# 2007 Oil and Gas

Industry Survey

Results

Final Report

December 2011Final 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

Princip al 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)

Indep endent Oil Producers’ Agency (IOPA)

We would also like to tha nk 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

................................ ................................ . 1 0

- 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 Engin e Use Categories

................................ ......... D

- 1

Appendix E : Separator Type Categories

................................ ................................ ..... E

- 1Final 2007 Oil and Gas Industry Survey Results



### iv 

## 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 : Combu stion 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 CO 2 

### e Range (Metric Tons/Year)

................ 3

- 6

Table 3

- 11 : Total California Combustion Emissions by CO 2 

### e Range

........................... 3

- 6

Table 3

- 12 : Total California Vented Emissions by CO 2 

### e Range (Metric Tons/Year)

.... 3

- 6

Table 3

- 13 : Total California Fugitive Emissions by CO 2 

### e 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 (Me tric Tons/Year)

................................ ..... 5

- 1Final 2007 Oil and Gas Industry Survey Results



### v 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 Recov ery 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 Co mbustion 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 : Co mbustion 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 Emission s of Natural Gas Components by Type

........................... 8

- 3

Table 8

- 6 : Fugitive Emissions of Light Crude 1 

### Components by Type

........................... 8

- 4

Table 8

- 7 : Fugitive Emissions of Heavy Crude 1 

### 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 Natur al 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

- 3Final 2007 Oil and Gas Industry Survey Results



### vi 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 Blo wdown 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

Tabl e 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 o f 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 Syst em 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

- 1Final 2007 Oil and Gas Industry Survey Results



### vii 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 : Storag e 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 CO 2 

### e Range (Metric Tons/Year)

.............. 20

- 2

Table 20

- 4 : Crude Oil Combustion Emissions by CO 2 

### e Range

................................ .. 20

- 2

Table 20

- 5 : Crude Oil Vented Emissions by CO 2 

### e Range (Metric Tons/Year)

........... 20

- 2

Table 20

- 6 : Crude Oil Fugitive Emissions by CO 2 

### e Range (Metric Tons/Year)

.......... 20

- 3

Table 20

- 7 : Average Total CO 2 

### e Emissions per Barrel Crude Oil Produced

.............. 20

- 4

Table 20

- 8 : Average Combustion CO 2 

### e Emissions per Barrel Crude Oil Produced

... 20

- 4

Table 20

- 9 : Average Vented CO 2 

### e Emissions per Barrel Crude Oil Produced

.......... 20

- 5

Table 20

- 10 : Average Fugitive CO 2 

### e Emissions per Barrel Crude Oi l 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 CO 2 

### e Range (Metric Tons/Year)

.......... 21

- 2

Table 21

- 4 : Natural Gas Combustion Emissions by CO 2 

### e Range (Metric Tons/Year) 21

- 2

Table 21

- 5 : Natural Gas Vented Emissions by CO 2 

### e Range (Metric Tons/Year)

....... 21

- 2

Table 21

- 6 : Natural Gas Fugitive Emissions by CO 2 

### e Range (Metric Tons/Year)

...... 21

- 2

Table 21

- 7 : Average Total CO 2 

### e Emissions per MSCF Natural Gas Produced

......... 21

- 3

Table 21

- 8 : Average Combustion CO 2 

### e Emissions per MSCF Natural Gas

.............. 21

- 4

Table 21

- 9 : Average Vented CO 2 

### e Emissions per MSCF Natural Gas Produced

...... 21

- 4

Table 21

- 10 : Avera ge Fugitive CO 2 

### e Emissions per MSCF Natural Gas Produced

... 21

- 4Final 2007 Oil and Gas Industry Survey Results



### viiiFinal 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 CO 2 

### 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

CH 4 

### Methane

CHP Combined Heat and Power

CIPA California Independent Petroleum Association

CNG Compressed natural gas

CO 2 

### Carbon dioxide

CO 2 

### e 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 in tegrated 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 pre ssure 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 recoveryFinal 2007 Oil and Gas Industry Survey Results



### xi 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

atmo sphere

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 CO 2



### H 2 

### S 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 In spection 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 ofFinal 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 eng ines 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

N 2 

### O 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 Registrati on 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 cylind er.

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



### xiii 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 t he 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

combusti on 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, orFinal 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 greenhous e 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 AssociationExecutive 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 conduct ed 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, a nd 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 inf ormation 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 CO 2 

### e. Combustion sources (equi pment burning fuel for energy) account

for 87 percent of the total CO 2 

### e emissions. The remaining 13 percent of the CO 2 

### e

emissions, or about 2.4 million metric tons of CO 2 

### e, come from vented and fugitive

sources, which are, respectively, intentional and un intentional 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

mentione d 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

measur es, 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 deve loping 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 c rude o il and n atural g as p roduction, p rocessing, and s torage

sector

. This report provides the results of the 2007 s urvey 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 prelimi nary concepts for

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

distribution , and refinery sector s. 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 sect ion.

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 plant s;

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 D evelopment and Reportin g 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 surveyi ng 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 meeting s, 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 group s 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 w ere due on April 30 , 2009

.

**•** Survey database was developed and surveys uploaded asChapter 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 pre liminary 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 w ere 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 wor king

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 one

time collection of data intended to accurately quantify operations and proce sses needed

t o 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.

Cr ude 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 exclude s 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 fac ility that produced

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

Produced Water Disposal: any facility that sto red 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

s urvey 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 t he

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 h ad 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 grea ter 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 i s 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 perc entages 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 b y 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 f acilities 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

- reporte d facility types:

o CNG compression and marketing

o CogenerationChapter 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

PERP 1 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”, “natura l 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 Tab le 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 petro leum 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 Su rvey 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

produ ced 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 ofChapter 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 fo rmation, 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 techniqu es (DOGGR, 2008).

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

represents 9 6 percent of California’s total production. Table 2

- 3 lists the California

crude oil production reported in the 2007 Oil and Gas Industry Surve y 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 deli vered

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 i t 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. Ac cording 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, ifChapter 2 Final 2007 Oil and Gas Industry Survey Results



### 2

- 5 the amount combusted onsite is sub tracted from the amount produced, the amount

available becomes similar to the EIA number.

Table 2

- 4 : Natural Gas Totals

Type MSCF 1 Natural

Gas Produced MSCF Natural Gas

Combusted MSCF Natural Gas

Available t o 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. M S CF 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 b illion 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 (CO 2 

### ), methane (CH 4 

### ), and nitrous oxide

(N 2 

### O). Carbon dioxide equivalents (CO 2 

### e) 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 CO 2 

### . GWP numbers are

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

Assessment Reports. Table 2

- 5 lists the GWP for CO 2 

### , CH 4 

### , and N 2 

### O from the Second,

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

Table 2

- 5 : Global Warming Potentials

CO 2 CH 4 N 2 O

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 CO 2 

### e 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 remain ing chapters of the report total th e

emissions for oil production and na tural 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 G as, 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.). C ontribution 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. Callande r, N. Harris, A. Kattenberg

and K. Maskell (eds.). Contribution of W orking G roup 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 show s 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 atmo sphere. Fugitive emissions are unintentional releases of

vapors to the atmosphere. The majority of the total CO 2 

### e emissions in California are

from combustion sources. Only 13 percent of the CO 2 

### e emissions come from vented or

fugitive sources.

Table 3

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

Type CO 2 CH 4 N 2 O CO 2 e Percent of

Total CO 2 e

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%

Total s: 16,392,641 109,267 314 18,784,582



### Table 3

- 2 lists the total CO 2 

### e emissions by primary business type. Primary business

type is defined in Chapter 2. 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

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

confidential company data . The facility type s “ 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 CO 2 

### e 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 CO 2 CH 4 N 2 O CO 2 e Percent

of Total

CO 2 e

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%

Total s: 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 CO 2 

### e

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 case s , the CO 2 

### e emissions for

that facility were split equally between each air district. This r esulted 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 CO 2 

### e 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 CO 2 e Percent of Total

CO 2 e

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 18,784,582Chapter 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 CO 2 

### e

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

Table 3

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

Type CO 2 CH 4 N 2 O CO 2 e Percent of

Total CO 2 e

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%

Total s: 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 productio n and the business type “other.”

Table 3

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

Type CO 2 CH 4 N 2 O CO 2 e Percent of

Total CO 2 e

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%

Total s: 16,073,395 10,836 314 16,398,268Chapter 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 ventin g 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 CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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%

Total s: 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 Cal ifornia 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 CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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%

Total s: 48,432 24,880 570,922Chapter 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

pipe lines. Natural gas processing equipment and compressor seals account for 80

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

Table 3

- 8 : Fugitive Emissions by Source Typ e (Metric Tons/Year)

Type CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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%

Total s: 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 CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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%

Total s: 270,815 73,551 1,815,393



## Total Emissions by CO 2 

## e Range

Total CO 2 

### e emissions were calculated for each facility. All facilities were then

categorized into ranges of CO 2 

### e emissions. Table 3

- 10 lists the number of facilities in

each range and the total CO 2 

### e 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 CO 2 

### e Range (Metric Tons/Year)

Range

(CO 2 e per Facility) Number of

Facilities CO 2 e Percent of Total

CO 2 e

< 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%

Total s: 1,632 18,784,582



### Tables 3

- 11, 3

- 12, and 3

- 13 list the number of facilities and total CO 2 

### e 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 : Tot al California Combustion Emissions by CO 2 

### e Range

(Metric Tons/Year)

Range

(CO 2 e per Facility) Number of

Facilities CO 2 e Percent of Total

CO 2 e

< 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%

Total s: 1,632 16,398,268



### Table 3

- 12 : Total California Vented Emissions by CO 2 

### e Range (Metric Tons/Year)

Range

(CO 2 e per Facility) Number of

Facilities CO 2 e Percent of Total

CO 2 e

<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%

Total s: 1,632 570,922



### Table 3

- 13 : Total California Fugitive Emissions by CO 2 

### e Range

(Metric Tons/Year)

Range

(CO 2 e per Facility) Number of

Facilities CO 2 e Percent of Total

CO 2 e

< 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%

Total s: 1,632 1,815,393Chapter 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 bring ing 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 th e 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 w ell 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 inc rease 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 Numbe r 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 CO 2 

### and CH 4 

### values are multiplied by their corresponding GWP (1 for CO 2 

### and 21 for CH 4 

### ) to get t he CO 2 

### e number.Chapter 4 Final 2007 Oil and Gas Industry Survey Results



### 4

- 3 **Active Wells**

The emissions of CO 2 

### and CH 4 

### 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 cal culated 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 c rude 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 CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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 CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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 CO 2 

### and CH 4 

### 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 CH 4 CO 2 e Percent of

Total CO 2 e

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 45,225Chapter 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 CO 2 

### and CH 4 

### 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 CO 2 

### and CH 4 

### in the

associated or dry gas, and emission factors. These calc ulations 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 CO 2 

### e

emissions from well maintenance activities.

