# Petroleum and Natural Gas Systems

201 2 Data Summary

Greenhouse Gas Reporting Program



## Introduction

In October 2013, the U.S. Environmental P rotection Agency (EPA) released 2012 greenhouse gas (GHG)

data for P etroleum and N atural G as S ystems 1 collected under the Greenhouse Gas Reporting Program

(GHGRP). The GHGRP, which was required by Congress in the FY2008 Consolidated Appropriations

Act, requires facilities to report data from large emission sources across a range of industry sectors, as

we ll as supplie rs of certain greenhouse gases and products that would emit GHGs if released or

combusted.

The data show 201 2 GHG emissions from over 2

, 0 00 facilities conducting P etroleum and N atural G as

S ystems activities, such as production, processing, t ransmission, and distribution. In total, these facilities

accounted for GHG emissions of 217 million metric tons of carbon dioxide equivalent (CO 2 e)

. This is an

increase of 3 % compared to 2011 GHG emissions from this sector.

The data represent a significant step forward in better understanding GHG emissions from Petroleum and

Natural Gas Systems

. The EPA is working to improve the quality of data from this sector and expects that

the GHGRP will be an important tool for the Agen cy and the public to analyze emissions, identify

opportunities for improving the data, and understand emissions trends.

When reviewing this data and comparing it to other data sets or published literature, it is important to

understand the GHGRP reporting requirements and the impacts of these requ irements on the reported

data. Facilities used uniform methods prescribed by the EPA to calculate GHG emissions, such as direct

measurement, engineering calculations, or emission factors derived from direct measur ement. In some

cases, facilities had a choice of calculation methods for an emission source. In order to provide facilities

with time to adjust to the requirements of the GHGRP, the EPA made available the optional use of Best

Available Monitoring Methods ( BAMM) for unique or unusual circumstances. Where a facility used

BAMM, it was required to follow emission calculations specified by the EPA, but was allowed to use

alternative methods for determining inputs to calculate emissions.

Petroleum and N atural G as S ystems is one of the more complex source categories within the GHGRP

because of the number of emission sources covered, technical complexity, and variability across facilities.

It is expected that there can be differences in reported emissions from one facility to another. I t is not

uncommon for a handful of facilities to contribute the majority of the national reported emissions total for

a specific emission source

. As described in more detail below, there is a reporting threshold and the data

does not cover certain emission sources, and therefore the data does not represent the entire universe of

emissions from Petroleum and Natural Gas Systems

. There is also variability in the methods used which

could impact cross

- segment, cross

- sour ce, or cross

- facility comparisons. Emission changes may not

solely be due to the change in the number of facilities , and could be the result of a number of factors

. It is

important to be a ware of these limitations and differences when using this data, part icularly when

attempting to draw broad conclusions about emissions from this sector.

1 The implementing regulations of the Petroleum and Natural Gas Systems source category of the GHGRP are located at 40 CFR

Part 98 Subpart W.

October 2013 1

## Petroleum and Natural Gas Systems in the GHG Reporting Program

The Petroleum and Natural Gas Systems source category of the GHGRP requires reporting from the

following eight industry segments, which account for most of the largest emission sources :

• Onshore Production: P roduction of petroleum and natural gas associated with onshore production

wells and related equipment.

• Offshore Production: Production of petroleum and natural gas from offshore production

platforms.

• Natural Gas Processing: Processing of field quality gas to produce pipeline quality natural gas.

• Natural Gas Transmission: Compressor station s used to transfer natural gas through transmission

pipelines.

• Unde rground Natural Gas Storage: Facilities that store natural gas in underground formations.

• Natural Gas Distribution: D istribution systems that deliver natural gas to customers

.

• Liquified Natural Gas ( LNG ) Import/Export: Liquified Natural Gas import and export terminals.

• LNG Storage: Liquified Natural Gas storage equipment.

The diagram below illustrates the segments of the Petroleum and N atural G as S ystems source category
that are required to report under t he GHGRP

.

Other segments of the petroleum and natural gas industry are covered by the GHGRP, but not included in

the Petroleum and Natural Gas Systems source category, such as : Petroleum Refineries (Subpart Y)

, Figure adapted from AGA and Natural Gas STAR Production and Processing

1. Onshore Production

2a, 2b. Offshore Production

3. Gathering and Boosting (not

covered by Subpart W)

4. Natural Gas Processing

Transmission and Storage

5. Natural Gas Transmission

6. Underground Natural Gas

Storage

7. LNG Storage

8. LNG Import

- Export

Distribution

9, 10. Natural Gas Distribution

Not Covere d

• Emissions below 25,000 metric ton CO2e threshold

• Process emissions from gathering and boosting

• Vented emissions from hydraulic fracturing of oil wells

• Process emissions from transmission lines between

compressor stations

October 2013 2Petrochemical P roduction (Subpart X), S uppliers of Petroleum Products (Subpart MM) , and Suppliers of

Natural Gas and Natural Gas Liquids (Subpart NN).

The GHGRP also includes reporting of stationary fuel combustion emissions from facilities that are

associated with the petroleum and natural ga s industry, but that do not report process emissions from any

of the above source categories , such as certain facilities that have a North American Industry

Classification System (NAICS) code beginning with 211 ( the general NAICS for oil and gas extraction )

. The se facilities are referred to as “Other Oil and Gas Combustion” in this document.

