ESTIMATES OF METHANE EMISSIONS FROM THE

U.S. OIL INDUSTRY

FINAL DRAFT

Prepared for:

The U.S. Environmental Protection Agency

Prepared by:

ICF Consulting

October 1999
FINAL DRAFT

i

TABLE OF CONTENTS

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

I. BACKGROUND.......................................................................................................................................... 4

II. METHODOLOGY...................................................................................................................................... 6

III. EMISSION ESTIMATES ....................................................................................................................... 7

A. PRODUCTION SECTOR EMISSIONS ................................................................................................................ 8

1. Production Vented Emissions ................................................................................................................... 9

2. Production Fugitive Emissions................................................................................................................ 12

3. Production Combustion Emissions.......................................................................................................... 15

4. Production Upset Emissions.................................................................................................................... 17

B. CRUDE TRANSPORTATION SECTOR EMISSIONS .......................................................................................... 18

1. Crude Transportation Vented Emissions................................................................................................. 18

2. Crude Transportation Fugitive Emissions............................................................................................... 20

3. Crude Transportation Combustion Emissions ......................................................................................... 21

C. CRUDE REFINING SECTOR EMISSIONS ........................................................................................................ 21

1. Crude Refining Vented Emissions .......................................................................................................... 22

2. Crude Refining Fugitive Emissions......................................................................................................... 23

3. Crude Refining Combustion Emissions................................................................................................... 24

IV. POTENTIAL IMPROVEMENTS IN EMISSION ESTIMATES........................................................ 25

V. OPPORTUNITIES FOR EMISSION REDUCTIONS............................................................................. 25

A. PRODUCTION SECTOR EMISSION REDUCTIONS ........................................................................................... 26

1. Production Vented Emission Reduction Options..................................................................................... 27

2. Production Fugitive Emission Reduction Options.................................................................................... 32

3. Production Combustion Emission Reduction Options.............................................................................. 34

4. Production Upset Emission Reduction Options ....................................................................................... 35

5. Summary of Significant Production Sector Methane Emission Reduction Options .................................. 37

B. CRUDE TRANSPORTATION SECTOR EMISSION REDUCTIONS......................................................................... 37

1. Crude Transportation Vented Emission Reduction Options..................................................................... 38

2. Crude Transportation Fugitive Emission Reduction Options................................................................... 39

3. Crude Transportation Combustion Emission Reduction Options............................................................. 39

C. CRUDE REFINING SECTOR EMISSION REDUCTIONS ..................................................................................... 39

1. Crude Refining Vented Emission Reduction Options.............................................................................. 40

2. Crude Refining Fugitive Emission Reduction Options............................................................................. 40

3. Crude Refining Combustion Emission Reduction Options....................................................................... 41

VI. CONCLUSIONS.................................................................................................................................... 41
FINAL DRAFT

ii

APPENDIX A: REFERENCES..............................................................................................................................

A-1

APPENDIX B: INDUSTRY REVIEWERS...........................................................................................................

B-1

APPENDIX C: EMISSION ESTIMATES.............................................................................................................

C-1

APPENDIX D: COMPARISON OF METHANE EMISSION ESTIMATES....................................................... D1

APPENDIX E: SUMMARY OF OCS EMISSIONS..............................................................................................

E-1

APPENDIX F: OPTIONS FOR REDUCING EMISSIONS...................................................................................

F-1
FINAL DRAFT 1

METHANE EMISSIONS

FROM THE U.S. OIL INDUSTRY

EXECUTIVE SUMMARY

Methane emissions from anthropogenic sources contribute significantly to the concentration of

greenhouse gases in the earth’s atmosphere. Reduced emissions from anthropogenic sources, including

those associated with the U.S. oil industry, could have a considerable positive environmental impact.

Because of the similarities that exist between oil and natural gas production operations, methods currently

being used to reduce emissions in natural gas production operations are often transferable to oil production

operations.

Unlike many other atmospheric emissions, methane has value as an energy resource, which

provides an economic incentive for reducing losses. Economic recovery of the methane is an important

consideration in motivating companies to install the equipment needed to reduce emissions. Economic

recovery of methane depends on:

• The volume of methane and other associated hydrocarbon gases available for recovery;

• The value of the methane and other associated hydrocarbon gases;

• The availability of a recovery technology; and

• The costs of gas recovery and transportation to a processing plant.

The purposes of this study are to: 1) develop an improved estimate of U.S. oil industry methane

emissions; 2) identify the technical potential of options for reducing oil industry methane emissions; and 3)

evaluate the economics of reducing methane emissions from the significant emission sources identified.

The study background and methodology are laid out in Chapters I and II. Chapter III provides both the

latest estimates of oil industry methane emissions and descriptions of how these estimates have been

developed. In Chapter IV, areas for potential improvements in the emissions estimates are offered.

Chapter V describes the options available to reduce oil industry methane emissions and evaluates their cost

effectiveness. Chapter VI summarizes the conclusions reached from the study.

Methane Emission Estimates

Oil-related methane emissions are primarily associated with crude oil production, transportation

and refining. Annual methane emission estimates for these three sectors totaled 61 billion cubic feet (Bcf)

in 1995. This number is substantially lower than the most comprehensive previous study, by Radian

International in 1996, which estimated 1993 emissions at 98 Bcf.1 There are two primary reasons for this

difference: 1) the current study accounts for differences between the oil and gas industries when using gas

industry data, and 2) the current study incorporated significant industry input through workshops and peer

reviews.

 

1

 Radian International LLC, Methane Emissions From the U.S. Petroleum Industry, draft report for the U.S.

Environmental Protection Agency, June 14, 1996.
FINAL DRAFT 2

At an estimated 59.1 Bcf, the production sector of the oil industry has by far the largest emission

rate of the three sectors. The crude oil transportation and refining sectors are estimated at 0.3 Bcf and 1.3

Bcf, respectively. Thus, the producing sector is responsible for 97 percent of the total methane emissions

from the oil industry. The following table summarizes emission estimates for the three sectors. Tables C-1,

C-2, and C-3 in Appendix C provide a detailed look at the emissions from each sector.

Emissions from the various sectors of the oil industry are broken down into four types — fugitive

emissions (unintentional leaks), vented emissions (intentional leaks), operational upset emissions, and

emissions from the combustion of fuels (these are described in Chapter 3). Emissions in the production

sector are further concentrated into six “significant sources,” which represent over 90 percent of all

methane emissions from the oil industry. These sources include vented emissions from oil tanks, high and

low-bleed pneumatic devices, chemical injection pumps, and light crude oil wellheads, as well as

combustion emissions from gas engines. The term “significant source” refers to those that are estimated to

emit at least 1.0 Bcf of methane nationally per year. There are no significant methane emission sources in

the crude transportation and refining sectors. Throughout the report, the term “source” refers to a category

of items that emit methane, not individual items.

Sources of Methane Emissions in the Oil Industry

Methane Emission Estimates by Sectors

Oil Industry Sector Emission Estimate

(Bcf/yr)

Percent of Total

Crude Oil Production 59.1 97%

Crude Oil Transportation 0.3 <1%

Crude Oil Refining 1.3 2%

 Total 60.7 100%

Storage Tanks

42%

High-Bleed

Pneumatics 33%

 Oil

Wellheads 2%

Low-Bleed

Pneumatics 6%

Chemical Injection

 Pumps 5%

Gas Engines

2%

Other

10%
FINAL DRAFT 3

Methane Emission Reduction Potential

The technical potential and economic feasibility of emission reductions are estimated for each

emission source identified. For the six significant sources, the economics of emission reductions were

evaluated more rigorously.

The technical potential for methane emission reductions from all sources is an estimated 44 Bcf.

This represents an 73 percent reduction from the industry’s total methane emissions. An estimated 14 Bcf

of the methane released could be retained economically in oil industry production systems. The emission

reduction options that have been evaluated and their estimated effectiveness for the significant sources are

summarized in the following table.

*Electric motors reduce local emissions but overall emission reduction depends on the source of electricity.

Principal Conclusions

The principal conclusions of this study are as follows:

• The oil industry releases significant volumes of methane to the atmosphere;

• These volumes are concentrated in a small number of production sector sources; and

• Technologies are available to reduce a significant share of these emissions.

Methane Emission Reduction Estimates for Significant Sources

Emission Reductions

Significant

Emission

Source

Emission Reduction Option

Emission

Rate

(Bcf/yr)

Technical

Potential

(Bcf/yr)

Economically

Feasible

(Bcf/yr)

Storage tanks Install vapor recovery or flare systems 25.8 24.4 8.2

Pneumatic devices

 (high-bleed)

Replace or modify pneumatic devices 19.9 17.5 4.9

Pneumatic devices

 (low-bleed)

Use directed I/M programs 3.7 0.4 0.2

Chemical injection

 pumps

Use air-drive, motor-drive, or high efficiency

pumps

2.8 0.7 0.0

Oil wellheads

 (light crude)

Use directed I/M programs 1.3 0.6 0.3

Gas engines Use electric motors* or low emission engines 1.4 0.1 0.1

 Totals 54.8 43.7 13.7
FINAL DRAFT 4

I. BACKGROUND

According to EPA’s U.S. Greenhouse Gas Emissions and Sinks: 1990-1996, “atmospheric

methane is an integral component of the greenhouse effect, second only to carbon dioxide as a contributor

to anthropogenic greenhouse gas emissions.” Moreover, over a 100-year period, methane is estimated to be

21 times more effective than CO2 at trapping heat in the atmosphere.2 In addition to the oil industry,

primary anthropogenic methane sources are landfills, domesticated livestock, coal mining, livestock

manure, and natural gas systems. Other smaller sources include rice cultivation, industrial processes, and

changes in land use.3 The following chart shows the breakdown of the primary anthropogenic sources of

methane emissions in the U.S. Data for the oil industry was updated to include the results of the current

study.

U.S. Sources of Methane Emissions in 19954

Enteric

20%

Natural Gas

18%

Coal

11%

Manure

9%

Landfill

s 36%

Petroleum

1%

Other

5%

Controlling methane emissions is one of the most effective means of mitigating global climate

change in the short term because the atmospheric life of methane is shorter than other major greenhouse

gases. Methane is an excellent candidate for mitigating climate change impacts because emission

reductions could lead to a stabilization or reduction in atmospheric methane concentrations within 10 to 20

years. It is estimated that a 10 percent reduction of total anthropogenic methane emissions worldwide

would halt the annual rise in methane concentrations.

Since methane is the major component of natural gas, methane emissions during production,

processing, transmission, and distribution of natural gas can be significant. According to EPA’s

greenhouse gas inventory, methane emissions from natural gas systems have remained relatively constant in

 

2

 Environmental Protection Agency, U.S. Greenhouse Gas Emissions and Sinks: 1990-1996, 1998 (draft).

3

 Ibid.

4

 Ibid.
FINAL DRAFT 5

the 1990s. Natural gas facilities account for over 18 percent of methane emissions in the U.S. Although

there are over a million miles of pipeline and thousands of facilities now in operation, most methane

emissions stem from a small number of high-leak facilities. The EPA Natural Gas STAR program has

demonstrated that targeting high-leak facilities or components can result in substantial emission reductions.

Furthermore, since methane has value as an energy resource, these emission reductions can often be

profitable for producers.

Emissions from oil production, transportation, and refining facilities involve technology similar to

the natural gas production, transportation, and processing. Figure 1 shows the flow of oil and gas

production from the wellhead to market, demonstrating the points of similarity between the two. As a

result, some methods for reducing emissions in natural gas production and processing can be readily

transferred to oil production. Economic recovery of the methane is an important consideration in

motivating companies to install the necessary equipment to reduce emissions. Factors determining the costeffectiveness of emission reductions include the volume of methane present in the oil, access to a gas

gathering system, and the availability of an efficient technology to recover or reduce the emissions.

To date, most studies of methane emissions from the petroleum industry have focused on the

natural gas sector. Other than Gas Research Institute (GRI) reports, these studies have often included oil

industry estimates with gas industry estimates. EPA, the American Petroleum Institute (API), and the

Canadian Association of Petroleum Producers (CAPP) have conducted several studies focusing on the oil

industry, but these were generally broad estimates, such as industry total or sector total, rather than by

equipment item.5 The most recent and comprehensive previous work on methane emissions from the oil

industry was performed for EPA by Radian International LLC.6 The Radian study, however, did not

evaluate emission reduction methods. Appendix A provides a list of the references used in preparation of

this report.

Despite the similarities between the oil and natural gas industries, there are many differences that

necessitate a detailed report of oil-specific methane emissions. In the oil industry, unlike the natural gas

industry, methane is usually a small part of total emissions. An emission from an individual oil industry

source may contain numerous ingredients, such as a mixture of gaseous and/or liquid hydrocarbons that

may include methane, hydrogen, carbon dioxide, nitrogen, oxygen, and water vapor. Furthermore, most of

the processes involved in the two industries differ to some extent, resulting in different activity and

emission factors (see Methodology section for explanation).

This study aims to fill the gap in existing data by focusing strictly on oil industry methane

emissions and taking into account differences between gas and oil industry data. The purposes of this

study are to: 1) develop an improved estimate of U.S. oil industry methane emissions; 2) identify the

technical potential of options for reducing oil industry methane emissions; and 3) evaluate the economics of

reducing methane emissions from the significant emission sources identified.

 

5

 Appendix D contains a comparison of previous studies of methane emissions in the oil industry.

6

 Radian International LLC, Methane Emissions From the U.S. Petroleum Industry, draft report for the U.S.

Environmental Protection Agency, June 14, 1996. Because this report was the starting point for the current study,

it is frequently cited. To reduce repetitiveness, it will generally be referred to in the text as the ‘Radian report.’
FINAL DRAFT 6

II. METHODOLOGY

The methodology used to estimate oil industry methane emissions involved developing emission

factors and activity factors. Emission factors measure the average emissions per source (e.g., emission rate

per equipment item or per activity). Activity factors are estimates of the number of equipment items or

frequency of activity. Total emissions from a source are estimated by multiplying the emission factor by

the activity factor. The activity and emission factors were developed using a variety of sources, including a

literature survey, emission and activity factor updating, and reviews by oil industry experts. A number of

sources were also used to determine available technologies for reducing emissions. Recent studies,

including EPA’s Lessons Learned for the Natural Gas STAR program and a CAPP report on methane

reduction, were evaluated to develop initial lists of reduction options. These were further refined through

input from industry reviewers. This combination of identifying and using the best and/or

Figure 1. Oil & Gas Industry Boundaries

Gas Well Production

Oil Well Production

Separator

Compressor

Field Use

Gas

Meter

Dehydrator

Vapor Recovery

Compressor

Water

Tank

Hydrocarbon

Condensate

or Oil Tank

 Oil

Industry

Gas Well

Wellhead

Processing/Sales

Pneumatic

Level Control

Valves (L)

L

L

Pneumatic

Pressure Control

Valve (P)

P

Water

Sales

Oil

Gas

Oil Well

Wellhead

(with associated

gas)

Compressor

Compressor

Re-injection/

Gas Lift Gas

Field Use

Gas

Separator

Chemical

Injection

Pump

Pneumatic

Level Control

Valves (L)

Oil Stock Tanks

Meter

Dehydrator

Vapor Recovery

Compressor

 Oil

Industry

Water

Tank

Oil

Processing/Sales

Gas

Pneumatic

Pressure Control

Valve (P)

L

L

L

P

Water

Sales

Heater/

Treater

Water

L

Gas

Gas Gas
FINAL DRAFT 7

most up-to-date published information available and enhancing it with current industry expertise provides

an improved estimate of methane emissions for the oil industry. Appendix B identifies the oil industry

representatives that reviewed this report.

III. EMISSION ESTIMATES

Methane emission estimates from the oil industry are described in the following paragraphs and

detailed by industry sector in Tables C-1 (Production), C-2 (Transportation), and C-3 (Refining) of

Appendix C. The emission sources for each oil industry sector are aggregated into four types of emissions

— vented, fugitive, combustion, and operational upset emissions.

• Vented emissions are intentional releases to the atmosphere by facility design or operational

practice. Examples of vented emissions are the continuous releases from vented storage tanks;

occasional depressurizing of process equipment and piping prior to maintenance procedures; and

cycling releases from equipment that is driven by pressurized gas, such as pneumatic control

devices and chemical injection pumps.

• Fugitive emissions are unintentional, and typically continuous, releases associated with leaks

caused by failure of the integrity of a component within a system. Common leak sources are valve

stem packing, pipe flange gaskets, smaller pipe connectors, and seals on pumps, compressors, and

floating roof tanks.