Tabl e 4

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

(Metric Tons/Year)

Type Number of Well

Workovers CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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 CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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 CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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 CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

Dry Gas 86 0 14 292 PD

Natural Gas Storage PD PD PD PD PD

Totals: PD PD PD PDChapter 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 stea m 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 ter ra

- 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 fa cilities. 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 redu ced . 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. The se 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 t ransmission 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

**•** CH 4 

### and CO 2 

### content of the gas stream

**•** Carbon mole ratio

o For carbon adsorbers

**•** Size in cubic feet

**•** Throughput in scf

**•** Capture efficiency

**•** CH 4 

### content of the gas stream

Table 6

- 1 lists the number of vapor recovery units by type. Flares re presented th e 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: 255Chapter 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

adsorbe rs are considered vented emissions. The emissions are calculated using fuel

data supplied in the survey and are detailed in Appendix B. The CO 2 

### , CH 4 

### , and N 2 

### O

emissions are multiplied by their corresponding GWP (1 for CO 2 

### , 21 for CH 4 

### , and 310

for N 2 

### O) to get the CO 2 

### e 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 p ieces of

equipment. For example, i ncinerators, burners, and afterburners were combined into

the category “incinerator

. ” This table shows that flares and thermal oxidizers have

similar CO 2 

### e emissions even though there are 10 times as many flares as therma l

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 CO 2 CH 4 N 2 O CO 2 e Percent

of Total

CO 2 e

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 CO 2 

### e 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 CH 4 CO 2 e

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 standbyChapter 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 CO 2 

### e emissions.

Table 6

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

Type Number of

Units CO 2 CH 4 N 2 O CO 2 e Percent

of Total

CO 2 e

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: 238Chapter 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 equip ment: 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 spe cify 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 ar e dependent on the information

reported in the survey. Three methods are available to calculate CO 2 

### , CH 4 

### , and N 2 

### O.

The first method uses a mass balance appr oach, 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 eit her the first or second method,

fuel

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

detailed in Appendix B. The CO 2 

### , CH 4 

### , and N 2 

### O emissions are multiplied by their

corresponding GWP numbers (1 for CO 2 

### , 21 for CH 4 

### , and 310 for N 2 

### O) to get the CO 2 

### e

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 equip ment 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 categori es 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

.

Tabl e 7

- 1 lists the CO 2 

### , CH 4 

### , and N 2 

### O 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 Eq uipment Type (Metric Tons/Year)

Type Number

of Units CO 2 CH 4 N 2 O CO 2 e Percent

of Total

CO 2 e

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 compan y data and to aggregate

similar pieces of equipment. Below is a list of equipment categori es 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 turbin es 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 cre ate 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 appea r as both internal and external combustion.

Table 7

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

Type Number

of Units CO 2 CH 4 N 2 O CO 2 e Percent

of Total

CO 2 e

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 7,778,505Chapter 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 surv ey; thus

, their age s 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 p ump 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 CO 2 CH 4 N 2 O CO 2 e Percent

of Total

CO 2 e

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 CO 2 

### e emissions. Crude oilChapter 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

- str oke.

Survey respondents did not report the type for a bout 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 CO 2 CH 4 N 2 O CO 2 e Percent

of Total

CO 2 e

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 u ses. Below is a list of use categori es 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 a nd 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 N umber

of Units CO 2 CH 4 N 2 O CO 2 e Percent

of Total

CO 2 e

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 aChapter 7 Final 2007 Oil and Gas Industry Survey Results



### 7

- 6 steam turbine or injected in to 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

pr otect 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 a re from combined cycle turbines.

Table 7

- 8 : Turbine Combustion Emissions by Cycle Type (Metric Tons/Year)

Type Number

of Units CO 2 CH 4 N 2 O CO 2 e Percent

of Total

CO 2 e

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 inc rease

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 rep orted. 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

. ”

Ta ble 7

- 9 : Cogeneration Combustion Emissions by Type (Metric Tons/Year)

Type Number

of Units CO 2 CH 4 N 2 O CO 2 e Percent

of Total

CO 2 e

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 7,129,158Chapter 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 CO 2 CH 4 N 2 O CO 2 e Percent of

Total CO 2 e

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 CO 2 CH 4 N 2 O CO 2 e Percent of

Total CO 2 e

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) CO 2 CH 4 N 2 O CO 2 e Percent

of Total

CO 2 e

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 16,398,268Chapter 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, c onnectors, 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. CO 2 

### and CH 4 

### emissions are calculated using emission

factors and total c omponent counts and are detailed in Appendix B. The CO 2 

### and CH 4 

### , emissions are multiplied by their corresponding GWP numbers (1 for CO 2 

### and 21 for

CH 4 

### ) to get the CO 2 

### e 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 CO 2 

### e 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 CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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 CO 2 

### e 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 CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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 CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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 CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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 6,866Chapter 8 Final 2007 Oil and Gas Industry Survey Results



### 8

- 4 Table 8

- 6 : Fugitive Emissions of Light Crude 1 

### Components by Type

( Metric Tons /Year )

Type Number of

Units CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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 Crude 1 

### Components by Type

( Metric Tons /Year )

Type Number of

Units CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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 w ith 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. CO 2 

### and CH 4 

### emissions from automated control devi ces

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.

D evices on gas recovery capture the gas used to actuate. The CO 2 

### and CH 4 

### emissions

are multiplied by their corresponding GWP numbers (1 for CO 2 

### and 21 for CH 4 

### ) to get

the CO 2 

### e 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 a utomated control

devices found i n 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 CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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 CO 2 CH 4 CO 2 e Percent

of Total

CO 2 e

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 5,727 120,434Chapter 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 follow s 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

le aks. 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 lon g

the facility has to repair th e leak. Components with a higher leak rate generally must be

repair ed sooner than one s with a lower leak rate.

Of the 1,63 2 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

n umber 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 E ach Leak Threshold

Leak Threshold Number of Faciliti es

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 60Chapter 1 1 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 CH 4 

### , H 2 

### S, CO 2 

### 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 (ft 3 

### )

**•** Pressure (psig)

**•** Percent of packed vessel volume that is natural gas

**•** Frequency of desiccant replacement (days) ; and

o For all units’ vapor recovery sys tem

**•** 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 calculatin g 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 thi rd method calculates the fugitive emissions using a mass balance

approach. Appendix B details the calculations for all three methods. The CO 2 

### and CH 4Chapter 1 1 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 CO 2 

### and 21 for CH 4 

### ) to get the CO 2 

### e 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 categori es 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 CO 2 

### e emissions.

Table 11

- 1 : Vented Emissions of Natural Gas Dehydrators by Type

( Metric Tons / Year )

Type Number of

Units CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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 CO 2 

### e emissions reported in this survey.

Table 11

- 2 : Fugitive Emissions of Natural Gas Dehydrators by Type

( Metric Tons /Year )

Type Number of

Units CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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, n early 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: 703,581,432Chapter 1 1 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 CO 2 

### e emissions make up the majority

of the emissions from this category.

Table 11

- 4 : Total Emissions of Natural Gas Dehydrators (Metric Tons/Year)

Type CO 2 CH 4 N 2 O CO 2 e Percent of

Total CO 2 e

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 categori es 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: 308Chapter 1 2 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 CO 2 

### 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 Append ix A)

**•** Facilities could also specify a type not listed ;

o Average natural gas composition

**•** Percent CH 4 

### , H 2 

### S, CO 2 

### 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 Quant ity of liquids removed in tons/year ;

o CO 2 

### removal

**•** Total CO 2 

### removed (tons/year)

**•** Amount vented (tons/year)

**•** Amount incinerated (tons/year)

**•** Amount captured (tons/year) ;

o For solid material units

**•** Volume of unit (ft 3 

### )

**•** 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 emis sions 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 f or detailed calculations. The CO 2 

### and CH 4 

### emissions are adjusted by the vapor recovery efficiency and then multiplied by

their corresponding GWP numbers (1 for CO 2 

### and 21 for CH 4 

### ) to get the CO 2 

### e values.

Table 12

- 1 lists the vented emissions by type of A GR unit. These emissions contain the

calculated vented emissions from solid material replacement as well as the reportedChapter 1 2 Final 2007 Oil and Gas Industry Survey Results



### 12

- 2 vented CO 2 

### 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 categori es 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 CO 2 

### e emissions are from amine AGR

units.

Table 12

- 1 : Vented Emissions of Natural Ga s AGR Units by Type

( Metric Tons /Year )

Type Number of

Units CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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

ar e more spread out among the three categories. Here

, 65 percent of the fugitive CO 2 

### e

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 CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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 detai led in Chapter 7 of this

report . This table shows that fugitive CO 2 

### e emissions make up the majority of the

emissions from this category.Chapter 1 2 Final 2007 Oil and Gas Industry Survey Results



### 12

- 3 Table 12

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

Type CO 2 CH 4 N 2 O CO 2 e Percent of

Total CO 2 e

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 categori es and the types they represent:

o Combustion Unit

– boilers, heater/trea ters, 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: 65Chapter 1 3 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 informati on 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 CH 4 

### , H 2 

### S, CO 2 

### 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, collec tion system

 Facilities could also specify a type not listed above

**•** Control efficiency

.



## Emissions

Emissions of CO 2 

### and CH 4 

### 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 emissi ons or both is not possible. Thus

, emissions from these

units are categorized as fugitive. The CO 2 

### and CH 4 

### emissions are adjusted by the

vapor recovery efficiency and then multiplied by their corresponding GWP numbers (1

for CO 2 

### and 21 for CH 4 

### ) to get th e CO 2 

### e 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 : Emiss ions of Other Natural Gas Processing Units by Type

( Metric Tons /Year )

Type Number

of Units CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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 list s 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 1 3 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 1 4 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,

f ugitive em issions account for 79 percent of the total emissions from this category.

Table 14

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

Type CO 2 CH 4 N 2 O CO 2 e Percent of

Total CO 2 e

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 CO 2 CH 4 N 2 O CO 2 e Percent of

Total CO 2 e

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 1,355,878Chapter 1 5 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 info rmation 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 integ ral ;

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 typ e. 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.