The GHGRP covers a subset of national emissions from Petroleum and Natural Gas Systems

. A facility in

the Petroleum and Natural Gas Systems source category is required to submit annual reports if total

emissions are 25,000 metric tons carbon dioxide equivalent ( CO 2 e ) or more . In addition, the Petroleum

and Natural Gas Systems source category does not currently include process emissions from the gathering

and boosting se gment. It also does not include vented emissi ons from hydraulic fracturing of oil wells. In

addition, the GHGRP does not cover process emissions from transmission lines between compressor

stations. The petroleum and natural gas industry is growi ng and chan ging rapidly and there could be other

sources of emissions that are not currently covered. The Agency will continue to review regulatory

requirements to ensure the reporting of high quality data.

The EPA has a multi

- step data verification process, including automatic checks during data

- entry,
statistical analyses on completed reports, and staff review of the reported data. Based on the results of the

verification process, the EPA follows up with facili ties to resolve mistakes that may have occurred. In

addition, because of the nature of the petroleum and natural gas industry, there can be variation in

emissions from facility to facility.

In order to provide facilities with time to adjust to the require ments of the GHGRP, the EPA made

available the optional use of BAMM for unique or unusual circumstances. Where a facility used BAMM,

it was required to follow emission calculations specified by the EPA, but was allowed to use alternative

methods for determining inputs to calculate emissions. Inputs are the values used by facilities to calculate

equation outputs . Examples of BAMM include m onitoring methods used by the facility that do not meet

th e specifications of 40 CFR Part 98 Subpart W, supplier data, engineering calculations, and o ther

company records. F acilities used BAMM in different ways and for different parameters depending on

their unique or unusual circumstances.

In 2012 , facilities were required to receive approval from the EPA prior to using BAMM for the

Petroleum and Natural Gas Systems source category and th ese facilities were required to specify in their

GHG annual reports when BAMM was used for an emission source. In 2012, 33% of facilities in the

petroleum and natural gas source category reported using BAMM. The largest number of facilities in

Petroleum an d Natural Gas Systems was in the onshore production, natural gas transmission , and natu ral

gas processing segments, and t hese three segments also represented the segments with the largest

frequency of BAMM use . The onshore production segment had 44% of fac ilities reporting BAMM use,

natural gas transmission had 46% of facilities reporting BAMM use, and natural gas processing had 53%

of facilities reporting BAMM use . The remaining segments had a lower n umber of facilities and

proportionally lower BAMM use. F acilities in the other oil and gas combustion category we re not
permitted to use BAMM. For purposes of this document, f acilities are recorded as using BAMM if they

indicated the use of BAMM for any piece of equipment from any emission source

.

October 2013 3

## Report ed GHG Emissions from Petroleum and Natural Gas Systems

The following section provides information on reported GHG emissions by industry segment, by

greenhouse gas, by combustion and process emissions, and by emission source for the 2012 calendar year

.

Reported Emissions by Industry Segment

The 2012 calendar year was the second year that GHG e missions from Petroleum and Natural Gas

S ystem s activities were required to be collected. A nnual reports were due to the EPA by April 1, 201 3

. The EPA received reports from over 2,000 facilities 2 with Petroleum and Natural Gas Systems activities,

with total reported GHG emissions of 217 Million Metric Tons (MMT) CO 2 e.

The largest industry segment in terms of reported GHG emissions wa s onshore production, with a total of

88 MMT CO 2 e, followed by natural gas processing, with reported emissions of 60 MMT CO 2 e

. Other oil

and gas combustion accounted for 24 MMT CO 2 e . The next largest segment was natural gas

transmission, with reported emis sions of 23 MMT CO 2 e

. R eported emissions from natural gas

distribution totaled 13 MMT CO 2 e . The rem aining segments accounted for total reported emissions of

less than 10 MMT CO 2 e

.

2 In general, a “facility” for purposes of the GHGRP means all co

- located emission sources that are commonly owne d or

operated. However, the GHGRP has developed specialized facility definitions for natural gas distribution and onshore

production. For natural gas distribution, the “facility” is a local distribution company as regulated by a single state publi c utility

commission. For onshore production, the “facility” includes all emissions associated with wells owned or operated by a single

company in a specific hydrocarbon producing basin (as defined by the geologic provinces published by the American Association

of Petroleum Geologists). 21 17 212 210 219

381 153 32 250 184 102 278

0 100 200 300 400 500 600 Other Oil and Gas Combustion LNG Storage LNG Import/Export Natural Gas Distribution Underground Natural Gas Storage Natural Gas Transmission

Natural Gas Processing

Offshore Production Onshore Production

Facility Count 

## 2012 BAMM Use

BAMM Used

No BAMM

October 2013 42012 Reported Emissions by Industry Segment

Segment Number of Facilities Reported Emissions

(Million Metric Tons CO 2 e)

Onshore Production 49 7 88

Offshore Production 106 7

Natural Gas Processing 394 60

Natural Gas Transmission 46 2 23

Underground Natural Gas Storage 49 1

Natural Gas Distribution 174 13

LNG Import/Export 8 1

LNG Storage 4 < 1

Other Oil and Gas Combustion 3 81 24

Total 2,05 8 217

Note: Total number of facilities is smaller than the sum of facilities from each segment because some facilities

reported under multiple segments. A facility is included in the count of number of facilities if it reported non

- zero emissions under any segment.