• Combustion emissions are the product of the burning of fuels. Examples of combustion emissions

are the exhausts of engines that drive reciprocating and centrifugal compressors, and the effluent

from stacks on fired heaters and from waste gas flares.

• Upset emissions are unintentional releases that occur when a process goes out of control.

Examples of process upset emissions are releases from emergency pressure relief valves, oil well

blowouts during oil well drilling operations, and emergency offshore oil production platform

shutdowns. Process upset emissions of methane are estimated for the production sector of the oil

industry only because downstream of the production area methane is only a small part of the total

emission from an oil process upset.

The annual methane emission estimates for the three oil industry sectors analyzed are estimated to

total 61 billion cubic feet (Bcf) using 1995 data for activity factors, as shown in Table III-1. This estimate

is approximately 38 percent lower than the most comprehensive previous estimate of 98 Bcf, developed by

Radian using 1993 data. Prior to the Radian report, most studies on oil industry methane emissions were

on a broad, industry-wide scale, rather than focusing on individual equipment items. These earlier studies

estimated much lower total oil industry methane emissions than the current study, ranging from 5 to 31 Bcf

per year.7 Comparisons of the current methane emission estimates with those made by Radian and others

are tabulated in Appendix D.

 

7

 API’s 1992 Global Emissions of Methane from Petroleum Sources estimated U.S. emissions at 5.9 Bcf. EPA’s

1990 Report to Congress estimated between 5.2 and 31.2 Bcf.
FINAL DRAFT 8

A. Production Sector Emissions

The production sector is estimated to have the largest methane emissions, from both individual

sources and as an overall sector. Total production sector emissions are estimated to have been 59.1 Bcf/yr

in 1995. The largest individual sources are estimated to be venting of crude oil storage tanks (25.7 Bcf/yr),

venting from high-bleed pneumatic devices (19.9 Bcf/yr), venting from low-bleed pneumatic devices (3.7

Bcf/yr), and venting from chemical injection pumps (2.8 Bcf/yr).

Venting emissions total 53.7 Bcf/yr and comprise 91 percent of the total emissions from this

sector. Fugitive emissions, which total 3.0 Bcf/yr, account for 5 percent. Combustion emissions, totaling

1.8 Bcf/yr, make up 3 percent of the 1995 total. Emissions from process upsets account for approximately

one percent of total emissions, with only 0.6 Bcf/yr. Table III-2, below, summarizes the production sector

emissions by type. Table C-1 in Appendix C provides details of methane emission estimates for all 39

identified emission sources in the production sector.

The following paragraphs describe the sources of production sector methane emissions. They also

discuss how the emission factors and activity factors were determined for each of the significant production

sector emission sources. Because 90 percent of methane emissions from the oil production sector come

from just six sources that each emit over 1.0 Bcf/yr, this study focuses on these significant sources.

Table III-1

Methane Emission Estimates by Sectors

Oil Industry Sector Emission Estimate

(Bcf/yr)

Percent of Total

Crude Oil Production 59.1 97%

Crude Oil Transportation 0.3 <1%

Crude Oil Refining 1.3 2%

 Total 60.7 100%

Table III-2

1995 Production Sector Emission Estimates by Type of Emission

Type of Emission Emission Estimate (Bcf/yr) Percent of Total

Vented 53.7 91%

Fugitive 3.0 5%

Combustion 1.8 3%

Upsets 0.6 <1%

 Total 59.1 100%
FINAL DRAFT 9

1. Production Vented Emissions

In the oil production sector, methane emissions are vented from 13 sources and are estimated at 54

Bcf for 1995. The four significant sources — storage tanks, high and low-bleed pneumatic control devices,

and chemical injection pumps — emit an estimated 52 Bcf/yr, or 97 percent of the total. Losses from the

other 9 identified sources range from zero to 0.8 Bcf/yr. Table III-3 summarizes the vented emission rates

from the production sector.

Storage Tank Vented Emissions

Venting from oil storage tanks is the largest source of methane emissions in the oil industry, with

an estimated 26 Bcf emitted per year. These tanks hold crude oil that has been through a separator, (a

pressure vessel used to separate well fluids into oil, gas, and water). When the crude enters the storage

tanks, which are at atmospheric pressure, some of the dissolved gases and lighter liquid hydrocarbons flash

off (vaporize). Most of these tanks are vented to the atmosphere, allowing methane and other gases to

escape.

The emission factor for tank venting was developed using API’s E&P TANK program and

assuming that essentially all tanks in crude production service are the fixed roof design.8 E&P TANK is

designed to calculate the emissions of 22 components (including methane) from individual oil production

sites using measured characteristics of the site and of the crude oil properties. Important crude oil

parameters include pressure, temperature, gravity, and vapor pressure. To develop the emission factor

used in this study, the sample cases9 included in E&P TANK were run and a weighted average of the results

was obtained. Using these samples to estimate total U.S. methane emissions requires assuming that the

sample sites are a fair representation of total U.S. oil production. This assumption has not been tested, but

 

8

 Most tanks in the oil production sector have fixed roofs and emit gas primarily through venting. Floating roof

tanks, which produce fugitive emissions, are prevalent in other sectors of the oil industry

9

 One of the samples was excluded from this study because it represented 67 percent of the total production rate

included in the 103 sites, skewing the results significantly.

Table III-3

Summary of Vented Emissions From the Production Sector

Emission Source Emission Estimate

(Bcf/yr)

Percent of

Total

Significant Sources

Storage Tanks 25.7 48%

High-Bleed Pneumatic Devices 19.9 37%

Low-Bleed Pneumatic Devices 3.7 7%

Chemical Injection Pumps 2.8 5%

Smaller Sources Total 1.7 3%

 Totals 53.8 100%
FINAL DRAFT 10

is believed to be a reasonable approach to estimating U.S. methane emissions from production site tanks for

the current analysis. The E&P TANK computations provide an emission factor of 18 scf of methane per

barrel of crude produced.

The activity factor for tank venting takes into account emission reductions from the use of vapor

recovery systems, flaring and floating roof tanks. According to an unpublished API survey, nine percent of

oil tanks are reported to have VRUs in place and two percent have flare systems.10 When weighted for oil

production rates by the states that are included in the API survey, the emission reductions caused by these

systems affect 29 percent of U.S. oil production. In addition, methane vented from oil stripper wells does

not enter the storage tanks. These two deductions reduce total crude oil production from 2,394 million

barrels in 1995 to 1,434 million barrels. This provides an activity factor of 1.4 billion barrels for 1995.

When multiplied by the 18 scf/barrel emission factor, tank batteries contribute 26 Bcf of methane

emissions.

High-Bleed Pneumatic Device Vented Emissions

The pressurized gas that is released from the crude in the separator is often used in a facility’s

process control systems. The gas is used to transmit signals between sensing and control devices and to

drive automatic control valves for controlling liquid levels, flow rates, and pressures. Pneumatic control

valves are designed to bleed gas to the atmosphere as they cycle up and down to modulate the system being

controlled.

Venting from high-bleed pneumatic devices11 is the second largest source of methane emissions

from the oil industry. In 1995, these devices released an estimated 19.9 Bcf, or 37 percent of total

production vented releases. The emission factor used to derive this number is the EPA Natural Gas STAR

program default value of 126 Mcf/year, which corresponds to 345 cubic feet per day (scfd).12 The activity

factor, 157,581 high-bleed devices, assumes that tank batteries with heater treaters have four pneumatic

devices (three level controllers and one pressure controller). Tank batteries without heater treaters are

assumed to have three devices. The share of high-bleed devices is estimated using an EPA/GRI study13

showing that 35 percent of more than 4,000 devices observed were high-bleed types.

Low-Bleed Pneumatic Device Vented Emissions

Venting from low-bleed rate pneumatic controllers is estimated to add another 3.7 Bcf of methane

emissions to the high-bleed venting of 19.9 Bcf. The emission factor for low-bleed devices is estimated by

EPA to be only 10 percent of the activity factor for high-bleed devices, or 35 scfd per device.14 The

activity factor for low-bleed devices is 292,650 devices; this is 65 percent of the total number of production

sector devices estimated, based on the EPA survey described in the previous paragraph.

 

10 API, Unpublished data from survey of major and independent producers, 1996.

11 Pneumatic devices are defined as “high-bleed” if they vent more than 6 scf per hour (scfh).

12 EPA/GRI, Methane Emissions from the Natural Gas Industry, Volume 12: Pneumatic Devices, prepared by

Radian, June 1996.

13 Ibid.

14 EPA Natural Gas STAR Program default value for low-bleed pneumatic devices is ten percent of the high-bleed

rate of 126 Mcf/year.
FINAL DRAFT 11

Chemical Injection Pump Vented Emissions

Chemical injection pumps are used to inject various chemicals into crude oil at the well site. The

injected chemicals are used to break oil-water emulsions, inhibit corrosion, dewax paraffins, kill bacteria,

and control other processing problems. As in the case of pneumatic devices, the pressurized natural gas

that is frequently available at oil production sites may be used to drive chemical injection pumps. Chemical

injection pumps account for an estimated 2.8 Bcf/yr of production sector vented emissions. The EPA/GRI

estimated average emission rate for each pump is 91 Mcf/yr.15 The activity factor is computed by using the

Radian estimate of 125,088 pumps and a pump manufacturer’s estimate that only 25 percent of these

pumps are driven by gas.16 The remainder are driven mechanically or by electric motors or compressed

air.17

Offshore Production Platform Vented Emissions

In 1993, the Minerals Management Service (MMS) estimated oil and gas production platform total

hydrocarbon emissions in the Gulf of Mexico Outer Continental Shelf (OCS).18 The MMS study

encompasses all of the sources located on the platforms, such as engines, pumps, and pneumatic devices.

Specific emissions sources are not detailed in the MMS report, except for crude oil and diesel oil tanks

which comprise only five percent of the total. Based on methane venting rates from onshore production

sites, the remaining 95 percent of vented emissions are likely to be primarily from pneumatic devices and

chemical injection pumps.

Using the MMS study, oil platform methane emissions in the Gulf are estimated to be

approximately 0.8 Bcf per year. This rate is calculated by assuming that: 1) 61 percent of the vented

hydrocarbons from oil and gas platforms are methane,19 and 2) 14 percent of the emissions are from oil

platforms. The 14 percent assumption is based on EIA production data showing that 14 percent of natural

gas production in the Gulf in 1995 was associated-dissolved gas, which is produced in association with

oil.20 The remaining 86 percent was produced from gas wells, which are located on platforms primarily

producing gas and are outside the scope of this study.

The MMS estimate of total hydrocarbon emissions from offshore platforms in the Federal waters

in the Gulf of Mexico was based on a count of 1,807 platforms. It should be noted that this MMS approach

does not include the emissions from the smaller platforms located in state waters in the Gulf of Mexico,

which represent around 5 percent of total offshore Gulf production.21 To account for state offshore

 

15 EPA/GRI, Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks, prepared by Radian,

June 1996.

16 Ron Rayman, Dresser Texsteam, Personal Communication. Dresser Industries is one of the largest suppliers of

chemical injection pumps in the industry. Mr. Rayman estimated that approximately 25 percent of Dresser’s

chemical injection pumps run on methane. Representatives from Moyno Oilfield Products and Danco Pump &

Supply Co. both agreed that most chemical injection pumps are operated with electric motors.

17 Please see discussion in Chapter IV, Potential Improvements.

18 Minerals Management Service, Gulf of Mexico Air Quality Study, August 1995.

19 Light crude speciation fraction for total hydrocarbon emissions from API’s Workbook No. 4638.

20 U.S. Department of Energy, Energy Information Administration, U.S. Crude Oil, Natural Gas, and Natural Gas

Liquids Reserves, Annual Report 1995.

21 DOE, EIA, Petroleum Supply Annual 1995.
FINAL DRAFT 12

production, 5 percent has been added to the MMS estimate. See Table E-1 in Appendix E for a summary

of the MMS hydrocarbon emission estimates.

Emissions from offshore areas other than the Gulf are estimated using the Gulf emission factor and

the 22 platforms identified by Radian. The resulting vented emission rate is 0.01 Bcf.

Stripper Well Vented Emissions

Stripper wells are those that produce fewer than ten barrels of oil a day. The average production

rate for U.S. stripper wells is 2.1 barrels per day;22 approximately one-third of the 434,000 stripper wells in

the U.S. produce an average of one barrel of crude per day. Methane is emitted from the casinghead

valves23 on an estimated 80 percent of stripper wells that are left open to maximize oil flow. This is

because gas pressure buildup in the well casing can restrict the already slow drainage of oil from the

reservoir into the well. Based on an estimated gas/oil ratio of five scf of gas per barrel of crude,24 the

annual total hydrocarbon gas emission is 3,832 scf per stripper well. Using the API Publication No. 4638

speciation fraction of 0.612 for light oil methane content, the annual methane emission factor is 2,345 scf

per stripper well. For the 347,500 stripper wells that are vented, the annual methane emission rate is

estimated to be 0.82 Bcf.

Other Vented Emissions

There are several smaller sources of vented emissions in the production sector: pressure vessel and

compressor blowdowns, compressor starting, and oil well completions and workovers. Emission factors

for these sources are taken from Radian. The activity factors for pressure vessels (combination of

separators and heater treaters) and small compressors are taken from the fugitive emissions section of this

report. The activity factor for oil well completions comes from DOE’s Energy Information

Administration.25 The number of oil well workovers is estimated by Radian to be 7.5 percent of producing

wells each year. Table C-1 in Appendix C provides the details of emission and activity factors for each of

these venting sources.

2. Production Fugitive Emissions

Total fugitive emissions from 16 oil production sources are estimated at 2.9 Bcf for 1995.

Wellheads producing light crude oil are the only significant source of fugitives, emitting an estimated 1.3

Bcf, or 45 percent of the total. Losses from the other 15 identified sources range from near zero to 0.6 Bcf

each. Table III-4 summarizes the fugitive emission sources from the production sector.

 

22 API, Basic Petroleum Databook, July 1997.

23 The pipes that are used in oil wells to seal off fluids from the bore hole are called casing. The casinghead is the

part of the casing that protrudes above the surface and holds the control valves and flow pipes.

24 ARCO Laboratory, Plano, TX, personal communication. Based on assumed reservoir pressures of 25 to 50 psia.

25 U.S. Department of Energy, Energy Information Administration, Monthly Energy Review, April 1997.
FINAL DRAFT 13

Oil Wellhead Fugitive Emissions

Oil wellheads are the above-ground extension of oil wells where production control and

measurement facilities are located. Wellheads are formed by a combination of parts; in this study, potential

leak sources of a typical oil wellhead are assumed to be five valves, ten flanges, four small pipe

connections, and a polished rod stuffing box.26 For light crude wellheads (API gravity above 20°), the

emission factor is estimated to be 16.6 scf per well per day. This was calculated using the average total

hydrocarbon (THC) leak rates for each component from the API No. 4638 Workbook and the workbook’s

estimate that methane accounts for 61.2 percent of THC emissions.27 The activity factor of 210,946 light

crude producing wells was estimated using API data28 for the number of producing oil wells less stripper

wells, and the Radian estimate that 93 percent of oil wells produce light crude. Total emissions from light

crude oil wellheads are estimated to be 1.3 Bcf.

Emissions from the seven percent of non-stripper wellheads that produce heavy crude were

calculated to be 0.001 Bcf using the component leak rates and THC speciation fraction of 0.94 for methane

from heavy crude reported in the API workbook.29

Offshore Platform Fugitive Emissions

Fugitive emissions from offshore platforms in the Gulf of Mexico are estimated to be 0.04 Bcf.

This estimate is based on the same sources and assumptions described earlier under offshore platform

vented emissions. It is important to note that these emissions represent those associated with production

operations only. During some offshore drilling operations, some gas produced in association with oil may

be flared (or in rare cases vented). When this does occur, it is only for a very short time and the total

emissions associated with this activity would be quite small. As with vented emission estimates, the

fugitive emission estimates for the Gulf of Mexico only consider emissions from production operations in

 

26 Consensus of industry review panel.

27 American Petroleum Institute, Calculation Workbook for Oil and Gas Production Equipment Fugitive

Emissions, No. 4638, by Star Environmental, July 1996.

28 American Petroleum Institute, Basic Petroleum Data Book, January 1997.

29 API Workbook No. 4638.

Table III-4

Summary of Fugitive Emissions From the Production Sector

Emission Source Emission Estimate

(Bcf/yr)

Percent of Total

Significant sources

 Light oil wellheads 1.3 43%

Smaller sources total 1.7 57%

Totals 3.0 100%
FINAL DRAFT 14

Federal waters. However, since 95 percent of all Gulf of Mexico offshore associated-dissolved gas

production takes place in Federal waters, this should have an insignificant impact on total emissions.