Tab le 15

- 1 : Number of Compressors by Type

Type Number of

Compressors

Centrifugal 47

Reciprocating 911

Rotary 97

Unknown 16

Totals: 1,071Chapter 1 5 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 CompressorChapter 1 5 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 separat ed. 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 sal es 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 1 5 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 CO 2 

### and CH 4 

### , emissions are multiplied by their

corresponding GWP numbers (1 for CO 2 

### and 21 for CH 4 

### ) to get the CO 2 

### e values.

Table 15

- 5 lists the vented emissions from natural gas compressor startups

, and

Table 15

- 6 lists the vented emissions from blowdowns. The maj ority 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 Compre ssor Startup Vented Emissions (Metric Tons/Year)

Type CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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 CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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 CO 2 

### e emissions for this category.

Table 15

- 7 : Natural Gas Compressor Fugitive Seal Emissions (Metric Tons/Year)

Type CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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 CO 2 

### e emissions make up the majority of the emissions from this category while fugitive CO 2 

### e

account for the majority of the remaining 34 percent.Chapter 1 5 Final 2007 Oil and Gas Industry Survey Results



### 15

- 5 Table 15

- 8 : Tot al Emissions of Natural Gas Compressors (Metric Tons/Year)

Type CO 2 CH 4 N 2 O CO 2 e Percent of

Total CO 2 e

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 CO 2 CH 4 N 2 O CO 2 e Percent of

Total CO 2 e

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 CO 2 

### e 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 CO 2 CH 4 N 2 O CO 2 e Percent of

Total CO 2 e

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 1,319,792Chapter 1 5 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 CO 2 

### e emissions.

Table 15

- 11 : Total Emissions of Natural Gas Compressors by Primary Driver

(Metric Tons/Year)

Type Number

of Units CO 2 CH 4 N 2 O CO 2 e Percent of

Total CO 2 e

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 CO 2 CH 4 N 2 O CO 2 e Percent of

Total CO 2 e

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 1,319,792Chapter 1 5 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 16Chapter 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 in formation about

their pipelines:

o Length of natural gas gathering system pipelines ;

o M aintenance 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 n atural 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 Syst em 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: 2,295Chapter 16 Final 2007 Oil and Gas Industry Survey Results



### 16

- 2 M aintenance 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 Gathe ring System Pipeline Maintenance Activity Volumes

Type Flared

(m sc f) 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 b oth crude oil and natural gas pipelines. The natural gas pig launchers and

receivers are pressurized with natural gas. This gas is either purged wi th 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

deta iled in Appendix B. The CO 2 

### and CH 4 

### emissions are multiplied by their

corresponding GWP numbers (1 for CO 2 

### and 21 for CH 4 

### ) to get the CO 2 

### e values.

Table 16

- 4 lists the vented emissions from the natural gas gathering system

maintenance activities and natu ral gas pigging operations. As shown, p ipeline

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 CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

Natural Gas Pipelines 2,659 2,490 54,940 100%

Natural Gas Pigging 104 5 211 0%

Totals: 2,763 2,495 55,151Chapter 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 Pipeline s

(Metric Tons/Year)

Type CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

Natural Gas Pipelines 327 867 18,541 100%

Totals: 327 867 18,541Chapter 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 contaminant s. Table 14 of

the 2007 Oil and Gas Industry Survey gathered information about separators. Facilities

were required to submit the following inf ormation about their separators:

o Type

**•** Free water knockout, heater/treater, horizontal separator, vertical

sepa rator, 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 Cr ude 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 CH 4 

### and CO 2 

### 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 contr ol efficiency

.

Table 17

- 1 lists the number of separators by primary business type. The business type

“crude processing” and “crude pipeline” w ere 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: 4,618Chapter 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 emission s from

working, breathing, and flashing losses and the head space vapor concentrations.

These equations are detailed in Appendix B. The CO 2 

### and CH 4 

### emissions are adjusted

by the vapor recovery efficiency and then multiplied by their corresponding GWP

num bers (1 for CO 2 

### and 21 for CH 4 

### ) to get the CO 2 

### e values.

Table 17

- 2 lists the total vented and fugitive emissions from separators as reported in

the survey

. As shown, a lmost all of the emissions are fugitive.

Table 17

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

Type CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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 a pproximately 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 rep ort.

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 CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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 3,578Chapter 17 Final 2007 Oil and Gas Industry Survey Results



### 17

- 3 Seventy

- two percent of the emissions come from the categor ies “ 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 pe rcent 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 CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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 vaporChapter 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 da ta.

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 categori es and the types they represent:

o Flare

– flares, flares/collection systems, flares/collection

systems/combustion equipment ;

o Combustion Un it

– 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 num ber 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: 4,618Chapter 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 I ndustry Survey gathered

information about sumps and pits . Facilities were required to submit the followi ng

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 liq uids 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 e mission factors based on the

typ e, area, and the days of use of the sump. These equations are detailed in

Appendix B. The CO 2 

### and CH 4 

### emissions are adjusted by the vapor recovery efficiency

and th en multiplied by their corresponding GWP numbers (1 for CO 2 

### and 21 for CH 4 

### ) to

get the CO 2 

### e values.

Table 18

- 1 lists the fugitive emissions by type of sump /pit

. About h alf the emissions are

from primary sumps /pits . The remaining half is split between se condary and tertiary

sumps /pits

.

Table 18

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

Type Number of

Sumps CH 4 CO 2 e Percent of

Total CO 2 e

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 CO 2 

### e 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 CH 4 CO 2 e

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: 2 50 125 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 categori es and the types they represent:

o Collection System

– compressors, collection systems, tank s, 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 5 0 %

Cover 73 2 9 %

Collection System 48 19%

Flare PD PD

Incinerator PD PD

Totals: 250Chapter 1 9 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 followin g 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 CH 4 

### and CO 2 

### in the vapor losses ;

o Whether the storage tank had an access hatch or pressure relief valve

**•** Were they counted in the co mponents 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

**•** Facil ities 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 ca lculate d 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 CO 2 

### and CH 4 

### emissions are adjusted

by the vapor recovery efficiency and then multiplied by their corresponding GWP

numbers (1 for CO 2 

### and 21 for CH 4 

### ) to get the CO 2 

### e values.

Table 19

- 1 lists the total vented and fugitive emissions from storage tanks. As shown,

n ear ly all of the emissions are fugitive.Chapter 1 9 Final 2007 Oil and Gas Industry Survey Results



### 19

- 2 Table 19

- 1 : Total Emissions of Storage Tanks (Metric Tons/Year)

Type CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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 th e final draft of this report.

Table 19

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

Type Number of

Units CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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 CO 2 CH 4 CO 2 e Percent of

Total CO 2 e

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, l ess than half of the fixed roof tanks have vapor recovery. Floating

roof tanks, both internal and external, are considered a type of vapor recovery syst em

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 1 9 Final 2007 Oil and Gas Industry Survey Results



### 19

- 3 Table 19

- 4 : Storage Tanks by Type Perc ent 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 categori es 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 ste am

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 : Stor age 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: 3,639Chapter 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 CO 2 CH 4 N 2 O CO 2 e Percent of

Total CO 2 e

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 re maining 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 Comb ustion Vented Fugitive CO 2 e Percent of

Total CO 2 e

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 CO 2 

### e emissions were calculated for each facility. The facilities were then

categorized into ranges of CO 2 

### e emissions. Table 20

- 3 lists the number of facilities in

each range and the total CO 2 

### e 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 E missions by CO 2 

### e Range (Metric Tons/Year)

Range

(CO 2 e per Facility) Number of

Facilities CO 2 e Percent of Total

CO 2 e

< 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



### Table s 20

- 4, 20

- 5, and 20

- 6 list the number of facilities and total CO 2 

### e 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 CO 2 

### e Range

(Metric Tons/Year)

Range

(CO 2 e per Facility) Number of

Facilities CO 2 e Percent of Total

CO 2 e

< 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



### Table s 20

- 5 and 20

- 6 list the number of facilities and total CO 2 

### e emissions for vented

and fugitive emissions separately. With the combustion emissions removed, the range

of CO 2 

### e values is much smaller. The majority of the facilities fall in the “ less than 1,000

metric ton CO 2 

### e 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 CO 2 

### e Range (Metric Tons/Year)

Range

(CO 2 e per Facility) Number of

Facilities CO 2 e Percent of Total

CO 2 e

<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: 791 169,488Chapter 20 Final 2007 Oil and Gas Industry Survey Results



### 20

- 3 Table 20

- 6 : Crude Oil Fugitive Emissions by CO 2 

### e Range (Metric Tons/Year)

Range

(CO 2 e per Facility) Number of

Facilities CO 2 e Percent of Total

CO 2 e

< 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 CO 2 

### e emissions per barrel of crude

oil produced. Thi s can be calculated in two ways, as a facility average and as a

production

- weighted average.

Facility Average

The average CO 2 

### e emissions per barrel of crude oil produced was calculated for each

facilit y by dividing the facility’s total CO 2 

### e emissions by its total production. Those

values were then averag ed for each range of production, as a facility average and as a

production

- weighted average.

Avg. CO 2 

### e/bbl range 

### = ∑[(CO 2 

### e/bbl facility 

### )] range 

### /number facilities range



### Production

- Weighted Average

The average CO 2 

### e emissions per barrel of crude production was calculated by summing

the total CO 2 

### e emissions for each range of production and dividing it by the total barrels

produced in that range.

Avg. CO 2 

### e/ bbl range 

### = (total CO 2 

### e range 

### )/(total bbl range 

### )

The above calculations were done for total emissions and combustion, vented, and

fugitive emissions separately. Table 20

- 7 shows the average CO 2 

### e emissions per

barrel for total emissions. The range “not rep orted” includes facilities that listed

themselves as crude production but did not fill out their crude oil production for 2007.

Most of the CO 2 

### e emissions per barrel numbers are very close with the exception of the

range 10,000 to 25,000. This range is s kewed upwards due to facilit ies generat ing

electricity as well as producing crude oil.Chapter 20 Final 2007 Oil and Gas Industry Survey Results



### 20

- 4 Table 20

- 7 : Average Total CO 2 

### e 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 CO 2 e Facility

Average CO 2 e

per Barrel Production

Weighted

Average CO 2 e

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 CO 2 

### e 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 facilit ies generating electricity as well as producing crude oil.

Table 20

- 8 : Average Combustion CO 2 

### e 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 CO 2 e Facility

Average CO 2 e

per Barrel Production

Weighted

Average CO 2 e

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 CO 2 

### e 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 CO 2 

### e 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

CO 2 e Facility

Average CO 2 e

per Barrel Production

Weighted

Average CO 2 e

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 CO 2 

### e emissions per barrel for fugitive emissions only. The high

average CO 2 

### e 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 CO 2 

### e 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

CO 2 e Facility

Average CO 2 e

per Barrel Production

Weighted

Average CO 2 e

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 0.003Chapter 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 bu siness type s: 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 2 1

- 1, about half of the em issions come from combustion sources and about a

third come from fugitive sources.

Table 21

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

Type CO 2 CH 4 N 2 O CO 2 e Percent of

Total CO 2 e

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 2 1

- 2 lists the combustion, vented, and fugitive emissions for natural gas facilities.

