 

to retain internal compressor pressure. Wet seal units may be identified as having a 

separate “seal oil” pump used to maintain seal pressure. Dry seal compressors may be 

identified as having a separate “seal gas” outlet for gas to escape the compressor. Both 

wet and dry seal compressors will have a lube oil pump.

Indicate the primary driver and starter type. Enter the average discharge and idle 

pressure in units of pounds per square inch and the discharge temperature in degrees 

F. The discharge pressure is the average pressure inside the unit during operation. The 

idle pressure is the average pressure when the unit is idle.

Indicate the hours of usage, number of start-ups and blowdowns, and the inspection

frequency. The maintenance frequency is the number of times the unit had to be

disassembled to replace valves, seals, or packing. If actual numbers are not available,

estimated values are acceptable.
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-29

Table 13: Pipelines

Table 13 pertains to natural gas gathering systems found within an extraction or 

underground natural gas storage facility (prior to a gas meter). Enter, or estimate, the 

length of the natural gas pipeline gathering system where indicated. Enter estimated 

volumes depicting how gas is handled for system maintenance or modification activities.

Table 13 also pertains to crude oil transmission and natural gas pipeline pigging 

operations conducted at the facility. Enter, or estimate how many times a pig was sent 

or received for the 2007 calendar year. Please indicate whether the operations were for 

crude oil or natural gas pipeline.

Table 14: Crude Oil or Natural Gas Separation Units

Table 14 is designed to accommodate a variety of crude oil and natural gas separation 

units. There are a variety of units in this category. We have included a list of some 

examples and an option to specify units at the facility that may go by a different name. 

Please complete one table per individual unit. In some cases, it may be more 

convenient to use one of the electronic templates provided.

Enter the Working, Breathing, and Flashing Losses as calculated with TANKS (US

Environmental Protection Agency) or similar software or calculation, or enter the values 

as listed on the district permit. If the calculations have not been performed and are not 

required by the local air district, please leave these fields blank.

In order to prevent double counting of components, indicate if the separation unit 

components were included in Table 6 and indicate if the unit is controlled by a vapor 

recovery system.

Table 15: Crude Oil Separation Units Sumps or Pits

Crude oil separation sumps or pits are used to separate water from crude oil and may 

be used for permanent or emergency purposes. Indicate whether the sump is primary, 

secondary, or tertiary and list the average crude oil API number and number of days the 

sump or pit was in use. In some cases, a sump may be used in conjunction with a cover 

or a vapor collection system. Please indicate if either type of system is used.

Table 16: Crude Oil Storage Tanks

Table 16 is designed to accommodate fixed roof and floating roof crude oil storage 

tanks. Please complete one table per storage tank. In some cases, it may be convenient 

to use one of the electronic templates.

Enter the tank type, size, and average crude oil API number. Enter the number of 

degassing events that required the tank to be completely emptied of liquid and vapor. 
Appendix A Final 2007 Oil and Gas Industry Survey Results

A-30

For fixed roof and floating roof tanks, enter the Working, Breathing, and Flashing 

Losses as reported to the local air district. If available, enter the average methane and 

carbon dioxide values as depicted in a Gas Chromatograph analysis. If information is 

not available for methane or carbon dioxide concentration, please leave those fields 

blank.
Appendix B Final 2007 Oil and Gas Industry Survey Results

B-1

Appendix B: Emission Calculation Methodologies and Corresponding 

Emission Factors

California Air Resources Board

Oil and Gas Industry Survey

Emission Calculation Methodologies 

and 

Corresponding Emission Factors
Appendix B Final 2007 Oil and Gas Industry Survey Results

B-2
Appendix B Final 2007 Oil and Gas Industry Survey Results

B-3

Appendix B details the individual equations and emission factors used to calculate 

greenhouse gas emissions. Default mole percent of CH4 and CO2 are 78.8 percent and 

3 percent, respectively (API, 2004). For equipment that has vapor recovery, CO2 and 

CH4 emissions are reduced by the vapor recovery efficiency before conversion to CO2e. 

All CO2, CH4, and N2O values are multiplied by their corresponding GWP (1 for CO2, 21 

for CH4, and 310 for N2O) to get the CO2e number.

Method 1 – Active Wells 

The 2007 Industry survey separates crude oil into four categories: ultra-heavy, heavy, 

light, and ultra-light. It also separates gas wells by dry gas fields and gas storage fields. 

When calculating GHG emissions from active wells, the categories ultra-heavy and 

heavy crude use the emission factor “heavy crude”, light and ultra-light crude use the 

emission factor “light crude”, and dry gas and gas storage use the emission factor 

“natural gas”. 

CO2 emissions (tonnes/year) = (CO2 EF)*(Number)*(CO2 Mole Fraction\0.03)

Where 

CO2 EF = See Table 1

Number = Number of active wells

CO2 Mole Fraction = (lbmole CO2)/(lbmole gas)

Data Requirements

1. Number of active wells

2. Mole % CO2

CH4 emissions (tonnes/year) = (CH4 EF)*(Number)*(CH4 Mole Fraction\0.788)

Where 

CH4 EF = See Table 1

Number = Number of active wells

CH4 Mole Fraction = (lbmole CH4)/(lbmole gas)

Data Requirements

1. Number of active wells

2. Mole % CH4

Table 1: Wellheads

Type CH4

(tonnes/well-year)

% Methane 

Assumption

CO2

(tonnes/well-year)

% CO2

Assumption

Natural Gas 0.1571 78.8 1.644E-021 3

Light Crude 0.1081 78.8 1.128E-021 3

Heavy Crude 4.568E-031 78.8 4.782E-04 3

1. API (2004)
Appendix B Final 2007 Oil and Gas Industry Survey Results

B-4

Method 2 – Well Cellars

The 2007 Industry survey separates crude oil into four categories: ultra-heavy, heavy, 

light, and ultra-light. When calculating GHG emissions from well cellars, an average 

dimension of 6 feet by 6 feet is used (Kern County APCD,1990). Additionally, the 

categories ultra-heavy and heavy crude use the emission factor “heavy crude”, light and 

ultra-light crude use the emission factor “light crude”.

CH4 emissions (tonnes/year) = (CH4 EF)*(Number)

Where

CH4 EF = See Table 2

Number = number of well cellars

Data Requirements

1. Number of well cellars

Table 2: Well Cellars 

Type CH4

(tonnes/well cellar-year)

Light Crude 0.1701

Heavy Crude 0.1251

1. Kern County APCD (1990)

Method 3 – New Wells Drilled

CH4 emissions (tonnes/year) = (CH4 EF)*(Number)

Where 

CH4 EF = See Table 3

Number = Number of wells drilled

Data Requirements

1. Number of wells drilled

Table 3: New Wells Drilled

Type CH4

(tonnes/well-year)

Natural Gas

Light Crude

Heavy Crude

Method 4 – Well Workovers and Cleanups

The calculations for well workovers and cleanups assume an average well depth, 

casing diameter, and tubing diameter and that only one well volume is released. For 

crude oil wells, the volume of gas released is assumed to be the space between the 

casing and tubing. For natural gas wells, the volume of gas released is assumed to be 

the entire volume of the casing. 
Appendix B Final 2007 Oil and Gas Industry Survey Results

B-5

CO2 emissions (tonnes/year) = (EF)*(CO2 Mole Fraction)*(D)* (Events)

Where 

EF = See Table 4

CO2 Mole Fraction = (lbmole CO2)/(lbmole gas)

D = (molar volume)*(Molecular Weight CO2)*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CO2 = (44 lb CO2)/(lbmole CO2)

Events = Number of well workovers and cleanups

Data Requirement

1. Number of well workovers and cleanups

2. Mole % CO2

CH4 emissions (tonnes/year) = (EF)*(CH4 Mole Fraction)*(D)* (Events)

Where 

EF = See Table 4

CH4 Mole Fraction = (lbmole CH4)/(lbmole gas)

D = (molar volume)*(Molecular Weight CH4)*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CH4 = (16 lb CH4)/(lbmole CH4)

Events = Number of well workovers and cleanups

Data Requirement

1. Number of well workovers and cleanups

2. Mole % CH4

Emission Factor Calculation (Listed in Table 4)

Equation = [(V)*(P1)*(T2)]/[(P2)*(T1)]

Where

V = volume of well 

P1 = shut-in pressure (psia) of well

P2 = 14.7 psia (standard surface pressure)

T1 = temperature in well at shut-in pressure

T2 = 60° F (standard surface temperature)

Assumptions

Depth = 5000 ft

Casing Diameter = 7 in

Tubing Diameter = 2.875 in

P1 = 100 psia

T1 = 60° F

Table 4: Well Workovers and Cleanups

Type CH4/CO2

(scf/event)

Natural Gas 9090.256

Light Crude 7556.855

Heavy Crude 7556.855
Appendix B Final 2007 Oil and Gas Industry Survey Results

B-6

Method 5 – Well Completions

CH4 emissions (tonnes/year) = (CH4 EF)*(Number)

Where 

CH4 EF = See Table 5

Number = Number of wells completed

Data Requirements

1. Number of wells completed

Table 5: Well Completions

Type CH4

(tonnes/well)

Natural Gas

Light Crude

Heavy Crude

Method 6 – Flares, Incinerators, Thermal Oxidizers 

CO2 and CH4 emission calculations based on the following mass balance equations 

(API, 2004). 