Fugitive methane emissions from offshore locations other than the Gulf are estimated using the

fugitive emission factor from the Gulf and the 22 platforms in the Pacific and Alaskan offshore, as

described in the section on vented emissions. The estimate of fugitive emissions for offshore oil platforms

not in the Gulf is 0.001 Bcf.

Separator, Heater Treater, and Header Fugitive Emissions

Additional sources of fugitive emissions in the production sector are: separators, which separate

oil, gas and water; heater treaters, which separate crude oil and water; and headers, which are collection

points for oil or gas gathering lines. Fugitive emissions from these sources are based on component leak

rates from the API 4638 Workbook and average component numbers for each of the three sources.

Emissions from these sources varied from near zero to 0.59 Bcf per source. Table C-1 in Appendix C

provides details of the emission and activity factors for all of the fugitive emission sources.

Floating Roof Storage Tank Fugitive Emissions

Floating roof storage tanks have flat roofs that float on the surface of the oil, reducing evaporation

to a minimum. Fugitive emissions from production sector floating roof storage tanks are small primarily

because smaller, less expensive fixed roof tanks (which are vented) are used almost exclusively in this

service. Even on Alaska’s North Slope, where production rates are very high, fixed roof tanks with vapor

recovery systems are used. Floating roof tanks for crude storage typically average 200 to 250 feet in

diameter and there are fewer than 500 production sector tanks in this size range. Although no floating roof

tanks have been identified in the production sector, an assumption is made that five percent of the larger

tanks have floating roofs. As a result, the activity factor for floating roof production sector tanks is

estimated to be 24 tanks.

The emission factor for crude storage in the production sector was estimated to be 0.3 MMcf

(million cubic feet) per tank per year, using the API TANKS computer program which is documented in

EPA’s AP-42. The TANKS program is designed to estimate emissions of organic chemicals from storage

tanks. Unlike API’s E&P TANK program, TANKS allows the user to specify floating roof tanks for

emission estimates. Thus, although TANKS is primarily designed for downstream operations, it was used

here to estimate emissions from crude storage floating roof tanks at production facilities. Because the

TANKS model is designed to estimate emissions from individual floating roof tanks, assumptions were

made to characterize an average or typical tank. Appendix G lists the assumptions made for characterizing

a typical floating roof tank and estimating emissions from these tanks. Emissions from floating roof tanks

in the production sector are estimated to be 0.008 Bcf per year.

Compressor Fugitive Emissions

The emissions factor for compressors used at oil production sites (which are smaller than natural

gas pipeline compressors) was estimated by oil industry experts to be 100 scfd per compressor. The

activity factor of 2,797 compressors was taken from Radian; the resulting emissions estimate is 0.1 Bcf per

year. No large compressors similar to those used in the gas transmission industry have been identified in

the oil production sector.
FINAL DRAFT 15

Crude Sales Facility Fugitive Emissions

Fugitive emissions from crude sales facilities primarily stem from losses when trucks are filled.

The fugitive emission estimate for crude sales facilities is based on the number of truck loadings per year

and an emissions factor of 40.55 scf per loading. Approximately 25 percent of total sales volumes are

transported by truck. The remaining 75 percent of sales are delivered by pipeline, with negligible

emissions. Truck loadings are estimated at 1,995,000 per year, using 25 percent of total volumes and

assuming an average of 300 barrels per truck. This results in an estimated annual emission rate of 0.08

Bcf.

Crude Production Area Pipeline Fugitive Emissions

Methane leakage rates from crude pipelines are estimated to be essentially zero, since crude is

nearly totally degassed in storage tanks and any crude leaks from production area piping are quickly

repaired.

Drilling Fugitive Emissions

No data for methane losses during oil well drilling operations have been identified. No emissions

will occur until a hydrocarbon bearing formation is entered, at which point most emissions will be vented

rather than fugitive.

Pump Fugitive Emissions

Pumps are used in the oil production sector to move crude oil through pipes. Methane can leak

through the pump’s various components, such as seals, connectors, and flanges. The 0.24 scfd per pump

emission factor for leakage from battery pumps was calculated using component THC leak rates and

methane contents of THC from API Publication No. 4615.30 The activity factor is estimated to be 172,345

battery pumps, based on 2.5 wells per battery, one pump per battery equipped with a lease automatic

custody transfer (LACT) unit, and assuming 75 percent of leases have a LACT unit.31 The resulting

annual emission rate is 0.015 Bcf.

3. Production Combustion Emissions

Total estimated emissions from combustion sources are 1.8 Bcf per year, with 80 percent coming

from incomplete combustion of methane in gas engines. The remaining four sources (heaters, drilling rigs,

flares, and offshore platforms) contribute from 0.001 to 0.3 Bcf per year. Table III-5 provides a summary

of combustion emission sources from the production sector.

 

30 American Petroleum Institute, Emission Factors for Oil and Gas Production Operations, No. 4615, January

1995.

31 Consensus of Industry Review Panel. A LACT unit is a system of oil handling on a lease that receives crude into

tankage, measures and tests it, and puts it into a pipeline.
FINAL DRAFT 16

Engine Combustion Emissions

Gas-fueled engines include both internal combustion engines and gas combustion turbines used to

drive compressors, pumps, and generators. In any gas-powered engine, some of the gas will not burn

completely and methane will be emitted to the atmosphere. The methane emission factor for gas-fueled

engines at oil production sites is estimated to be 0.08 scf per HP-hr. This factor is one-third of the value

used by Radian, and is based on an estimation that these engines are 98 percent efficient.32 The activity

factor of 17,634 MMHP-hrs per year is taken from the Radian draft report. Gas engine combustion is

estimated to have produced 1.4 Bcf of methane emissions in 1995.

Offshore Platform Combustion Emissions

At a total of 0.3 Bcf, offshore platforms are the second largest source of combustion emissions in

the production sector. As described earlier in the section on venting, the platform emission estimates come

from a MMS Gulf of Mexico OCS study.33 Table E-1 in Appendix E provides details of the emission

estimates made by the MMS.

Flare Combustion Emissions

For safety reasons, flares are used in oil production to burn vented gases that contain H2S or other

highly combustible gases. Emissions from flares are based on estimates that 2.2 percent of tank emissions

are flared and two percent of flared gases from production sites are unburned.34 Studies by EPA and the

Canadian Association of Petroleum Producers (CAPP) also estimate that methane is 98 percent destroyed

in flares.35, 36 This corresponds to an emission factor of 20 scf per Mcf flared. Using the 26 Bcf estimated

above for oil tank vented emissions, the activity factor is calculated to be 0.56 Bcf. Total methane

 

32 Consensus of industry review panel.

33 MMS, 1995

34 Consensus of industry review panel.

35 EPA/GRI, Methane Emissions from the Natural Gas Industry, Volume 6: Vented and Combustion Source

Summary, prepared by Radian, June 1996.

36 Canadian Association of Petroleum Producers, A Detailed Inventory of CH4 and VOC Emissions From Upstream

Oil and Gas Operations in Alberta, Volume II, March 1992.

Table III-5

Summary of Combustion Emissions From the Production Sector

Emission Source Emission Estimate

(Bcf/yr)

Percent of Total

Significant sources

 Gas engines 1.4 80%

Smaller sources total 0.4 20%

Totals 1.8 100%
FINAL DRAFT 17

emissions are estimated to be 0.01 Bcf. In rare cases where flared gas is not ignited by the pilot flame or

electronic igniter, the flare will vent temporarily.

Well Drilling Combustion Emissions

Well drilling combustion emissions come from the engine/generator set used to power the drilling

rig draw works, which serve as the power-control center for the hoisting gear and rotary elements of the

drill column. The emission factor of 2,453 scf per well comes from a 1992 API report.37 The activity

factor for the 10,049 oil wells drilled in 1995 comes from API data and includes oil well completions and a

proportionate share of dry holes.38 The total emission estimate for combustion sources associated with

drilling operations is 0.025 Bcf.

4. Production Upset Emissions

Process upset venting is the least significant source of methane emissions in the oil production

sector. Upsets include offshore platform emergency shutdowns, pressure relief valve (PRV) releases, and

well blowouts. With total emissions from upsets at only 0.6 Bcf per year, no individual source is

significant. Table C-1 in Appendix C provides details of emission estimates from the four sources

identified.

Offshore Platform Emergency Shutdown Emissions

The largest production upset emission estimate is 0.47 Bcf from offshore platform emergency

shutdowns, which are a vital safety procedure. The isolation, size of crews in residence, and confined

spaces of offshore platforms have placed high priorities on safe, tightly controlled operations. When

processes vary from the tight control ranges, operations are shutdown quickly, causing gas venting. The

256,888 scf/yr per platform emission factor for emergency shutdowns is taken from 1996 GRI/EPA

report.39 The activity factor of 1,829 platforms is the sum of offshore platforms in the Gulf of Mexico

(1,807) and other waters (22), as described in the vented emissions section.

Pressure Relief Valve Emissions

Pressure relief valves (PRVs) are usually installed on pressurized vessels to prevent catastrophic

failure of the vessel from an uncontrolled pressure rise. In production facilities, the usual pressure vessels

are separators and heater treaters. The emission factor of 34 scf/yr per PRV comes from the 1996

GRI/EPA report.40 The activity factor of 200,000 is estimated by combining the number of field separators

with the number of heater treaters (from the fugitive emissions section of this report). Total PRV emissions

are estimated to be 0.007 Bcf.

 

37 API, Global Emissions of Methane from Petroleum Sources, prepared by Radian Corporation, February 1992.

38 API, Basic Petroleum Data Book, 1995.

39 EPA/GRI, Methane Emissions from the Natural Gas Industry, Volume 7: Blow and Purge Activities, prepared by

Radian, June 1996.

40 Ibid.
FINAL DRAFT 18

Oil Well Blowout Emissions

Oil well blowouts occur when a drill bit enters a reservoir that is pressurized above the pressure

level expected for the well depth. Normally anticipated pressures are approximately equal to the

hydrostatic head of a column of salt water to the depth of the well. Higher pressures can be caused by

water drives that have sources at higher altitudes than the well head or by geopressuring from soil

overburden buildup on unconsolidated reservoir sands as can occur beneath river deltas. The estimated

emission factors for offshore and onshore blowouts are 5.0 MMscf (million cubic feet) and 2.5 MMscf per

blowout, respectively.41 These emission factors, that are about ten times those used by Radian, are very

uncertain even though industry judgement was involved in their estimation. The offshore blowout activity

factor of 2.25 per year is from an MMS report showing nine OCS blowouts from 1991 to 1994.42 The

onshore blowout estimate is 33.5 per year, or less than 0.3 percent of wells drilled.43 Total emissions from

oil well blowouts are estimated to be 0.01 Bcf for offshore and 0.08 for onshore.

B. Crude Transportation Sector Emissions

Of the three oil industry sectors analyzed, the crude transportation sector has the lowest methane

emissions with a total of 0.3 Bcf per year. The two largest sources are venting from fixed roof tanks and

during marine loading operations, each at 0.1 Bcf per year. Table III-6 provides a summary of crude

transportation emission estimates by each type of emission.

1. Crude Transportation Vented Emissions

Crude transportation vented emissions are estimated to be 0.26 Bcf per year. At 0.14 Bcf, methane

vented during the loading of crude into marine vessels, tank trucks, and rail tank cars account for over half

of these emissions. Venting from storage tanks, pumping station maintenance, and pipeline pigging

 

41 Consensus of industry review panel.

42 MMS, Accidents Associated with Oil and Gas Operations – Outer Continental Shelf: 1991-1994 (MMS 95-

0052).

43 Consensus of industry review panel.

Table III-6

1995 Crude Transportation Sector Emission Estimates by Type of Emission

Type of Emission Emission Estimate

(Bcf/yr)

Percent of Total

Vented 0.26 84%

Fugitive 0.05 16%

Combustion 0.00 0%

 Total 0.31 100%
FINAL DRAFT 19

operations contribute the other half of emissions in this group. Table C-2 of Appendix C provides details

of the methane emissions from crude transportation venting.

Marine Loading Vented Emissions

As crude oil is loaded into marine vessels, vapors are displaced by the oil and released to the

atmosphere. The emission factor for marine loading of crude is estimated to be 2.54 scf per 1,000 gallons

of crude loaded. The basis for this estimate are the AP-4244 total hydrocarbon emission factors for barges

and tankers loading crude and an estimate that 15 percent of the hydrocarbon emissions are methane.45 An

estimated 38,667 million gallons of crude oil is loaded in the U.S. each year, including exports and

domestic movements by tankers and barges.46 These factors provide an annual methane emission rate of

0.098 Bcf.

Truck and Rail Loading Vented Emissions

Similar to vented emissions from marine loading, methane is released during truck and rail loading

as gas vapors are displaced by crude oil. The emission factor for truck and rail loading operations is taken

from EPA AP-42,47 assuming a mixture of splash and submerged loading48 that results in 3.5 pounds of

total hydrocarbons released per 1,000 gallons of crude transported. Using the Radian value of 15 percent

methane in the total hydrocarbon emissions, the emission factor converts to 0.5 scf of methane per barrel of

crude loaded per year. Activity factors for the number of barrels loaded in trucks and rail cars are taken

from the Petroleum Supply Annual.49 Combined emissions from truck and rail loading total 0.04 Bcf per

year.

Storage Tank Vented Emissions

Storage tank vented emissions, which come from tank farms associated with crude terminals and

pipelines, are estimated to be 0.11 Bcf per year. These emissions are substantially lower than those from

vented tanks in the production sector for two reasons. First, the methane content of crude by the time it

leaves the production area is only about 0.2 percent of the amount in crude as it enters production tankage.

Second, most of the crude tankage capacity in the transportation sector is the floating roof type that

releases fugitive (rather than vented) emissions, as described earlier. The emission factor of 20.6 scf per

1,000 barrels of crude is taken from a 1992 API report.50 Crude oil delivered to refineries is used as the

activity factor for transportation storage tanks because the oil stored in these tanks is generally on its way

to a refinery. According to DOE’s Monthly Energy Review, 5.1 billion barrels of crude were delivered to

refineries in 1995.

 

44 EPA, Compilation of Air Pollution Emission Factors, AP-42, January 1995.

45 API, Global Emissions of Methane from Petroleum Sources, No. DR 140, prepared by Radian, February 1992.

46 United States Army Corps of Engineers, Waterborne Commerce of the United States, 1995, Part 5: National

Summaries.

47 EPA, AP-42, 1995.

48 These procedures are described in the emission reduction section.

49 DOE/EIA, Petroleum Supply Annual 1996, Volume 1.

50 API, No. DR 140, prepared by Radian, February 1992.
FINAL DRAFT 20

Pumping Station Vented Emissions

Very small amounts of methane are emitted from crude that is exposed to the atmosphere when

pipeline pumping stations are dismantled for maintenance. Pipeline Systems, Inc. (PSI) estimates that only

36.8 scf is released per station each year, based on component counts and emission rates.51 The number of

pumping stations in 1995 is reported by the Oil & Gas Journal to be 587.52 Annual methane emissions

from this source are essentially zero.

Pipeline Pigging Vented Emissions

Pigs, or scrapers, are cylindrical devices, equipped with blades and brushes, that are used to clean

build-ups of water, rust, wax, sludge, or other materials from pipelines. Pipeline pigging operations are a

potential source of methane emissions when pig stations are opened to inject and recover pigs. CAPP53

estimates that the emission factor for pig stations is 39 scf per day per station. Assuming two pig stations

per pumping station (one receiving and one injecting), the resulting activity factor of 1,174 stations

provides an estimated annual emission rate of 0.02 Bcf

2. Crude Transportation Fugitive Emissions

None of the sources of fugitive methane emissions in the crude transportation sector are significant.

The largest emission rate is from floating roof tanks at 0.05 Bcf per year, representing 98 percent of the

total.

Floating Roof Tank Fugitive Emissions

Although floating roof tanks are much more prominent in the crude transport sector than in the

production sector, only a small amount of methane remains in crude after the degassing that occurs during

field processing and from venting during storage at the field. Radian estimates that vented emissions from

transportation and refining sector tanks were only 0.17 percent of vented emissions from production sector

tanks. However, 18.5 percent of U.S. oil production comes from offshore, where tank storage and venting

are minimized. For this high methane content crude that is first stored onshore, the emission factor is

assumed to be the same as for floating roof tanks used in the production sector. These considerations result

in an emission factor of 58,965 scf per tank per year. The number of transportation sector floating roof

tanks is estimated to be 824; this is based on an Entropy54 estimate of larger tanks in fluid heavy oil storage

service, assuming all are floating roof tanks. The resulting emission estimate is 0.05 Bcf.