Reported Emissions by Greenhouse Gas

For all segments combined, carbon dioxide ( CO 2 ) emissions accounted for 147 MMT CO 2 e of reported

emissions and methane ( CH 4 ) emissions accounted for 70 MMT CO 2 e of reported emissions. E missions

from onshore production were primarily methane while emissions from natural gas transmission and

natural gas processing were primarily carbon dioxide

.

Repo rted Combustion and Process Emissions

Each segment of Petroleum and Natural Gas Systems has unique emission sources. Emissions may result

from the combustion of fossil fuels or from process sources that result in the direct emi ssion of GHGs.

Reported combustion emissions in Petroleum and Natural Gas Systems total ed 111 MMT CO 2 e and

reported p rocess emissions total ed 106 MMT CO 2 e

. The majority of combustion emissions were reported

by natural gas processing, natural gas transmission, onshore production

, and other oil and gas

combustion . The majority of process emissions were reported by onshore production, natural gas

processing , and natural gas distribution. 24 19 56 5 40

13 4 4 48

0 20 40 60 80 100 Other Oil and Gas Combustion LNG Storage LNG Import/Export Natural Gas Distribution Underground Natural Gas Storage Natural Gas Transmission

Natural Gas Processing

Offshore Production Onshore Production

Emissions, MMT CO
2 e 

## 2012 Reported Emissions by Greenhouse Gas

CO2 Emissions

CH4 Emissions

N2O Emissions

October 2013 5Process emissions may be further classified as vented emissions, equipment leaks, and flaring

. Vented

emissions totaled 57 MMT CO 2 e, equipment leaks totaled 27 MMT CO 2 e, and flaring emissions totaled

22 MMT CO 2 e. Vented emissions in onshore production were primarily methane while vented emissions

in natural gas processing were primarily carbon dio xide . Equipment leak emissions were primarily

methane and flaring emissions were primarily carbon dioxide

.

Reported Process Emission Source s

The Petroleum and Natural Gas Systems source category ( Subpart W ) specifies the methods that facilities

must use to calculate emissions from applicable sources.

The top reported process emission source in Petroleum and Natural Gas Systems wa s pneumatic devices

with repor ted emissions of 18.4 MMT CO 2 e

. Natural gas pneu matic devices are automated flow control 24 19 37 5 24

13 4 23 2 64

0 20 40 60 80 100 Other Oil and Gas Combustion LNG Storage LNG Import/Export Natural Gas Distribution Underground Natural Gas Storage Natural Gas Transmission Natural Gas Processing

Offshore Production Onshore Production

Emissions, MMT CO 2 e 

## 2012 Reported Combustion and Process Emissions

Combustion Emissions

Process Emissions

1 17 39

13 2 2 9

5 17

0 10 20 30 40 50 60 70 LNG Storage LNG Import/Export Natural Gas Distribution Underground Natural Gas Storage Natural Gas Transmission Natural Gas Processing

Offshore Production Onshore Production

Emissions, MMT CO 2 e



## 2012 Reported Process Emissions by Vented Emissions,

Equipment Leaks, and Flaring

Vented Emissions

Equipment Leaks

Flaring

October 2013 6devices powered by pressurized natural gas and used for maintaining a process condition such as liquid

level, pressure, delta

- pressure and temperature. Emissions from natural gas pneumatic devices are

calculated by applying a facility determined population count to a default emission factor.

Acid gas removal units we re the top reported contributor to CO 2 emissions from non

- combustion sources

and the top reported source of process emissions in the natural gas proces sing segment (15.4 MMT

CO 2 e ) . Acid gas removal units are process units that separate hydrogen sulfide, carbon dioxide or both

hydrogen sulfide and carbon dioxide from sour natural gas using absorbents or membrane separators. The

CO 2 emitted from acid gas r emoval units is a part of the gas stream that is produced at the wellhead. 3 2 8 7 15

1 1 1 2 2 3

3 4 3 6 8 7 1 8 2 18

0 5 10 15 20 Enhanced Oil Recovery Pumps Enhanced Oil Recovery Liquids Transmission Tanks Gas Well Compl. and Work. without HF Well Testing Distribution M

- R Stations Dehydrators Offshore Sources Blowdown Vent Stacks Centrifugal Compressors Pneumatic Pumps Reciprocating Compressors Distribution Services

Atmospheric Tanks

Liquids Unloading Distribution Mains Gas Well Compl. and Work. with HF Other Flare Stacks Misc Equipment Leaks Associated Gas Venting and Flaring Acid Gas Removal Units Pneumatic Devices

Emissions, MMT CO
2 e 

## 2012 Reported Process Emission Sources

CO2 Emissions

CH4 Emissions

N2O Emissions

October 2013 7Natural gas processing creates pipeline quality natural gas and removal of CO 2 from the gas streams is a

key step in this process.