About h alf 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 Bu siness Type (Metric Tons/Year)

Type Number

of

Facilities Combustion Vented Fugitive CO 2 e Percent

of Total

CO 2 e

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 CO 2 

### e emissions were calculated for each facility. The facilities were then

categorized into ranges of CO 2 

### e emissions. Table 2 1

- 3 lists the number of facilities in

each range and the CO 2 

### e emissions for the facilities in that range. As this table shows,

about 76 percent of the emissio ns come from about on e 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 CO 2 

### e Range (Metric Tons/Year)

Range

(CO 2 e per Facility) Number of Facilities CO 2 e Percent of Total

CO 2 e

< 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 2 1

- 4 lists the number of facilities in each range and the total combustion CO 2 

### e

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 CO 2 

### e range.

Table 21

- 4 : Natural Gas Combustion Emissions by CO 2 

### e Range (Metric Tons/Year)

Range

(CO 2 e per Facility) Number of Facilities CO 2 e Percent of Total

CO 2 e

< 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 2 1

- 5 and 2 1

- 6 show the number of facilities and the total CO 2 

### e 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 CO 2 

### e Range (Metric Tons/Year)

Range

(CO 2 e per Facility) Number of Facilities CO 2 e Percent of Total

CO 2 e

<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 CO 2 

### e Range (Metric Tons/Year)

Range

(CO 2 e per Facility) Number of Facilities CO 2 e Percent of Total

CO 2 e

< 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: 730 787,044Chapter 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 CO 2 

### e emissions per thousand

cubic feet ( mscf ) of natural gas produced. This can be calculated in two ways.

Facility Average

The average CO 2 

### e emissions per mscf natural gas produced was calculated for each

facility by dividing the facility’s total CO 2 

### e emissions by its total production. Those

values were then averaged for each range of production.

Avg. CO 2 

### e/mscf range 

### = ∑[(CO 2 

### e/mscf facility 

### ) ] range 

### /number facilities range



### Production

– Weighted Average

The average CO 2 

### e emissions per mscf natural gas production was calculated by

summing the total CO 2 

### e emissions for each range of production and dividing it by the

total mscf produced in that range.

Avg. CO 2 

### e/mscf range 

### = (total CO 2 

### e range 

### )/(total mscf range 

### )

The above calculations were done for total emissions and combustion, vented, and

fugitive emissions separately. Table 2 1

- 7 shows the average CO 2 

### e 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 CO 2 

### e 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 CO 2 

### e 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 CO 2 

### e 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 CO 2 e Facility

Weighted

Average CO 2 e

per MSCF Production

Weighted

Average CO 2 e

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 25 0,000 242 34,859,306 252,624 0.007 0.007

25 0,000 to 5 00,000 35 10,830,889 27,687 0.003 0.003

> 5 00,000 9 13,178,870 12,805 0.001 0.001

Totals: 703 68,055,293 547,624 2.090 0.008Chapter 21 Final 2007 Oil and Gas Industry Survey Results



### 21

- 4 Table 21

- 8 lists the average CO 2 

### e emissions per mscf natural gas produced for

combustion emissions by range of production. Here, the bottom two ranges have

higher CO 2 

### e per mscf values due to the reasons stated above for Table 21

- 7.

Table 21

- 8 : Average Combustion CO 2 

### e 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 CO 2 e Facility

Weighted

Average CO 2 e

per MSCF Production

Weighted

Average CO 2 e

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 25 0,000 242 34,859,306 59,464 0.0018 0.0017

25 0,000 to 5 00,000 35 10,830,889 7,777 0.0008 0.0007

> 5 00,000 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 CO 2 

### e 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 CO 2 

### e 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 CO 2 e Facility

Weighted

Average CO 2 e

per MSCF Production

Weighted

Average CO 2 e

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 25 0,000 242 34,859,306 71,806 0.0020 0.0021

25 0,000 to 5 00,000 35 10,830,889 6,308 0.0006 0.0006

> 5 00,000 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 CO 2 

### e 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 CO 2 e Facility

Weighted

Average CO 2 e

per MSCF Production

Weighted

Average CO 2 e

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 25 0,000 242 34,859,306 121,354 0.0037 0.0035

25 0,000 to 5 00,000 35 10,830,889 13,601 0.0013 0.0013

> 5 00,000 9 13,178,870 1,780 0.0001 0.0001

Totals: 703 68,055,293 210,879 1.9852 0.0031Appendix 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 SurveyAppendix A Final 2007 Oil and Gas Industry Survey Results



### A

- 2Appendix A Final 2007 Oil and Gas Industry Survey Results



### A

- 3Appendix A Final 2007 Oil and Gas Industry Survey Results



### A

- 4Appendix 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 Owner 2

 Other (Specify): _________________ Air District Facility ID 1 :

______________________

______________________

______________________

______________________

______________________

______________________

______________________

______________________

______________________

______________________

______________________

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: Fa cility Production

Facility Name :

Box 1: Production

Number of: Produced

Natural

Gas 1 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 Cleanups 3

________ ________ ________ ________ ________ ________

Well Completions

________ ________ ________ ________ ________ ________

Volume Produced (bbl)

________ ________ ________ ________ ________

Box 2: Associated or Produced Natural Gas Production 2

Mole %

Methane Mole %

CO 2 Mole %

H 2 S 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 Ai r 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:

_________________ MWhAppendix 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 (ft 3 ): _______________

Throughput (SCF): ________________________ Throughput (SCF): _______________

Combustion Efficiency: ________________________ Capture Efficiency: _______________

Avg. Composition (Mole %) :

___________ % Methane ____________ % CO 2 Avg. Composition (Mole %) :

___________ % Methane

Carbon Mole Ratio 1

________________

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 ID 1

______________  Vapor Recovery

 Crude Oil Pump

 Well Pump

 Water Injection Pump

 Other (Specify)

_____________________

Manufacturer 2 : 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

PERP 4 Registered? Gaseous Fuel Molecular Weight 3

__________ __________  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 Counts 1

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 Devices 1

Air District Facility ID:

Controllers:

Gas Actuated Number: Number on

Gas Recovery 2

Continuous Bleed

___________________ ___________________

Intermittent Bleed

___________________ ___________________

Low Bleed

___________________ ___________________

No Bleed 3

___________________

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 Program 1



### (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 electronic al ly?  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

_________ % H 2 S

_________ % CO 2 _________ % Methane

_________ % H 2 S

_________ % CO 2 Output Volume (SCF):

Volume of Liquids Removed (tons/year) :

_________ HHV 1 (Btu) _________ HHV 1 (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 (ft 3 ): ________________ % of Packed Vessel Volume that is Natural Gas 2 : ____________

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

_________ % H 2 S

_________ % CO 2 _________ % Methane

_________ % H 2 S

_________ % CO 2 Output Volume (SCF):

Volume of Liquids Removed (tons/year) :

_________ HHV 1 (Btu) _________ HHV 1 (Btu)

CO 2 Removal:

Total CO 2 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 (ft 3 ): ________________ % of Packed Vessel Volume that is Natural Gas 2 : ___________

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

_________ % H 2 S

_________ % CO 2 _________ % Methane

_________ % H 2 S

_________ % CO 2 Output Volume (SCF):

Volume of Liquids Removed (tons/year) :

_________ HHV 1 (Btu) _________ HHV 1 (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 ID 1

__________

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 Frequency 2 :

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 Gas 1 Produced Gas 2

Vented

__________________ __________________ __________________ Flared

__________________ __________________ __________________ Recovered 3

__________________ __________________ __________________

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 G as 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) Component s :

Working Loss

_________ _________  Access Hatch

 Pressure Relief Valve

Breathing Loss

_________ _________

Flashing Loss

_________ _________ Are hatches and pressure relief valves included

Avg. Methane _________ % Avg. CO 2 _________ % in Table 6?  Yes  No

Vapor Recovery System:

Control Efficiency: _________%  Flare

 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 ___________

Dimension s:

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) Component s :

Working Loss

_________ _________  Access Hatch

 Pressure Relief Valve

Breathing Loss

_________ _________

Flashing Loss

_________ _________ Are hatches and pressure relief valves included

Avg. Methane _________ % Avg. CO 2 _________ % 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:

Control Efficiency: _________%  Flare

 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 2009Appendix 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 ba seline. 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 ope rator 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 g as

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 : incl udes 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 e

mail 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.govAppendix 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 informat ion 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 no t 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 cou ld 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) in clude 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 natura l 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 na tural 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 f acility 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 back up, 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 easie r 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 param eters, 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 % h ydrocarbon

100 �

∗ Number carbons i n h ydrocarbon

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 (CH 4 ) 80

Ethane (C 2 H 2 ) 15

Propane (C 3 H 8 ) 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) = 1.25Appendix 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 equipme nt. 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 L iquid 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 

### �

∗ � MW compound 

### � �

Where:

Mole % compound 

### = indicated on GC analysis

MW compound 

### = � Weig h t element 

### ∗ Coefficient element



### An example calculation for MW compound 

### : CH 4 

### = (12*1) + (1*4) = 16Appendix 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 h as 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 ac tuator 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 compone nts. 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 v arious 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 componen ts are acceptable.

Figure 1. Typical Vee

- Ball® Valves with Type 1052 Actuators and DVC6020 Digital Valve Controllers. Controller Ball Valve ActuatorAppendix 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 requireme nts. 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 da ta 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 re moved 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 s weetening 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 CO 2 

### is mixed with waste g as and sent to an incinerator or vented. Indicate

the method of CO 2 

### disposal. For units that require regular solid material replacement,

indicate the average remaining volume that exists after the unit is packed with materialAppendix 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 CO 2 

### , H 2 

### S, an d 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 vapo r 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 shaf t.

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 dr iver 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 av erage 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 a ctual 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, th e

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 piggin g

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 Separati **on 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 d ifferent 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 coun ting 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 su mp 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 empt ied 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 a nalysis. 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 FactorsAppendix B Final 2007 Oil and Gas Industry Survey Results



### B

- 2Appendix 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 CH 4 

### and CO 2 

### are 78.8 percent and

3 percent, respectively (API, 2004). For equipment that has vapor recovery, CO 2 

### and

CH 4 

### emissions are reduced by the vapor recovery efficiency before conversion to CO 2 

### e.

All CO 2 

### , CH 4 

### , and N 2 

### O values are multiplied by their corresponding GWP (1 for CO 2 

### , 21

for CH 4 

### , and 310 for N 2 

### O) to get the CO 2 

### e number.

Method 1

– Active Wells

The 2007 Industry survey separates crude oil into four categories: ultra

- heavy, hea vy,

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 cr ude use the

emission factor “light crude”, and dry gas and gas storage use the emission factor

“natural gas”.