Oil Pipeline & Pump Station Fugitive Emissions

The fugitive emission factors for oil pipelines and pumping stations is taken from a PSI study, that

estimates oil pipeline emissions to be near zero.55 The oil pipeline pumping station emission factor is

 

51 Pipeline Systems, Inc., Annual Methane Emission Estimate of the Natural Gas and Petroleum Systems in the

United States, for ICF Incorporated, December 1989.

52 OGJ, 11/25/96, p.56.

53 CAPP, 1992

54 API, Aboveground Storage Tank Survey, by Entropy Limited, April 1989.

55 PSI, 1989.
FINAL DRAFT 21

estimated by PSI to be 25 scf per pipeline-mile per year. The Oil & Gas Journal56 states that oil pipeline

mileage was 58,720 miles in 1995. The resulting annual emission rate for pump stations is less than 0.001

Bcf.

3. Crude Transportation Combustion Emissions

No activity factors have been found for the two potential sources of combustion emissions

identified — engine drivers for pipeline and loading pumps and crude heaters. Table C-2 in Appendix C

provides emission factors for these sources that can be used whenever activity factors are available. PSI

estimates that nearly all crude pipeline pumps are driven with electric motors.57 A few pumps in remote

locations may use diesel engine drivers or steam turbines with boilers burning fuel oils. Pipeline heaters

also probably use fuel oils which have essentially no methane content. Consequently, the combustion

emissions from crude transportation pumps and heaters are estimated to be negligible.

C. Crude Refining Sector Emissions

Total annual methane emissions from the refining sector are estimated to be 1.3 Bcf, with no

significant sources. Table III-7 summarizes the refining sector emissions by type. As with the previous

two industry sectors analyzed, the vented emissions are substantially larger than the other types. Table C-3

in Appendix C provides details of estimated emissions for the refining sector from all of the sources

identified.

Very small amounts of methane are present in the gaseous and liquid process streams in refineries.

In the refinery fuel gas system, however, methane is more concentrated. This system contains a mixture of

light gases that are not valuable enough to be included in the refinery product mix, such as ethane,

hydrogen, and methane. Natural gas is frequently added to the waste gases in the fuel gas system to

maintain pressure and volume requirements. Consequently, the fuel gas system is the only refinery system

where emissions will contain a substantial amount of methane.

 

56 OGJ, 11/25/96, p.56.

57 Ted Doud, PSI, Personal Communication.

Table III-7

1995 Crude Refining Sector Emission Estimates by Type of Emission

Type of Emission Emission Estimate

(Bcf/yr)

Percent of Total

Vented 1.1 86%

Fugitive 0.1 7%

Combustion 0.1 7%

 Total 1.3 100%
FINAL DRAFT 22

Other process streams that can contain small amounts of methane are the light gaseous overhead

streams from the atmospheric distillation towers (the first location where crude is heated to high

temperatures and most of the remaining methane in the crude will be released) and the processes where

these lighter overhead streams are sent after atmospheric distillation. These downstream processes are

referred to as the light ends processes. However, no emission factors have been found for the atmospheric

distillation and light ends processes. Heavier product streams, such as gasoline and heating oil, contain

essentially no methane.

1. Crude Refining Vented Emissions

Total vented methane emissions from the three identified sources in refining operations are

estimated to be 1.1 Bcf per year. The two largest sources are system blowdowns and asphalt blowing.

Methane vented from refinery tankage is much lower than that from production sector tankage because

most of the methane has already been released during production. Table C-3 of Appendix C provides

details of all refining vented emissions evaluated.

System Blowdown Vented Emissions

System blowdown emissions of 0.7 Bcf include maintenance preparation venting and releases of

gases used to regenerate catalysts and molecular sieves. The emission factor of 136.8 scf per thousand

barrels of refinery feed is taken from Radian. The activity factor for 1995 is 14 million barrels (mmbbls)

per day of crude fed to refineries.58

Asphalt Blowing Vented Emissions

In some refineries, hot air is blown through asphalt recovered from vacuum distillation to change

the asphalt’s physical characteristics. This operation is estimated by Radian to emit 60 pounds of total

hydrocarbon (THC) per ton of asphalt processed. Methane is estimated to be only 1.0 percent of the THCs

in asphalt, because the high temperatures to which it has already been exposed have removed most of the

methane. These values provide an emission factor of 2,555 scf of methane per 1,000 barrels of asphalt

processed. The activity factor of 467,000 barrels of asphalt processed per day is taken from the Petroleum

Supply Annual59 report of U.S. asphalt and road oil production. The resulting methane emission rate is 0.4

Bcf per year.

Storage Tank Vented Emissions

Fixed roof tank vented emissions from tanks at refineries are estimated to be 0.01 Bcf per year.

These emissions are substantially lower than those from vented tanks in the production sector for two

reasons. First, the methane content of crude by the time it leaves the production area is much lower than

when it enters production tankage. Second, most of the crude tankage capacity in the refining sector is the

floating roof type that releases fugitive emissions as described below in the crude refining fugitive

emissions section. The emission factor of 20.6 scf per 1,000 barrels of crude is taken from a 1992 API

report.60 The activity factor is the 1,792,600 barrels per day of heavy crude fed to refineries in 1995, based

 

58 DOE/EIA, Monthly Energy Review, December 1997.

59 DOE/EIA, Petroleum Supply Annual, 1996.

60 API, No. DR 140, prepared by Radian, February 1992.
FINAL DRAFT 23

on total crude feed to refineries as reported in DOE’s Monthly Energy Review and the Radian estimate that

13 percent of feed is heavy crude. Since some heavy crude is stored in floating roof tanks (along with

essentially all light crude), this activity factor may be somewhat high.

2. Crude Refining Fugitive Emissions

Fugitive emissions from crude oil refining operations are estimated to total 0.09 Bcf per year; 0.07

Bcf of this, or 78 percent of the total, comes from the refinery fuel gas system. Other fugitive sources are

cooling towers and wastewater treating.

Fuel Gas System Fugitive Emissions

Annual fugitive methane emissions from an average fuel gas system are estimated to be 439 Mcf

per refinery. This value was obtained by estimating the number of valve, flange, and connection

components per average fuel gas system and applying standard API component leak rates to each.61 The

numbers of components estimated are 400 valves, 818 flanges, and 3 connectors.62 The methane content of

released gas is estimated to be 45 percent.63 The Oil & Gas Journal reported 163 refineries for 1995. The

resulting annual fugitive emission rate for fuel gas systems is 0.07 Bcf.

Floating Roof Tank Fugitive Emissions

The emission factor of 587 scf per tank per year for refinery floating roof tanks was developed

using the API TANKS program as described earlier in the section on transportation sector emissions from

floating roof tanks.64 The activity factor of 767 floating roof tanks in the refining sector is the sum of the

larger tanks in fluid heavy oils service that are listed in the Entropy tank survey.65 The resulting annual

emission rate is less than 0.001 Bcf.

Wastewater Treating Fugitive Emissions

Methane emissions from wastewater treating operations are quite small for two major reasons.

First, the hydrocarbons that leak and runoff into the sewer system have little methane content. Second, the

gases that are contained in the hydrocarbons have had ample opportunity to release to the atmosphere while

in the sewer system. The emission factor of 1.882 scf per thousand barrels of crude feed to refineries is

taken from Radian. The 1995 refinery feed rate from EIA’s Monthly Energy Review is 5.1 billion barrels

per year.66 These factors provide an annual emission rate of 0.01 Bcf.

 

61 API 4638

62 Consensus of refinery industry experts.

63 Estimated by calculating the methane content from typical refinery fuel gas heating values.

64 No allowance is made in the refining sector for the higher methane content of crude produced offshore, which is

assumed to have been accounted for in the transportation sector fugitives (see transportation section for details).

65 API, Aboveground Storage Tank Survey, 1989.

66 EIA, Monthly Energy Review, April 1997.
FINAL DRAFT 24

Cooling Tower Fugitive Emissions

Methane emissions from cooling towers, although small, are slightly larger than those from

wastewater treatment. This is because recirculated cooling water receives hydrocarbons that have not

previously been exposed to the atmosphere in the refinery. The emission factor of 2.4 scf per thousand

barrels of crude feed to refineries is taken from Radian. The activity factor for 1995 is the 5.1 billion

barrels of crude fed to refineries. The 0.01 Bcf of methane emitted from cooling towers could be

categorized as vented emissions as well as fugitive.

3. Crude Refining Combustion Emissions

Nearly all of the 0.09 Bcf of methane emissions from combustion in refineries is from the small

amount of unburned methane emitted from the stacks of process heaters that typically burn refinery fuel

gas. Two other sources, totaling only 0.01 Bcf per year, are flares and gas-fueled drivers for compressors

and generators.

Process Heater Combustion Emissions

The estimated annual combustion emissions from the 11 primary processes listed in Table C-3 of

Appendix C total 0.08 Bcf. Atmospheric distillation and hydrotreating are the largest sources at

approximately 0.02 Bcf each. Emission factors for the 11 processes are taken from Radian. The activity

factors, which are the feed rates for the 11 processes, are from Oil and Gas Journal’s December 18, 1995

Worldwide Refining Issue.

Engine Combustion Emissions

Most of the gas-fueled driver horsepower in refineries today is in the form of combustion gas

turbines driving electric generators. The emission factor for gas turbines estimated in the GRI/EPA report

on gas industry methane emissions is 0.006 scf per HP-hr.67 It is estimated that each of the 55 large U.S.

refineries with crude charges of 100,000 barrels per day or more has at most 25 MW of turbo generating

capacity.68 These large refinery turbines will deliver a total for 673 million HP-hr per year. Assuming that

the 108 smaller refineries each have engines that deliver half the horsepower of the larger refineries, their

total annual output will be 661 million HP-hr. This provides a total activity factor of 1,334 HP-hr per

year. The combustion turbine capacity allowances used in these estimates is believed to be large enough to

capture the small number of smaller compressor internal combustion drivers in use for refrigeration and

other process needs. The methane emission estimate resulting from these factors is 0.01 Bcf per year.

Flare Emissions

Methane emissions from refinery flare combustion are estimated to be small (less than 1.0 MMcf

per year). The emission factor for refinery flares is estimated by Radian to be 0.8 pounds of VOC per

1,000 barrels of refinery feed. From AP-42, Radian estimates that only 1.0 percent of VOC emissions

from refinery flares are unburned methane. Using these values, the methane emission rate is 0.19 scf per

1,000 barrels of crude feed. The refinery feed rate activity factor is 5.1 billion barrels per year.

 

67 EPA/GRI, Methane Emissions from the Natural Gas Industry, Volume 11: Compressor Driver Exhaust, by

Radian, June 1996.

68 Consensus of industry review panel.
FINAL DRAFT 25

IV. POTENTIAL IMPROVEMENTS IN EMISSION ESTIMATES

Review of the results presented in this report indicates that two of the more significant methane

emission estimates reported could be improved. The most obvious of the uncertain estimates is apparently

the largest single source of emissions — the 26 Bcf from fixed roof tank venting at oil production sites.

The availability of E&P TANK, the sophisticated model developed by API for estimating emissions from

individual vented fixed roof tanks, argues strongly for developing inputs to the model that reasonably

represent the characteristics of all U.S. crudes and tank facilities. This improvement can be accomplished

by using one of the crude oil reservoir data bases currently available or by using other commercial sources

of data on crude oil characteristics by region. These databases provide crude oil characteristics for

thousands of reservoirs that can be aggregated regionally prior to running as individual production sites in

the E&P TANK model.

The emission estimate for chemical injection pumps, which this study found to be a significant

source of methane, is another potential area for improvement. The current estimate is that 25 percent of oil

industry chemical injection pumps are powered by natural gas. However, many industry experts say that

most oil production chemical injection pumps are driven mechanically (i.e., using the walking beam from

the oil pump) or with electric motors or compressed air. Generally, the pumps would only be gas-driven at

flowing oil wells where walking beams and electricity are not present. The number of wells meeting these

criteria is expected to be small, possibly less than five percent.

Additional field testing is currently underway to quantify the methane emission factor for refinery

asphalt blowing. In this process, heated air is blown through hot liquefied asphalt to change its physical

properties. Since asphalt has been subjected to temperatures as high as 800 to 900 degrees F prior to

blowing, much of the original methane would already have escaped by this point. However, the asphalt

process can also produce new methane as the hydrocarbons split. Also, the activity factor used includes all

asphalt and road oil production, although only a portion of asphalt is blown and none of the road oil is.

V. OPPORTUNITIES FOR EMISSION REDUCTIONS

Methane is a valuable energy resource as well as a greenhouse gas, therefore many emission

control options have direct economic and environmental benefits. Unlike many other sources of greenhouse

gases, a few significant sources of methane emissions account for a very large portion of total oil industry

methane emissions. Thus, application of a few emission reduction techniques to sources with large losses

can result in substantial emission decreases. Some successful strategies for reducing methane emissions in

the oil and gas industries have proven to be low cost and profitable. Two examples of profitable emission

controls in the oil industry are the addition of vapor recovery systems to oil storage tanks used at oil

production sites and the replacement of high-bleed rate pneumatic devices which are used for process

controls with low-bleed rate devices. In the case of the vapor recovery units, vented gas that is rich in

methane and gas liquids can be compressed and sold, or if no gas gathering system is available, the gas can

be flared. Reduction of gas usage by pneumatic devices also can result in additional gas sales at

production sites where gas gathering systems are available.

For this report, the economics of options for reducing methane emissions are described for only the

“significant” emission sources (those which release 1.0 Bcf per year or more). Of the 70 oil industry
FINAL DRAFT 26

methane emission sources analyzed, six production sector sources were found to contribute over 90 percent

of the total annual methane emissions estimated for the oil industry.

In this analysis, two levels of methane emission reductions are estimated — the technical potential

and the economically feasible. The larger emission reduction estimates are for those that have technical

potential and are not constrained by a requirement for an economic return on the costs required to

implement the reduction option. The estimates of economically feasible emission reductions have this

economic constraint. Economically feasible options for emission sources smaller than 1.0 Bcf per year

have been less rigorously evaluated than for the significant sources.

The following paragraphs discuss options that are available to reduce methane emissions from the

crude oil production, transportation, and refining sectors of the oil industry. For each of the three sectors,

the emissions are further divided into types of emissions — vented, fugitive, and combustion. Upset

emissions are added for the production sector.

A. Production Sector Emission Reductions

Technically achievable emission reductions in the oil production sector are an estimated 45 Bcf, or

77 percent of the estimated 58 Bcf total in 1995. Applying a requirement for a reasonable return on the

costs of implementing these options reduces the technical potential to an estimated 14 Bcf, or 24 percent of

the total. Table V-1 summarizes these estimates of production sector methane emission reductions. The

emission reduction options that can provide these decreases are described in the following paragraphs and

listed in Table F-1 of Appendix F.

Table V-1

Estimated Methane Emission Reductions from Production Sector Sources

Methane Emission Reductions

Emission Source Type of

Emission

Total Methane

Emissions

(Bcf/yr)

Technical

Potential

(Bcf/yr)

Economically

Feasible

(Bcf/yr)

Significant sources

 Storage tanks Vented 25.7 24.4 8.2

 Pneumatic devices (high-bleed) Vented 19.5 17.5 4.9

 Pneumatic devices (low-bleed) Vented 3.6 0.4 0.2

 Chemical injection pumps Vented 2.8 0.7 0

 Oil wellheads (light crude) Fugitive 1.3 0.6 0.3

 Gas engines Combustion 1.4 0.1 0.1

Smaller sources total All 4.1 1.2 0.4

Totals 58.4 44.9 14.1
FINAL DRAFT 27

Although detailed economic evaluations of the options for reducing methane emissions from the

smaller sources (each emitting less than 1.0 Bcf per year) have not been developed, estimates have been

made for emission reduction options that have technical potential and for those that are economically

feasible.