Associated gas and other flare stacks we re the to p reported sources of process emissions from flaring for

Petroleum and Natural Gas Systems . Associated gas is natural gas that is produced out of petroleum

wells

, but due to proximity and pipeline limitations

, may be vented or flared instead of being proce ssed.

The other flare stacks category is a catch

- all category intended to c over all flares not otherwise reported in

the onshore production and natural gas processing segments . For example, flaring for gas well

completions and workovers with hydraulic frac turing would be reported under the gas well completions

and workovers with hydraulic fracturing emission source rather than the other flare stacks emission

source . The majority of emissions from other flare stacks were from natural gas processing and onshore

production.



## Reported GHG Emissions by Industry Segment and Source

The following section provides information on reported GHG emissions organized by industry segment

. For each segment, the top reported emission sources are presented, as well as additional information on

emission sources for which stakeholders have expressed interest

. Over time , we hope to provide

additional information on other emission sources of interest to stakeholders

.

Onshore P r oduction

The EPA received annual reports from 49 7 facilities in the onshore production segment and reported

emissions totaled 88.0 MMT CO 2 e. Methane emissions totaled 48.2 MMT CO 2 e and carbon dioxide

emissions totaled 39.7 MMT CO 2 e. The top reported emission sources for onshore production were

generally consistent with the top reported emission sources for Petroleum and Natural Gas Systems

. Combustion equipment ( 24.3 MMT CO 2 e) and p neumatic devices ( 18.1 MMT CO 2 e) were the top
reported emission sources, follow ed by associated gas venting and flaring ( 9.0 MMT CO 2 e )

, gas well

completions and workovers with hydraulic fracturing (8.1 MMT CO 2 e), miscellaneous equipment leaks

( 7.7 MMT CO 2 e ) , and liquids unloading ( 5.8 MMT CO 2 e )

.

4 3 2 7 24

3 3 6 8 7 2 18

0 5 10 15 20 25 30 Pneumatic Pumps Other Flare Stacks Atmospheric Tanks

Liquids Unloading Misc Equipment Leaks Gas Well Compl. and Work. with HF Associated Gas Venting and Flaring Pneumatic Devices Combustion Equipment

Emissions, MMT CO
2 e 

## 2012 Onshore Production: Top Reported Emission Sources

CO2 Emissions

CH4 Emissions

N2O Emissions

October 2013 8The basins with the top reported emissions were the Gulf Coast Basin with 12.2 MMT CO 2 e , the Permian

Basin with 9.3 MMT CO 2 e, the Williston Basin with 9.3 MMT CO 2 e, the San Juan Basin with 9.1 MMT

CO 2 e , and the Anadarko Basin with 9.1 MMT CO 2 e.

Emission Source in Detail : Gas Well Completions and Workovers with Hydraulic Fracturing

The data reported to the GHGRP includes gas well completions and worko vers with hydraulic fracturing.

In the hydraulic fracturing process, a mixture of water, chemicals and a “proppant” (usually sand) is

pumped into a well at high pressures to fracture rock and allow natural gas to escape. During a stage of

well completion known as “flowback,” fracturing fluids, water, and reservoir gas come to the surface at a

high velocity and volume. Specialized equipm ent can be employed that separates natural gas from the

backflow, known as a “ Reduced Emission Completion ” (REC) or “green completion”

.

The GHGRP provides facilities options for calculating emissions for gas well completions and workovers

with hydraulic fracturing

. F acilities may measure or estimate t he backflow ra te in order to report
emissions using an engineering calculation. Alternatively, the backflow vent or flare volume may be

measured directly.

The EPA received information on gas well completions and workovers with hydraulic fracturing from

208 onshore production facilities. Of these fac ilities 85 reported using BAMM to calculate emissions. The

total reported emissions for gas well completions and workovers with hydraulic f racturing were 8.1 MMT

C O 2 e

. Reported CO 2 emissions were 1.5 MMT CO 2 e and reported CH 4 emissions were 6.6 MMT CO 2 e

.

Emissions were reported by GHG for flaring and venting activities. Facilities were also required to report

the total count of completions and workovers. In addition, facilities provided a count of the number of

completions or workovers employing purposely designed equipment that separates natural g as from the

backflow (RECs)

.

The table below shows reported activity data and emissions nationally for gas well completions and

workovers with hydraulic fracturing . Data collected by the GHGRP also allows for co unty

- level analysis

of reported data. As noted earlier, when reviewing the data it is important to be aware of the GHGRP

reporting requirements and the impacts of these requirements on the reported data. For example, the

GHGRP covers a subset of national emissions and there is variability in the methods used in calculating

emissions and use of BAMM

.

