Oil and Natural Gas Sector Compressors

Report for Oil and Natural Gas Sector Compressors
Review Panel
April 2014

Prepared by
U.S. EPA Office of Air Quality Planning and Standards (OAQPS)

This information is distributed solely for the purpose of pre-dissemination peer review underapplicable information quality guidelines. It has not been formally disseminated by EPA. It does not
represent and should not be construed to represent any Agency determination or policy.

ii

Table of Contents
PREFACE1

1.0

INTRODUCTION

2

2.0

PROCESS DESCRIPTIONS

4

2.1

Reciprocating Compressors ...........................................................................................................................4

2.2

Centrifugal Compressors ................................................................................................................................5

3.0
3.1

EMISSIONS DATA AND EMISSIONS ESTIMATES

7

GRI/EPA Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks(GRI/EPA, 1996a) ...........................................................................................................................................8

3.2

Natural Gas Industry Methane Emission Factor Improvement Study, Final Report (URS/UT, 2011) 13

3.3

Greenhouse Gas Reporting Program (U.S. EPA, 2013) ............................................................................. 15

3.4

Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012 (U.S. EPA, 2014) .......................... 18

3.5

Development of the New Source Performance Standard (NSPS) For Oil and Natural Gas Production(U.S. EPA, 2011b and U.S. EPA, 2012a) ..................................................................................................... 21

3.6

Characterizing Pivotal Methane Emissions from the Oil and Natural Gas Sector, (API /ANGA, 2012)24

3.7

Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil andNatural Gas Industries (ICF International, 2014)...................................................................................... 25
3.7.1 ICF 2011 Baseline ................................................................................................................................. 25
3.7.2 ICF Projections to 2018 ......................................................................................................................... 28

4.0
4.1

AVAILABLE COMPRESSOR EMISSIONS MITIGATION TECHNIQUES

29

Reciprocating Compressor - Rod Packing Replacement ........................................................................... 29
4.1.1 Description ............................................................................................................................................. 29
4.1.2 Effectiveness .......................................................................................................................................... 30
4.1.3 Cost of Controls ..................................................................................................................................... 32

4.2

Reciprocating Compressor – Gas Recovery ............................................................................................... 34
4.2.1 Description ............................................................................................................................................. 34
4.2.2 Effectiveness .......................................................................................................................................... 35iii

4.2.3 Cost of Controls ..................................................................................................................................... 35
4.3

Centrifugal Compressor - Dry Seals............................................................................................................ 36
4.3.1 Description ............................................................................................................................................. 36
4.3.2 Effectiveness .......................................................................................................................................... 37
4.3.3 Cost of Controls ..................................................................................................................................... 38

4.4

Centrifugal Compressor - Wet Seal with a Flare ....................................................................................... 39
4.4.1 Description ............................................................................................................................................. 39
4.4.2 Effectiveness .......................................................................................................................................... 39
4.4.3 Cost of Controls ..................................................................................................................................... 40

4.5

Centrifugal Compressor - Wet Seals with Gas Recovery for Use ............................................................. 40
4.5.1 Description ............................................................................................................................................. 40
4.5.2 Effectiveness .......................................................................................................................................... 41
4.5.3 Cost of Controls ..................................................................................................................................... 41

5.0

SUMMARY

42

6.0

CHARGE QUESTIONS FOR REVIEWERS

43

7.0

REFERENCES

45

iv

PREFACE
On March 28, 2014 the Obama Administration released a key element called for in the
President’s Climate Action Plan: a Strategy to Reduce Methane Emissions. The strategy
summarizes the sources of methane emissions, commits to new steps to cut emissions of thispotent greenhouse gas, and outlines the Administration’s efforts to improve the measurement ofthese emissions. The strategy builds on progress to date and takes steps to further cut methane
emissions from several sectors, including the oil and natural gas sector.
This technical white paper is one of those steps. The paper, along with four others,
focuses on potentially significant sources of methane and volatile organic compounds (VOCs) in
the oil and gas sector, covering emissions and mitigation techniques for both pollutants. The
Agency is seeking input from independent experts, along with data and technical informationfrom the public. The EPA will use these technical documents to solidify our understanding ofthese potentially significant sources, which will allow us to fully evaluate the range of options
for cost-effectively cutting VOC and methane waste and emissions.
The white papers are available at:www.epa.gov/airquality/oilandgas/whitepapers.html

1

1.0

INTRODUCTION
The oil and natural gas exploration and production industry in the U.S. is highly dynamic

and growing rapidly. Consequently, the number of wells in service and the potential for greater
air emissions from oil and natural gas sources is also growing. There were an estimated 504,000
producing gas wells in the U.S. in 2011 (U.S. EIA, 2012a), and an estimated 536,000 producing
oil wells in the U.S. in 2011 (U.S. EIA, 2012b). It is anticipated that the number of gas and oilwells will continue to increase substantially in the future because of the continued and expanding
use of horizontal drilling combined with hydraulic fracturing (referred to here as simply
hydraulic fracturing).

Due to the growth of this sector and the potential for increased air emissions, it isimportant that the U.S. Environmental Protection Agency (EPA) obtain a clear and accurate
understanding of emerging data on air emissions and available mitigation options. This paper
presents the Agency’s understanding of emissions and available control technologies from apotentially significant source of emissions in the oil and natural gas sector.