CO 2 emissions (tonnes/year) = (CO 2 EF)*(Number)*(CO 2 Mole Fraction \ 0.03)

Where

CO 2 EF = See Table 1

Number = Number of active wells

CO 2 Mole Fraction = (lbmole CO 2 )/(lbmole gas)

Data Requirements

1. Number of active wells

2. Mole % CO 2

CH 4 emissions (tonnes/year) = (CH 4 EF)*(Number)*(CH 4 Mole Fraction \ 0.788)

Where

CH 4 EF = See Table 1

Number = Number of active wells

CH 4 Mole Fraction = (lbmole CH 4 )/(lbmole gas)

Data Requirements

1. Number of active wells

2. Mole % CH 4



### Table 1: Wellheads

Type CH 4 (tonnes/well

- year) % Methane

Assumption CO 2 (tonnes/well

- year) % CO 2 Assumption

Natural Gas 0.157 1 78.8 1.644E

- 02 1 3

Light Crude 0.108 1 78.8 1.128E

- 02 1 3

Heavy Crude 4.568E

- 03 1 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”.

CH 4 emissions (tonnes/year) = (CH 4 EF)*(Number)

Where

CH 4 EF = See Table 2

Number = number of well cellars

Data Requirements

1. Number of well cellars



### Table 2: Well Cellars

Type CH 4 (tonnes/well cellar

- year)

Light Crude 0.170 1

Heavy Crude 0.125 1

1. Kern County APCD (1990)



### Method 3

– New Wells Drilled

CH 4 emissions (tonnes/year) = (CH 4 EF)*(Number)

Where

CH 4 EF = See Table 3

Number = Number of wells drilled

Data Requirements

1. Number of wells drilled



### Table 3: New Wells Drilled

Type CH 4 (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 an d 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 C O 2 emissions (tonnes/year) = (EF)*(CO 2 Mole Fraction)*(D)* (Events)

Where

EF = See Table 4

CO 2 Mole Fraction = (lbmole CO 2 )/(lbmole gas)

D = (molar volume)*(Molecular Weight CO 2 )*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CO 2 = (44 lb CO 2 )/(lbmole CO 2 )

Events = Number of well workovers and cleanups

Data Requirement

1. Number of well workovers and cleanups

2. Mole % CO 2

C H 4 emissions (tonnes/year) = (EF)*(CH 4 Mole Fraction)*(D)* (Events)

Where

EF = See Table 4

CH 4 Mole Fraction = (lbmole CH 4 )/(lbmole gas)

D = (molar volume)*(Molecular Weight CH 4 )*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(3 79.3 scf gas)

Molecular Weight CH 4 = (16 lb CH 4 )/(lbmole CH 4 )

Events = Number of well workovers and cleanups

Data Requirement

1. Number of well workovers and cleanups

2. Mole % CH 4

Emission Factor Calculation (Listed in Table 4)

Equation = [(V)*(P 1 )*(T 2 )]/[( P 2 )*(T 1 )]

Where

V = volume of well

P 1 = shut

- in pressure (psia) of well

P 2 = 14.7 psia (standard surface pressure)

T 1 = temperature in well at shut

- in pressure

T 2 = 60° F (standard surface temperature)

Assumptions

Depth = 5000 ft

Casing Diameter = 7 in

Tubing Diameter = 2.875 in

P 1 = 100 psia

T 1 = 60° F



### Table 4: Well Workovers and Cleanups

Type CH 4 /CO 2 (scf/event)

Natural Gas 9090.256

Light Crude 7556.855

Heavy Crude 7556.855Appendix B Final 2007 Oil and Gas Industry Survey Results



### B

- 6 Method 5

– Well Completions

CH 4 emissions (tonnes/year) = (CH 4 EF)*(Number)

Where

CH 4 EF = See Table 5

Number = Number of wells completed

Data Requirements

1. Number of wells completed



### Table 5: Well Completions

Type CH 4 (tonnes/well)

Natural Gas

Light Crude

Heavy Crude



### Method 6

– Flares, Incinerators, Thermal Oxidizers

CO 2 

### and CH 4 

### emission calculations based on the following mass balance equations

(API, 2004).

CO 2 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 CO 2 )*(t onne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CO 2 = (44 lb CO 2 )/(lb mole CO 2 )

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)*(CO 2 Mole Fraction)*(D)

Where

Throughput = volume of gas flared (scf/year)

CO 2 Mole Fraction = (lbmole CO 2 )/(lbmole gas)

D = (molar volume)*(Molecular Weight CO 2 )*(tonne/2204.6lb)

Molar Volum e = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CO 2 = (44 lb CO 2 )/(lb mole CO 2 )

Data Requirements

1. Throughput (scf/year)

2. Mole % CO 2Appendix B Final 2007 Oil and Gas Industry Survey Results



### B

- 7 CH 4 emissions (tonnes/year) = (Throughput)*(CH 4 Mole Fraction)*(% Residual CH 4 )*(D)

Where

Throughput = volume of gas flared (scf gas/year)

CH 4 Mole Fraction = (lbmole CH 4 )/(lbmole gas)

% Residual CH 4 = 100

– (Combustion Efficiency)

D = (molar volume)*(Molecular Weight CH 4 )*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CH 4 = (16 lb CH 4 )/(lb mole CH 4 )

Data Requirements

1. Throughput (scf gas/year)

2. Combustion Efficiency (98% will be assumed if no combustion efficiency is supplied)

3. Mole % CH 4

N 2 O emissions (tonnes/year) = (Throughput)*(N 2 O Emission Factor)

Where

Throughput = volume of gas flared (scf gas/year)

N 2 O 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 th e gas stream passes through the adsorber.

CH 4 emissions (tonnes/year) = (Throughput)*(CH 4 Mole Fraction)*(D)

Where

Throughput = volume of gas (scf gas/year)

CH 4 Mole Fraction = (lbmole CH 4 )/(lbmole gas)

D = (molar volume)*(Molecular Weight CH 4 )*( tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CH 4 = (16 lb CH 4 )/(lbmole CH 4 )

Data Requirements

1. Throughput (scf gas/year)

2. Mole % CH 4



### Method 8

– Mass Balance Fuel Consumption

CO 2 

### and CH 4 

### combustion calculations for all c ombustion 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

CO 2 emissions (tonnes/year) = (Combustion Emissions) + (Vented Emissions)

Combustion Emissions (to nnes/year) = (Fuel Use)*(MW fuel )*(Carbon Weight %)*(COX)*(D)

Where

Fuel Use = fuel use (scf/year)

MW fuel = 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/MW C )*(lbmole CO 2 /lbmole C)*(MW CO2 )*(tonne/2204.6 lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

MW C = (12 lb C)/(lb mole C)

MW CO2 = (44 lb CO 2 )/(lb mole CO 2 )

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)*(CO 2 Mole Fraction)*(D)

Where

Fuel Use = fuel use (scf/year)

COX = fraction of fuel oxidized (assumed to be 99%)

D = (molar volume )*(MW C O2 )*(tonne/2204.6 lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

MW C O2 = (44 lb CO 2 )/(lb mole CO 2 )

Data Requirements

1. Fuel Use (scf gas/year)

2. COX (if different from assumed value of 99%)

3. Mole % CO 2

CH 4 emissions (tonnes/year) = (Fuel Use)*(CH 4 Mole Fraction)*(1

- COX)*(D)

Where

Fuel Use = fuel use (scf/year)

COX = fraction of fuel oxidized (assumed to be 99%)

D = (molar volume)*(MW C H4 )*(tonne/2204.6 lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

MW C H4 = (16 lb CH 4 )/(lb mole CH 4 )

Data Re quirements

1. Fuel Use (scf gas/year)

2. COX (if different from assumed value of 99%)

3. Mole % CH 4Appendix B Final 2007 Oil and Gas Industry Survey Results



### B

- 9 Liquid Fuels

CO 2 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/MW C )*(lbmole CO 2 /lbmole C)*(MW CO2 )*(tonne/2204.6 lb)

MW C = (12 lb C)/(lb mole C)

MW CO2 = (44 lb CO 2 )/(lb mole CO 2 )

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 e quipment that have emission factors listed in Table 6.

CO 2 emissions (tonnes/year) = (Fuel Use)*(HHV)*(CO 2 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)

CO 2 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)

CH 4 emissions (tonnes/year) = (Fuel Use)*(HHV)*(CH 4 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)

CH 4 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)

N 2 O emissions (tonnes/year) = (Fuel Use)*(H HV)*(N 2 O 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)

N 2 O Emission Factor = See Table 6Appendix 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. HH V of fuel (Btu/scf or Btu/gal)



### Table 6: Combustion Equipment

Equipment Type CO 2 (tonnes/MMBtu) CH 4 (tonnes/MMBtu) N 2 O

(tonnes/MMBtu)

Natural Gas Fired

Boilers 0.0534 2 1.023E

- 06 4 9.8E

- 07 5

Steam Generators 0.0534 2 1.023E

- 06 4 9.8E

- 07 5

Heaters 0.0534 2 1.023E

- 06 4 9.8E

- 07 5

Reciprocating Engine

Two

– Stroke Lean 0.0499 3 6.577E

- 04 4 2.3E

- 06 5

Four

– Stroke Lean 0.0499 3 5.670E

- 04 4 1.4E

- 06 5

Four

– Stroke Rich 0.0499 3 1.043E

- 04 4 4.5E

- 07 5

Turbine 0.0499 3 3.901E

- 06 4 3.8E

- 06 5

Diesel Fired

Reciprocating Engine

Two

– Stroke Lean 0.0744 1 4E

- 06 5

Two

– Stroke Rich 0.0744 1 4E

- 06 5

Four

– Stroke Lean 0.0744 1 4E

- 06 5

Four

– Stroke Rich 0.0744 1 4E

- 06 5

Gasoline Fired

Reciprocating Engine

Two

– Stroke Lean 0.0699 1 1.2E

- 04 5

Two

– Stroke Rich 0.0699 1 1.2E

- 04 5

Four

– Stroke Lean 0.0699 1 3.9

- 05 5

Four

– Stroke Rich 0.0699 1 3.9

- 05 5

Landfill Gas Fired

Turbine 0.0227 3

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.