1. Production Vented Emission Reduction Options

There are four significant vented methane emission sources in the production sector. These four

sources — crude storage tanks, high-bleed rate pneumatic devices, low-bleed rate pneumatic devices, and

chemical injection pumps — account for 51.6 Bcf of the 53.3 Bcf total vented emissions. The remaining

1.7 Bcf comes from eight lesser sources that vary from near zero to 0.8 Bcf per year. These eight smaller

sources include:

• venting on offshore production platforms;

• depressuring of equipment (blowdown) prior to maintenance;

• starting compressors with compressed gas;

• stripper wells;

• venting of oil wells during well completion and workover operations; and

• venting at pipeline pig stations.

Options for reducing vented emissions from each source in the production sector are listed in Table F-1 of

Appendix F. Table V-2 provides a summary of these reduction options.

Table V-2

Summary of Vented Emission Reductions from the Production Sector

Methane Emission Reductions

Emission Source Total Methane

Emissions

(Bcf/yr)

Technical

Potential

(Bcf/yr)

Economically

Feasible

(Bcf/yr)

Significant sources

 Storage tanks 25.7 24.4 8.2

 Pneumatic devices (high-bleed) 19.5 17.5 4.9

 Pneumatic devices (low-bleed) 3.6 0.4 0.2

 Chemical injection pumps 2.8 0.7 0

Smaller sources total 1.7 0.2 <0.1

Totals 53.3 43.2 13.3
FINAL DRAFT 28

Tank Venting

At an estimated 26 Bcf in 1995, methane emissions from production area tanks is the largest

methane source in the oil industry. The most effective options for reducing these emissions are the

installation of vapor recovery units (VRUs) and vapor flaring systems. VRUs are used when the recovered

gases can be sold for the value of the methane and other hydrocarbons in the vapor. Where a gas gathering

system is not available, a flare system can be used to burn the captured gases, thereby reducing the

methane released to the atmosphere to the approximately 1.0 percent that is unburned in the flare. Both of

these systems are in use in many areas where economics favor capturing and selling the gas that would

otherwise be vented, or where tank emission controls are mandated.

The technical potential for methane emission reductions from tank venting is estimated to be the 95

percent effectiveness cited by the Natural Gas STAR program for VRUs. The effectiveness of flare

systems are estimated to be essentially the same as for VRU systems. At 95 percent effective, an emission

reduction of 24 Bcf should be technically achievable.

Table V-3 provides examples of the returns available for installing VRU systems on production

sector crude tanks for several levels of gas emissions. The returns are based on a gas price of $2.00 per

Mcf, a 10 percent discount rate, and a five-year service life for the system. The industry rule-of-thumb is

to size units at double the average daily emission rate (i.e., gas throughputs are estimated to be 50 percent

of the system capacities listed below).

Source: Natural Gas STAR program, draft Lessons Learned, Installing Vapor Recovery Units on Crude Oil Storage 

Tanks.

For producers who require a payback period of about three years or less, the minimum acceptable

gas recovery rate apparent from these examples is 25 Mcf per day (one-half of the 50 Mcf/day capacity).

Higher natural gas prices and recognition of the added value of the gas liquids (ethane, propane, butane) in

the gas recovered would tend to lower the minimum acceptable gas recovery rate and result in greater

emission reductions.

This economic analysis can be used to estimate the economically achievable emission reductions.

Assuming that oil storage tanks that are discharged into tank trucks are designed to hold at least two days

Table V-3

Sample Economic Analyses for VRU Systems

Capacity

(Mcf/day)

Total

Investment ($)

O & M Costs

($/yr)

Value of Gas

($/yr)

@ 1⁄2 capacity

Payback

Period

(months)

Return on

Investment

(%)

50 34,125 6,000 18,250 38 23%

100 41,125 7,200 36,500 19 66%

200 55,125 8,400 73,000 11 115%

500 77,000 12,000 182,500 6 221%
FINAL DRAFT 29

of production and assuming a gas-to-oil ratio of 50 scf per barrel of crude entering the tank, a tank venting

rate of 25 Mcf per day would require 1,000 barrels of tank capacity. The share of total U.S. crude tanks

with this capacity or larger is about 35 percent.69 As estimated in Chapter III, about nine percent of these

tanks already have vapor recovery systems. Thus, the potential for emission reduction by installation of

economically justified VRUs is estimated to be 32 percent (91 percent of 35 percent) of the 26 Bcf

emission estimate for 1995, or 8.2 Bcf.

High-Bleed Pneumatic Device Venting

By definition, high-bleed pneumatic devices are those that vent at least 52 Mcf per year. The EPA

average emission factor for these high-bleed units is estimated to be 126 Mcf per year. In all, venting from

high-bleed rate pneumatic devices is the second largest source of methane emissions from the oil industry,

estimated to be 19.5 Bcf in 1995. The technical potential for reducing these emissions is as high as 90

percent, which may be achieved by replacing the high-bleed devices with low-bleed units or retrofitting

them with low-bleed modification kits. These options could eliminate 17.5 Bcf of the estimated 19.5 Bcf

emitted each year from high-bleed devices.

The Natural Gas STAR program Best Management Practice Number 1 (BMP 1) for the natural

gas industry production sector provides sample economics on the returns that can be available for investing

in low-bleed pneumatic devices. Table V-4 shows costs of switching to low-bleed devices, the value of gas

conserved, and returns for retrofit and replacement devices. The returns are based on replacing a device

that bleeds 250 Mcf per year, a gas price of $2.00 per Mcf, a 10 percent discount rate, and a five-year

service life. The retrofit device in this example is a Mizer kit that reduces the bleed rate, but also reduces

control sensitivity. In some close control applications the Mizer kit cannot be used and a replacement

controller is required to obtain the bleed reductions desired.

These two examples are based on a 250 Mcf per year bleed rate that is nearly twice that of the

average 126 Mcf per year rate for these devices. The results shown in Table V-4 indicate that for

producers who require at least a 3-year payout, a replacement controller will be economic only for those

devices that bleed greater than average volumes of gas. However, the less costly retrofit option can be

 

69 Estimated using the results of API’s Aboveground Storage Tank Survey, prepared by Entropy Limited, April

1989.

Table V-4

Economic Comparison of Retrofit and Replacement High-Bleed Pneumatic Devices

Economic Element Retrofit Controller Replace Controller

Implementation costs ($) $500 $1,341

Bleed rate reduction (Mcf/yr) 219 228

Value of gas saved ($/yr) $428 $456

Payback period (yrs.) 1.1 2.9

Net present value ($) $1,073 $300

Internal rate of return (%) 78% 18%
FINAL DRAFT 30

justified for lower bleed rates — down to less than 100 Mcf per year in services where less sensitive

process control is acceptable. Based on these comparisons, the share of methane emissions from pneumatic

devices that can be reduce economically is judged to be about 25 percent, or 4.9 Bcf per year.

Low-Bleed Pneumatic Device Venting

Since low-bleed rate pneumatic control devices typically emit 90 percent less than high-bleed

devices, there is little room for additional emission reductions from low-bleed devices. Use of a directed

inspection and maintenance (I/M) program to optimize operation and minimize venting of low-bleed devices

is judged to have a technical potential for emission reductions of 10 percent, or 0.4 Bcf per year. The

economically feasible reductions are estimated to be half of the technical potential, or 0.2 Bcf per year.

Chemical Injection Pump Venting

At 3.6 Bcf in 1995, methane vented during the normal operation of chemical injection pumps is the

third largest source of emissions from the U.S. oil industry. As in the case of pneumatic devices, the

pressurized natural gas that is frequently available at oil production sites is used to drive pumps that inject

various chemicals into produced crude oil. When electricity is available, motors can be used to drive these

pumps. The injected chemicals are used to break oil-water emulsions, inhibit corrosion, dewax paraffins,

kill bacteria, and control other processing problems. The estimated average emission rate for each pump is

122 Mcf per year. At $2.00 per Mcf the lost gas has an average annual value of $244. Newer, higher

efficiency, pump designs can reduce emissions by up to 25 percent. At most, this would provide annual

savings of only $61. At a capital and installation cost of $1,500 to $7,500 for a more efficient pump, there

is obviously inadequate incentive for replacing injection pumps that have an average bleed rate. Moreover,

since larger pumps with higher bleed rates will be more costly, there is little likelihood that many pump

replacements will be economic. For new installations and replacement of defective pumps where electricity

is available, pumps with electric drive motors are the preferred choice. They cost about 20 percent less

than gas or air driven pumps and emit no methane. For new and necessary replacements where electricity

is not available, the current incremental cost of at least $400 for a higher efficiency gas driven pump cannot

be economically justified.

The technical potential for emission reductions from chemical injection pumps is the 25 percent

decrease in emissions available by replacing existing older designs with higher efficiency units. These

replacements would provide emission reductions of 0.7 Bcf per year. There are no economically feasible

emission reductions at $2.00 per Mcf.

Offshore Platform Venting

Emissions from offshore platform venting have been estimated to be 0.9 Bcf per year based on a

MMS study. As noted previously, most of these emissions likely come from pneumatic devices and

chemical injection pumps. For safety reasons, directed I/M programs are typically in use on platforms and

fugitive emissions are minimized relative to onshore operations. However, the close control of offshore

processing operations requires sensitive controllers that use more gas, typically high-bleed devices. Thus,

venting from pneumatic devices is typically a larger part of total emissions.

Changing to electric drives for pneumatic devices and chemical injection pumps on offshore

platforms would require more power generation capacity and costly wiring additions on the platforms. As

in the case of onshore facilities, pressurized gas is available and inexpensive compared to the alternatives
FINAL DRAFT 31

for driving process control valves and chemical injection pumps. Many producers have switched, or plan

to switch, to air-powered pneumatics and controllers offshore for safety reasons — particularly on manned

platforms. However, no data is currently available to estimate how many are currently air-powered.

Consequently, reductions in vented offshore platform methane emissions are estimated to be restricted to

application of directed I/M programs. Offshore platform I/M programs are estimated to provide an

emission reduction technical potential of 10 percent, or 0.08 Bcf per year, with a five percent reduction, or

0.04 Bcf per year, economically feasible.
FINAL DRAFT 32

Stripper Well Venting

Stripper well venting can be stopped by simply closing well casing valves. The problem with this

emission reduction option is that closing the casing valve will allow gas pressure to build up in the annulus

between the production tubing and casing, thereby slowing the oil production rate. Since the emission

factor is based on the one-third of total stripper wells estimated to produce an average of one barrel per

day, anything that slows the production rate will cause many of these wells to be shut in. Shutting in half

of the 142,000 stripper wells that average one barrel per day would reduce U.S. oil production by 71,000

barrels per day, or 26 million barrels per year. This 1.1 percent of total U.S. oil production, valued at $20

per barrel, is worth $520 million per year. The value of the 160 MMcf per year of methane vented at

$2.00 per Mcf is $320,000 per year. Additionally, if this gas is not vented at the casing valve, it will be

vented from the crude storage tanks, because no vapor recovery units are installed at such small producing

facilities. The technical potential for reduction of these emissions is 100 percent, or 0.16 Bcf per year.

There is no economic incentive for reducing these emissions.

Other Venting

Technically achievable and economically feasible options for reducing the 0.2 Bcf of methane

emissions from the remaining eight minor venting sources are summarized in Table F-1 of Appendix F.

The emission factors for each of these sources are so small that use of the available options for reducing

emissions on an economic share of the sources is estimated to provide insignificant reductions.

2. Production Fugitive Emission Reduction Options

The only significant source of fugitive emissions in the production sector is light crude oil

wellheads. The estimated emission rate from 211,127 oil wells (excluding stripper wells) is 1.3 Bcf. This

one source is responsible for 45 percent of the 2.9 Bcf total production sector fugitive emissions. The

remaining 65 percent comes from 15 smaller sources that vary from zero to 0.6 Bcf per year. Table V-5

summarizes the fugitive emission reductions possible in the production sector.

Table V-5

Summary of Fugitive Emission Reductions from the Production Sector

Methane Emission Reductions

Emission Source Total Methane

Emissions

(Bcf/yr)

Technical

Potential

(Bcf/yr)

Economically

Feasible

(Bcf/yr)

Significant sources

 Oil wellheads (light crude) 1.3 0.6 0.3

Smaller sources total 1.6 0.9 0.5

Totals 2.9 1.5 0.8
FINAL DRAFT 33

Oil Wellheads, Light Crude

At wells producing light crude oil, gas leaks from the valves, flanges, pipe fittings, and polished

rod stuffing box on the wellheads. A directed I/M program that concentrates on repairing leaky wellhead

components provides an estimated technically achievable emission reduction of 50 percent, or 0.6 Bcf per

year. The economically feasible reduction is estimated to be half of the technical potential, or 0.3 Bcf. The

cost of a directed I/M programs can be minimized by combining its activities with those normally required

to operate and maintain production equipment and systems.

Separators, Heater Treaters and Headers

Separators, heater treaters, and piping headers handling light crude each emit from 0.3 to 0.6 Bcf

of methane a year. Totaling 1.4 Bcf a year, these emissions come from the valves, flanges, and small

connections on each equipment item and can be reduced by applying a directed I/M program. As with the

oil wellheads and smaller emission sources, the leak reductions available from a directed I/M program are

judged to be 50 percent for technical potential and 25 percent economically feasible. This results in

emission reductions of 0.7 Bcf and 0.4 Bcf, respectively.

Compressors and Pumps

The 0.1 Bcf of methane emitted from compressors and pumps can be reduced through a directed

I/M program. The economically achievable emission reductions are estimated to be approximately 70

percent, or 0.07 Bcf.70 The technical potential for emission reductions is judged to be 80 percent, or 0.08

Bcf.

Floating Roof Tanks

Floating roof tank emissions are only 0.008 Bcf in the production sector because nearly all

production area tanks have fixed roofs that are vented. Reduction of vented emissions from fixed roof

tanks were discussed earlier in this report section. Emissions from floating roof tanks are categorized as

fugitive emissions because the use of floating roofs prevents the intentional venting that occurs with fixed

roof tanks. Most of the leakage from floating roof tanks containing crude oil is at the sealing mechanisms

where the roof guide poles penetrate the roof and around the circumference of the roof where it meets the

vertical tank shell.

For average sized crude storage floating roof tanks, with diameters of approximately 200 feet, the

$676 annual value (338 Mcf per year emitted at $2.00 per Mcf) of gas emitted is only a small fraction of

the costs involved of adding improved seals. If the tank must be taken out of service, cost estimates for

installing improved guide pole seals range from $15,000 to $30,000 depending on tank size. If the tank for

some reason is already out of service and clean, the cost of replacing guide pole seals is reduced to $5,000

to $10,000. Improved guide pole seals are estimated to reduce emissions by 99 percent.

The cost range for replacing primary perimeter seals is $120 to $175 per linear foot. For a 200 ft.

diameter tank, the cost would range from $75,000 to $110,000. Secondary perimeter seals cost about half

as much as the primary seals. Labor costs for installing the perimeter seals are twice the cost of the seals

themselves. Because of these high costs and low savings, no economically feasible emission reductions are

 

70 See EPA, Natural Gas STAR 1996 Workshop and Implementation Guide, BMP III.
FINAL DRAFT 34

expected to be available from improved roof seals. In locations where such improvements to floating roof

crude storage tanks are mandated, there will be a technical potential for emission reductions — estimated to

be between 90 and 95 percent. If such mandates applied to half of the floating roof tanks, the technical

potential for emission reduction would be only 0.004 Bcf.

Sales Areas

Fugitive emissions totaling 0.08 Bcf per year at the loading docks where crude is placed into tank

trucks can be reduced by installing vapor recovery or flare systems. Because most of the tank batteries

where crude is loaded are low volume (average methane emission rate of 664 scf per year) and the cost of a

vapor recovery system is at least $10,000, the number of locations where these emission reduction options

can be economically justified will be a small fraction of the 122 thousand loading docks. A more

practicable option for reducing loading emissions is to use a submerged loading procedure in filling tank

trucks. Submerged loading, in which the loading nozzle is held below the liquid level during tanker filling,

creates fewer emissions than splash loading, which drops the crude into the tanker from above. The cost of

installing loading line extensions for submerged loading is estimated to be less than $200 per average sales

area. The technical potential for reducing emissions using this option is estimated to reduce sales area

emissions 60 percent, or by 0.05 Bcf, compared to splash loading. Since the producer receives no

additional revenue for gas that remains in solution in the crude being loaded, the economically feasible

emission reduction for submerged loading is estimated to be insignificant.