CO2 emissions (tonnes/year) = (Combustion Emissions) + (Vented Emissions)

Combustion emissions (tonnes/year) = (Throughput)*(Carbon Mole Ratio)*(Combustion Efficiency)*(D)

Where 

Throughput = volume of gas flared (scf gas/year)

Carbon Mole Ratio = ∑[(mole % hydrocarbon/100)*(# carbons in hydrocarbon)]

D = (molar volume)*(Molecular Weight CO2)*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CO2 = (44 lb CO2)/(lb mole CO2)

Data Requirements

1. Throughput (scf gas/year)

2. Combustion Efficiency (98% will be assumed if no combustion efficiency is supplied)

3. Carbon Mole Ratio of gas

Vented emissions (tonnes/year) = (Throughput)*(CO2 Mole Fraction)*(D)

Where

Throughput = volume of gas flared (scf/year)

CO2 Mole Fraction = (lbmole CO2)/(lbmole gas)

D = (molar volume)*(Molecular Weight CO2)*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CO2 = (44 lb CO2)/(lb mole CO2)

Data Requirements

1. Throughput (scf/year)

2. Mole % CO2
Appendix B Final 2007 Oil and Gas Industry Survey Results

B-7

CH4 emissions (tonnes/year) = (Throughput)*(CH4 Mole Fraction)*(% Residual CH4)*(D)

Where 

Throughput = volume of gas flared (scf gas/year)

CH4 Mole Fraction = (lbmole CH4)/(lbmole gas)

% Residual CH4 = 100 – (Combustion Efficiency)

D = (molar volume)*(Molecular Weight CH4)*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CH4 = (16 lb CH4)/(lb mole CH4)

Data Requirements

1. Throughput (scf gas/year)

2. Combustion Efficiency (98% will be assumed if no combustion efficiency is supplied)

3. Mole % CH4

N2O emissions (tonnes/year) = (Throughput)*(N2O Emission Factor)

Where

Throughput = volume of gas flared (scf gas/year)

N2O Emission Factor = 1E-10 tonnes/scf gas (INGAA, 2005)

Data Requirements

1. Throughput (scf/year)

Method 7 – Carbon Adsorbers

The vented emission calculation for carbon adsorbers assumes that 100% of the 

methane in the gas stream passes through the adsorber.

CH4 emissions (tonnes/year) = (Throughput)*(CH4 Mole Fraction)*(D)

Where 

Throughput = volume of gas (scf gas/year)

CH4 Mole Fraction = (lbmole CH4)/(lbmole gas)

D = (molar volume)*(Molecular Weight CH4)*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CH4 = (16 lb CH4)/(lbmole CH4)

Data Requirements

1. Throughput (scf gas/year)

2. Mole % CH4

Method 8 – Mass Balance Fuel Consumption

CO2 and CH4 combustion calculations for all combustion equipment (except flares, 

incinerators, and thermal oxidizers) are based on the following mass balance equations 

(INGAA, 2005).
Appendix B Final 2007 Oil and Gas Industry Survey Results

B-8

Gaseous Fuels

CO2 emissions (tonnes/year) = (Combustion Emissions) + (Vented Emissions)

Combustion Emissions (tonnes/year) = (Fuel Use)*(MWfuel)*(Carbon Weight %)*(COX)*(D) 

Where

Fuel Use = fuel use (scf/year)

MWfuel = molecular weight of fuel (lb fuel/lbmole fuel)

Carbon Weight % = (lb C/lb fuel)

COX = fraction of fuel oxidized (assumed to be 99%)

D = (molar volume)*(1/MWC)*(lbmole CO2/lbmole C)*(MWCO2)*(tonne/2204.6 lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

MWC = (12 lb C)/(lb mole C)

MWCO2 = (44 lb CO2)/(lb mole CO2)

Data Requirements

1. Fuel Use (scf gas/year)

2. Molecular Weight of fuel

3. Carbon Weight % of fuel

4. COX (if different from assumed value of 99%)

Vented Emissions (tonnes/year) = (Fuel Use)*(1-COX)*(CO2 Mole Fraction)*(D)

Where

Fuel Use = fuel use (scf/year)

COX = fraction of fuel oxidized (assumed to be 99%)

D = (molar volume)*(MWCO2)*(tonne/2204.6 lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

MWCO2 = (44 lb CO2)/(lb mole CO2)

Data Requirements

1. Fuel Use (scf gas/year)

2. COX (if different from assumed value of 99%)

3. Mole % CO2

CH4 emissions (tonnes/year) = (Fuel Use)*(CH4 Mole Fraction)*(1-COX)*(D)

Where

Fuel Use = fuel use (scf/year)

COX = fraction of fuel oxidized (assumed to be 99%)

D = (molar volume)*(MWCH4)*(tonne/2204.6 lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

MWCH4 = (16 lb CH4)/(lb mole CH4)

Data Requirements

1. Fuel Use (scf gas/year)

2. COX (if different from assumed value of 99%)

3. Mole % CH4
Appendix B Final 2007 Oil and Gas Industry Survey Results

B-9

Liquid Fuels

CO2 emissions (tonnes/year) = (Fuel Use)*(Fuel Density)*(Carbon Weight %)*(COX)*(D)

Where

Fuel Use = fuel use (gal/year)

Fuel Density = density of fuel (lb fuel/gal fuel)

Carbon Weight % = (lb C/lb fuel)

COX = fraction of fuel oxidized (assumed to be 99%)

D = (1/MWC)*(lbmole CO2/lbmole C)*(MWCO2)*(tonne/2204.6 lb)

MWC = (12 lb C)/(lb mole C)

MWCO2 = (44 lb CO2)/(lb mole CO2)

Data Requirements

1. Fuel Use (gal fuel/year)

2. Fuel Density

3. Carbon Weight % of fuel

4. COX (if different from assumed value of 99%)

Method 9 - Equipment Specific

Combustion calculations for equipment with equipment specific emission factors. This 

method is used only for those equipment that have emission factors listed in Table 6. 

CO2 emissions (tonnes/year) = (Fuel Use)*(HHV)*(CO2 Emission Factor)*(10-6)

Where

Fuel Use = volume of fuel used (scf/year or gal/year)

HHV = Higher Heating Value of fuel (Btu/scf or Btu/gal)

CO2 Emission Factor = See Table 6

Data Requirement

1. Type of equipment

2. Fuel Use (scf/year or gal/year)

3. HHV of fuel (Btu/scf or Btu/gal)

CH4 emissions (tonnes/year) = (Fuel Use)*(HHV)*(CH4 Emission Factor)*(10-6)

Where

Fuel Use = volume of fuel used (scf/year or gal/year)

HHV = Higher Heating Value of fuel (Btu/scf or Btu/gal)

CH4 Emission Factor = See Table 6

Data Requirement

1. Type of equipment

2. Fuel Use (scf/year or gal/year)

3. HHV of fuel (Btu/scf or Btu/gal)

N2O emissions (tonnes/year) = (Fuel Use)*(HHV)*(N2O Emission Factor)*(10-6)

Where

Fuel Use = volume of fuel used (scf/year or gal/year)

HHV = Higher Heating Value of fuel (Btu/scf or Btu/gal)

N2O Emission Factor = See Table 6
Appendix B Final 2007 Oil and Gas Industry Survey Results