2012 Reported Emissions from Gas Well Completions and Workovers with Hydraulic Fracturing

Activity Total

Number Number

of RECs Reported

Venting CO 2

Emissions

(MT CO 2 e) Reported

Venting CH 4

Emissions

(MT CO 2 e) Reported

Flaring CO 2

Emissions

(MT CO 2 e) Reported

Flaring CH 4

Emissions

(MT CO 2 e) Total Reported

Emissions

(MT CO 2 e)

Gas Well

Completions

with Hydraulic

Fracturing 9,466 5,059 9,078 6,225,393 1,478,340 176,052 7,889,716

Gas Well

Workovers with

Hydraulic

Fracturing 1,198 147 985 238,267 17,758 2,964 259,988

Total 10,664 5,206 10,063 6,463,659 1,496,098 179,016 8,149,704

October 2013 9Emission Source in Detail : Liquids Unloading

In mature gas wells, the accumulation of fluids in the well can impede and sometimes halt gas production.

Liquids unloading is the process by which liquids are removed from the well through venting, the use of

plunger lift systems, or other remedial treatments. The liquids unloading source within the GHGRP

covers emissions from facilities that have wells that are venting or using plunger lifts.

A total of 251 facilities reported emissions for well venting for liquids unloading in onshore production.

Of these facilities 120 reported using BAMM to calculate emissions. Total reported emissions for liquids

unloading were 5.8 MMT CO 2 e. A total of 0.04 MMT CO 2 e reported emissions were from carbon

dioxide and 5.8 MMT CO 2 e were from methane

.

Facilities were given the option between three methods for calculating emissions from liquids unloading.

The first calculation method involved usin g a representative well sample to calculate emissions for both

wells with and without plunger lifts. The second and third calculation methods provided engineering

equations for wells with plunger lifts and without plunger lifts . The following table shows t otal activity

count and reported emissions for the different calculation methods.

2012 Reported Emissions from Liquids Unloading

Calculation Method Number of

Wells Venting

During Liquids

Unloading Number of

Wells Equipped

With Plunger

Lifts Reported

CO 2 Emissions

(MT CO 2 e) Reported

CH 4 Emissions

(MT CO 2 e) Total Reported

Emissions

(MT CO 2 e)

Method 1: Direct

Measurement of

Representative Well Sample 10,024 7,149 29,767 2,362,423 2,392,190

Method 2: Engineering

Calculation for Wells without

Plunger Lifts 23,536 0 6,523 1,503,451 1,509,974

Method 3: Engineering

Calculation for Wells with

Plunger Lifts 25,103 25,103 6,400 1,938,071 1,944,471

Total 58,663 32,252 42,689 5,803,946 5,846,634

Offshore Pr oduction

The EPA received annual reports from 106 facilities in the offshore production segment and reported

emissions totaled 6.5 MMT CO 2 e

. Methane emissions totaled 1.3 MMT CO 2 e and carbon dioxide

emissions totaled 5.2 MMT CO 2 e. For offshore production, facilities calculate process emissions using

requirements that were established by the Bureau of Ocean Energy Management (BOEM). In addition,

the GHGRP collects data on combustion emissions. The full list of process emission source s is extensive,

but can generally be categorized into vented emissions, flaring and equipment leaks. The top reported

source of emissions for offshore production was from combustion ( 4.7 MMT CO 2 e ) , followed by venting

( 0.9 MMT CO 2 e ) , flaring ( 0.5 MMT CO 2 e )

, and equipment leaks ( 0.4 MMT CO 2 e )

.

October 2013 10Natural Gas Pro cessing

The EPA received annual reports from 394 facilities in the natural gas processing segment and reported

emissions totaled 60.1 MMT CO 2 e. Methane emissions totaled 3.5 MMT CO 2 e and carbon dioxide

emissions totaled 56.3 MMT CO 2 e. T he top reported emission sources were combust ion equipment ( 36.7

MMT CO 2 e), a cid gas removal units ( 15.3 MMT CO 2 e), and other flare stacks ( 4.4 MMT CO 2 e )

. Emissions from the three top reported sources were primarily in the for m of CO 2

. Emissions from

compressors were the top reported source of methane emissions, but reported emissions from

reciprocating compressors ( 1.2 MMT CO 2 e ) and centrifugal compressors ( 0.8 MMT CO 2 e ) were small er

than the t hree top reported sources from this segment

.

Natural Gas Transmission

The EPA received annual reports from 46 2 facilities in the na tural gas transmission segment and reported

emissions totaled 33.0 MMT CO 2 e. Methane emissions totaled 3.7 MMT CO 2 e and carbon dioxide

emissions totaled 19.2 MMT CO 2 e. C ombustion emissions ( 19.2 MMT CO 2 e ) were larger than process

emissions

. Following combustion equipment, the top reported emission sources were reciprocating

compressors ( 1.6 MMT CO 2 e ) and blowdown vent stacks ( 1.1 MMT CO 2 e ). 5

1

0 1 2 3 4 5 Equipment Leaks Flaring Venting Combustion

Emissions, MMT CO
2 e 

## 2012 Offshore Production: Top Reported Emission Sources

CO2 Emissions

CH4 Emissions

N2O Emissions

4 15 37

0 5 10 15 20 25 30 35 40 Misc Equipment Leaks Dehydrators Centrifugal Compressors

Blowdown Vent Stacks Reciprocating Compressors Other Flare Stacks Acid Gas Removal Units Combustion Equipment

Emissions, MMT CO
2 e 

## 2012 Natural Gas Processing: Top Reported Emission Sources

CO2 Emissions

CH4 Emissions

N2O Emissions

October 2013 11Underground Natural Gas Storage

The EPA received annual reports from 49 facilities in the underground na tural gas storage segment and

reported emissions totaled 1.3 MMT CO 2 e. Methane emissions totaled 0. 5 MMT CO 2 e and carbon

dioxide emissions totaled 0. 9 MMT CO 2 e. Combustion equipment ( 0.9 MMT CO 2 e ) was the top reported

source of emissions for underground natural gas storage, followed by reciprocating compressors ( 0.2

MMT CO 2 e ).