Other Smaller Sources

Four smaller sources of fugitive emissions that are best controlled by a directed I/M program are

listed in Table F-1 of Appendix F which provides a summary of all the production sector emission

estimates and options for reducing the emissions. These four sources involve offshore oil platforms in the

Gulf of Mexico and in other areas, heavy crude oil wellheads, and oil pipelines. The total leakage of 0.06

Bcf from these sources is primarily from pipe flanges, pipe fittings, and valves. The technical potential for

reducing these emissions by use of a well managed direct I/M program is judged to be 50 percent, or 0.03

Bcf. The economically feasible reduction is judged to be half of the technical potential, or 0.01 Bcf. Oil

well drilling also releases an insignificant volume of methane from crude spills during operations.

Procedures that minimize spills could reduce these minimal emissions.

3. Production Combustion Emission Reduction Options

Production combustion methane emissions, resulting from the incomplete burning of methane used

as fuel, are estimated to be 1.8 Bcf per year. The combustion occurs in internal combustion engines, which

can be reciprocating or turbine types, and process heaters. Gas engines, with 1.4 Bcf emitted per year, are

the only significant source of methane from combustion sources in the production sector. The remaining

five combustion emission sources have a combined total estimated at 0.4 Bcf. Table V-6 summarizes the

combustion emission reductions estimated to be available from the significant source, gas engines, and

other smaller sources. In Appendix F, Table F-1 provides a more detailed list of the combustion emissions

and the options for reducing them.
FINAL DRAFT 35

Gas Engines

Gas-fueled engines are the only significant source of combustion emissions in the oil production

sector, at an estimated 1.4 Bcf per year. In areas where electricity is available, the use of electric motor

drives for pumps and compressors will eliminate combustion emissions from engines. Where electric

motors are not feasible, engines can be tuned and modified to burn less fuel and to burn catalytically fuels

more completely. For larger, new production sites, the use of lean-burn engines may be economic. Several

factors indicate that directed I/M programs for engine tuning and the use of minor engine modifications

may prove to be the only economic options for emission reductions. For instance, most engines at

production sites are relatively small, major engine modifications can be costly, and fuel consumption is not

a major cost. Based on engineering judgment, the technical potential for engine emission reductions is

judged to be 10 percent, or 0.14 Bcf Economically feasible reductions are judged to be 5 percent, or 0.07

Bcf.

Smaller Sources

The largest combustion emission source for methane among the smaller sources is offshore

platforms in the Gulf of Mexico at 0.3 Bcf per year. Since these emissions are primarily from flaring and

the engines that drive generators and compressors, the opportunities for emission reductions are limited.

Flaring is used to dispose of small gas volumes that cannot be recovered economically because of the

platform location relative to gas gathering systems. The technical potential for emission reductions are

judged to be no more than 10 percent, or 0.03 Bcf. Economically feasible emission reductions are judged

to be insignificant. These same levels of emission reduction are estimated for the remaining four

combustion sources that release an estimated total of 0.04 Bcf per year. The four sources are heaters, well

drilling, offshore platforms other than in the Gulf of Mexico, and flares. See Table F-1 of Appendix F for

estimates of emission reductions by sources and the options available for the reductions.

4. Production Upset Emission Reduction Options

Production upsets occur when a process or operation accidentally goes out of control. Examples of

upsets are releases from pressure relief valves when pressures rise above safe levels, and oil well blowouts

Table V-6

Summary of Combustion Emission Reduction from the Production Sector

Methane Emission Reductions

Emission Source Total Methane

Emissions

(Bcf/yr)

Technical

Potential

(Bcf/yr)

Economically

Feasible

(Bcf/yr)

Significant sources

 Gas engines 1.4 0.1 0.1

Smaller sources total 0.4 0.1 Nil

Totals 1.8 0.2 0.1
FINAL DRAFT 36

that occur when unanticipated high pressures are encountered while drilling. Table V-7 summarizes

methane emissions from production sector upsets.

The 1995 total estimated emissions from production sector upsets are 0.3 Bcf from four small

sources: offshore platform emergency shutdowns, pressure relief valves, and oil well blowouts onshore and

offshore. Table F-1 in Appendix F provides a summary of the estimated emission rates and emission

reduction options for these sources. It is not surprising that emissions from upsets are minor. Since upsets

can be costly and hazardous, facility designs and operating and maintenance procedures concentrate on

preventing upsets. The largest of the upset emissions is estimated to come from offshore platform

emergency shutdowns. For safety reasons, as explained earlier, offshore platforms are designed and

operated to be more sensitive to deviations from normal operating conditions than are onshore operations.

Thus they may shut down more often than onshore facilities with similar production rates. Since directed

I/M programs are currently used on platforms and no other options for emission reductions have been

identified, no significant reductions in production upset emissions are judged to be available — either

technically or economically.

Pressure Relief Valves

For those few pressure relief valves (PRVs) that leak frequently, a directed I/M program and

blowout disks can be used to reduce emissions. Since the 0.007 Bcf annual emission rate from PRVs is so

small, both the technical potential and economically feasible emission reductions are estimated to be

insignificant from this source.

Well Blowouts

Onshore, where the use of blowout preventers during well drilling is not always mandated, there

may be some slight reduction in emissions if more preventers were used. Since blowouts can be costly and

hazardous, preventers are typically used at sites where high reservoir pressures are expected to be

encountered during drilling. A potential option for reducing emissions from well blowouts is the use of

preventers that sense high pressures and shut off automatically, rather than manually. Since the annual

emissions from blowouts are quite small and preventive measures are already practiced, the emission

reductions from greater use of blowout preventers are judged to be insignificant.

Table V-7

Summary of Upset Emissions from the Production Sector

Methane Emission

Reductions

Emission Source Total Methane

Emissions

(Bcf/yr)

Technical

Potential

(Bcf/yr)

Economically

Feasible

(Bcf/yr)

Significant sources None None None

Smaller sources total 0.3 Nil Nil

Totals 0.3 Nil Nil
FINAL DRAFT 37

5. Summary of Significant Production Sector Methane Emission Reduction Options

For the six significant production sector sources of methane emissions that represent 90 percent of

total production sector losses, the technical potential for emission reductions is estimated to total 43.7 Bcf.

The economically viable options that are available for emission reductions from five of the significant

sources total an estimated 13.7 Bcf. These six significant sources, the available emission reduction

options, and the emission reduction estimates are summarized in Table V-8, below.

A list of smaller production sector emission sources and the options available to reduce them is

provided in Table F-1 of Appendix F.

B. Crude Transportation Sector Emission Reductions

In 1995, the methane emission sources in the crude transportation sector had estimated emissions

totaling only 0.31 Bcf, with no sources approaching the 1.0 Bcf level. At 0.26 Bcf, vented emissions

account for 84 percent of the total crude transport emissions. Nearly all of the remaining 16 percent are

fugitive emissions from floating roof tanks. Table V-9 summarizes estimated emission reductions in the

production sector. Table F-2 of Appendix F provides a more detailed account of the emissions and

emission reduction options for the crude transportation sector. Combustion emission levels have not been

estimated due to a lack of data on emission and activity factors for pipeline pumps and heaters.

Table V-8

Summary of Options for Reducing Significant Methane Emissions in the Production

Sector

Emission Reductions

Emission Source Emission Reduction Option

Emission

Rate

(Bcf/yr)

Technical

Potential

(Bcf/yr)

Economically

Feasible

(Bcf/yr)

Significant sources

Storage tanks Install vapor recovery or flare systems 25.7 24.4 8.2

Pneumatic devices

 (high-bleed)

Replace or modify pneumatic devices 19.5 17.5 4.9

Pneumatic devices

 (low-bleed)

Use directed I/M programs 3.6 0.4 0.2

Chemical injection

 pumps

Use air-drive, motor-drive, or high

efficiency pumps

2.8 0.7 0.0

Oil wellheads

 (light crude)

Use directed I/M programs 1.3 0.6 0.3

Gas engines Use electric motors or low emission

engines

1.4 0.1 0.1

 Totals 54.3 43.7 13.7
FINAL DRAFT 38

1. Crude Transportation Vented Emission Reduction Options

Fixed Roof Tanks

The largest source of vented emissions in the crude transport sector of the oil industry is fixed roof

tanks, at 0.11 Bcf. This volume is substantially lower than venting from similar tanks in the oil production

sector for two reasons. First, most of the gas has escaped from the crude while stored in fixed roof tanks at

the oilfield. Second, most tanks at pipeline and marine terminals are the floating roof type. Vented

emissions could be reduced by installing vapor recovery systems; the technical potential for reducing

emissions from venting tanks is 90 percent of the emission rate, or 0.10 Bcf. However, since oil pipeline

terminals rarely have adjacent natural gas gathering and processing systems, high capital cost vapor

recovery systems are not judged to be economic.

Loading Operations

Marine loading vented emissions, along with tank truck and rail tank car loading venting, total 0.14

Bcf. These vented emissions can be reduced by using submerged loading procedures and by installing

vapor recovery systems. Submerged loading is estimated to have the technical potential to reduce loading

emissions by 60 percent, or 0.08 Bcf, compared to splash loading. Since the crude transporter receives no

additional revenue for gas that remains in solution in the crude being loaded, the economically feasible

emission reduction for submerged loading is estimated to be insignificant.

Since transportation loading operations are minor sources of emissions, the economics of using

vapor recovery systems have not been analyzed. However, the addition of vapor recovery systems at large

loading facilities where such systems are not already installed could reduce these emissions.

Other Vented Emissions

Other vented emissions, from pump station maintenance and pipeline pigging operations, are

insignificant and should be controlled by use of procedures that minimize spills. Table F-1 in Appendix F

provides options for reducing emissions from vented emissions.

Table V-9

Estimated Methane Emission Reductions from Crude Transportation Sector Sources

Methane Emission Reductions

Emission Source

Type of

Emission

Total Methane

Emissions

(Bcf/yr)

Technical

Potential

(Bcf/yr)

Economically

Feasible

(Bcf/yr)

Significant sources None None None None

Smaller sources total All 0.3 0.2 0.0

Totals 0.3 0.2 Nil
FINAL DRAFT 39

2. Crude Transportation Fugitive Emission Reduction Options

Fugitive crude transportation emissions total only 0.05 Bcf, mostly from floating roof tanks. No

estimated emission reductions have been developed for this small source, since: 1) nearly all of the methane

has escaped crude at the production site, 2) floating roof tanks are standard for crude storage at tank farms

and terminals, and 3) floating roof tank modifications are costly.

3. Crude Transportation Combustion Emission Reduction Options

No estimates of combustion emissions have been developed due to a lack of data on these sources.

Industry sources have stated that nearly all crude pipeline pumps are driven by electric motors, providing

an activity factor of close to zero. In a few remote locations where electricity is not available, pumps are

driven by diesel engines and by steam turbines in which fuel oils are burned to raise steam. No data have

been found on the activity and emission factors for oil heaters used to keep crude from becoming too

viscous to flow in cold weather. Table F-2 in Appendix F provides options for reducing emissions from

combustion emissions.

C. Crude Refining Sector Emission Reductions

There are no significant methane emission sources in the refining sector of the oil industry,

although the total losses in 1995 are estimated to be 1.3 Bcf. As with the other production and

transportation sectors, vented emissions are the largest share of total refinery emissions — representing 86

percent of total emissions. Fugitive and combustion emissions are each responsible for about seven percent

of refinery emissions. Table V-10 summarizes the estimated refinery emission reductions. A more detailed

breakdown of these options is provided in Table F-3 of Appendix F.

Table V-10

Estimated Methane Emission Reductions from Crude Refining Sector Sources

Methane Emission Reductions

Emission Source

Type of

Emission

Total Methane

Emissions

(Bcf/yr)

Technical

Potential

(Bcf/yr)

Economically

Feasible

(Bcf/yr)

Significant sources None None None None

Smaller sources total All 1.3 0.6 Nil

Totals 1.3 0.6 Nil
FINAL DRAFT 40

1. Crude Refining Vented Emission Reduction Options

Process Blowdowns

The largest refining sector vented emission source is processing system blowdowns prior to

maintenance activities at 0.7 Bcf per year. System blowdown venting can be reduced by connecting

equipment to the refinery blowdown or flare systems when blowdown pressures are adequate to enter these

systems. These connections can be permanent or temporary. Alternatively, blowdown gases can be

combusted in a gas scavenging and thermal oxidation system. The technical potential for reducing

blowdown emissions is judged to be 50 percent of the total, or 0.2 Bcf. No reductions are judged to be

economically feasible.

Asphalt Blowing

The hot air discharged from asphalt blowing is the second largest source of refinery emissions, at

0.4 Bcf. These emissions can be reduced by scrubbing or incinerating the air that has contacted the asphalt

before releasing it to the atmosphere. The technical potential for emission reductions is estimated to be 0.2

Bcf. No economic reductions are judged to be available.

Fixed Roof Tanks

In some refineries, tank venting occurs because part of the crude is stored in fixed roof tanks rather

than floating roof tanks. Venting is greater if the crude has not had normal methane release at the

production site. These methane emissions can be reduced by adding vapor recovery systems connected to

the refinery fuel gas system or the flare system. Since refinery vented emissions are small and reduction

options are relatively expensive, no estimates of economically feasible methane emission reductions are

estimated. The technical potential for reductions are judged to be 50 percent of the total 0.013 Bcf

emissions, or 0.007 Bcf

2. Crude Refining Fugitive Emission Reduction Options

Fuel Gas System

The largest source of fugitive methane emissions in refineries is the fuel gas system which typically

contains methane, ethane, and waste refinery gases. Since the emissions are caused by small leaks from

hundreds of components, the only reasonable emission reduction option is a directed I/M program.

Additionally, most of the potential leaks are located at burner manifolds beneath or adjacent to process

heaters. Any gas leaks in these areas will be swept into the combustion chamber of the heater by incoming

combustion air for the burners. Furthermore, the existing refinery Leak Detection and Repair (LDAR)

program — mandated under numerous federal and state regulations for reducing volatile organic chemicals

(VOCs) — requires periodic inspections and repairs of potential leak sources. With fuel gas system

leakage estimated at only 0.07 Bcf per year, and considering these existing conditions and programs, no

significant emission reductions are estimated for the fuel gas system.

Other Fugitive Emissions

Emissions from floating roof tanks, wastewater systems, cooling towers, and oil processing are

relatively insignificant, at a total of 0.02 Bcf per year. Consequently, insignificant emission reduction

estimates are estimated. Table F-3 in Appendix F lists several options for emission reductions including:
FINAL DRAFT 41

1) directed I/M programs to complement the LDAR programs 2) reduction of heat exchanger leaks to the

water side, and 3) upgrading seals on floating roof tanks.

3. Crude Refining Combustion Emission Reduction Options

Gas Fired Heaters

Over 94 percent of the 0.09 Bcf of refinery methane emissions caused by combustion are from gas

fired heaters at processing units. The emissions are from unburned methane in the combusted gases. Since

incomplete combustion is a function of burner design and burner adjustment, one obvious option for

emission reductions is maintenance of optimum burner adjustment as process conditions change. In some

cases, replacement of older, less efficient burners with better designs may be necessary. These options

apply to 11 of the 13 combustion emission sources listed in Table F-3 of Appendix F. Burner adjustments

and improvements are judged to provide methane emission reductions of 10 percent, or 0.01 Bcf, from

process heaters. This reduction applies to both the technical potential and economic feasibility.

Other Combustion Emissions

The other two combustion emission sources are engines and flares that have relatively insignificant

emission rates, totaling less than 0.01 Bcf per year. Table F-3 in Appendix F provides a summary of the

combustion emission rates and options for reducing them. Both the technical and economic potential for

emission reductions are estimated to be insignificant.

VI. CONCLUSIONS

The results of this study indicate that the oil industry is a significant source of methane emissions

in the United States — estimated to be 60 Bcf in 1995. However, because of certain industry

characteristics, it also appears to be a good place to look for emission reductions. First, unlike other

greenhouse gas emissions, methane has value as a fuel and a feedstock. This gives producers an incentive

to consider emission reduction methods that conserve gas. Second, the bulk of oil industry methane

emissions are concentrated in a few sources; over 90 percent of emissions come from just six sources.

Third, there are technologies available to reduce emissions profitably from five of these significant sources.

Because of these factors, 24 percent of oil industry methane emissions are estimated to be susceptible to

reductions at a profit. The technical potential for emission reductions is judged to be 76 percent of total

emissions.
FINAL DRAFT 42

APPENDICES
A-1

APPENDIX A

REFERENCES

API (American Petroleum Institute). 1997. Basic Petroleum Data Book. January 1997.

CAPP (Canadian Association of Petroleum Producers). 1992. A Detailed Inventory of CH4 and VOC

Emissions from Upstream Oil & Gas Operations in Alberta. Vols. 1-3. March 1992.