Oil and gas production from unconventional formations such as shale deposits or plays
has grown rapidly over the last decade. Oil and natural gas production is projected to steadily
increase over the next two decades. Specifically, natural gas development is expected to increaseby 44% from 2011 through 2040 and crude oil and natural gas liquids are projected to increase
by approximately 25% through 2019 (U.S. EIA, 2013). The projected growth is primarily led by
the increased development of shale gas, tight gas, and coalbed methane resources utilizing new
production technology and techniques such as horizontal drilling and hydraulic fracturing.
According to the U.S. Energy Information Administration (EIA), over half of new oil wells
drilled co-produce natural gas (U.S. EIA, 2013). Based on this increased oil and gas development
and the fact that half of these new oil wells co-produce natural gas, the potential exists forincreased emissions from production through distribution of natural gas from these operations.

Compressors have been identified as an emission source that has the potential to produce
emissions to the atmosphere during oil and gas production (gathering and boosting), processing,2

transmission and storage. Compressors are mechanical devices that increase the pressure ofnatural gas and allow the natural gas to be transported from the production site, through the
supply chain, and to the consumer. Vented emissions from compressors occur from seals (wetseal compressors) or packing surrounding the mechanical compression components(reciprocating compressors) of the compressor. These emissions typically increase over time as
the compressor components begin to degrade. Leak emissions from various compressor
components can also occur, but those emissions are not covered in this paper because the causes
and mitigation techniques are different than the vented emissions.
The purpose of this paper is to summarize the EPA’s understanding of vented VOC andmethane emissions from compressors, and the EPA’s understanding of available mitigation
techniques (practices and equipment) to reduce vented emissions from compressors. Included in
the mitigation techniques discussion is our understanding of the efficacy and cost of thesetechnologies and the prevalence of use of the technologies in the industry.

In the oil and natural gas sector, the most prevalent types of compressors used arereciprocating and centrifugal compressors. For the purposes of this paper, a reciprocating
compressor is defined as:

A piece of equipment that increases the pressure of a process gas by positive
displacement, employing linear movement of the driveshaft.

For the purposes of this paper, a centrifugal compressor is defined as:

Any machine for raising the pressure of a natural gas by drawing in low pressure natural
gas and discharging significantly higher pressure natural gas by means of mechanicalrotating vanes or impellers.

Compressors are used in all aspects of natural gas development. In the production
segment, compressors are used at the wellhead to compress gas for fluids removal and pressure
equalization with gathering equipment systems. However, the primary use of compressors is in3the natural gas processing, transmission and storage (particularly underground storage) segmentsof the industry.

Section 2 of this document provides background and context for discussions of vented
emissions from compressors, Section 3 presents our understanding of vented VOC and methane
emissions from compressors, and Section 4 provides our understanding of available emissions
mitigation techniques. Section 5 summarizes the EPA’s understanding based on the information
presented in Sections 3 and 4, and Section 6 presents a list of charge questions for reviewers toassist us with obtaining a more comprehensive understanding of vented VOC and methane
emissions from compressors and emission mitigation techniques.

2.0

PROCESS DESCRIPTIONS

2.1

Reciprocating Compressors
In a reciprocating compressor, natural gas enters the suction manifold, and then flows

into a compression cylinder where it is compressed by a piston driven in a reciprocating motion
by the crankshaft powered by an internal combustion engine. For the purposes of this paper,
reciprocating compressor rod packing is defined to mean:

A series of flexible rings in machined metal cups that fit around the reciprocating
compressor piston rod to create a seal limiting the amount of compressed natural gas thatescapes to the atmosphere.

Over the operating life of the compressor, the rings become worn and the packing system
will begin to wear resulting in higher leak rates. Emissions from packing systems originate frommainly four components; the nose gasket, between the packing cups, around the rings andbetween the rings and the shaft. See Figure 2-1 for a depiction of a typical compressor rod
packing system configuration. Typically, gases leaked from the packing system are vented.

4

Figure 2-1. Typical Reciprocating Compressor Rod Packing System(U.S. EPA, 2006a)
2.2

Centrifugal Compressors
Centrifugal compressors use a rotating disk or impeller to increase the velocity of the gas

where it is directed to a divergent duct section that converts the velocity energy to pressure
energy. These compressors are primarily used for continuous, stationary transport of natural gas
and are widely used in the processing and transmission industry segments. Centrifugal
compressors are equipped with either a wet or dry seal configuration. Wet seals use oil aroundthe rotating shaft to prevent natural gas from escaping where the compressor shaft exits thecompressor casing. The oil is circulated at high pressure to form a barrier against compressed
natural gas leakage. The circulated oil entrains and absorbs some compressed natural gas that
may be released to the atmosphere during the seal oil recirculation process (degassing or offgassing). Figure 2-2 illustrates the wet seal compressor configuration.

5

Figure 2-2. Typical Centrifugal Compressor Wet Seal (U.S. EPA, 2006b)

Alternatively, dry seal compressors use the opposing force created by hydrodynamic
grooves and springs to provide a seal. The opposing forces create a thin gap of high pressure gas
between the rings through which little gas can leak. The rings do not wear or need lubrication
because they are not in contact with each other. The combination of two or more of the dry seals
in series is called “tandem dry seals” and is effective in reducing gas leakage. Figure 2-3
illustrates the tandem dry seal compressor configuration.