Emission Source in Detail: Compressors

Compr essors are used in the production, processing, transmission, and storage segments to keep pipelines

at a high enough pressure so natural gas will continue flowing through the pipelines. The two primary

types of compressors in use in the petroleum and natur al gas industry are reciprocating compressors and

centrifugal compressors.

Compressors are a large source of combustion emissions in Petroleum and Natural Gas Systems, and

combustion emissions for Petroleum and Natural Gas Systems were presented earlier i n this document. 19

1 2

0 5 10 15 20 25 Transmission Tanks Pneumatic Devices Misc Equipment Leaks Centrifugal Compressors

Blowdown Vent Stacks Reciprocating Compressors Combustion Equipment

Emissions, MMT CO
2 e 

## 2012 Natural Gas Transmission: Top Reported Emission

Sources

CO2 Emissions

CH4 Emissions

N2O Emissions

0.0 0.2 0.4 0.6 0.8 1.0 Misc Equipment Leaks Pneumatic Devices Centrifugal Compressors Reciprocating Compressors Combustion Equipment

Emissions, MMT CO
2 e 

## 2012 Underground Natural Gas Storage: Top Reported

Emission Sources

CO2 Emissions

CH4 Emissions

N2O Emissions

October 2013 12Compressors can also be a source of process emissions. The primary source of process emissions from

compressors are from leaks in rod packing (reciprocating compressors), emissions from wet or dry seals

(centrifugal compressors), emissions from blowdown vents, and emissions from isolation valve leakage.

The source of emissions may vary based on the mode of operation that the compressor is in. A

compressor in operating mode may have different emissions from a compressor in a shutdown

depress urized mode. Because the emissions are from seal leakage, even compressors of the same

manufacture can have different emissions based on the quality of the compressor seals. Emissions can be

mitigated through rigorous maintenance practices and leak surveys , routing emissions to a flare, or

capturing emissions.

Total reported compressor emissions from all industry segments were 5.1 MMT CO 2 e. Reported carbon

dioxide emissions were 0.2 MMT CO 2 e and reported methane emissions were 4.9 MMT CO 2 e. The

calculation method varied by industry segment. Emissions from compressors in onshore production were

calculated by using population counts multiplied by an emission factor and accounted for 0.9 MMT CO 2 e of reported emissions. Emissions from compress ors in the other industry segment were calculated by the

use of direct measurement.

The table below shows activity data and emissions for reciprocating compressors by industry segment

(excluding onshore production which used population counts). The EPA r eceived data from 4,493

reciprocating compressors, including 2,149 reciprocating compressors in natural gas processing, 2,008

reciprocating compressors in natural gas transmission, and 309 reciprocating compressors in underground

natural gas storage. Of th ese reciprocating compressors, 1,854 reported using BAMM to calculate

emissions, including 993 in natural gas processing, 790 in natural gas transmission, and 64 in

underground natural gas storage.

2012 Reported Process Emissions from Reciprocating Compressors

Industry Segment Total Number of

Reciprocating

Compressors Number of

Reciprocating

Compressors that

used BAMM Reported

CO 2 Emissions

(MT CO 2 e) Reported

CH 4 Emissions

(MT CO 2 e) Total Reported

Process

Emissions

(MT CO 2 e)

Natural Gas

Processing 2,149 993 107,777 1,009,045 1,117,065

Natural Gas

Transmission 2,008 790 3,270 1,591,990 1,595,261

Underground Natural

Gas Storage 309 64 290 160,809 161,192

LNG Import/Export 23 7 10.9 7477.7 7,950

LNG Storage 4 0 8.3 90.4 99

Total 4,493 1,854 111,356 2,769,412 2,881,568

The table below shows activity data and emissions for centrifugal compressors by industry segment. For

centrifugal compressors the number of compressors with wet seals is also shown. Overall emissions from

centrifugal compressors were lower than those for reciprocating compressors, but the total number of

reported compressors was lower as well. The EPA received data from 1,203 centrifugal compressors,

including 428 centrifugal compressors in natural gas processing, 724 centrifugal compressors in natural

gas transmission, and 39 centrifugal compressors in underground natural gas storage. Of these centrifugal

compressors, 547 reported using BAMM to calculate emissions, including 234 in natural gas processing,

292 in natural gas transmission, and 12 in undergro und natural gas storage.