CAPP (Canadian Association of Petroleum Producers). 1993. Options for Reducing Methane and VOC

Emissions from Upstream Oil & Gas Operations. December 1993.

Department of State. Climate Action Report. 1997 Submission of the United States of America Under the

United Nations Framework Convention on Climate Change.

Doug, Ted. Personal Communication. Pipeline Systems Incorporated, Walnut Creek, California.

EIA (Energy Information Administration). 1995, U.S. Crude Oil, Natural Gas, and Natural Gas Liquids

Reserves, Annual Report 1995. U.S. Department of Energy.

EIA (Energy Information Administration). 1996. Emissions of Greenhouse Gases in the United States

1995. U.S. Department of Energy. October 1996.

EIA (Energy Information Administration). 1997. Monthly Energy Review. U.S. Department of Energy.

April 1997.

Energy Resources Co. 1997. Atmospheric Emissions from Offshore Oil and Gas Production and

Development. Prepared for EPA. June 1977.

Entropy Limited. 1989. Aboveground Storage Tank Survey. Prepared for the American Petroleum

Institute. April 1989.

Gallagher, Terry. Personal Communication. Chicago Bridge and Iron.
A-2

ICF Kaiser International. 1996. Estimation of Activity Factors for the Natural Gas Exploration and

Production Industry in the United States. Prepared for the Environmental Protection Agency.

August 1996.

MMS (Minerals Management Service). 1995. Gulf of Mexico Air Quality Study. Final Report. U.S.

Department of Interior. August 1995.

Pipeline Systems Incorporated. 1989 Annual Methane Emission Estimate of the Natural Gas and

Petroleum Systems in the U.S. Prepared for ICF Incorporated.

Radian. 1977. Revision of Emission Factors for Petroleum Refining. Prepared for EPA. October 1977.

Radian. 1992. Global Emissions of Methane from Petroleum Sources (#DR 140). Prepared for API.

February 1992.

Radian. 1996. Methane Emissions from the Natural Gas Industry, V7: Blow and Purge Activities.

Prepared for the Gas Research Institute and EPA. April 1996.

Radian. 1996. Methane Emissions from the Natural Gas Industry, V11: Compressor Driver Exhaust.

Prepared for GRI and EPA. April 1996.

Radian. 1996. Methane Emissions from the Natural Gas Industry, V12: Pneumatic Devices. Prepared

for GRI and EPA. April 1996.

Radian. 1996. Methane Emissions from the Natural Gas Industry, V13: Chemical Injection Pumps.

Prepared for GRI and EPA. April 1996.

Radian. 1996. Methane Emissions from the U.S. Petroleum Industry. Draft. Prepared for EPA. June

1996.

Radian. 1996. Methane and Carbon Dioxide Emissions Estimate for U.S. Petroleum Sources. Prepared

for API. July 1996.

Rayman, Ron. 1997. Personal Communication. Dresser Texsteam, Houston, Texas (manufacturer of

chemical injection pumps).

Star Environmental. 1993 Fugitive Hydrocarbon Emissions from Oil and Gas Production Operations.

Prepared for API. API Document No. 4589. December 1993.

Star Environmental. 1994. Emission Factors for Oil & Gas Operations. Prepared for API. API

Document No. 4615. December 1994.
A-3

Star Environmental. 1996. Calculation Workbook for Oil and Gas Production Equipment Fugitive

Emissions. Prepared for API. API Document No. 4638. July 1996.

True, Warren R. “U.S. Pipelines Continue Gains into 1996.” Oil & Gas Journal, 25 November 1996:

39-58.

United States Army Corps of Engineers. Waterborne Commerce of the United States 1995, Part 5:

National Summaries. 1995

USEPA (U.S. Environmental Protection Agency). 1993. Anthropogenic Methane Emissions in the U.S.:

Estimates for 1990, Report to Congress. Office of Air and Radiation. EPA-430-R-93-003. April

1993.

USEPA (U.S. Environmental Protection Agency). 1993. Opportunities to Reduce Anthropogenic

Methane Emissions in the United States, Report to Congress. Office of Air and Radiation. EPA430-R-93-012. October 1993.

USEPA (U.S. Environmental Protection Agency). 1995. Compilation of Air Pollution Emission Factors.

Office of Air and Radiation. Research Triangle Park, North Carolina. AP-42. January 1995.

USEPA (U.S. Environmental Protection Agency). 1997. Natural Gas STAR Program, draft Lessons

Learned. Installing Vapor Recovery Units on Crude Oil Storage Tanks.

USEPA (U.S. Environmental Protection Agency). 1996. Natural Gas STAR 1996 Workshop and

Implementation Guide, Best Management Practice III.
B-1

APPENDIX B

Industry Reviewers

Name Company

Production

Bill Freeman Shell Oil Company

Wayne A. Hamilton Shell Oil Company

Vernon H. Schievelbein Texaco, Inc.

John Weust Marathon Oil Company

C. Mark Pike Exxon Company, USA

Vick Newsom BP/Amoco Corporation

Gary Kizior BP/Amoco Corporation

Refining

R.J. Aimone Mobil Corporation

A.Y. Tso Mobil Corporation
APPENDIX C

EMISSION ESTIMATES
C-1

TABLE C-1

OIL EXPLORATION & PRODUCTION METHANE EMISSIONS

Emission

Source No. Emission Source EmissionFactor

Methane Emission

Units

1995 

Activity

Factor

Activity

Units

Emissions

(Bcf/yr)

Vented Emissions:

1 Oil Tanks 18 scf of CH4/bbl crude 1,433.6 MMbbl/yr (non stripper wells) 25.662

2 Pneumatic Devices, High Bleed 345 scfd CH4/device 157,581 No. of high-bleed devices 19.855

3 Pneumatic Devices, Low Bleed 35 scfd CH4/device 292,650 No. of low-bleed devices 3.687

4 Chemical Injection Pumps 248 scfd CH4/pump 31,272 No. of pumps 2.831

5 Vessel Blowdowns 78 scfy CH4/vessel 205,865 No. of vessels 0.016

6 Compressor Blowdowns 3,775 scf/yr of CH4/compressor 2,797 No. of compressors 0.011

7 Compressor Starts 8,443 scf/yr. of CH4/compressor 2,797 No. of compressors 0.024

8 Stripper wells 2,345 scf/yr of CH4/stripper well 347,538 No. of stripper wells vented 0.815

9 Well Completion Venting 733 scf/completion 7,627 Oil well completions 0.006

10 Well Workovers 96 scf CH4/workover 43,086 Oil well workovers 0.004

11 Pipeline Pigging 2.40 scfd of CH4/pig station 0 No. of crude pig stations 0.000

12 Offshore Platforms, Gulf of Mexico 1,283 scfd CH4/platform 1,807 No. of oil platforms 0.846

13 Offshore Platforms, Other U.S. Areas 1,283 scfd CH4/platform 22 No. of oil platforms 0.010

 Total Vented Emissions 53.767

Fugitive Emissions:

14 Offshore Platforms, Gulf of Mexico 56 scfd CH4/platform 1,807 No. of oil platforms 0.037

15 Offshore Platforms, Other U.S. Areas 56 scfd CH4/platform 22 No. of oil platforms 0.000

16 Oil Wellheads (heavy crude) 0.13 scfd/well 16,000 No. of hvy. crude wells * 0.001

17 Oil Wellheads (light crude) 16.6 scfd/well 210,946 No. of lt. crude wells * 1.280

18 Separators (heavy crude) 0.15 scfd CH4/separator 12,098 No. of hvy. crude seps. 0.001

19 Separators (light crude) 14 scfd CH4/separator 110,085 No. of lt. crude seps. 0.557

20 Heater/Treaters (light crude) 19 scfd CH4/heater 83,682 No. of heater treaters 0.586

21 Headers (heavy crude) 0.08 scfd CH4/header 9,279 No. of hvy. crude hdrs. 0.000

22 Headers (light crude) 11 scfd CH4/header 84,436 No. of lt. crude hdrs. 0.335

23 Floating Roof Tanks 338,306 scf CH4/floating roof tank/yr. 24 No. of floating roof tanks 0.008

24 Compressors 100 scfd CH4/compressor 2,797 No. of compressors 0.102

25 Large Compressors 16,360 scfd CH4/compressor 0 No. of large comprs. 0.000

26 Sales Areas 41 scf CH4/loading 1,995,000 Loadings/year 0.081

27 Pipelines 0 scfd of CH4/mile of pipeline 35,223 Miles of gathering line 0.000

28 Well Drilling 0 scfd of CH4/oil well drilled 10,682 No. of oil wells drilled 0.000

29 Battery Pumps 0.24 scfd of CH4/pump 172,345 No. of battery pumps 0.015

 Total Fugitive Emissions 3.003

Combustion Emissions:

30 Gas Engines 0.08 scf CH4/HP-hr 17,634 MMHP-hr 1.411

31 Heaters 0.52 scf CH4/bbl 2394.4 MBbl/yr 0.001

32 Well Drilling 2,453 scf CH4/well drilled 10,049 Oil wells drilled, 1995 0.025

33 Flares 20 scf CH4per Mcf flared 564,566 Mcf flared/yr 0.011

34 Offshore Platforms, Gulf of Mexico 481 scfd CH4/platform 1,807 No. of oil platforms 0.317

35 Offshore Platforms, Other U.S. Areas 481 scfd CH4/platform 22 No. of oil platforms 0.004

 Total Emissions from Combustion 1.769

Process Upset Emissions: 

36 Platform Emergency Shutdowns 256,888 scfy/platform 1,829 No. of platforms 0.470

37 Pressure Relief Valves 35 scf/yr/PR valve 200,000 No. of PR valves 0.007

38 Well Blowouts Offshore 5.0 MMscf/blowout 2.25 No. of blowouts/yr 0.011

39 Well Blowouts Onshore 2.5 MMscf/blowout 33.5 No. of blowouts/yr 0.084

 Total Emissions from Upsets 0.572

 Total CH4 Emissions, Bcf 59.111

 Share of total from sources higher than 1.0 Bcf of CH4 0.926

Annual production, 1995 2394.4 MM Bbl/yr.

Percent heavy crude API<20o12.83% % of annual prod.

Total producing oil wells 1995 574,483 No. of wells

Percent heavy oil wells, API<20o6.97% % of total wells

Total stripper oil wells 1995 434,422 No. of stripper wells

* Number of oil wells, less number of stripper wells that are vented
C-2

TABLE C-2

CRUDE TRANSPORTATION METHANE EMISSIONS

Emission

Source No. Emission Source EmissionFactor

Emission

Units

1995 

Activity

Factor

Activity

Units

Emissions

(Bcf/yr)

Vented Emissions:

1 Tanks 0.021 scf CH4/yr/bbl of crude delivered to refineries 5,100 MMbbl crude feed/yr 0.105

2 Truck Loading 0.520 scf CH4/yr/bbl of crude transported by truck 70 MMbbl crude feed/yr 0.036

3 Marine Loading 2.544 scf CH4/1000 gal.crude marine loadings 38,666,930 1000 gal./yr loaded 0.098

4 Rail Loading 0.520 scf CH4/yr/bbl of crude transported by rail 6.6 MMbbl.crude by rail/yr 0.003

5 Pump Station Maintenance 36.80 scf CH4/station/yr 587 No. of pump stations 0.000

6 Pipeling Pigging 39 scfd of CH4/pig station 1,174 No. of pig stations 0.017

 Total Vented Emissions 0.259

 

Fugitive Emissions:

7 Pump Stations 25 scfCH4/mile/yr. 58,720 No. of miles of crude p/l 0.001

8 Pipelines 0 scf CH4/bbl crude transported by pipeline 6,952 MM bbl crude piped 0.000

9 Floating Roof Tanks 58,965 scf CH4/floating roof tank/yr. 824 No. of floating roof tanks 0.049

 Total Fugitive Emissions 0.050

Combustion Emissions:

10 Pump Engine Drivers 0.24 scf CH4/hp-hr NA No. of hp-hrs NA

11 Heaters 0.521 scf CH4/bbl.burned NA No. of bbl. burned NA

 Total Combustion Emissions 0.000

 Total CH4 Emissions, Bcf 0.309

 Share of total from sources higher than 1.0 Bcf of CH4 0.0%
C-3

TABLE C-3

REFINERY METHANE EMISSIONS

Emission

Source No. Emission Source EmissionFactor

Emission

Units

1995 

Activity

Factor

Activity

Units

Emissions

(Bcf/yr)

Vented Emissions:

1 Tanks 20.6 scfCH4/Mbbl 1,793 Mbbl/cd heavy crude feed 0.013

2 System Blowdowns 137 scfCH4/Mbbl 13,972 Mbbl/cd refinery feed 0.698

3 Asphalt Blowing 2,555 scfCH4/Mbbl 467 Mbbl/cd production 0.435

 Total Vented Emissions 1.147

 

Fugitive Emissions:

4 Fuel Gas System 439 McfCH4/refinery/yr 165 refineries 0.072

5 Floating Roof Tanks 587 scf CH4/floating roof tank/yr. 767 No. of floating roof tanks 0.0005

6 Wastewater Treating 1.88 scfCH4/Mbbl 13,972 Mbbl/cd refinery feed 0.010

7 Cooling Towers 2.36 scfCH4/Mbbl 13,972 Mbbl/cd refinery feed 0.012

 Total Fugitive Emissions 0.095

Combustion Emissions:

8 Atmospheric Distillation 3.61 scfCH4/Mbbl 13,972 Mbbl/cd refinery feed 0.018

9 Vacuum Distillation 3.61 scfCH4/Mbbl 6,178 Mbbl/cd feed 0.008

10 Thermal Operations 6.02 scfCH4/Mbbl 1,722 Mbbl/cd feed 0.004

11 Catalytic Cracking 5.17 scfCH4/Mbbl 4,808 Mbbl/cd feed 0.009

12 Catallytic Reforming 7.22 scfCH4/Mbbl 3,297 Mbbl/cd feed 0.009

13 Catalytic Hydrocracking 7.22 scfCH4/Mbbl 1,216 Mbbl/cd feed 0.003

14 Hydrorefining 2.17 scfCH4/Mbbl 1,707 Mbbl/cd feed 0.001

15 Hydrotreating 6.50 scfCH4/Mbbl 7,461 Mbbl/cd feed 0.018

16 Alkylation/Polymerization 12.6 scfCH4/Mbbl 1,061 Mbbl/cd feed 0.005

17 Aromatics/Isomeration 1.80 scfCH4/Mbbl 825 Mbbl/cd feed 0.001

18 Lube Oil Processing 0.00 scfCH4/Mbbl 197 Mbbl/cd feed 0.000

19 Engines 0.006 scfCH4/hp-hr 1,334 MMhp-hr/yr 0.008

20 Flares 0.189 scfCH4/Mbbl 13,972 Mbbl/cd refinery feed 0.001

 Total Combustion Emissions 0.084

 Total CH4 Emissions, Bcf 1.325

 Share of total from sources higher than 1.0 Bcf of CH4 0.0%
APPENDIX D

COMPARISON OF EMISSION ESTIMATES
D-1

TABLE D-1

COMPARISON OF OIL EXPLORATION & PRODUCTION

METHANE EMISSION ESTIMATES

Emission

Source No. Emission Source Current Emission Estimate (Bcf/yr)

Radian Emission 

Estimate1 (BCF/yr)

Other Emission 

Estimates2 (Bcf/yr)

Vented Emissions:

1 Oil Tanks 25.662 30.235

2 Pneumatic Devices, High Bleed3

19.855 14.734

3 Pneumatic Devices, Low Bleed 3.687

4 Chemical Injection Pumps 2.831 11.323

5 Vessel Blowdowns 0.016 0.016

6 Compressor Blowdowns 0.011 0.011

7 Compressor Starts 0.024 0.024

8 Stripper Wells 0.815

9 Well Completion Venting 0.006 0.005

10 Well Workovers 0.004 0.004

 Oil Wellheads (heavy crude) 0.012

 Oil Wellheads (light crude) 3.879

11 Pipeline Pigging 0.000

12 Offshore Platforms, Gulf of Mexico 0.846

13 Offshore Platforms, Other U.S. Areas 0.010

 Total Vented Emissions 53.767 56.352

Fugitives Emissions:

14 Offshore Platforms, Gulf of Mexico 0.037 1.163

15 Offshore Platforms, Other U.S. Areas 0.000 0.009

16 Oil Wellheads (heavy crude) 0.001

17 Oil Wellheads (light crude) 1.280

18 Separators (heavy crude) 0.001 0.004

19 Separators (light crude) 0.557 2.062

20 Heater/Treaters (light crude) 0.586 1.644

21 Headers (heavy crude) 0.000 0.002

22 Headers (light crude) 0.335 6.250

23 Floating Roof Tanks 0.008 0.681

24 Compressors 0.102 0.011

25 Large Compressors 0.000 11.585

26 Sales Areas 0.081 0.080

27 Pipelines 0.000 0.725

28 Well Drilling 0.000

29 Battery Pumps 0.015

 Total Fugitive Emissions 3.003 24.216 4.232

Combustion Emissions:

30 Gas Engines 1.411 4.232

31 Heaters 0.001 0.001

32 Well Drilling 0.025 0.001

33 Flares 0.011

34 Offshore Platforms, Gulf of Mexico 0.317

35 Offshore Platforms, Other U.S. Areas 0.004

 Total Emissions from Combustion 1.769 4.234

Upsets: 

36 Platform Emergency Shutdowns 0.470 0.286

37 Pressure Relief Valves 0.007 0.007

38 Well Blowouts Offshore 0.011 0.001

39 Well Blowouts Onshore 0.084 0.008

 Total Emissions from Upsets 0.572 0.302

 Total CH4 Emissions, Bcf 59.111 85.104

1

The Radian estimates are updated using 1995 activity factors where available.