Gas emissions from wet seal centrifugal compressors have been found to be higher thandry seals compressors primarily due to the off-gassing of the entrained gas from the oil. This gas
is not suitable for sale and is either released to the atmosphere, flared, or routed back to aprocess. In addition to lower gas leakage (and therefore lower emissions), dry seals have beenfound to have lower operation and maintenance costs than wet seal compressors because they area mechanically simpler design, require less power to operate, are more reliable and require lessmaintenance. Dry seal compressors will be discussed in more detail in Section 4.

6

Figure 2-3. Typical Centrifugal Compressor Tandem Dry Seal (U.S. EPA, 2006b)

3.0

EMISSIONS DATA AND EMISSIONS ESTIMATES
There are several sources of emissions factors, activity data, and direct measurement datathat have been used to estimate emissions from compressors in the oil and natural gas sector.
Some of these studies are listed in Table 3-1, along with an indication of the type of information
contained in the study (i.e., activity level and emissions data).

7

Table 3-1. Summary of Major Sources of Information and Data on Compressors
Year of
ReportActivity
FactorEmissions
Data

Gas ResearchInstitute (GRI)/ U.S.
Environmental
Protection Industry

1996

Nationwide

X

Natural Gas Industry Methane
Emission Factor Improvement Study((URS/UT, 2011)

URS Corporation,
UT Austin, and U.S.
Environmental
Protection Agency

2011

None

EF Only

Greenhouse Gas Reporting Program(U.S. EPA, 2013)

U.S. Environmental
Protection Agency

2013

Facility
Level

X

Inventory of Greenhouse Gas
Emissions and Sinks: 1990-2012(2014 GHG Inventory)

U.S. Environmental
Protection Agency

2014

Nationwide

X

2012

Nationwide

X

Name

Affiliation

Methane Emissions from the Natural
Gas Industry: Equipment Leaks(GRI/U.S. EPA, 1996)

Analysis under subpart OOOO (U.S.
EPA, 2012a)

U.S. Environmental
Protection Agency

Characterizing Pivotal Sources ofMethane Emissions from Natural Gas
Production: Summary and Analysisof API and ANGA Survey Responses(API/ANGA Survey)

AmericanPetroleum Institute(API)/America’s
Natural Gas
Alliance (ANGA)2012

Regional

Xa

Economic Analysis of Methane
Emission Reduction Opportunities in
the U.S. Onshore Oil and Natural
Gas Industries (ICF/EDF Study)

ICF International(Prepared for theEnvironmental
Defense Fund)2014

RegionalX

a. The API/ANGA study provided information on equipment counts that could augment nationwide emissions
calculations. No source emissions information was included .

The following sections describe emissions data, emission factors, the origin of theemission factors, and the methodologies used in the emission estimation process including theidentification of national populations for several sources of information.
3.1

GRI/EPA Methane Emissions from the Natural Gas Industry, Volume 8:

Equipment Leaks (GRI/EPA, 1996a)
This report provides an estimate of annual methane emissions from reciprocating andcentrifugal compressor seals from the natural gas production, processing, transmission and8storage sector using the component method. The component method uses average emission
factors for reciprocating and centrifugal compressor seals and the average number ofreciprocating and centrifugal compressors per facility to estimate the average facility emissions.
The average facility emissions were then extrapolated to a national estimate using the number offacilities in each of the sectors.

The emissions data for natural gas production sites were based on screening and bagging
data collected at 12 oil and gas production sites in the Western U.S. Screening involves using ahandheld organic vapor analyzer (OVA) or toxic vapor analyzer (TVA) to measure theconcentration (e.g., parts per million volume, ppmv) of the vented vapors. The method ofbagging involves enclosing the component to collect venting vapors and measuring the flow rate.
The measured flow rates from bagged equipment coupled with screening values are used todetermine the unit-specific mass emission rate. A total of 40 reciprocating compressor seals werescreened and bagged and an emission factor of 2.37 thousand standard cubic feet per cylinder per
year (Mscf/cyl-yr) was calculated. No centrifugal compressors were located at any of the
production sites that were screened.

The reciprocating and centrifugal compressor seal emissions data for the natural gas
processing, natural gas transmission and natural gas storage sectors were obtained using a GRI
Hi-Flow™ (trademark of the Gas Research Institute) sampler to quantify emissions and todevelop emissions factors (GRI/EPA, 1996b). The sampler has a high flow rate and generates aflow field around the component that captures the entire leak. As the sample stream passes
through the instrument, both the flow rate and the total hydrocarbon (THC) concentration aremeasured. The mass emission rate was then determined using these measurements. Different
emission rates were calculated for the different operating modes of the compressor (GRI/EPA,
1996b), and were as follows;

Operating and pressurized;

Idle and fully pressurized;

Idle and partially pressurized using a fuel saver system (reciprocating compressors only);Idle and depressurized.
9

The pressurized compressor seal emission rates (operating and idle) were calculated as
the average of all reciprocating and centrifugal compressor seals combined. The compressor seal
emission rates were determined to be 599 thousand standard cubic feet per seal per year
(Mscf/seal-yr) in the operating and pressurized mode, 531 Mscf/seal-yr in the idle andpressurized mode, and 116 Mscf/seal-yr in the idle and partially pressurized mode (e.g., fuelsaver) (GRI/EPA, 1996b). The compressor seal emission rate was assumed to be negligible in theidle and depressurized mode.