B-10

Data Requirement

1. Type of equipment

2. Fuel Use (scf/year or gal/year)

3. HHV of fuel (Btu/scf or Btu/gal)

Table 6: Combustion Equipment 

Equipment Type CO2

(tonnes/MMBtu)

CH4

(tonnes/MMBtu)

N2O

(tonnes/MMBtu)

Natural Gas Fired

Boilers 0.05342 1.023E-064 9.8E-075

Steam Generators 0.05342 1.023E-064 9.8E-075

Heaters 0.05342 1.023E-064 9.8E-075

Reciprocating Engine

 Two – Stroke Lean 0.04993 6.577E-044 2.3E-065

 Four – Stroke Lean 0.04993 5.670E-044 1.4E-065

 Four – Stroke Rich 0.04993 1.043E-044 4.5E-075

Turbine 0.04993 3.901E-064 3.8E-065

Diesel Fired

Reciprocating Engine

 Two – Stroke Lean 0.07441 4E-065

 Two – Stroke Rich 0.07441 4E-065

 Four – Stroke Lean 0.07441 4E-065

 Four – Stroke Rich 0.07441 4E-065

Gasoline Fired

Reciprocating Engine

 Two – Stroke Lean 0.06991 1.2E-045

 Two – Stroke Rich 0.06991 1.2E-045

 Four – Stroke Lean 0.06991 3.9-055

 Four – Stroke Rich 0.06991 3.9-055

Landfill Gas Fired

Turbine 0.02273

1. EPA (1996b); 2. EPA (1998); 3. EPA (2000); 4. API (2004); 5. INGAA (2005)

Method 10 – Fuel Based

Combustion calculations for equipment using fuel based emission factors listed in Table 

7.

CO2 emissions (tonnes/year) = (Fuel Use)*(HHV)*(CO2 Emission Factor)*(10-6)

Where

Fuel Use = volume of fuel used (scf/year or gal/year)

HHV = Higher Heating Value of fuel (Btu/scf or Btu/gal)

CO2 Emission Factor = See Table 7

Data Requirement

1. Fuel Use (scf/year or gal/year)

2. HHV of fuel (Btu/scf or Btu/gal)

CH4 emissions (tonnes/year) = (Fuel Use)*(HHV)*(CH4 Emission Factor)*(10-6)

Where

Fuel Use = volume of fuel used (scf/year or gal/year)

HHV = Higher Heating Value of fuel (Btu/scf or Btu/gal)

CH4 Emission Factor = See Table 7
Appendix B Final 2007 Oil and Gas Industry Survey Results

B-11

Data Requirement

1. Fuel Use (scf/year or gal/year)

2. HHV of fuel (Btu/scf or Btu/gal)

N2O emissions (tonnes/year) = (Fuel Use)*(HHV)*(N2O Emission Factor)*(10-6)

Where

Fuel Use = volume of fuel used (scf/year or gal/year)

HHV = Higher Heating Value of fuel (Btu/scf or Btu/gal)

N2O Emission Factor = See Table 7

Data Requirement

1. Fuel Use (scf/year or gal/year)

2. HHV of fuel (Btu/scf or Btu/gal)

Table 7: Fuels

Fuel Type CO2

(tonnes/MMBtu)

CH4

(tonnes/MMBtu)

N2O

(tonnes/MMBtu)

Natural Gas

 Unspecified 0.053021 9E-071 1E-071

 975 to 1,000 Btu/scf 0.053971 9E-071 1E-071

 1,000 to 1,025 Btu/scf 0.052871 9E-071 1E-071

 1,025 to 1,050 Btu/scf 0.053021 9E-071 1E-071

 1,050 to 1,075 Btu/scf 0.053421 9E-071 1E-071

 1,075 to 1,100 Btu/scf 0.053681 9E-071 1E-071

 > 1,100 Btu/scf 0.054671 9E-071 1E-071

Landfill Gas 0.052031 9E-071 1E-071

Diesel 0.07312 3E-061 6E-071

Liquidfied Petroleum Gas 0.062981 1E-061 1E-071

Propane 0.063021 1E-061 1E-071

Gasoline 0.070831 3E-061 6E-071

1. ARB Manditory Reporting (2008) 

2. ARB Manditory Reporting (2008) Distillate Fuel Oil #1, #2, #4

Method 11 – Components

Components for other equipment (e.g. storage tanks) will be backed out of this 

calculation.

CO2 emissions (tonnes/year) = (CO2 EF)*(Number)*(CO2 Mole Fraction/0.03)

Where 

CO2 EF = See Table 8

Number = Number of components

CO2 Mole Fraction = (lbmole CO2)/(lbmole gas)

Data Requirements

1. Mole % CO2

2. Number of components
Appendix B Final 2007 Oil and Gas Industry Survey Results

B-12

CH4 emissions (tonnes/year) = (CH4 EF)*(Number)*(CH4 Mole Fraction/0.788)

Where 

CH4 EF = See Table 8

Number = Number of components

CH4 Mole Fraction = (lbmole CH4)/(lbmole gas)

Data Requirements

1. Mole % CH4

2. Number of components

Table 8: Components

Component Type Natural Gas1 Light Crude2 Heavy Crude3

(tonnes/component-year)

CH4 (78.8% Methane Assumption)

Manual Valves 1.759E-044 1.348E-044 1.341E-044

Flanges 1.407E-044 1.703E-044 2.203E-044

Connectors 6.029E-054 7.095E-054 7.661E-054

Open-ended Lines 1.206E-044 1.277E-044 1.436E-044

Threaded Components 6.029E-054 7.095E-054 7.661E-054

Pump Seals 5.004E-034 1.880E-034 5.458E-044

Pressure Relief Valves 7.386E-044 9.294E-044 5.458E-044

Bursting Discs 7.386E-044 9.294E-044 5.458E-044

Diaphragms 7.386E-044 9.294E-044 5.458E-044

Drains 7.386E-044 9.294E-044 5.458E-044

Hatches 7.386E-044 9.294E-044 5.458E-044

Instruments 7.386E-044 9.294E-044 5.458E-044

Meters 7.386E-044 9.294E-044 5.458E-044

Polished Rod Stuffing Boxes 7.386E-044 9.294E-044 5.458E-044

Sight Glasses 7.386E-044 9.294E-044 5.458E-044

Loading Arms 7.386E-044 9.294E-044 5.458E-044

Dump Lever Arm 7.386E-044 9.294E-044 5.458E-044

CO2 (3% CO2 Assumption) 

Manual Valves 2.247E-054 1.411E-054 1.404E-054

Flanges 1.473E-054 1.783E-054 2.306E-054

Connectors 6.312E-064 7.428E-064 8.021E-064

Open-ended Lines 1.263E-054 1.337E-054 1.504E-054

Threaded Components 6.312E-064 7.428E-064 8.021E-064

Pump Seals 5.239E-044 1.968E-044 5.715E-054

Pressure Relief Valves 7.733E-054 9.730E-054 5.715E-054

Bursting Discs 7.733E-054 9.730E-054 5.715E-054

Diaphrams 7.733E-054 9.730E-054 5.715E-054

Drains 7.733E-054 9.730E-054 5.715E-054

Hatches 7.733E-054 9.730E-054 5.715E-054

Instruments 7.733E-054 9.730E-054 5.715E-054

Meters 7.733E-054 9.730E-054 5.715E-054

Polished Rod Stuffing Boxes 7.733E-054 9.730E-054 5.715E-054

Sight Glasses 7.733E-054 9.730E-054 5.715E-054

Loading Arms 7.733E-054 9.730E-054 5.715E-054

Dump Lever Arm 7.733E-054 9.730E-054 5.715E-054

1. Assume THC is 70% CH4; 2. Assume THC is 74% CH4; 3. Assume THC is 72% CH4; 4. CAPCOA (1999)
Appendix B Final 2007 Oil and Gas Industry Survey Results

B-13

Method 12 – Automated Control Devices

CO2 emissions (tonnes/year) = (CO2 Emission Factor)*(CO2 Mole Fraction/0.03)*(# Devices)

Where 

CO2 Emission Factor = See Table 9

CO2 Mole Fraction = (lbmole CO2)/(lbmole gas)

# Devices = Number of automated control devices

Data Requirements

1. Mole % CO2

2. Number of automated control devices

CH4 emissions (tonnes/year) = (CH4 Emission Factor)*(CH4 Mole Fraction/0.788)*(# Devices)

Where 

CH4 Emission Factor = See Table 9

CH4 Mole Fraction = (lbmole CH4)/(lbmole gas)

# Devices = Number of automated control devices

Data Requirements

1. Mole % CH4

2. Number of automated control devices

Table 9: Automated Control Devices

Device Type CH4

(tonnes/device-year)

% Methane 

Assumption

CO2

(tonnes/device-year)

% CO2

Assumption

Controllers 

Continuous Bleed 3.5991 78.8 0.3771 3

Intermittent Bleed 1.7781 78.8 0.1861 3

Low Bleed 0.7922 78.8 0.0832 3

Actuators - Production

Piston Valve Operator 7.237E-043 78.8 7.577E-05 3

Hydraulic Valve Operator 4.095E-023 78.8 4.287E-03 3

Turbine Valve Operator 1.086E-023 78.8 1.137E-03 3

1. API (2004); 2. EPA (2003a); 3. EPA (1996a)
Appendix B Final 2007 Oil and Gas Industry Survey Results

B-14

Method 13 – Natural Gas Dehydration (Glycol Units)

Vented emissions from glycol dehydrators (CEC 2006).