October 2013 132012 Reported Process Emissions from Centrifugal Compressors

Industry

Segment Total Number

of Centrifugal

Compressors Number of

Centrifugal

Compressors that

used BAMM Number of

Centrifugal

Compressors

with Wet Seals Reported

CO 2 Emissions

(MT CO 2 e) Reported

CH 4 Emissions

(MT CO 2 e) Total Reported

Process

Emissions

(MT CO 2 e)

Natural Gas

Processing 428 234 274 13,775 752,054 766,100

Natural Gas

Transmission 724 292 291 661 439,714 440,375

Underground

Natural Gas

Storage 39 12 23 166 118,500 118,666

LNG

Import/Export 10 9 5 51 37031.9 37,083

LNG Storage 2 0 2 0 0 0

Total 1,203 547 595 14,653 1,347,300 1,362,224

Natural Gas Distribution

The EPA received annual reports from 174 facilities in the na tural gas distribution segment and reported

emissions totaled 13.0 MMT CO 2 e. Methane emissions totaled 12.7 MMT CO 2 e and carbon dioxide

emissions totaled 0.3 MMT CO 2 e. For the natural gas distribution segment

, combustion emissions ( 0.3

MMT CO 2 e ) were relat ively low er compared to other industry segments. The primary sources of

emission for natural gas distribution were distribution mains ( 7.9 MMT CO 2 e ) and distribution services

( 4.0 MMT CO 2 e ) , which are caused by natural gas equipment leaks and calculated by multiplying

population counts by default emission factors that are specific to pipe material.

1 4 8

0 2 4 6 8 10 Misc Equipment Leaks Combustion Equipment Distribution Metering

- Regulating

... Distribution Services

Distribution Mains

Emissions, MMT CO
2 e 

## 2012 Natural Gas Distribution: Top Reported Emission Sources

CO2 Emissions

CH4 Emissions

N2O Emissions

October 2013 14LNG Import/Export

The EPA received emission reports from 8 LNG i mport/ e xport terminals and reported emissions totaled

0.6 MMT CO 2 e. Methane emissions totaled 0.1 MMT CO 2 e and carbon dioxide emissions totaled 0.5

MMT CO 2 e. Th e top reported source of emissions was combustion equipment ( 0.5 MMT CO 2 e )

, followed by centrifugal compressors (0.04 MMT CO 2 e), blowdown vent stacks ( 0.03 MMT CO 2 e ) , and

reciprocating compressors ( 0.01 MMT CO 2 e )

.

LNG Storage

LNG s torage had the fewest number of facilities of the industry segments that comprise Petroleum and

Natural Gas Systems , with 4 facilities reporting. Total reported emissions from LNG s torage were 0.02

M MT CO 2 e

. Equipment leaks ( 0.01 MMT CO 2 e ) was the top reported source of emissions, followed by

combustion equipment ( 0.01 MMT CO 2 e )

. 0.0 0.1 0.2 0.3 0.4 0.5 0.6 Misc Equipment Leaks Reciprocating Compressors Blowdown Vent Stacks Centrifugal Compressors Combustion Equipment

Emissions, MMT CO
2 e 

## 2012 LNG Import/Export: Top Reported Emission Sources

CO2 Emissions

CH4 Emissions

N2O Emissions

0.00 0.01 0.02 Reciprocating Compressors Combustion Equipment

Misc Equipment Leaks

Emissions, MMT CO
2 e 

## 2012 LNG Storage: Top Reported Emission Sources

CO2 Emissions

CH4 Emissions

N2O Emissions

October 2013 15

## Changes from 2011 to 2012

The following section describes changes between the reported data for the 2011 and 2012 calendar years

for Petroleum and N atural G as S ystems. The EPA received resubmissions of 2011 data from certain

facilities and t he re submitt ed 2011 data is reflected bel ow

.

Change s in Number of Facilities

In 2012, the number of facilities in Petroleum and Natural Gas Systems increased from 1,904 facilities to

2,052 facilities . The largest increases occurred in onshore production ( 42 ), natural gas transmission (34),

and natural gas processing (20).

The increased number of facilities is primarily a result of facilities triggering the 25,000 metric ton CO 2 e reporting threshold. Emissions can be variable in the Petroleum and Natural Gas Systems sec tor and it is

not unexpect ed that emissions for a facility may go above 25,000 metric tons CO 2 e in a given year . Once

the reporting threshold is triggered, facilities must report to the GHGRP until emissions are below the

threshold for a period of time specified in the regulations

, or until all emission sources at a facility cease

operation. As a result, the number of facilities reporting to the GHGRP may vary from year to year

.

Change s in Number of Facilities by Industry Segment: 2011 to 2012

Segment Number of Facilities

2011 Number of Facilities

2012 Change in Number

of Facilities

Onshore Production 455 49 7 42

Offshore Production 99 106 7

Natural Gas Processing 374 394 20

Natural Gas Transmission 428 46 2 34

Underground Natural Gas

Storage 45 49 4

Natural Gas Distribution 173 174 1

LNG Import/Export 8 8 0

LNG Storage 4 4 0

Other Oil and Gas

Combustion 338 381 43

Total 1,904 2,05 8 154

In addition to the increase in number of facilities, an increase was also seen in total reported emissions as

discussed below. This does not necessarily indicate that total national emissions increased; rather it may

indicate a larger percentage of total Petroleum and Natural Gas Systems emissions are covered by the

GHGRP.