Using the percentage of the time pressurized and the compressor seal emission rates forthe operating modes (e.g., operating and pressurized, idle and pressurized, idle and partiallypressurized, idle and depressurized), emission factors were calculated for the natural gas
processing, transmission, and storage segments. A summary of the emissions factors for each ofthese segments and the natural gas production segment are provided in Table 3-2. The number ofseals was determined by averaging the compressor seal counts from the data in each of thesegments. The number of centrifugal compressor seals depends on the type of compressor:
centrifugal compressors with overhung rotors have one seal and beam type compressors have
two seals. Information from three compressor vendors and one compressor seal vendor showed
an even split between the two type of centrifugal compressors; therefore, the number of seals per
centrifugal compressor was averaged to be 1.5.

10

Table 3-2. Summary of Reciprocating and Centrifugal Compressor Seal
Methane Emission Factors

Compressor Seal
Methane Emission
Factor(Mscf/seal-yr)

AssumedNumber of Seals
per Compressor

AverageCompressor
Methane Emission
Factor from Seals(Mscf/yr)

N/A

2.37

4

9.48

Reciprocating

89.7

450

2.5

1,125

Centrifugal

43.6

228

1.5

342

Reciprocating

79.1

396

3.3

1,307

Centrifugal

24.2

165

1.5

248

Reciprocating

67.5

300

4.5

1,350

Centrifugal

22.4

126

1.5

189

Type ofCompressor

Percentage ofTime theCompressor is
Pressurized (%)

Natural Gas Production
Reciprocating
Natural Gas Processing

Natural Gas Transmission

Natural Gas Storage

The GRI/EPA study presented the emissions for reciprocating and centrifugal
compressors as a sum of the emission components from compressors. These components
included methane emissions from compressor seals, blowdown open-ended line, pressure relief
valves, starter open-ended line, and miscellaneous, which includes valves and connectors. For
the purposes of this paper, only the methane emissions from reciprocating and centrifugal
compressor seals were calculated using the equipment counts of reciprocating and centrifugal
compressors and applying the methane emission factor for each of the sectors. A summary ofthese emissions are presented in Table 3-3 for each of the sectors reported in the GRI/EPA study.

11

Table 3-3. Summary of GRI/EPA Methane Emissions from Reciprocating andCentrifugal Compressor Seals
Activity Factor,
Compressor
Count

Annual Methane
Emissions(Mscf/yr)

Average Methane
Emissions(MT/yr)9.48

17,152

162,601

3,071

Reciprocating

1,125

4,092

4,603,500

86,949Centrifugal

342

726

248,292

4,690

Reciprocating

1,307

6,799

8,886,293

167,841

Centrifugal

248

681

168,888

3,190

Reciprocating

1,350

1,396

1,884,600

35,596

Centrifugal

189

136

25,704

485

15,978,655

301,799

Type ofCompressor

Average Methane
Emission Factor(Mscf/yr)

Natural Gas Production
Reciprocating
Natural Gas Processing

Natural Gas Transmission

Natural Gas Storage

Total

The GRI/EPA study reported methane emissions of 568,670 Mscf/yr (10,741 MT) fromreciprocating compressors from both Eastern and Western U.S. natural gas production. These
totals, as stated earlier, include emissions from compressor blowdowns, starter gas, andmiscellaneous equipment associated with the compressor. Methane emissions from reciprocating
compressor seals represent approximately 29% of the total emissions from reciprocating
compressors. Note that the Eastern U.S. natural gas production did not include methane
emissions from compressor seals in the reciprocating compressor emission factor, only emissions
from the associated equipment (e.g., valves, connectors, and open-ended lines). Table 3-3 does12

include the estimated 129 gathering reciprocating compressors from the Eastern U.S. in theactivity factor for natural gas production and estimates compressor seal methane emissions using
the listed reciprocating compressor seal emission factor.

For natural gas processing, the total methane emissions from reciprocating andcentrifugal compressors and associated equipment and operations were reported as 16,736,280
Mscf/yr (316,108 MT) and 5,626,500 Mscf/yr (106,271 MT), respectively. The methane
emissions from reciprocating and centrifugal compressor seals represent 28% and 4.4%,
respectively, of the total methane emissions from reciprocating and centrifugal compressors in
the natural gas processing sector. In the natural gas transmission sector, the total methane
emissions from reciprocating and centrifugal compressors were estimated to be 37,734,450
Mscf/yr (712,714 MT) and 7,559,100 Mscf/yr (142,773 MT), respectively. The methane
emissions from reciprocating and centrifugal compressor seals represent 24% and 2.2%,
respectively, of the total methane emissions from reciprocating and centrifugal compressors in
the natural gas processing sector. The total methane emissions from reciprocating and centrifugal
compressors and their associated equipment were estimated to be 10,763,160 Mscf/yr (203,290MT) and 1,517,760 Mscf/yr (28,667 MT), respectively, for the natural gas storage sector. The
methane emissions from reciprocating and centrifugal compressor seals represents 18% and1.7%, respectively, of the total methane emissions from reciprocating and centrifugal
compressors in the natural gas storage sector.
3.2

Natural Gas Industry Methane Emission Factor Improvement Study, Final Report(URS/UT, 2011)
The report describes the effort to update default methane emission factors for selected
processes and equipment in the natural gas industry. These processes and equipment are believed
to contribute the greatest uncertainty in the U.S. natural gas industry methane emissions
inventory and concentrated on high emission rate leaks (fugitive leaks) from transmission,
gathering/boosting, and gas processing reciprocating and centrifugal compressor components,
including emissions from compressor vents (i.e., blowdown lines and compressor seals).