CO2 emissions (tonnes/year) = (Throughput)*(EF\0.90)*(CO2 Mole Fraction)*D

Where 

EF = [(0.0066)*(GCR)*(P)*(GAP)] + (SG)

EF units = (Mcf CH4/year per MMcf gas throughput/day)

EF conversion = [(1 year)/(365 days)]*[(1 MMcf gas)/(106 scf gas)]*[(1000 scf CH4)/(1 Mcf CH4)]

0.90 = % methane used to create EF (lbmole CH4)/(lbmole gas)

GCR = glycol circulation rate (gph)

P = flash tank or contactor pressure (psia)

GAP = 2.5 if a gas assist pump is installed or 1.0 if there is no gas assist pump

SG = 0.245 if stripping gas is used or 0 if no stripping gas is used

CO2 Mole Fraction = (lbmole CO2)/(lbmole gas)

D = (CH4 Density)*(lb/453.5 grams)*(1/MWCH4)*(MW CO2)*(tonne/2204.6lb)*(EF conversion)

CH4 Density = (19.2 grams)/(scf CH4)

MW CH4 = (16 lb CH4)/(lbmole CH4)

MW CO2 = (44 lb CO2)/(lbmole CO2)

Data Requirements

1. Throughput (scf/year)

2. Input Mole % CO2

3. Glycol circulation rate (gallons/hour)

4. Flash tank pressure (psia) 

5. Contactor pressure (psia)

6. Gas assist pump installation

7. Stripping gas use

CH4 emissions (tonnes/year) = (Throughput)*(EF\0.90)*(CH4 Mole Fraction)*D

Where 

EF = [(0.0066)*(GCR)*(P)*(GAP)] + (SG)

EF units = (Mcf CH4/year per MMcf gas throughput/day)

EF conversion = [(1 year)/(365 days)]*[(1 MMcf gas)/(106 scf gas)]*[(1000 scf CH4)/(1 Mcf CH4)]

0.90 = % methane used to create EF (lbmole CH4)/(lbmole gas)

GCR = glycol circulation rate (gph)

P = flash tank or contactor pressure (psia)

GAP = 2.5 if a gas assist pump is installed or 1.0 if there is no gas assist pump

SG = 0.245 if stripping gas is used or 0 if no stripping gas is used

CH4 Mole Fraction = (lbmole CH4)/(lbmole gas)

D = (CH4 Density)*(lb/453.5 grams)*(tonne/2204.6lb)*(EF conversion)

CH4 Density = (19.2 grams)/(scf CH4)

Data Requirements

1. Throughput (scf/year)

2. Input Mole % CH4

3. Glycol circulation rate (gallons/hour)

4. Flash tank pressure (psia) 

5. Contactor pressure (psia)

6. Gas assist pump installation

7. Stripping gas use
Appendix B Final 2007 Oil and Gas Industry Survey Results

B-15

Method 14 – Natural Gas Dehydration (Desiccant Units)

Vented emissions from refilling desiccant (EPA 2003b).

CO2 emissions (tonnes/year) = (EF)*(CO2 Mole Fraction)*D

Where 

EF = [(P2)*(G)*(365 days/yr)*(V)]\[(P1)*(T)]

P1 = 14.7 psia (atmospheric pressure)

P2 = (Pressure of Gas (psig)) + 14.7

G = % of Packed Vessel Volume that is Natural Gas

V = Volume of Dehydrator (ft3

)

T = Frequency of Desiccant Replacement (days)

CO2 Mole Fraction = (lbmole CO2)/(lbmole gas)

D = (molar volume)*(Molecular Weight CO2)*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CO2 = (44 lb CO2)/(lbmole CO2)

Data Requirements

1. Mole % CO2

2. Volume of Dehydrator

3. Pressure of Natural Gas 

4. Frequency of Desiccant Replacement

5. % of Packed Vessel Volume that is Natural Gas (45% will be assumed if no value is 

provided)

CH4 emissions (tonnes/year) = (EF)*(CH4 Mole Fraction)*D

Where 

EF = [(P2)*(G)*(365 days/yr)*(V)]\[(P1)*(T)]

P1 = 14.7 psia (atmospheric pressure)

P2 = (Pressure of Gas (psig)) + 14.7

G = % of Packed Vessel Volume that is Natural Gas

V = Volume of Dehydrator (ft3

)

T = Frequency of Desiccant Replacement (days)

CH4 Mole Fraction = (lbmole CH4)/(lbmole gas)

D = (molar volume)*(Molecular Weight CH4)*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CH4 = (16 lb CH4)/(lbmole CH4)

Data Requirements

1. Mole % CH4

2. Volume of Dehydrator

3. Pressure of Natural Gas 

4. Frequency of Desiccant Replacement

5. % of Packed Vessel Volume that is Natural Gas (45% will be assumed if no value is 

provided)
Appendix B Final 2007 Oil and Gas Industry Survey Results

B-16

Method 15 – Natural Gas Dehydration Fugitive Emissions

Fugitive emission calculations using mass balance.

CO2 emissions (tonnes/year) = (Mass Balance) – (Vented Emissions)

Where

Mass Balance = D*[(Input)*(In CO2 Mole Fraction) – (Output)*(Out CO2 Mole Fraction)]

Vented Emissions = Method 13 or Method 14

Input = Input volume (scf/year)

Output = Output volume (scf/year)

In CO2 Mole Fraction = Input CO2 Mole Fraction = (lbmole CO2)/(lbmole gas)

Out CO2 Mole Fraction = Output CO2 Mole Fraction = (lbmole CO2)/(lbmole gas)

D = (molar volume)*(Molecular Weight CO2)*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CO2 = (44 lb CO2)/(lbmole CO2)

Data Requirements

1. Input volume (scf/year)

2. Output volume (scf/year)

3. Input Mole % CO2

4. Output Mole % CO2

5. Vented Emissions

CH4 emissions (tonnes/year) = (Mass Balance) – (Vented Emissions)

Where

Mass Balance = D*[(Input)*(In CH4 Mole Fraction) – (Output)*(Out CH4 Mole Fraction)]

Vented Emissions = Method 13 or Method 14

Input = Input volume (scf/year)

Output = Output volume (scf/year)

In CH4 Mole Fraction = Input CH4 Mole Fraction = (lbmole CH4)/(lbmole gas)

Out CH4 Mole Fraction = Output CH4 Mole Fraction = (lbmole CH4)/(lbmole gas)

D = (molar volume)*(Molecular Weight CH4)*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CH4 = (16 lb CH4)/(lbmole CH4)

Data Requirements

1. Input volume (scf/year)

2. Output volume (scf/year)

3. Input Mole % CH4

4. Output Mole % CH4

5. Vented Emissions
Appendix B Final 2007 Oil and Gas Industry Survey Results

B-17

Method 16 –Natural Gas Sweetening/Acid Gas Removal (Solid Material Units)

Vented emissions from refilling solid material (EPA 2003b).