CO 2 emissions (tonnes/year) = (Fuel Use)*(HHV)*(CO 2 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)

CO 2 Emission Factor = See Table 7

Data Requirement

1. Fuel Use (scf/year or gal/year)

2. HHV of fuel (Btu/scf or Btu/gal)

CH 4 emissions (tonnes/year) = (Fuel Use)*(HHV)*(CH 4 Emission Factor)*(10 - 6 )

Where

Fuel Use = volume o f fuel used (scf/year or gal/year)

HHV = Higher Heating Value of fuel (Btu/scf or Btu/gal)

CH 4 Emission Factor = See Table 7Appendix 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)

N 2 O emissions (tonnes/year) = (Fuel Use)*(HHV )*(N 2 O 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)

N 2 O 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 CO 2 (tonnes/MMBtu) CH 4 (tonnes/MMBtu) N 2 O

(tonnes/MMBtu)

Natural Gas

Unspecified 0.05302 1 9E

- 07 1 1E

- 07 1

975 to 1,000 Btu/scf 0.05397 1 9E

- 07 1 1E

- 07 1

1,000 to 1,025 Btu/scf 0.05287 1 9E

- 07 1 1E

- 07 1

1,025 to 1,050 Btu/scf 0.05302 1 9E

- 07 1 1E

- 07 1

1,050 to 1,075 Btu/scf 0.05342 1 9E

- 07 1 1E

- 07 1

1,075 to 1,100 Btu/scf 0.05368 1 9E

- 07 1 1E

- 07 1

> 1,100 Btu/scf 0.05467 1 9E

- 07 1 1E

- 07 1

Landfill Gas 0.05203 1 9E

- 07 1 1E

- 07 1

Diesel 0.0731 2 3E

- 06 1 6E

- 07 1

Liquidfied Petroleum Gas 0.06298 1 1E

- 06 1 1E

- 07 1

Propane 0.06302 1 1E

- 06 1 1E

- 07 1

Gasoline 0.07083 1 3E

- 06 1 6E

- 07 1

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.

CO 2 emissions (tonnes/year) = (CO 2 EF)*(Number) *(CO 2 Mole Fraction/0.03)

Where

CO 2 EF = See Table 8

Number = Number of components

CO 2 Mole Fraction = (lbmole CO 2 )/(lbmole gas)

Data Requirements

1. Mole % CO 2

2. Number of componentsAppendix B Final 2007 Oil and Gas Industry Survey Results



### B

- 12 CH 4 emissions (tonnes/year) = (CH 4 EF)*(Number) *(CH 4 Mole Fraction/0.788)

Where

CH 4 EF = See Table 8

Number = Number of components

CH 4 Mole Fraction = (lbmole CH 4 )/(lbmole gas)

Data Requiremen ts

1. Mole % CH 4

2. Number of components



### Table 8: Components

Component Type Natural Gas 1 Light Crude 2 Heavy Crude 3

(tonnes/component

- year)

CH 4 (78.8% Methane Assumption)

Manual Valves 1.759E

- 04 4 1.348E

- 04 4 1.341E

- 04 4

Flanges 1.407E

- 04 4 1.703E

- 04 4 2.203E

- 04 4

Connectors 6.029E

- 05 4 7.095E

- 05 4 7.661E

- 05 4

Open

- ended Lines 1.206E

- 04 4 1.277E

- 04 4 1.436E

- 04 4

Threaded Components 6.029E

- 05 4 7.095E

- 05 4 7.661E

- 05 4

Pump Seals 5.004E

- 03 4 1.880E

- 03 4 5.458E

- 04 4

Pressure Relief Valves 7.386E

- 04 4 9.294E

- 04 4 5.458E

- 04 4

Bursting Discs 7.386E

- 04 4 9.294E

- 04 4 5.458E

- 04 4

Diaphragms 7.386E

- 04 4 9.294E

- 04 4 5.458E

- 04 4

Drains 7.386E

- 04 4 9.294E

- 04 4 5.458E

- 04 4

Hatches 7.386E

- 04 4 9.294E

- 04 4 5.458E

- 04 4

Instruments 7.386E

- 04 4 9.294E

- 04 4 5.458E

- 04 4

Meters 7.386E

- 04 4 9.294E

- 04 4 5.458E

- 04 4

Polished Rod Stuffing Boxes 7.386E

- 04 4 9.294E

- 04 4 5.458E

- 04 4

Sight Glasses 7.386E

- 04 4 9.294E

- 04 4 5.458E

- 04 4

Loading Arms 7.386E

- 04 4 9.294E

- 04 4 5.458E

- 04 4

Dump Lever Arm 7.386E

- 04 4 9.294E

- 04 4 5.458E

- 04 4

CO 2 (3% CO 2 Assumption)

Manual Valves 2.247E

- 05 4 1.411E

- 05 4 1.404E

- 05 4

Flanges 1.473E

- 05 4 1.783E

- 05 4 2.306E

- 05 4

Connectors 6.312E

- 06 4 7.428E

- 06 4 8.021E

- 06 4

Open

- ended Lines 1.263E

- 05 4 1.337E

- 05 4 1.504E

- 05 4

Threaded Components 6.312E

- 06 4 7.428E

- 06 4 8.021E

- 06 4

Pump Seals 5.239E

- 04 4 1.968E

- 04 4 5.715E

- 05 4

Pressure Relief Valves 7.733E

- 05 4 9.730E

- 05 4 5.715E

- 05 4

Bursting Discs 7.733E

- 05 4 9.730E

- 05 4 5.715E

- 05 4

Diaphrams 7.733E

- 05 4 9.730E

- 05 4 5.715E

- 05 4

Drains 7.733E

- 05 4 9.730E

- 05 4 5.715E

- 05 4

Hatches 7.733E

- 05 4 9.730E

- 05 4 5.715E

- 05 4

Instruments 7.733E

- 05 4 9.730E

- 05 4 5.715E

- 05 4

Meters 7.733E

- 05 4 9.730E

- 05 4 5.715E

- 05 4

Polished Rod Stuffing Boxes 7.733E

- 05 4 9.730E

- 05 4 5.715E

- 05 4

Sight Glasses 7.733E

- 05 4 9.730E

- 05 4 5.715E

- 05 4

Loading Arms 7.733E

- 05 4 9.730E

- 05 4 5.715E

- 05 4

Dump Lever Arm 7.733E

- 05 4 9.730E

- 05 4 5.715E

- 05 4

1. Assume THC is 70% CH 4 ; 2. Assume THC is 74% CH 4 ; 3. Assume THC is 72% CH 4 ; 4. CAPCOA (1999)Appendix B Final 2007 Oil and Gas Industry Survey Results



### B

- 13 Method 12

– Automated Control Devices

C O 2 emissions (tonnes/year) = (CO 2 Emission Factor)*(CO 2 Mole Fraction/0.03)*(# Devices)

Where

CO 2 Emission Factor = See Table 9

CO 2 Mole Fraction = (lbmole CO 2 )/(lbmole gas)

# Devices = Number of automated control devices

Data Requirements

1. Mole % CO 2

2. Number of automated control devices

CH 4 emissions (tonnes/year) = (CH 4 Emission Factor)*(CH 4 Mole Fraction/0.788)*(# Devices)

Where

CH 4 Emission Factor = See Table 9

CH 4 Mole Fraction = (lbmole CH 4 )/(lbmole gas)

# Devices = Number of automated control devices

Data Requirements

1. Mole % CH 4

2. Number of automated control devices



### Table 9: Automated Control Devices

Device Type CH 4 (tonnes/device

- year) % Methane

Assumption CO 2 (tonnes/device

- year) % CO 2 Assumption

Controllers

Continuous Bleed 3.599 1 78.8 0.377 1 3

Intermittent Bleed 1.778 1 78.8 0.186 1 3

Low Bleed 0.792 2 78.8 0.083 2 3

Actuators

- Production

Piston Valve Operator 7.237E

- 04 3 78.8 7.577E

- 05 3

Hydraulic Valve Operator 4.095E

- 02 3 78.8 4.287E

- 03 3

Turbine Valve Operator 1.086E

- 02 3 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).

C O 2 emissions (tonnes/year) = (Throughput)*(EF \ 0.90)*(CO 2 Mole Fraction)*D

Where

EF = [(0.0066)*(GCR)*(P)*(GAP)] + (SG)

EF units = (Mcf CH 4 /year per MMcf gas throughput/day)

EF conversion = [(1 year)/(365 days)]*[(1 MMcf gas)/(10 6 scf gas)]*[(1000 scf CH 4 )/(1 Mcf CH 4 )]

0.90 = % methane used to create EF (lbmole CH 4 )/(lbmole gas)

GCR = glycol circulation rate (gph)

P = fl ash 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

CO 2 Mole Fraction = (lbmole CO 2 )/(lbmole gas)

D = (CH 4 Density) *(lb/453.5 grams)*(1/MW CH4 )*(MW CO 2 )*(tonne/2204.6lb)*(EF conversion)

CH 4 Density = (19.2 grams)/(scf CH 4 )

MW CH 4 = (16 lb CH 4 )/(lbmole CH 4 )

MW CO 2 = (44 lb CO 2 )/(lbmole CO 2 )

Data Requirements

1. Throughput (scf/year)

2. Input Mole % CO 2

3. Glycol circulation rate (gallons/hour)

4. Flash tank pressure (psia)

5. Contactor pressure (psia)

6. Gas assist pump installation

7. Stripping gas use

C H 4 emissions (tonnes/year) = (Throughput)*(EF \ 0.90)*(CH 4 Mole Fraction)*D

Where

EF = [(0.0066)*(GCR)*(P)*(GAP)] + (SG)

EF units = ( Mcf CH 4 /year per MMcf gas throughput/day)

EF conversion = [(1 year)/(365 days)]*[(1 MMcf gas)/(10 6 scf gas)]*[(1000 scf CH 4 )/(1 Mcf CH 4 )]

0.90 = % methane used to create EF (lbmole CH 4 )/(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

CH 4 Mole Fraction = (lbmole CH 4 )/(lbmole gas)

D = (CH 4 Density)*(lb/453.5 g rams)*(tonne/2204.6lb)*(EF conversion)

CH 4 Density = (19.2 grams)/(scf CH 4 )

Data Requirements

1. Throughput (scf/year)

2. Input Mole % CH 4

3. Glycol circulation rate (gallons/hour)

4. Flash tank pressure (psia)

5. Contactor pressure (psia)

6. Gas assist pump installatio n

7. Stripping gas useAppendix 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).

C O 2 emissions (tonnes/year) = (EF)*(CO 2 Mole Fraction)*D

Where

EF = [(P 2 )*(G)*(365 days/yr)*(V)] \ [(P 1 )*(T)]

P 1 = 14.7 psia (atmospheric pressure)

P 2 = (Pressure of Gas (psig)) + 14.7

G = % of Packed Vessel Volume that is Natural Gas

V = Volume of Dehydrator (ft 3 )

T = Frequency of Desiccant Replacement (days)

CO 2 Mole Fraction = (lbmole CO 2 )/(lbmole gas)

D = (molar volume)*(Molecular Weight CO 2 )*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CO 2 = (44 lb CO 2 )/(lbmole CO 2 )

Data Requirements

1. Mole % CO 2

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)

C H 4 emissions (tonnes/year) = (EF)*(CH 4 Mole Fraction)*D

Where

EF = [(P 2 )*(G)*(365 days/yr)*(V)] \ [(P 1 )*(T)]

P 1 = 14.7 psia (atmospheric pressure)

P 2 = (Pressure of Gas (psig)) + 14.7

G = % of Packed Vessel Volume that is Natural Gas

V = Volume of Dehydrator (ft 3 )

T = Frequency of Desiccant Replacement (days)

CH 4 Mole Fraction = (lbmole CH 4 )/(lbmole gas)

D = (molar volume)*(Molecular Weight CH 4 )*(to nne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CH 4 = (16 lb CH 4 )/(lbmole CH 4 )

Data Requirements

1. Mole % CH 4

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.