13

The emissions data were collected at 11 sites in Texas and New Mexico and included
data from gathering and boosting stations, natural gas processing plants, and transmission
stations. The sites were all constructed between the 1950s and 2000s. The total number ofcompressors that were measured included 66 reciprocating compressors and 18 centrifugal
compressors, with 48 of the reciprocating compressors located at transmission compressor
stations. For compressor seals, the measurements were conducted using the following steps:Where the reciprocating compressor rod packing vent lines were piped together (multiple
cylinders joined into a single vent line for each compressor), the enclosed rotary vane
anemometer was used to make the measurements at the top of the rod packing vent line;Where the reciprocating rod packing vent lines were individually vented to theatmosphere, each vent line was measured with a handheld hot wire anemometer; andFor centrifugal compressors equipped with wet seals, measurements were made at thewet seal degassing fill port to the seal oil pump using plastic bags of known internal
volume and measuring the required flow to fill the bag.
The study noted several technical issues with measuring emissions from a wet seal

system including location of the flash emissions and configuration of the seal oil degassing
system (which may include blowers or a flash drum/pot). The study noted that the wet sealmeasurements from this study should be used as a benchmark and requires further analysis
before the measurements could be used to develop emission factors.

A summary of the testing results from the study are provided in Table 3-4. The study
grouped the test results for centrifugal compressors located at natural gas gathering and boosting,processing and transmission together. The test data for reciprocating compressors were separated
into units located at gathering and boosting stations and units located at transmission stations.
The study found that the largest emission sources at a compressor stations are the compressor
blowdown vent lines and the compressor seal vents (URS/UT, 2011).

14

Table 3-4. Sampling Results for Reciprocating and Centrifugal Compressor Seals

Compressor Vent Measured

Average
MethaneEmission
Factor(Mscf/yr)

1996
GRI/EPA
Emission
Factora(Mscf/yr)

15

241

9.48b

5

12,236

Sample Size

Natural Gas Gathering/Boosting Reciprocating Compressors
Average Rod Packing
Natural Gas Transmission Reciprocating Compressors
Average Rod Packing (Idle + depressurized)

396c
Average Rod Packing

229,603Natural Gas Gathering/Boosting, Processing and Transmission Centrifugal Compressors
Average Wet Seal

9

8,137

396d

a

(GRI/EPA, 1996b)
Appendix B-4, assumes 4 seals per compressor.
c
Table 4-15, adjusted for 79.1% time the compressor is pressurized.
dTable 4-15, adjusted for 24.2% time the compressor is pressurized.
b

The study authors concluded that the centrifugal compressor wet seal degassing ventemissions were much higher in comparison to the GRI/EPA emission factors. The study authors
also determined that the average reciprocating compressor rod packing vent emissions that theycalculated were significantly higher than the GRI/EPA study (GRI/EPA, 1996b).
3.3

Greenhouse Gas Reporting Program (U.S. EPA, 2013)
In October 2013, the EPA released 2012 greenhouse gas (GHG) data for Petroleum andNatural Gas Systems 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, aswell as suppliers of certain GHGs and products that would emit GHGs if released or combusted.

15

When reviewing this data and comparing it to other data sets or published literature, it isimportant to understand the GHGRP reporting requirements and the impacts of theserequirements on the reported data. The GHGRP covers a subset of national emissions fromPetroleum 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 (CO2e) or more. Facilities use uniform methods prescribed by the EPA tocalculate GHG emissions, such as direct measurement, engineering calculations, or emission
factors derived from direct measurement. In some cases, facilities have a choice of calculation
methods for an emission source. Because some of the methods required direct measurement ofemissions or parameters, for an interim period, 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 wasallowed to use alternative methods for determining inputs to calculate emissions.

Emissions for both reciprocating and centrifugal compressors are reported under theprocessing, transmission, underground gas storage, and liquid natural gas (LNG) import/export
and storage segments. The calculation method varied by industry segment. Emissions fromcompressors in onshore production were calculated by using population counts multiplied by anemission factor. Emissions from compressors in the other industry segments were calculated by
the use of direct measurement.

Table 3-4 shows activity data and emissions for reciprocating compressors for the natural
gas processing, natural gas transmission, and underground natural gas storage industry segments.
The EPA received data for 4,466 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 thereciprocating compressors, BAMM was used to calculate emissions for 1,847 compressors,
including 993 in natural gas processing, 790 in natural gas transmission, and 64 in undergroundnatural gas storage.

16

Table 3-5. 2012 Direct Measurement Reported Process Emissions from Reciprocating
Compressors from Natural Gas Processing, Natural Gas Transmission
and Underground Natural Gas Storage

Industry Segment

Total
Number of
Number of
Reciprocating
Reciprocating
Compressors
Compressors that used BAMM

Reported
CH4
Emissions(MT CO2e)

Reported
CH4
Emissionsa(MT)

Natural Gas Processing

2,149

993

1,009,045

48,050Natural Gas Transmission

2,008

790

1,591,990

75,809309

64

160,809

7,658

4,466

1,847

2,761,844

131,516

Underground Natural Gas
Storage
Total
a.