CO2 emissions (tonnes/year) = (EF)*(CO2 Mole Fraction)*D

Where 

EF = [(P2)*(G)*(365 days/yr)*(V)]\[(P1)*(T)]

P1 = 14.7 psia (atmospheric pressure)

P2 = (Pressure of Gas (psig)) + 14.7

G = % of Packed Vessel Volume that is Natural Gas

V = Volume of Unit (ft3

)

T = Frequency of Solid Material Replacement (days)

CO2 Mole Fraction = (lbmole CO2)/(lbmole gas)

D = (molar volume)*(Molecular Weight CO2)*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CO2 = (44 lb CO2)/(lbmole CO2)

Data Requirements

1. Input Mole % CO2

2. Volume of unit

3. Pressure of Natural Gas 

4. Frequency of solid material replacement

5. % of Packed Vessel Volume that is Natural Gas (45% will be assumed if no value is 

provided)

CH4 emissions (tonnes/year) = (EF)*(CH4 Mole Fraction)*D

Where 

EF = [(P2)*(G)*(365 days/yr)*(V)]\[(P1)*(T)]

P1 = 14.7 psia (atmospheric pressure)

P2 = (Pressure of Gas (psig)) + 14.7

G = % of Packed Vessel Volume that is Natural Gas

V = Volume of Unit (ft3

)

T = Frequency of Solid Material Replacement (days)

CH4 Mole Fraction = (lbmole CH4)/(lbmole gas)

D = (molar volume)*(Molecular Weight CH4)*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CH4 = (16 lb CH4)/(lbmole CH4)

Data Requirements

1. Input Mole % CH4

2. Volume of unit

3. Pressure of Natural Gas 

4. Frequency of solid material replacement

5. % of Packed Vessel Volume that is Natural Gas (45% will be assumed if no value is 

provided)
Appendix B Final 2007 Oil and Gas Industry Survey Results

B-18

Method 17 – Natural Gas Sweetening/Acid Gas Removal Fugitive Emissions 

(Solid Material Units)

Fugitive emission calculations using mass balance.

CO2 emissions (tonnes/year) = (Mass Balance) – (Vented Emissions)

Where

Mass Balance = D*[(Input)*(In CO2 Mole Fraction) – (Output)*(Out CO2 Mole Fraction)]

Vented Emissions = Method 16

Input = Input volume (scf/year)

Output = Output volume (scf/year)

In CO2 Mole Fraction = Input CO2 Mole Fraction = (lbmole CO2)/(lbmole gas)

Out CO2 Mole Fraction = Output CO2 Mole Fraction = (lbmole CO2)/(lbmole gas)

D = (molar volume)*(Molecular Weight CO2)*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CO2 = (44 lb CO2)/(lbmole CO2)

Data Requirements

1. Input volume (scf/year)

2. Output volume (scf/year)

3. Input Mole % CO2

4. Output Mole % CO2

5. Vented Emissions

CH4 emissions (tonnes/year) = (Mass Balance) – (Vented Emissions)

Where

Mass Balance = D*[(Input)*(In CH4 Mole Fraction) – (Output)*(Out CH4 Mole Fraction)]

Vented Emissions = Method 16

Input = Input volume (scf/year)

Output = Output volume (scf/year)

In CH4 Mole Fraction = Input CH4 Mole Fraction = (lbmole CH4)/(lbmole gas)

Out CH4 Mole Fraction = Output CH4 Mole Fraction = (lbmole CH4)/(lbmole gas)

D = (molar volume)*(Molecular Weight CH4)*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CH4 = (16 lb CH4)/(lbmole CH4)

Data Requirements

1. Input volume (scf/year)

2. Output volume (scf/year)

3. Input Mole % CH4

4. Output Mole % CH4

5. Vented Emissions
Appendix B Final 2007 Oil and Gas Industry Survey Results

B-19

Method 18 – Natural Gas Sweentening/Acid Gas Removal Mass Balance (Nonsolid Material Units)

Fugitive emissions from natural gas sweetening or acid gas removal.

CO2 emissions (tonnes/year) = D*[(Input)*(In CO2 Mole Fraction) – (Output)*(Out CO2 Mole Fraction)]

Where

Input = Input volume (scf/year)

Output = Output volume (scf/year)

In CO2 Mole Fraction = Input CO2 Mole Fraction = (lbmole CO2)/(lbmole gas)

Out CO2 Mole Fraction = Output CO2 Mole Fraction = (lbmole CO2)/(lbmole gas)

D = (molar volume)*(Molecular Weight CO2)*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CO2 = (44 lb CO2)/(lbmole CO2)

Data Requirements

1. Input volume (scf/year)

2. Output volume (scf/year)

3. Input Mole % CO2

4. Output Mole % CO2

CH4 emissions (tonnes/year) = D*[(Input)*(In CH4 Mole Fraction) – (Output)*(Out CH4 Mole Fraction)]

Where

Input = Input volume (scf/year)

Output = Output volume (scf/year)

In CH4 Mole Fraction = Input CH4 Mole Fraction = (lbmole CH4)/(lbmole gas)

Out CH4 Mole Fraction = Output CH4 Mole Fraction = (lbmole CH4)/(lbmole gas)

D = (molar volume)*(Molecular Weight CH4)*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CH4 = (16 lb CH4)/(lbmole CH4)

Data Requirements

1. Input volume (scf/year)

2. Output volume (scf/year)

3. Input Mole % CH4

4. Output Mole % CH4

Method 19 – Other Natural Gas Processing

Vented and fugitive emissions from other natural gas processing.

CO2 emissions (tonnes/year) = D*[(Input)*(In CO2 Mole Fraction) – (Output)*(Out CO2 Mole Fraction)]

Where

Input = Input volume (scf/year)

Output = Output volume (scf/year)

In CO2 Mole Fraction = Input CO2 Mole Fraction = (lbmole CO2)/(lbmole gas)

Out CO2 Mole Fraction = Output CO2 Mole Fraction = (lbmole CO2)/(lbmole gas)

D = (molar volume)*(Molecular Weight CO2)*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CO2 = (44 lb CO2)/(lbmole CO2)
Appendix B Final 2007 Oil and Gas Industry Survey Results

B-20

Data Requirements

1. Input volume (scf/year)

2. Output volume (scf/year)

3. Input Mole % CO2

4. Output Mole % CO2

CH4 emissions (tonnes/year) = D*[(Input)*(In CH4 Mole Fraction) – (Output)*(Out CH4 Mole Fraction)]

Where

Input = Input volume (scf/year)

Output = Output volume (scf/year)

In CH4 Mole Fraction = Input CH4 Mole Fraction = (lbmole CH4)/(lbmole gas)

Out CH4 Mole Fraction = Output CH4 Mole Fraction = (lbmole CH4)/(lbmole gas)

D = (molar volume)*(Molecular Weight CH4)*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CH4 = (16 lb CH4)/(lbmole CH4)

Data Requirements

1. Input volume (scf/year)

2. Output volume (scf/year)

3. Input Mole % CH4

4. Output Mole % CH4

Method 20 – Natural Gas Compressor Startups

CO2 emissions (tonnes/year) = (Total Volume of Gas Vented)*(CO2 Mole Fraction)*D

Where 

CO2 Mole Fraction = (lbmole CO2)/(lbmole gas)

D = (molar volume)*(Molecular Weight CO2)*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CO2 = (44 lb CO2)/(lbmole CO2)

Data Requirements

1. Total volume of gas vented (scf)

2. Mole %CO2

CH4 emissions (tonnes/year) = (Total Volume of Gas Vented)*(CH4 Mole Fraction)*D

Where 

CH4 Mole Fraction = (lbmole CH4)/(lbmole gas)

D = (molar volume)*(Molecular Weight CH4)*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CH4 = (16 lb CH4)/(lbmole CH4)

Data Requirements

1. Total volume of gas vented (scf)

2. Mole %CH4
Appendix B Final 2007 Oil and Gas Industry Survey Results

B-21

Method 21 – Natural Gas Compressor Blowdowns

CO2 emissions (tonnes/year) = (Total Volume of Gas Vented)*(CO2 Mole Fraction)*D

Where 

CO2 Mole Fraction = (lbmole CO2)/(lbmole gas)

D = (molar volume)*(Molecular Weight CO2)*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CO2 = (44 lb CO2)/(lbmole CO2)

Data Requirements

1. Total volume of gas vented (scf)

2. Mole %CO2

CH4 emissions (tonnes/year) = (Total Volume of Gas Vented)*(CH4 Mole Fraction)*D

Where 

CH4 Mole Fraction = (lbmole CH4)/(lbmole gas)

D = (molar volume)*(Molecular Weight CH4)*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CH4 = (16 lb CH4)/(lbmole CH4)

Data Requirements

1. Total volume of gas vented (scf)

2. Mole %CH4

Method 22 – Natural Gas Compressor Seals

Fugitive emission calculations for natural gas compressor seals.