C O 2 emissions (tonnes/year) = (Mass Balance)

– (Vented Emissions)

Where

Mass Balance = D*[(Input)*(In CO 2 Mole Fraction)

– (Output)*(Out CO 2 Mole Fraction)]

Vented Emissions = Method 13 or Method 14

Input = Input volume (scf/year)

Output = Output volume (scf/year)

In CO 2 Mole Fraction = Input CO 2 Mole Fraction = (lbmole CO 2 )/(lbmole gas)

Out CO 2 Mole Fraction = Output CO 2 Mole Fraction = (lbmole CO 2 )/(lbmole gas)

D = (molar volume)*(Molecular Weight CO 2 )*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CO 2 = (44 lb CO 2 )/(lbmole CO 2 )

Data Requirements

1. Inpu t volume (scf/year)

2. Output volume (scf/year)

3. Input Mole % CO 2

4. Output Mole % CO 2

5. Vented Emissions

C H 4 emissions (tonnes/year) = (Mass Balance)

– (Vented Emissions)

Where

Mass Balance = D*[(Input)*(In CH 4 Mole Fraction)

– (Output)*(Out CH 4 Mole Fraction)]

Vented Emissions = Method 13 or Method 14

Input = Input volume (scf/year)

Output = Output volume (scf/year)

In CH 4 Mole Fraction = Input CH 4 Mole Fraction = (lbmole CH 4 )/(lbmole gas)

Out CH 4 Mole Fraction = Output CH 4 Mole Fraction = (lbmole CH 4 )/(lbmol e gas)

D = (molar volume)*(Molecular Weight CH 4 )*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CH 4 = (16 lb CH 4 )/(lbmole CH 4 )

Data Requirements

1. Input volume (scf/year)

2. Output volume (scf/year)

3. Input Mole % CH 4

4. Output Mole % CH 4

5. Vented EmissionsAppendix 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).

C O 2 emissions (tonnes/year) = (EF)*(CO 2 Mole Fraction)*D

Where

EF = [(P 2 )*(G)*(365 day s/yr)*(V)] \ [(P 1 )*(T)]

P 1 = 14.7 psia (atmospheric pressure)

P 2 = (Pressure of Gas (psig)) + 14.7

G = % of Packed Vessel Volume that is Natural Gas

V = Volume of Unit (ft 3 )

T = Frequency of Solid Material Replacement (days)

CO 2 Mole Fraction = (lbmole CO 2 )/(lbmole gas)

D = (molar volume)*(Molecular Weight CO 2 )*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CO 2 = (44 lb CO 2 )/(lbmole CO 2 )

Data Requirements

1. Input Mole % CO 2

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)

C H 4 emissions (tonnes/year) = (EF)*(CH 4 Mole Fraction)*D

Where

EF = [(P 2 )*(G)*(365 days/yr)*(V) ] \ [(P 1 )*(T)]

P 1 = 14.7 psia (atmospheric pressure)

P 2 = (Pressure of Gas (psig)) + 14.7

G = % of Packed Vessel Volume that is Natural Gas

V = Volume of Unit (ft 3 )

T = Frequency of Solid Material Replacement (days)

CH 4 Mole Fraction = (lbmole CH 4 )/(lbmole gas)

D = (molar volume)*(Molecular Weight CH 4 )*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CH 4 = (16 lb CH 4 )/(lbmole CH 4 )

Data Requirements

1. Input Mole % CH 4

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 usin g mass balance.

C O 2 emissions (tonnes/year) = (Mass Balance)

– (Vented Emissions)

Where

Mass Balance = D*[(Input)*(In CO 2 Mole Fraction)

– (Output)*(Out CO 2 Mole Fraction)]

Vented Emissions = Method 16

Input = Input volume (scf/year)

Output = Output vo lume (scf/year)

In CO 2 Mole Fraction = Input CO 2 Mole Fraction = (lbmole CO 2 )/(lbmole gas)

Out CO 2 Mole Fraction = Output CO 2 Mole Fraction = (lbmole CO 2 )/(lbmole gas)

D = (molar volume)*(Molecular Weight CO 2 )*(tonne/2204.6lb)

Molar Volume = (1 lbmole ga s)/(379.3 scf gas)

Molecular Weight CO 2 = (44 lb CO 2 )/(lbmole CO 2 )

Data Requirements

1. Input volume (scf/year)

2. Output volume (scf/year)

3. Input Mole % CO 2

4. Output Mole % CO 2

5. Vented Emissions

C H 4 emissions (tonnes/year) = (Mass Balance)

– (Vented Emissions)

Where

Mass Balance = D*[(Input)*(In CH 4 Mole Fraction)

– (Output)*(Out CH 4 Mole Fraction)]

Vented Emissions = Method 16

Input = Input volume (scf/year)

Output = Output volume (scf/year)

In CH 4 Mole Fraction = Input CH 4 Mole Fraction = (lbmole CH 4 )/(lbmo le gas)

Out CH 4 Mole Fraction = Output CH 4 Mole Fraction = (lbmole CH 4 )/(lbmole gas)

D = (molar volume)*(Molecular Weight CH 4 )*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CH 4 = (16 lb CH 4 )/(lbmole CH 4 )

Data Requireme nts

1. Input volume (scf/year)

2. Output volume (scf/year)

3. Input Mole % CH 4

4. Output Mole % CH 4

5. Vented EmissionsAppendix B Final 2007 Oil and Gas Industry Survey Results



### B

- 19 Method 18

– Natural Gas Sweentening/Acid Gas Removal Mass Balance (Non

solid Material Units)

Fugitive emissions from natural gas sweetening or acid gas removal.

C O 2 emissions (tonnes/year) = D*[(Input)*(In CO 2 Mole Fraction)

– (Output)*(Out CO 2 Mole Fraction)]

Where

Input = Input volume (scf/year)

Output = Output volume (scf/year)

In CO 2 Mole Fraction = Input CO 2 Mole Fraction = (lbmole CO 2 )/(lbmole gas)

Out CO 2 Mole Fraction = Output CO 2 Mole Fraction = (lbmole CO 2 )/(lbmole gas)

D = (molar volume)*(Molecular Weight CO 2 )*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CO 2 = (44 lb CO 2 )/(lbmole CO 2 )

Data Re quirements

1. Input volume (scf/year)

2. Output volume (scf/year)

3. Input Mole % CO 2

4. Output Mole % CO 2

C H 4 emissions (tonnes/year) = D*[(Input)*(In CH 4 Mole Fraction)

– (Output)*(Out CH 4 Mole Fraction)]

Where

Input = Input volume (scf/year)

Output = Output vol ume (scf/year)

In CH 4 Mole Fraction = Input CH 4 Mole Fraction = (lbmole CH 4 )/(lbmole gas)

Out CH 4 Mole Fraction = Output CH 4 Mole Fraction = (lbmole CH 4 )/(lbmole gas)

D = (molar volume)*(Molecular Weight CH 4 )*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CH 4 = (16 lb CH 4 )/(lbmole CH 4 )

Data Requirements

1. Input volume (scf/year)

2. Output volume (scf/year)

3. Input Mole % CH 4

4. Output Mole % CH 4



### Method 19

– Other Natural Gas Processing

Vented and fugitive emissions from other natural gas processing.

C O 2 emissions (tonnes/year) = D*[(Input)*(In CO 2 Mole Fraction)

– (Output)*(Out CO 2 Mole Fraction)]

Where

Input = Input volume (scf/year)

Output = Output volume (scf/year)

In CO 2 Mole Fraction = Input CO 2 Mole Fraction = ( lbmole CO 2 )/(lbmole gas)

Out CO 2 Mole Fraction = Output CO 2 Mole Fraction = (lbmole CO 2 )/(lbmole gas)

D = (molar volume)*(Molecular Weight CO 2 )*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CO 2 = (44 lb CO 2 )/(lbmole CO 2 )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 % CO 2

4. Output Mole % CO 2

C H 4 emissions (tonnes/year) = D*[(Input)*(In CH 4 Mole Fraction)

– (Output)*(Out CH 4 Mole Fraction)]

Where

Input = Input volume (scf/year)

Output = Output volume (scf/year)

In CH 4 Mole Fraction = Input CH 4 Mole Fraction = (lbmole CH 4 )/(lbmole gas)

Out CH 4 Mole Fraction = Output CH 4 Mole Fraction = (lbmole CH 4 )/(lbmole gas)

D = (molar volume)*(Molecular Weight CH 4 )*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CH 4 = (16 lb CH 4 )/(lbmole CH 4 )

Data Requirements

1. Input volume (scf/year)

2. Output volume (scf/year)

3. Input Mole % CH 4

4. Output Mole % CH 4



### Method 20

– Natural Gas Compressor Startups

C O 2 emissions (tonnes/year) = (Total Volume of Gas Vented)*(CO 2 Mole Fraction)*D

Where

CO 2 Mole Fraction = (lbmole CO 2 )/(lbmole gas)

D = (molar volume)*(Molecular Weight CO 2 )*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CO 2 = (44 lb CO 2 )/(lbmo le CO 2 )

Data Requirements

1. Total volume of gas vented (scf)

2. Mole %CO 2

C H 4 emissions (tonnes/year) = (Total Volume of Gas Vented)*(CH 4 Mole Fraction)*D

Where

CH 4 Mole Fraction = (lbmole CH 4 )/(lbmole gas)

D = (molar volume)*(Molecular Weight CH 4 )*(tonne /2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CH 4 = (16 lb CH 4 )/(lbmole CH 4 )

Data Requirements

1. Total volume of gas vented (scf)

2. Mole %CH 4Appendix B Final 2007 Oil and Gas Industry Survey Results



### B

- 21 Method 21

– Natural Gas Compressor Blowdowns

C O 2 emissions (tonnes/year) = (Total Volume of Gas Vented)*(CO 2 Mole Fraction)*D

Where

CO 2 Mole Fraction = (lbmole CO 2 )/(lbmole gas)

D = (molar volume)*(Molecular Weight CO 2 )*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CO 2 = (44 lb CO 2 )/(lbmo le CO 2 )

Data Requirements

1. Total volume of gas vented (scf)

2. Mole %CO 2

C H 4 emissions (tonnes/year) = (Total Volume of Gas Vented)*(CH 4 Mole Fraction)*D

Where

CH 4 Mole Fraction = (lbmole CH 4 )/(lbmole gas)

D = (molar volume)*(Molecular Weight CH 4 )*(tonne /2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CH 4 = (16 lb CH 4 )/(lbmole CH 4 )

Data Requirements

1. Total volume of gas vented (scf)

2. Mole %CH 4



### Method 22

– Natural Gas Compressor Seals

Fugitive emission calculations for natural gas compressor seals.