Conversion factors MT CO2e to tons: 21 MT CH4/MT CO2e

Table 3-6 shows activity data and emissions for centrifugal compressors for the natural
gas processing, natural gas transmission, and underground natural gas storage industry segments.
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 for 1,191
centrifugal compressors, including 428 centrifugal compressors in natural gas processing, 724
centrifugal compressors in natural gas transmission, and 39 centrifugal compressors inunderground natural gas storage. Of these centrifugal compressors, BAMM was used to calculate
emissions for 538 compressors, including 234 in natural gas processing, 292 in natural gas
transmission, and 12 in underground natural gas storage.

17

Table 3-6. 2012 Direct Measurement Reported Process Emissions from Centrifugal
Compressors from Natural Gas Processing, Natural Gas Transmission
and Underground Natural Gas Storage

Total Numberof Centrifugal
Compressors

Number ofCentrifugal
Compressorsthat used
BAMM

Number ofCentrifugal
Compressors
with Wet
Seals

Reported
CH4
Emissions(MT CO2e)

Reported
CH4
Emissionsa(MT)

Natural Gas
Processing

428

234

274

752,054

35,812Natural Gas
Transmission

724

292

291

439,714

20,939Underground
Natural Gas
Storage

39

12

23

118,500

5,643

Total

1,191

538

588

1,310,268

62,394

Industry Segmenta.
3.4

Conversion factors: 21 MT CH4/MT CO2eInventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012 (U.S. EPA, 2014)
The EPA leads the development of the annual Inventory of U.S. Greenhouse Gas

Emissions and Sinks (GHG Inventory). This report tracks total U.S. GHG emissions andremovals by source and by economic sector over a time series, beginning with 1990. The U.S.
submits the GHG Inventory to the United Nations Framework Convention on Climate Change(UNFCCC) as an annual reporting requirement. The GHG Inventory includes estimates ofmethane and carbon dioxide for natural gas systems (production through distribution) andpetroleum systems (production through refining).
The 2014 GHG Inventory (published in 2014; containing emissions data for 1990-2012)
calculates net methane emissions for reciprocating compressors using emission factors based on
the GRI/EPA study (GRI/U.S. EPA, 1996a). The factors are used to develop potential emissions.
The total potential emissions are reduced by known controls or practices that reduce emissions to
calculate net emissions. For centrifugal compressors, the EPA has developed emission factors forboth wet seal and dry seal compressors that are used to directly calculate net emissions (i.e., after
control).
18

For the natural gas production stage, emission factors for gathering compressors are
regional and cover small and large reciprocating compressors (no centrifugal compressors).
For natural gas processing, and transmission and storage, the emission factors are forreciprocating compressors and the two types of centrifugal compressors (wet and dry seal). For
LNG storage and import/export, there are factors for reciprocating and centrifugal compressors.
The emission factors used to calculate methane emission for compressors for the 2014 GHG
Inventory are summarized in Table 3-8.
Table 3-9 summarizes the activity data and 2012 calculated potential methane emissions
for compressors by industry segment and compressor type.
Table 3-8. Natural Gas Sector Methane Emission Factors for Compressors
Emission Factor (scf/day/compressor)
Reciprocating
Industry Activity
Production

Small1Large

263-312

14,947-17,728

Centrifugal
Wet Seal

Dry Seal-

Processing

11,196

51,37025,189Transmission

15,20550,22232,208Storage

21,11645,441

31,989LNG Storage/Import

21,11630,573

1

The GRI/EPA study defines small gathering compressors as compressors on the overhead lines from gas well
separators and associated gas well separators. Large gathering compressors are compressors at large gathering
compressor stations (stations with 8 compressors or more).

19

Table 3-9. Summary of Natural Gas Sector Compressor Activity andCalculated Potential Methane Emissions

Industry Segment
Production
Reciprocating (small)
Reciprocating (large)
Processing
Reciprocating
Centrifugal (wet seal)
Centrifugal (dry seal)
Transmission
Reciprocating
Centrifugal (wet seal)
Centrifugal (dry seal)
Storage
Reciprocating
Centrifugal (wet seal)
Centrifugal (dry seal)
LNG Storage
Reciprocating
Centrifugal
LNG Import Terminal
Reciprocating
Centrifugal

Activity(Compressor
Units)

Calculated
Potential Methane
Emissions (MT)35,930136

70,85915,400

5,624
658
248

442,634
237,724
43,937

7,235
659
66

773,294
232,826
14,972

1,012
70
29

150,225
22,347
6,532

270
64

40,147
13,766

37
7

5,552
1,419

The GHG Inventory emissions calculations used regional values by industry segment forthe methane content in natural gas. The average national value for general sources was 83.3%
methane for 2012.
The net 2012 methane emissions reported for compressors for the 2014 GHG Inventory
were 86,259 MT for the natural gas production segment, 724,295 MT for the natural gas
processing segment, and 1,261,080 MT for the natural gas transmission and storage segment, fora total of 2,071,633 MT of methane.