CO2 emissions (tonnes/year) = (CO2 EF)*(CO2 Mole Fraction\0.03)*(Seals)*(Usage)

Where 

CO2 EF = See Table 10

CO2 Mole Fraction = (lbmole CO2)/(lbmole gas)

Seals = Number seals

Usage = Annual Usage (hours/year)

Data Requirements

1. Mole % CO2

2. Number of compressor seals

3. Annual usage (hours/year)

CH4 emissions (tonnes/year) = (CH4 EF)*(CH4 Mole Fraction\0.788)*(Seals)*(Usage)

Where 

CH4 EF = See Table 10

CH4 Mole Fraction = (lbmole CH4)/(lbmole gas)

Seals = Number of seals

Usage = Annual Usage (hours/year)
Appendix B Final 2007 Oil and Gas Industry Survey Results

B-22

Data Requirements

1. Mole % CH4

2. Number of compressor seals

3. Annual usage (hours/year)

Table 10: Compressor Seals

Device Type CH4

(tonnes/component1-hr)

% Methane 

Assumption

CO2

(tonnes/component1-hr)

% CO2

Assumption

Reciprocating Seal 9.925E-042 78.8 1.039E-042 3

Centrifugal Seal 1.035E-032 78.8 1.083E-042 3

Rotary Seal3 1.035E-032 78.8 1.083E-042 3

Screw Seal3 1.035E-032 78.8 1.083E-042 3

Vane Seal3 1.035E-032 78.8 1.083E-042 3

1. Leak rate for when the compressor is pressurized.

2. EPA (1996a)

3. Assumed Rotary, Screw, and Vane seals emit at the same rate as Centrifugal seals. 

Method 23 – Natural Gas Gathering System Pipelines

Fugitive emission calculations for natural gas gathering system pipelines (before the 

gas meter).

CO2 emissions (tonnes/year) = (CO2 EF)*(CO2 Mole Fraction\0.03)*(Miles) + (Oxidation CO2 EF)*(Miles)

Where

CO2 EF = See Table 11

CO2 Mole Fraction = (lbmole CO2)/(lbmole gas)

Oxidation CO2 EF = See Table 10

Miles = miles of natural gas pipeline

Data Requirement

1. Mole % CO2

2. Mile of natural gas pipeline

CH4 emissions (tonnes/year) = (CH4 EF)*(CH4 Mole Fraction\0.788)*(Miles)

Where

CH4 EF = See Table 11

CH4 Mole Fraction = (lbmole CH4)/(lbmole gas)

Miles = miles of natural gas pipeline

Data Requirements

1. Mole % CH4

2. Miles of natural gas pipeline

Table 11: Natural Gas Gathering Pipelines

Type CH4

(tonnes/mile-yr)

% Methane 

Assumption

CO2 

(tonnes/mile-yr) 

% CO2

Assumption

Oxidation CO2 

(tonnes/mile-yr) 

Gathering Pipeline 0.3741 78.8 7.682E-021 3 3.833E-021

1. API (2004)
Appendix B Final 2007 Oil and Gas Industry Survey Results

B-23

Method 24 – Natural Gas Gathering System Maintenance Activities

CO2 emissions (tonnes/year) = (Total Volume of Gas Vented)*(CO2 Mole Fraction)*D

Where 

CO2 Mole Fraction = (lbmole CO2)/(lbmole gas)

D = (molar volume)*(Molecular Weight CO2)*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CO2 = (44 lb CO2)/(lbmole CO2)

Data Requirements

1. Total volume of gas vented (scf/year)

2. Mole % CO2

CH4 emissions (tonnes/year) = (Total Volume of Gas Vented)*(CH4 Mole Fraction)*D

Where 

CH4 Mole Fraction = (lbmole CH4)/(lbmole gas)

D = (molar volume)*(Molecular Weight CH4)*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CH4 = (16 lb CH4)/(lbmole CH4)

Data Requirements

1. Total volume of gas vented (scf/year)

2. Mole % CH4

Method 25 – Pipeline Pigging

Vented emission calculations for natural gas pipeline pigging (EPA 2005). 

CO2 emissions (tonnes/year) = (CO2 EF)*(CO2 Mole Fraction\0.03)*(Openings)

Where 

CO2 EF = See Table 12

CO2 Mole Fraction = (lbmole CO2)/(lbmole gas)

Openings = Number of time launcher/receiver is opened

Data Requirements

1. Mole % CO2

2. Number of launcher/receiver openings

Emission Factor Calculation

Equation = V*[(P1)*(T2)]/[(P2)*(T1)]

Where

V = pig laucher/receiver volume

P1 = gathering line pressure (psia)

P2 = 14.7 psia (standard surface pressure)

T1 = temperature of the pig launcher/receiver 

T2 = 60° F (standard surface temperature)
Appendix B Final 2007 Oil and Gas Industry Survey Results

B-24

Assumptions (from EPA 2005)

V = 11.5 ft3 (for an 18 in line)

P1 = 315 psia

T1 = 60° F

CH4 emissions (tonnes/year) = (CH4 EF)*(CH4 Mole Fraction\0.788)*(Openings)

Where 

CH4 EF = See Table 12

CH4 Mole Fraction = (lbmole CH4)/(lbmole gas)

Openings = Number of time launcher/receiver is opened

Data Requirements

1. Mole %CH4

2. Number of launcher/receiver openings

Table 12: Pigging

Device Type CH4

(tonnes/opening)

% Methane 

Assumption

CO2

(tonnes/opening)

% CO2

Assumption

Pigging 3.716E-031 78.8 3.89E-041 3

1. EPA (2005)

Method 26 – Tank Cleaning (Separators and Storage Tanks)

Vented emission calculations for the cleaning of crude oil storage tanks or separation 

units.

CO2 emissions (tonnes/year) = (V)*(CO2 Mole Fraction)*(0.1)*(Events)*D

Where

V = Volume of tank (ft3

)

0.1 = Common air district rule that vapors must be reduced at least 90% before opening

CO2 Mole Fraction = (lbmole CO2)/(lbmole gas)

D = (molar volume)*(Molecular Weight CO2)*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CO2 = (44 lb CH4)/(lbmole CO2)

Events = Number of degassing events

Data Requirements

1. Size of tank (bbl/ft3

)

2. Mole % CO2 in vapor head space

3. Number of degassing events

CH4 emissions (tonnes/year) = (V)*(CH4 Mole Fraction)*(0.1)*(Events)*D

Where

V = Volume of tank (ft3

)

0.1 = Common air district rule that vapors must be reduced at least 90% before opening

CH4 Mole Fraction = (lbmole CH4)/(lbmole gas)

D = (molar volume)*(Molecular Weight CH4)*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CH4 = (16 lb CH4)/(lbmole CH4)

Events = Number of degassing events
Appendix B Final 2007 Oil and Gas Industry Survey Results

B-25

Data Requirements

1. Size of tank (bbl/ft3

)

2. Mole % CH4 in vapor head space

3. Number of degassing events

Method 27 – Crude Oil Separation and Storage Tanks

Fugitive emission calculations for crude oil separation and storage tanks. Default CH4

and CO2 mole percents are 43% and 4% respectively (HARC, 2006).

CO2 emissions (tonnes/year) = (TOG)*(% CO2)

Where

TOG = (Working Loss TOG)+(Breathing Loss TOG)+(Flashing Loss TOG)

% CO2 = percent CO2 in the head space vapor concentration

Data Requirements

1. Working Losses (tons/year)

2. Breathing Losses (tons/year)

3. Flashing Losses (tons/year)

4. % CO2 in the head space vapor concentration

CH4 emissions (tonnes/year) = (TOG)*(% CH4)

Where

TOG = (Working Loss TOG)+(Breathing Loss TOG)+(Flashing Loss TOG)

% CH4 = percent CH4 in the head space vapor concentration 

Data Requirements

1. Working Losses (tons/year)

2. Breathing Losses (tons/year)

3. Flashing Losses (tons/year)

4. % CH4 in the head space vapor concentration

Method 28 – Sumps and Pits

Fugitive emission calculations for sumps and pits. 