2

Estimates in this column are from API DR 140.

3

The current study separates high bleed and low bleed devices. The Radian estimate is for all pneumatic devices.
D-2

TABLE D-2

COMPARISON OF CRUDE TRANSPORTATION 

METHANE EMISSION ESTIMATES

Emission

Source No. Emission Source Current Emission 

Estimate (Bcf/yr)

Radian Emission 

Estimate1 (BCF/yr)

Other Emission 

Estimates2 (Bcf/yr)

Vented Emissions:

1 Tanks 0.105 0.188

2 Truck Loading 0.036 0.034 0.023

3 Marine Loading 0.098 1.428 0.312 0.677

4 Rail Loading 0.003 0.002 0.002

5 Pump Station Maintenance 0.000 0

6 Pipeling Pigging 0.017

 Total Vented Emissions 0.259 1.651

Fugitive Emissions:

7 Pump Stations 0.001 0.001

8 Pipelines 0.000 0

9 Floating Roof Tanks 0.049

 Total Fugitive Emissions 0.050 0.001

Combustion Emissions:

10 Pump Engine Drivers NA

11 Heaters NA

 Total Combustion Emissions 0.000 0

 Total CH4 Emissions, Bcf 0.309 1.65

1

The Radian estimates are updated using 1995 activity factors where available.

2

Estimates in the first column are from API DR 140. Estimates in the second column are from 

 API's Methane and Carbon Dioxide Emission Estimates from U.S. Petroleum Sources .
D-3

TABLE D-3

COMPARISON OF REFINERY 

METHANE EMISSION ESTIMATES

Emission

Source No. Emission Source Current Emission 

Estimate (Bcf/yr)

Radian Emission 

Estimate1 (BCF/yr)

Vented Emissions:

1 Tanks 0.013 0.103

2 System Blowdowns 0.698 0.684

3 Asphalt Blowing 0.435 0.167

 Total Vented Emissions 1.147 0.954

Fugitive Emissions:

4 Fuel Gas System 0.072 3.260

5 Floating Roof Tanks 0.0005

6 Wastewater Treating 0.010 0.009

7 Cooling Towers 0.012 0.012

 Total Fugitive Emissions 0.095 3.281

Combustion Emissions:

8 Atmospheric Distillation 0.018 0.018

9 Vacuum Distillation 0.008 0.009

10 Thermal Operations 0.004 0.004

11 Catalytic Cracking 0.009 0.009

12 Catallytic Reforming 0.009 0.009

13 Catalytic Hydrocracking 0.003 0.003

14 Hydrorefining 0.001 0.001

15 Hydrotreating 0.018 0.019

16 Alkylation/Polymerization 0.005 0.005

17 Aromatics/Isomeration 0.001 0.000

18 Lube Oil Processing 0.000 0.000

19 Engines 0.008 0.162

20 Flares 0.001 0.001

 Total Combustion Emissions 0.084 0.240

 Total CH4 Emissions, Bcf 1.325 4.475

1

The Radian estimates are updated using 1995 activity factors where available.
E-1

APPENDIX E

Summary of Total Hydrocarbon Emissions

from Gulf of Mexico OCS Oil and Gas Platforms

Emission Source Number of

Sources

Total Hydrocarbon

(tons/yr)

Equipment

Internal Combustion Engines

Diesel Reciprocating (<600 hp) 2,642 177.6

Natural Gas Turbine 346 848.6

Diesel Turbine 5 <1

Natural Gas Reciprocating 2,272 37,293

Diesel Large Bore (>600 hp) 48 8.1

External Combustion

Natural Gas Boilers 668 18.3

Diesel Boiler 1 <1

Flares

Ignited Flares 78 215

Non-ignited Flares 124 40,120

Vents 552 189,344

Crude Tanks 632 10,599

Diesel Tanks 1,101 47

Amine 5 --

Platform Fugitives 1,513 9,139

Total Platform Emissions 287,810

SUMMARY BY TYPE OF EMISSION

Fugitive 9,139

Vented 199,990

Combustion 78,810

TOTAL 287,810

Source: Gulf of Mexico Air Quality Study, Final Report, U.S. Department of Interior, Minerals Management

Service. August 1995.
APPENDIX F

EMISSION REDUCTIONS
F-1

TABLE F-1

OIL EXPLORATION & PRODUCTION METHANE EMISSIONS

OPTIONS FOR REDUCING EMISSIONS

Emission Reductions 

(Bcf/yr)

Emission

Source 

No.

Emission Source Emissions

(Bcf/yr) Economic Technical Economically Feasible Options for Emission Reductions

 Emission Reduction Options with Technical 

Potential

Vented Emissions:

1

 Oil Tanks 25.662 8.21 24.38

Add vapor recovery system or flare system 

(with or without gas boot) pressure 

vacuum valves Same as economic options, cool sales oil

2 Pneumatic Devices, High Bleed 19.855 4.87 17.54

Low bleed devices, low bleed 

attachments, instrument air system

3 Pneumatic Devices, Low Bleed 3.687 0.18 0.36 Directed I/M program Directed I/M program

4 Chemical Injection Pumps 2.831 0.00 0.71 Directed I/M program Use higher efficiency pumps, electric drives

5

 Vessel Blowdowns 0.016 0.00 0.00

Connect to an existing vapor recovery or 

flare system

Connect to vapor recovery or flare system, transfer 

gas with a portable compressor prior to blowdown

6

 Compressor Blowdowns 0.011 0.00 0.00

Connect to an existing vapor recovery or 

flare system

Connect to vapor recovery or flare system, transfer 

gas with a portable compressor prior to blowdown

7 Compressor Starts 0.024 0.00 0.00 None Switch to air or hydraulic starting fluid

8 Stripper Wells 0.815 0.00 0.16 None Close casing valves

9 Well Completion Venting 0.006 0.00 0.00 Operating procedures to minimize venting Operating procedures to minimize venting

10 Well Workovers 0.004 0.00 0.00 Operating procedures to minimize venting Operating procedures to minimize venting

11 Pipeline Pigging 0.000 0.00 0.00 recovery station Transfer ejected oil with pump

12

 Offshore Platforms, Gulf of Mexico 0.846 0.04 0.08 Directed I/M program

Use electric drives for venting devices, install gas 

collection and incineration systems

13 Offshore Platforms, Other U.S. Areas 0.010 0.00 0.00 Use electric drives for venting devices Install gas collection and incineration systems

 Total Vented Emissions 53.767 13.31 43.23

Fugitives Emissions (Leaks):

14 Offshore Platforms, Gulf of Mexico 0.037 0.009 0.018 Directed I/M program Add leak collection & incineration system

15 Offshore Platforms, Other U.S. Areas 0.000 0.000 0.000 Directed I/M program Add leak collection & incineration system

16 Oil Wellheads (heavy crude) 0.001 0.000 0.000 Directed I/M program Directed I/M program

17 Oil Wellheads (light crude) 1.280 0.320 0.641 Directed I/M program Directed I/M program

18 Separators (heavy crude) 0.001 0.000 0.000 Directed I/M program Directed I/M program

19 Separators (light crude) 0.557 0.139 0.278 Directed I/M program Directed I/M program

20 Heater/Treaters (light crude) 0.586 0.132 0.264 Directed I/M program Directed I/M program

21 Headers (heavy crude) 0.000 0.000 0.000 Directed I/M program Directed I/M program

22 Headers (light crude) 0.335 0.084 0.167 Directed I/M program Directed I/M program

23 Floating Roof Tanks 0.008 0.000 0.004 Directed I/M program Upgrade guide poles and their seals, upgrade 

24 Compressors 0.102 0.071 0.082 Directed I/M program Directed I/M program, upgrade seals on rods and 

25 Large Compressors 0.000 0.000 0.000 Directed I/M program shafts

26

 Sales Areas 0.081 0.000 0.049 None

Add vapor recovery system or flare system at 

loading docks, use submerged loading

27 Pipelines 0.000 0.000 0.000 Directed I/M program More extensive use of directed I/M programs

28 Well Drilling 0.000 0.000 0.000 Procedures to minimize leakage

29 Battery Pumps 0.015 0.004 0.005

Directed I/M program, upgrade seals on 

rods and shafts

 Total Fugitive Emissions 3.003 0.761 1.509

Combustion Emissions:

30

 Gas Engines 1.411 0.071 0.141 Directed I/M program

engines for efficient combustion, add catalytic 

converters

31 Heaters 0.001 0.000 0.000 Replace old burners with more efficient Use waste heat exchangers to reduce fuel use

32

 Well Drilling 0.025 0.000 0.002 Directed I/M program

Use lean burn engines or electric motors, modify 

engines for efficient combustion, add catalytic 

converters

33 Flares 0.011 0.000 0.001 Reduce gas flow to pilots Replace flare pilots with igniters

34 Offshore Platforms, Gulf of Mexico 0.317 0.000 0.032 Directed I/M program

Modify engines, use turbines, replace flare pilots 

with igniters

35 Offshore Platforms, Other U.S. Areas 0.004 0.000 0.001 Directed I/M program Modify engines, use turbines, replace flare pilots 

 Total Emissions from Combustion 1.769 0.071 0.177

Upsets: 

36 Platform Emergency Shutdowns 0.470 0.000 0.000 None None

37 Pressure Relief Valves 0.007 0.000 0.000 Directed I/M program, blowout disks Directed I/M program, add blowout disks

38 Well Blowouts Offshore 0.011 0.000 0.000 None preventers

39 Well Blowouts Onshore 0.084 0.000 0.000 Increase use of blowout preventers preventers

 Total Emissions from Upsets 0.572 0.000 0.000

 Total CH4 Emissions, Bcf 59.11 14.14 44.92
F-2

TABLE F-2

CRUDE TRANSPORTATION METHANE EMISSIONS

OPTIONS FOR REDUCING EMISSIONS

Emission Reductions

(Bcf/yr)

Emission

Source No. Emission Source Emissions(Bcf/yr) Economic Technical Economically Feasible Options for Emission Reductions

 Emission Reduction Options with 

Technical Potential

Vented Emissions:

1 Tanks 0.105 0.000 0.095 None

Floating roof tanks, vapor recovery 

system, pressure-vacuum valves

2 Truck Loading 0.036 0.000 0.022 Use submerged loading

Use submerged loading, add vapor 

recovery system

3 Marine Loading 0.098 0.000 0.059 Use submerged loading

Use submerged loading, add vapor 

recovery system

4 Rail Loading 0.003 0.000 0.002 Use submerged loading

Use submerged loading, add vapor 

recovery system

5 Pump Station Maintenance 0.000 0.000 0.000 Directed I/M program Install pump system to transfer oil contents

6 Pipeling Pigging 0.017 0.000 0.000

Minimize oil volume ejected at 

recovery station Install pump system to transfer ejected oil

 Total Vented Emissions 0.259 0.000 0.177

Fugitive Emissions:

7 Pump Stations 0.001 0.000 0.000 Directed I/M program Upgrade pump seals

8 Pipelines 0.000 0.000 0.000 Directed I/M program Inspect lines with leak detecting pigs

9 Floating Roof Tanks 0.049 0.000 0.000 Directed I/M program

Upgrade guide poles and their seals, 

upgrade perimeter seals

 Total Fugitive Emissions 0.050 0.000 0.000

Combustion Emissions:

10 Pump Engine Drivers NA 0.000 0.000

Modify engines, add catalytic 

converters, use electric motors

Use lean burn engines or electric motors, 

modify engines for efficient combustion, 

add catalytic converters

11 Heaters NA 0.000 0.000 Directed I/M program

Replace burners with higher efficiency 

models

 Total Combustion Emissions 0.000 0.000 0.000

 Total CH4 Emissions, Bcf 0.309 0.000 0.177
F-3

TABLE F-3

REFINERY METHANE EMISSIONS

OPTIONS FOR REDUCING EMISSIONS

Emission Reductions

(Bcf/yr)

Emission

Source No. Emission Source Emissions

(Bcf/yr) Economic Technical

Economically Feasible 

Options for Emission 

Reductions

 Emission Reduction Options 

with Technical Potential

Vented Emissions:

1 Fixed Roof Tanks 0.013 0.000 0.007 None

Add vapor recovery system, flare 

system, activated charcoal, 

pressure/vacuum valves

2 System Blowdowns 0.698 0.000 0.349

Attach to existing refinery 

blowdown system

Connect to vapor recovery or flare 

system, transfer gas with a 

portable compressor prior to 

blowdown

3 Asphalt Blowing 0.435 0.000 0.218 None

Use vapor scrubber, vapor 

incinerator

 Total Vented Emissions 1.147 0.000 0.573

Fugitive Emissions:

4 Fuel Gas System 0.072 0.000 0.000 Directed I/M program

5 Floating Roof Tanks 0.000 0.000 0.000 Directed I/M program

Upgrade guide poles and their 

seals, upgrade perimeter seals

6 Wastewater Systems 0.010 0.000 0.000

Directed I/M program to 

reduce spills

Reduce leaks in oil-to-water heat 

exchangers, install vapor recovery 

system

7 Cooling Towers 0.012 0.000 0.000 None

Reduce oil-to-water leaks in heat 

exchangers

 Total Fugitive Emissions 0.095 0.000 0.000

Combustion Emissions:

8 Atmospheric Distillation 0.018 0.002 0.002

Maintain proper burner 

adjustment

Use high efficiency burners, air 

preheater, computer controls

9 Vacuum Distillation 0.008 0.001 0.001

Maintain proper burner 

adjustment

Use high efficiency burners, air 

preheater, computer controls

10 Thermal Operations 0.004 0.000 0.000

Maintain proper burner 

adjustment

Use high efficiency burners, air 

preheater, computer controls

11 Catalytic Cracking 0.009 0.001 0.001

Maintain proper burner 

adjustment

Use high efficiency burners, air 

preheater, computer controls

12 Catalytic Reforming 0.009 0.001 0.001

Maintain proper burner 

adjustment

Use high efficiency burners, air 

preheater, computer controls

13 Catalytic Hydrocracking 0.003 0.000 0.000

Maintain proper burner 

adjustment

Use high efficiency burners, air 

preheater, computer controls

14 Hydrorefining 0.001 0.000 0.000

Maintain proper burner 

adjustment

Use high efficiency burners, air 

preheater, computer controls

15 Hydrotreating 0.018 0.002 0.002

Maintain proper burner 

adjustment

Use high efficiency burners, air 

preheater, computer controls

16 Alkylation/Polymerization 0.005 0.000 0.000

Maintain proper burner 

adjustment

Use high efficiency burners, air 

preheater, computer controls

17 Aromatics/Isomeration 0.001 0.000 0.000

Maintain proper burner 

adjustment

Use high efficiency burners, air 

preheater, computer controls

18 Lube Oil Processing 0.000 0.000 0.000

Maintain proper burner 

adjustment

Use high efficiency burners, air 

preheater, computer controls

19 Engines 0.008 0.000 0.001 Directed I/M program

Install electric motors, gas 

turbines; for reciprocating 

compressors modify engines, add 

catalytic converters, use lean burn 

engines

20 Flares 0.001 0.000 0.000 Reduce gas flow to pilots

Use high efficiency burners, 

replace pilots with igniters

 Total Combustion Emissions 0.084 0.008 0.008

 Total CH4 Emissions, Bcf 1.325 0.008 0.582