20

3.5

Development of the New Source Performance Standard (NSPS) For Oil and Natural

Gas Production (U.S. EPA, 2011b and U.S. EPA, 2012a)2
VOC emission factors were developed for reciprocating and centrifugal compressors inorder to support the development of subpart OOOO. In order to develop these factors the EPA
used information from the GHGRP3, the GHG Inventory, the EPA’s Natural Gas STAR
Program, and a study by the GRI/EPA study. Updates to the GHGRP and the GHG Inventory
have occurred since this analysis, however, it is presented here for completeness.
The methodology for estimating emissions from reciprocating compressor rod packing
was to use the methane emission factors referenced in the EPA/GRI study (GRI/EPA, 1996a)
and use the methane-to-pollutant ratios developed in the gas composition memorandum
developed for subpart OOOO. (EC/R, 2011) The emission factors in the EPA/GRI study wereexpressed in thousand standard cubic feet per cylinder (Mscf/cyl), and were multiplied by theaverage number of cylinders per reciprocating compressor at each oil and gas industry segment.
The volumetric methane emission rate was converted to a mass emission rate using a density of
41.63 pounds of methane per thousand cubic feet. This conversion factor was developed
assuming that methane is an ideal gas and using the ideal gas law to calculate the density.
The centrifugal compressor emission factors for wet seals and dry seals were based onemission factors from the 2012 GHG Inventory (published in 2012; containing emissions datafor 1990-2010). The wet seal methane emission factor was calculated based on a sampling of 48
wet seal centrifugal compressors. The dry seal methane emission factor was based on datacollected by the Natural Gas STAR Program. The methane emissions were converted to VOC
emissions using the same gas composition ratios that were used for reciprocating engines. (EC/R,
2011) A summary of the methane emission factors is presented in Table 3-10.

2Unless otherwise indicated, the following sections are excerpts from either Section 6 of the technical support
document for the proposed subpart OOOO (U.S. EPA, 2011b) or Section 6.0 of the technical support document for
the final subpart OOOO rule (U.S. EPA, 2012a).
3
http://www.epa.gov/ghgreporting/21

Table 3-10. Methane Emission Factors for Reciprocating and Centrifugal Compressors
Reciprocating Compressors

Centrifugal Compressors

Oil and Gas
Industry
Segment

MethaneEmission Factor(scf/hr-cylinder)

Average
Number of
CylindersperCompressor

Pressurized
Factor (% ofhour/year
Compressor
Pressurized)

Wet Seal
MethaneEmission
Factor(scf/minute)

Dry Seals
MethaneEmission
Factor(scf/minute)

Production(Well Pads)

0.271a

4

100%

N/Af

N/Af

Gathering &Boosting

25.9b

3.3

79.1%

N/Af

N/Af

Processing

57c

2.5

89.7%

47.7g

6g

Transmission

57d

3.3

79.1%

47.7g

6g

Storage

51e

4.5

67.5%

47.7g

6g

a

(GRI/EPA, 1996a), Table 4-8.
Clearstone Engineering Ltd. Cost-Effective Directed Inspection and Maintenance Control Opportunities at Five
Gas Processing Plants and Upstream Gathering Compressor Stations and Well Sites.: 2006.
c(GRI/EPA, 1996a), Table 4-14.
d(GRI/EPA, 1996a) Table 4-17.
e(GRI/EPA, 1996a) Table 4-24.
f
The 1996 EPA/GRI Study Volume 114, does not report any centrifugal compressors in the production orgathering/boosting sectors; therefore, no emission factor data were published for those two sectors.
g(U.S. EPA, 2011a), Annex 3. Page A-153.
Source: Derived from (U.S. EPA, 2011b), Table 6-2 and (U.S. EPA, 2012a), Table 6-1
bOnce the methane emission rates for compressors were calculated using the emission
factors, ratios were applied to the methane emissions to estimate VOC emissions. The specificratios that were used for this analysis were 0.278 pounds VOC per pound of methane for the
production and processing segments, and 0.0277 pounds VOC per pound of methane for thetransmission and storage segments. A summary of the baseline individual compressor emission
rates are shown in Table 3-11 for each of the oil and gas industry segments.

4

EPA/GRI (1996) Methane Emission from the Natural Gas Industry, Vol. 11, .Pages 11 – 15. Available at:
http://epa.gov/gasstar/documents/emissions_report/11_compressor.pdf

22

Table 3-11. Baseline Emission Rates for Reciprocating andCentrifugal Compressors
Baseline Emission Estimates(tons/compressor/year)

Industry Segment/
Compressor Type

Methane

VOC

Production (Well Pads)

0.198

0.0549Gathering & Boosting

12.3

3.42

Processing

23.3

6.48

Transmission

27.1

0.751

Storage

28.2

0.782

Processing

228

20.5

Transmission

126

3.50

Storage126

3.50

Processing

28.6

2.58

Transmission

15.9

0.440

Storage

15.9

0.440

Reciprocating Compressors

Centrifugal Compressors (Wet seals)

Centrifugal Compressors (Dry seals)

Source: Derived from (U.S. EPA, 2011b), Table 6-2 and (U.S. EPA, 2012a), Table 6-1

The analysis performed in the technical support document (TSD) to proposed subpart
OOOO (U.S. EPA, 2011b) was designed to provide information about new compressors for the
purposes of establishing new source performance standards; accordingly, the analysis did not
estimate nationwide emissions for all compressors.