CH4 emissions (tonnes/year) = (CH4 EF)*(Area)*(Days)

Where

CH4 EF = See Table 13

Area = area of the sump or pit

Days = Number of Days in Use

Data Requirements

1. Area of sump or pit

2. Sump or pit level (primary, secondary, tertiary)

3. Crude Oil API

4. Number of days sump is in use
Appendix B Final 2007 Oil and Gas Industry Survey Results

B-26

Table 13: Sumps

Type CH4

(tonnes/ft2-day)

Light Crude

Primary Sump 1.297E-051

Secondary Sump 1.814E-061

Tertiary Sump 9.070E-071

Heavy Crude

Primary Sump 9.480E-061

Secondary Sump 4.672E-061

Tertiary Sump 5.90E-071

1. Kern County APCD (1990)
Appendix B Final 2007 Oil and Gas Industry Survey Results

B-27

References

API (2004). American Petroleum Institute. Compendium of Greenhouse Gas Emissions 

Methodologies for the Oil and Gas Industry. February 2004.

ARB Mandatory Reporting (2008) California Code of Regulation, Title 17, Chapter 1 

Subchapter 10, Article 2, Sections 95100-95133.

CAPCOA (1999). California Air Pollution Control Officers Association. California 

Implementation Guidelines for Fugitive Hydrocarbon Leaks at Petroleum Facilities.

CEC (2006). California Energy Commission. Evaluation of Oil and Gas Sector 

Greenhouse Gas Emissions Estimation and Reporting. April 2006.

EPA (1996a). US Environmental Protection Agency. Methane Emissions from the 

Natural Gas Industry. June 1996.

EPA (1996b). US Environmental Protection Agency. Compilation of Air Pollution 

Emission. AP-42. October 1996.

EPA (1998). US Environmental Protection Agency. Compilation of Air Pollution 

Emission. AP-42. July 1998.

EPA (2000). US Environmental Protection Agency. Compilation of Air Pollution 

Emission. AP-42. July 2000.

EPA (2003a). US Environmental Protection Agency. Natural Gas Star Lessons Learned. 

Options for Reducing Methane Emissions from Pneumatic Devices in the Natural Gas 

Industry. July 2003

EPA (2003b). US Environmental Protection Agency. Natural Gas Star Lessons Learned. 

Replacing Glycol Dehydrators with Desiccant Dehydrators. November 2003.

EPA (2005). US Environmental Protection Agency. Natural Gas Star Lessons Learned. 

Efficient Pigging of Gathering Lines. April 2005.

HARC (2006). Houston Advanced Research Center. VOC Emissions From Oil

and Condensate Storage Tanks. October, 2006.

INGAA (2005). Interstate Natural Gas Association of America. Greenhouse Gas 

Emission Estimation Guidelines for Natural Gas Transmission and Storage, Volume 1.

Kern County APCD (1990). Corrections to CARB’s AB2588 Air Toxics “Hot Spots” 

Technical Guidance Document Table D-1, Page 118. April 25. 1990.

Appendix C Final 2007 Oil and Gas Industry Survey Results

C-1

Appendix C: Site Visits and Meetings

California Air Resources Board

Oil and Gas Industry Survey

Site Visits and Meetings
Appendix C Final 2007 Oil and Gas Industry Survey Results

C-2
Appendix C Final 2007 Oil and Gas Industry Survey Results

C-3

Date Action

April 2008 • Staff held preliminary public workshop.

• Industry and district working groups created.

May 2008 • Staff met with the Western States Petroleum 

Association (WSPA) and several large crude oil 

production companies. Staff explained to WSPA our 

intention to survey the sector and asked for contacts for 

potential site visits.

June 2008 • Staff met with the California Independent Petroleum 

Association (CIPA). CIPA was asked for contacts for 

site visits and staff explained our intention for a survey 

to create an accurate baseline inventory for regulatory 

development. 

July 2008 • Staff traveled to Bakersfield to tour two large crude oil 

production fields and several small independent 

producers. 

• Staff met with the Independent Oil Producers’ Agency 

(IOPA) to hear their concerns about potential regulation 

and to inform them of our intention to survey the sector. 

• Staff toured a large Northern California dry gas field.

August 2008 • Staff toured a natural gas storage field.

• Staff traveled to Santa Barbara to tour an onshore 

processing plant for offshore platforms. 

• Staff met with Santa Barbara and Ventura air district 

personnel responsible for permitting oil and gas 

production facilities. 

• Staff travelled to Los Angeles to tour two large crude oil 

producers and to meet with South Coast air district 

staff. 

• A draft version of the survey was sent to the industry 

workgroup for review.

September 2008 • A conference call with the industry workgroup was held 

to discuss the draft survey. Attendees of the call gave 

detailed feedback to staff.

• A revised version of the survey was then sent out to the 

industry working group for review and comments. 

• Staff travelled to the Los Angeles area to tour several 

oil terminals and to meet with the South Coast air 

district staff again.

• Staff and the industry working group met to discuss the 

revised draft survey. Staff took detailed comments 

from the industry and incorporated them into another 
Appendix C Final 2007 Oil and Gas Industry Survey Results

C-4

revised draft survey. 

October 2008 • Staff travelled to the Santa Barbara area to tour an 

offshore platform and an onshore processing plant. 

Staff also toured a large natural gas storage facility in 

the northern Los Angeles area during that trip. 

• Staff sent a portion of the revised survey out to the 

industry working group for their review and comments. 

• Staff traveled to Bakersfield to attend the Oil and Gas 

Conference put on by the Department of Conservation, 

Division of Oil, Gas, and Geothermal Resources. 

During that trip, a crude oil pipeline storage and heating 

station was also toured.

November 2008 • Staff received supporting information from the industry 

working group for changes they had requested of the 

draft survey. Staff made the appropriate changes to 

the draft survey.

• Staff travelled to Bakersfield to tour a small crude oil 

production field using a microturbine to generate 

electricity. Staff also toured a crude oil pipeline 

processing station.

December 2008 • Staff sent out the draft survey with general instructions 

for completing the survey and electronic templates to 

two companies for a pilot survey. 

• Staff conducted a conference call with our district 

working group to discuss comments on the draft 

survey. 

• Staff toured a natural gas storage field north of 

Sacramento.

• Staff conducted a meeting with the industry working 

group to discuss emission factors ARB would be using 

to calculate the baseline GHG emissions inventory for 

the oil and gas production sector. 

• Staff continued working with the companies performing 

the pilot survey and incorporated changes to the draft 

survey based on comments from the industry and 

district working group. 

January 2009 • Comments from the pilot group were received. Staff 

revised the draft survey and general instructions based 

on those comments and sent out a revised version of 

both to the industry working group.

• Staff conducted a conference call with the industry 

working group. Comments were incorporated where 

appropriate and staff sent a revised draft survey and 

general instructions to the industry working group for 

review and comment. 
Appendix C Final 2007 Oil and Gas Industry Survey Results

C-5

February 2009 • Staff toured a large natural gas extraction facility just 

north of Sacramento.

• ARB staff mailed out the Oil and Gas Industry Survey 

on February 19.

March 2009 • On March 26, 2009 staff traveled to Bakersfield to 

conduct a training seminar for filling out the survey.

April 2009 • Staff answered questions from the industry about the 

survey.

• The Oil and Gas Industry Survey was due on April 30.

• Extensive follow-up with facilities started.

May to August 

2009

• Staff toured crude oil facilities in the Los Angeles area.

• Majority of surveys received.

• Staff continued to follow up with facilities with questions 

on surveys received.

• Surveys uploaded to survey database.

September to 

December 2009

• Staff contacted non-respondents for the survey.

• Remaining surveys received and uploaded.

• On December 8, 2009 staff conducted a workshop 

detailing preliminary results from the survey.

January to 

March 2010

• Staff worked with industry to answer questions about 

facility emissions. 

• Staff QA’d and QC’d data and followed up with 

facilities.

March 18, 2010 • Survey data was frozen.

April to May 

2010

• Staff developed survey data and emission summaries.

• Staff worked with industry working group on emission 

summaries.

June 2010 to 

January 2011

• Draft survey report developed.