C O 2 emissions (tonnes/year) = (CO 2 EF)*(CO 2 Mole Fraction \ 0.03)*(Seals)*(Usage)

Where

CO 2 EF = See Table 10

CO 2 Mole Fraction = (lbmole CO 2 )/(lbmole gas)

Seals = Number seals

Usage = Annual Usage (hours/year)

Data Requirements

1. Mo le % CO 2

2. Number of compressor seals

3. Annual usage (hours/year)

C H 4 emissions (tonnes/year) = (CH 4 EF)*(CH 4 Mole Fraction \ 0.788)*(Seals)*(Usage)

Where

CH 4 EF = See Table 10

CH 4 Mole Fraction = (lbmole CH 4 )/(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 % CH 4

2. Number of compressor seals

3. Annual usage (hours/year)



### Table 10: Compressor Seals

Device Type CH 4 (tonnes/component 1

- hr) % Methane

Assumption CO 2 (tonnes/component 1

- hr) % CO 2 Assumption

Reciprocating Seal 9.925E

- 04 2 78.8 1.039E

- 04 2 3

Centrifugal Seal 1.035E

- 03 2 78.8 1.083E

- 04 2 3

Rotary Seal 3 1.035E

- 03 2 78.8 1.083E

- 04 2 3

Screw Seal 3 1.035E

- 03 2 78.8 1.083E

- 04 2 3

Vane Seal 3 1.035E

- 03 2 78.8 1.083E

- 04 2 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).

C O 2 emissions (tonnes/year) = (CO 2 EF)*(CO 2 Mole Fraction \ 0.03)*(Miles) + (Oxidation CO 2 EF)*(Miles)

Where

CO 2 EF = See Table 11

CO 2 Mole Fraction = (lbmole CO 2 )/(lbmole gas)

Oxidation CO 2 EF = See Table 10

Miles = miles of natural gas pipeline

Data Requirement

1. Mole % CO 2

2. Mile of natural gas pipeline

C H 4 emissions (tonnes/year) = (CH 4 EF)*(CH 4 Mole Fraction \ 0.788)*(Miles)

Where

CH 4 EF = See Table 11

CH 4 Mole Fraction = (lbmole CH 4 )/(lbmole gas)

Miles = miles of natural gas pipeline

Data Requirements

1. Mole % CH 4

2. Miles of natural gas pipeline



### Table 11: Natural Gas Gathering Pipelines

Type CH 4 (tonnes/mile

- yr) % Methane

Assumption CO 2 (tonnes/mile

- yr) % CO 2 Assumption Oxidation CO 2 (tonnes/mile

- yr)

Gathering Pipeline 0.374 1 78.8 7.682E

- 02 1 3 3.833E

- 02 1

1. API (2004)Appendix B Final 2007 Oil and Gas Industry Survey Results



### B

- 23 Method 24

– Natural Gas Gathering System Maintenance Activities

C O 2 emissions (tonnes/year) = (Total Volume of Gas Vented)*(CO 2 Mole Fraction)*D

Where

CO 2 Mole Fraction = (lbmole CO 2 )/(lbmole gas)

D = (molar volume)*(Molecular Weight CO 2 )*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CO 2 = (44 lb CO 2 )/(lbmole CO 2 )

Data Requirements

1. Total volume of gas vented (scf/year)

2. Mole % CO 2

C H 4 emissions (tonnes/year) = (T otal Volume of Gas Vented)*(CH 4 Mole Fraction)*D

Where

CH 4 Mole Fraction = (lbmole CH 4 )/(lbmole gas)

D = (molar volume)*(Molecular Weight CH 4 )*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Molecular Weight CH 4 = (16 lb CH 4 )/(lbmole CH 4 )

Data Requirements

1. Total volume of gas vented (scf/year)

2. Mole % CH 4



### Method 25

– Pipeline Pigging

Vented emission calculations for natural gas pipeline pigging (EPA 2005).

C O 2 emissions (tonnes/year) = (CO 2 EF)*(CO 2 Mole Fraction \ 0.03)*(Openings)

Where

CO 2 EF = See Table 12

CO 2 Mole Fraction = (lbmole CO 2 )/(lbmole gas)

Openings = Number of time launcher/receiver is opened

Data Requirements

1. Mole % CO 2

2. Number of launcher/receiver openings

Emission Factor Calculation

Equation = V*[(P 1 )*(T 2 )]/[(P 2 )*(T 1 )]

Where

V = pig laucher/receiver volume

P 1 = gathering line pressure (psia)

P 2 = 14.7 psia (standard surface pressure)

T 1 = temperature of the pig launcher/receiver

T 2 = 60° F (standard surface temperature)Appendix B Final 2007 Oil and Gas Industry Survey Results



### B

- 24 Assumptions (from EPA 200 5)

V = 11.5 ft 3 (for an 18 in line)

P 1 = 315 psia

T 1 = 60° F

C H 4 emissions (tonnes/year) = (CH 4 EF)*(CH 4 Mole Fraction \ 0.788)*(Openings)

Where

CH 4 EF = See Table 12

CH 4 Mole Fraction = (lbmole CH 4 )/(lbmole gas)

Openings = Number of time launcher/receiver is opened

Data Requirements

1. Mole %CH 4

2. Number of launcher/receiver openings



### Table 12: Pigging

Device Type CH 4 (tonnes/opening) % Methane

Assumption CO 2 (tonnes/opening) % CO 2 Assumption

Pigging 3.716E

- 03 1 78.8 3.89E

- 04 1 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.

C O 2 emissions (tonnes/year) = (V)*(CO 2 Mole Fraction)*(0.1)*(Events)*D

Where

V = Volume of tank (ft 3 )

0.1 = Common air district rule that vapors must be reduced at least 90% before opening

CO 2 Mole Fraction = (lbmole CO 2 )/(lbmole gas)

D = (molar volume)*(Molecular Weight CO 2 )*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(379.3 scf gas)

Mole cular Weight CO 2 = (44 lb CH 4 )/(lbmole CO 2 )

Events = Number of degassing events

Data Requirements

1. Size of tank (bbl/ft 3 )

2. Mole % CO 2 in vapor head space

3. Number of degassing events

C H 4 emissions (tonnes/year) = (V)*(CH 4 Mole Fraction)*(0.1)*(Events)*D

Wh ere

V = Volume of tank (ft 3 )

0.1 = Common air district rule that vapors must be reduced at least 90% before opening

CH 4 Mole Fraction = (lbmole CH 4 )/(lbmole gas)

D = (molar volume)*(Molecular Weight CH 4 )*(tonne/2204.6lb)

Molar Volume = (1 lbmole gas)/(3 79.3 scf gas)

Molecular Weight CH 4 = (16 lb CH 4 )/(lbmole CH 4 )

Events = Number of degassing eventsAppendix B Final 2007 Oil and Gas Industry Survey Results



### B

- 25 Data Requirements

1. Size of tank (bbl/ft 3 )

2. Mole % CH 4 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 CH 4 

### and CO 2 

### mole percents are 43% and 4% respectively (HARC, 2006).

CO 2 emissions (tonnes/year) = (TOG)*(% CO 2 )

Where

TOG = (Working Loss TOG)+(Breathing Loss TOG)+(Flas hing Loss TOG)

% CO 2 = percent CO 2 in the head space vapor concentration

Data Requirements

1. Working Losses (tons/year)

2. Breathing Losses (tons/year)

3. Flashing Losses (tons/year)

4. % CO 2 in the head space vapor concentration

CH 4 emissions (tonnes/year) = (TOG )*(% CH 4 )

Where

TOG = (Working Loss TOG)+(Breathing Loss TOG)+(Flashing Loss TOG)

% CH 4 = percent CH 4 in the head space vapor concentration

Data Requirements

1. Working Losses (tons/year)

2. Breathing Losses (tons/year)

3. Flashing Losses (tons/year)

4. % CH 4 in the head space vapor concentration



### Method 28

– Sumps and Pits

Fugitive emission calculations for sumps and pits.

CH 4 emissions (tonnes/year) = (CH 4 EF)*(Area)*(Days)

Where

CH 4 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 useAppendix B Final 2007 Oil and Gas Industry Survey Results



### B

- 26 Table 13: Sumps

Type CH 4 (tonnes/ft 2

- day)

Light Crude

Primary Sump 1.297E

- 05 1

Secondary Sump 1.814E

- 06 1

Tertiary Sump 9.070E

- 07 1

Heavy Crude

Primary Sump 9.480E

- 06 1

Secondary Sump 4.672E

- 06 1

Tertiary Sump 5.90E

- 07 1

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 Manda tory Reporting (2008) California Code of Regulation, Title 17, Chapter 1

Subchapter 10, Article 2, Sections 95100

- 95133.

CAPCOA (1999). California Air Pol l ution 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 (1996 a ). US Environmental Protection Agency. Methane Emissions from the

Natural Gas Industry. June 1996.

EPA (1996 b ). 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). U S Environmental Protection Agency. Compilation of Air Pollution

Emission. AP

- 42. July 2000.

EPA (2003a). US Environmental Protection Agency. Natural Gas S tar Lessons Learned

. O ptions for Reducing Methane Emissions from Pneumatic Devices in the N atural Gas

Industry. July 2003

EPA (200 3b ). U S Environmental Protection Agency. Natural Gas Star Lessons Learned

. Replacing Glycol Dehydrators with Desiccant Dehydrators

. November 200 3

.

EPA (200 5 ). U S Environmental Protection Agency. Natural Gas Star Lessons Learned

. Efficient Pigging of Gathering Lines

. April 2005

.

HARC (2006). Houston Advanced Research Center. VOC E missions F rom O il

and C ondensate S torage T anks. October, 2006.

I NGAA (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 Docume nt 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 MeetingsAppendix C Final 2007 Oil and Gas Industry Survey Results



### C

- 2Appendix 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 staf f 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 n atural 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 tr avelled 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 h eld

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 anotherAppendix 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 Resou rces.

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

revis ed 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 S urvey

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

Marc h 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 review ed 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 E ngine Use Categories



# California Air Resources Board

Oil and Gas Industry Survey

Internal Combustion Engine Use CategoriesAppendix D Final 2007 Oil and Gas Industry Survey Results



### D

- 2Appendix 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 F reshwater 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 P ump 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 Ca psule #2

Top Drive

Tractor Engine

Tractor Loader

TRANSFER PUMP

Truck Engine

Vibe

Weed Eater

Welder

Welding MachineAppendix 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 RigAppendix 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 CategoriesAppendix E Final 2007 Oil and Gas Industry Survey Results



### E

- 2Appendix 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 tankAppendix 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