Change s in Reported Emission s

Total reported emissions increased by 7.1 MMT CO 2 e from 2011 to 2012. The largest increases occurred

in onshore production (5.4 MMT CO 2 e), natural gas processing (1. 9 MMT CO 2 e), and other oil and gas

combustion (1.5 MMT CO 2 e). The largest decreases were seen in natural gas distrib ution (

- 0.9 MMT

CO 2 e) and natural gas transmission (

- 0.8 MMT CO 2 e). The emission changes correspond to a reduction

in reported methane emissions of 0.5 MMT CO 2 e and increase in reported carbon dioxide emissions of

7.7 MMT CO 2 e.

October 2013 16Change s in Reported Emissio ns by Industry Segment: 2011 to 2012

Segment 2011 Reported

Emissions

(MMT CO 2 e) 2012 Reported

Emissions

(MMT CO 2 e) Change in Reported

Emission s (MMT CO 2 e)

Onshore Production 8 3 88 5.4

Offshore Production 6 7 0.2

Natural Gas Processing 58 60 1. 9

Natural Gas Transmission 24 23

- 0.8

Underground Natural Gas

Storage 1 1

- 0.1

Natural Gas Distribution 14 13

- 0.9

LNG Import/Export 1 1

- 0.1

LNG Storage < 1 < 1 0.0

Other Oil and Gas

Combustion 23 24 1.5

Total 2 10 21 7 7.1

Emission changes may not solely be due to the change in the number of facilities , and could be the result

of a number of factors, such as operational changes (e.g. increased flaring), calculation method changes

(e.g . reduced BAMM use or increased direct me asurement) , and changes in the regulatory landscape

.

Change s in BAMM Use

There was a decrease in the number of facilities using BAMM between 2011 and 2012. The number of

facilities reporting BAMM use decreased from 1,055 facilities in 2011 to 685 facili ties in 2012 , with

reductions seen across Petroleum and Natural Gas Systems industry segments.

Change s in BAMM Use by Industry Segment: 2011 to 2012

Segment 2011 BAMM Use 2012 BAMM Use Change in BAMM Use

Onshore Production 73% 44%

- 40%

Offshore Production 15% 4%

- 75%

Natural Gas Processing 84% 53%

- 37%

Natural Gas Transmission 71% 46%

- 35%

Underground Natural Gas

Storage 56% 35%

- 38%

Natural Gas Distribution 36% 12%

- 66%

LNG Import/Export 50% 25%

- 50%

LNG Storage 75% 25%

- 67%

Other Oil and Gas

Combustion 0% 0% 0%

Total 55% 33%

- 40%

October 2013 17Change s in Reported Emissions by Emission Source

The increase in emissions between 2011 and 2012 is not attributable to any individual emission source. Several sources saw increased emissions, including combustion equipment (2.7 MMT CO 2 e), other flare

stacks (2.3 MMT CO 2 e), atmospheric tanks (1.4 MMT CO 2 e), and associated gas venting and flaring (1.2

MMT CO 2 e). The sources with the largest changes occurred in the onshore production segment.

Change s in Reported Emissions by Emission Source: 2011 to 2012

Emission Source 2011 Reported

Emissions

(M M T CO 2 e) 2012 Reported

Emissions

( M MT CO 2 e) Change s in

Reported Emissions

(M M T CO 2 e)

Combustion Equipment 108.4 111.1 2.7

Pneumatic Devices 17.9 18.4 0.5

Acid Gas Removal Units 15.9 15.4

- 0.5

Associated Gas Venting and Flaring 7.8 9.0 1.2

Misc Equipment Leaks 9.0 8.4

- 0.6

Other Flare Stacks 6.0 8.4 2.3

Gas Well Compl etions and Workovers

with H ydraulic Fracturing 7.2 8.1 0.9

Distribution Mains 8.6 7.9

- 0.6

Liquids Unloading 6.2 5.8

- 0.4

Atmospheric Tanks 3.8 5.2 1.4

Distribution Services 4.4 4.0

- 0.3

Reciprocating Compressors 2.3 3.1

- 0. 1

Pneumatic Pumps 2. 5 2. 9 0.4

Centrifugal Compressors 1. 8 2. 1 0. 3

Blowdown Vent Stacks 1. 3 2.0 0 .7

Offshore Sources 1.9 1.8

- 0.1

Dehydrators 1. 7 1. 6

- 0. 1

Distribution Meter

- Regulating Stations 0.7 0.8 0.1

Well Testing 0.7 0.6

- 0.1

Gas Well Completions and Workovers

without Hydraulic Fracturing 0.7 0.1

- 0.6

Transmission Tanks 0.1 0.1 0.0

Enhanced Oil Recovery Liquids <0.1 <0.1 0.0

Enhanced Oil Recovery Pumps <0.1 <0.1 0.0

Total 209. 9 21 7

. 0 7.1



## Additional Information

Access GHG RP data: http://www.epa.gov/ghgreporting/

Additional information about Petroleum and Natural Gas Systems in the GHGRP, including reporting

requirements and calculation methods: http://www.epa.gov/ghgreporting/reporters/subpart/w.html

.

D ata shown in this document reflect the most recent report submissions from facilities as of September 1,

2013.

October 2013 18