April 2011 to 

June 2011

• Draft survey report reviewed by district and industry 

working groups.

August 2011 • Draft survey report released for public comment.

Appendix D Final 2007 Oil and Gas Industry Survey Results

D-1

Appendix D: Internal Combustion Engine Use Categories

California Air Resources Board

Oil and Gas Industry Survey

Internal Combustion Engine Use Categories
Appendix D Final 2007 Oil and Gas Industry Survey Results

D-2
Appendix D Final 2007 Oil and Gas Industry Survey Results

D-3

Air Compressor

Air Compressor

Emergency Instrument Air Compressor

Cogen Start

Cogeneration

Co-generation

Co-generation plant

Cogeneration Starter

Compressor

Compressor

Portable Compressor

30 ton Crane

Crane

Crane

Crane Engine

East Crane

Pedestal crane east

West Crane

Crude Oil Prod

Crude Oil Pump

Crude Oil Pump

Oil Pump

Well Pump

Well Pumps

Crude Oil Pump/Charge Pump

Emergency Fire pump

Emergency Services

Emergency Firewater Pump

Emergency Flood Control

Emergency Freshwater Fire 

Pump

Emergency Well Kill Pump

Fire Pump

Fire Water Pump

Firewater Pump

Acid pump

Miscellaneous

A-Frame

Backhoe

Blower

Broadbill - auxiliary engine

Broadbill - main engine

Building Heater

Concrete saw

Crew Boat - auxiliary engine

Crew boat - auxiliary engines DPV

Crew Boat - main engine

Crew boat - main engine DPV

Crew boat - main engine spot charter

Crew Boat - spot charter

Crew Boat -Auxiliary engines DPV

Crew Boat -Auxiliary engines DPV 

Broadbill

Crew Boat -Main engines

Crew Boat -Main engines DPV 

Broadbill

Crew Boat -Main engines spot charter

Dozer

E-line unit

Forklift

Gas Disposal

Hydroblaster

Hyperclean

Large Forklift

LIGHT PLANT

Light Tower

Loader Engine

Manilift

Nitrogen Pump

Paint Sprayer

Pipe Threader

Plate compactor

Poly Tank Pump motor

Portable Welder

Portable Wood Grinder

Pump Skid

Road Grader Engine

Roller

Single Drum Roller

Skip Loader

Small Forklift

Spare

Sprayer

STARTING AIR

Steam Cleaner

Sub-Base

Supply boat - Auxiliary engines

Supply boat - main engine

Supply boat - main engine 

(Spot charter)

Supply boat - main engine 

DPV

Supply boat - main engine 

spot charter

Supply Boat -Bow thruster 

and auxiliary engines

Supply Boat -Main engines 

spot charter

SupplyBoat -Main engines

Survival capsule

Survival Capsule #1

Survival Capsule #2

Top Drive

Tractor Engine

Tractor Loader

TRANSFER PUMP

Truck Engine

Vibe

Weed Eater

Welder

Welding Machine
Appendix D Final 2007 Oil and Gas Industry Survey Results

D-4

Backup Generator

Power Generation

Electric Generator

Electrical Generator

Emergency

Emergency drilling generator

Emergency Generator

emergency power

Emergency Power Generator

Emergency production generator

Emergency response - main and 

auxiliary

Gen House 

Gen Set

Generator

Generators

Hydraulic Power Unit

Portable Generator

Power Generation

Power Generator

Power Unit

Standby Generator

starter engine

Turbine Starter

Hydraulic Pump

Pump

Lift Pump

Pump

Pump Unit

Test Pump

Wash Pump

Water Injection Pump

Water Pump

Water Pump Engine

Water Transfer Pump

Baker/Apollo Injecting Unit

Well Servicing

BJ Cement Unit

Blackstart Engine

Cement Pump

Circulating Pump

Circulation pump

Cmt. Bulk Trailer

Coiled Tubing Powerpack

CTU

Draw Works

Drum Vibratory Roller

Emergency drilling engine

Fluid Pump

Foam unit

Foamer

Mud Pump

Mud Pump Driver

Portable Mud Pump

Portable Power Swivel

Power Pumping Unit

Power Swivel

Produced Water

Production Rig

Rig Engine

Rig Power

Stang Pump

Well Kill Pump Engine

Workover Rig
Appendix E Final 2007 Oil and Gas Industry Survey Results

E-1

Appendix E: Separator Type Categories

California Air Resources Board

Oil and Gas Industry Survey

Separator Type Categories
Appendix E Final 2007 Oil and Gas Industry Survey Results

E-2
Appendix E Final 2007 Oil and Gas Industry Survey Results

E-3

Condensate Accumulator

Condensate tank

Condensate tank

Condensate vessel

Condensate

Free Water Knockout

Free Water Knockout

Boiler

Heater/Treater

Heat Exchanger 

Heater/Treater

Heater-PU

Clean Out Tank

Crude Oil Separator

Clean Up Tank

Crude Oil Tank

Crude Stock Tank

Crude Tank

Dirty Oil Tank

Disc Pot

Discharge Drip Pot Vessel

Drip Vessel

Oil Water Separator

overflow drain tank

Skim oil tank

skim tank

Skim Water Tank

Skimmer

skims tank

Stand-by Surge/Skim oil tank

Wet oil reject tank

Wet oil tank

Production Unit

Absorber

Gas Separator

Casing Collection Separator

Casing Gas Scrubber

Casing Gas Separator

Contactor

Dehydrator

Flare Knock Out Drum

Flare Separator Vessel

Gas Scrubber

Flash Drum

Flow Splitter

Flowsplitter

Fuel Gas Scrubber

Gas Knockout

Gas Oil Separator

Gas Separator

Gas Trap Vessel

Glycol Catch Trap

Glycol separator

Inlet Scrubber

Reboiler

Spherical Separator

Horizontal

Horizontal Separator

Horizontal Separator

Horizontal Separators

Horizontal test trap

Horizontal Vessel

Loading Rack Vapor Recovery 

Suction Scrubber

Scrubber

Sales gas scrubber

Scrubber

Suction Bottle

Suction Drip Pot

Suction Pot

Suction Scrubber

Clarification Tank

Produced Water Tank

Clarifier

Clarifier Tank

Depurator

Floatation Unit

Flotation Cell

Induced Static Floatation

Induced Static Flotation

Produced Water

Produced Water Clarifier

Produced Water Tank

Production Inlet Drum

Reject oil / produced water

Reject tank

Waste Water Tank

Wastewater Surge Tank

Wastewater Tank

Water Mixing Tank

Water Tank

Water

Cone bottom tank

Separator

Methanol Tank

Natural Gasoline Bullet

Other - No Production Equipment

POT

Pressure Vessel

Rerun Tanks

Separator

Stripper Feed Separator

Tank

Test Tank

Tote Tank

Treater, unheated

Vapor Recovery

Vapor Recovery Unit

Vaporizer

Vessel

Blow Tank 

Sand Water Tank

Settling tanks

Settling tanks

Slop Tank

Sludge Collection Tank

Sludge Tank

Slug Catcher

solids tank

Shipping Tank

Shipping Tank

Stock Tank

Storage Tank

Injection Surge Tank

Surge Tank

Surge Drum

surge tank
Appendix E Final 2007 Oil and Gas Industry Survey Results

E-4

1st Stage Discharge

Stage Separator

1st Stage Discharge Bottle

1st Stage Suction Bottle

1st Stage Suction Scrubber

2nd Stage Discharge

2nd Stage Suction

2nd Stage Suction Bottle

2nd Stage Suction Scrubber

3-Phase

3rd Stage Discharge Bottle

3rd Stage Discharge Scrubber

3rd Stage Suc Drum

3rd Stage Suction Bottle

3rd Stage Suction Scrubber

4th Stage Discharge Drum

4th Stage Suc Drum

Compressor Interstage Scrubber

Compressor Interstage Separator

Three stage clarifier

Ball Separator

Trap Separator

Ball Trap

DBL Ball Trap

Gage Trap

Inlet Gas Trap

Master Trap

Master Trap / Scrubber

Vertical

Vertical Separator

Vertical Separator

Vertical Vessel

Wemco

Wemco

Wemco Flotation cell

Wemco holding tank

Wemco surge tank

Wash Tank

Wash Tank

Automatic Well Tester

Well Tester

Well Test separator