23

3.6

Characterizing Pivotal Methane Emissions from the Oil and Natural Gas Sector,(API /ANGA, 2012)
The API/ANGA study (API/ANGA, 2012) is an analysis of industry survey data that
includes data from over 20 companies covering over 90,000 gas wells. This study sample
population includes representation from most of the geographic regions of the country as well as
most of the geologic formations currently developed by the industry.
With respect to compressors, the API/ANGA study collected information related to theactivity count for centrifugal compressors, specifically to supplement the EPA’s data on theprevalence of wet seal and dry seal compressors in the industry. According to the survey results,
the data collected represented approximately 5% of the national centrifugal compressor count forgas processing operations (38 centrifugal compressors from the survey, compared to 811 from2012 GHG Inventory). Of the gas processing centrifugal compressors reported through thesurvey, 79% were dry seal compressors and 21% were wet seal units. If the results of the survey
were considered to be representative, the authors assert that the EPA’s current ratio of 80% wet
seal and 20% dry seals severely overestimates the emissions from the wet seal compressors.
Based on the emission factors from Table A-123 of Annex 3 of the 2012 GHG Inventory, themethane emissions from centrifugal compressors would be 190,573 tons (172,887 MT)compared to 288,068 tons (261,334 MT) from the 2012 GHG Inventory. This would equate to an
approximate 34% reduction in the emissions from this source. The authors recommended using
the GHGRP data to further refine these activity numbers.
With respect to production and gathering facilities that use centrifugal compressors, the
API/ANGA survey responses reported only 550 centrifugal compressors associated withproduction and gathering at 21 participating companies. The authors noted that the 2012 GHG
Inventory did not include centrifugal compressors in production/gathering operations. The study
reported that, on a well basis, the survey response equates to 0.07 centrifugal compressor per gas
well with 81% of those being dry seal and the remaining being wet seal. The authors
recommended that the EPA continue to refine these numbers using data from the GHGRP.

24

3.7

Economic Analysis of Methane Emission Reduction Opportunities in the U.S.

Onshore Oil and Natural Gas Industries (ICF International, 2014)
The Environmental Defense Fund (EDF) commissioned ICF International (ICF) to
conduct an economic analysis of methane emission reduction opportunities from the oil andnatural gas industry to identify the most cost-effective approach to reduce methane emissions
from the industry. The study projects the estimated growth of methane emissions through 2018
and focuses its economic analysis on 22 methane emission sources in the oil and natural gas
industry (referred to as the targeted emission sources). These targeted emission sources represent
80% of the study’s projected 2018 methane emissions from onshore oil and gas industry sources.
Centrifugal compressor and reciprocating compressor emission sources were included in theirlist of targeted emission sources.
The study relied on the 2013 GHG Inventory for methane emissions data for the oil andnatural gas sector. These emissions data for compressors were revised to include updated
information from the GHGRP, data from the 1996 GRI/EPA study of methane emissions,information on the Federal Energy Regulatory Commission (FERC) website, data obtained fromthe U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administrationand information from various state energy and environmental departments. The revised ICF 2011baseline methane emissions estimates were then used as the basis for projecting onshore methane
emissions to 2018. A summary of the most significant revisions made to the 2013 GHG
Inventory activity and emission factors to develop the revised ICF 2011 baseline by industry
segment are presented in Section 3.8.1. The methodology used to project onshore methane
emissions from the revised 2013 GHG Inventory (referred to as the ICF 2011 baseline) to 2018
for compressors is presented in Section 3.8.2.
3.7.1 ICF 2011 Baseline
The ICF study breaks out emissions by natural gas segment (gas production, gatheringand boosting, gas processing, gas transmission, gas storage, LNG and gas distribution) andpetroleum segment (oil production, oil transportation and oil refining). The most significant
revisions made to the 2013 GHG Inventory to develop the ICF 2011 baseline for compressors are25

summarized by industry segment in the following paragraphs. Note that no emission factor or
activity changes related to compressors were made for the gas production, oil production, oiltransportation, and oil refining segments.
3.7.1.1 Gathering and Boosting Segment
Reciprocating Compressors
Updated the 1996 EPA/GRI study emissions factors used in the 2013 GHG Inventory
using information obtained from five state energy agencies (Texas, Colorado, Wyoming,
Oklahoma and Pennsylvania) on permitted engines for production and gathering
compressors in the petroleum and natural gas industry. These data were split into large
and small compressors using the 1,600 horsepower (hp) threshold from the 1996
EPA/GRI study. The state data showed a larger percentage of large compressors thanassumed in the 2013 GHG Inventory. A new weighted average factor was calculatedusing the 1996 EPA/GRI study emission factors. The new methane emission factor for all
gathering compressors was calculated at 1,980 scf/day/compressor.

The reciprocating compressor emission factor used in the 2013 GHG Inventory was
updated to distinguish compressor seal emissions versus compressor fugitives (which are
combined in the GHG Inventory) using the 1996 EPA/GRI study emission factors,
whereby compressors seals were then separated into two categories: reciprocating
compressors – non-seals (75%) and reciprocating compressors – seals (25%).

Developed new activity factors for reciprocating compressors using information obtained
from the five state energy agencies (discussed above) by using the 2013 GHG Inventory
ratio of compressors in these five states to the national count of compressors to obtain a
new national reciprocating compressor count of 15,687.

Based on these revisions, ICF estimated the net change in methane emissions fromreciprocating compressors (as compared with the 2013 GHG Inventory) to be 166% or an
increase to 11 Bcf (228,965 tons).

26

Centrifugal CompressorsCreated a new emission category for wet seal centrifugal compressors based on
information obtained from the GHGRP that included 162 wet seal centrifugal
compressors used in the upstream sector. ICF assumed that the respondents under the
GHGRP represented 85% of the industry. Therefore, ICF adjusted the number of wet seal
centrifugal compressors to be 191. ICF used an emission factor of 12,000,000
scf/year/compressor (from subpart W) and their estimated number of wet seal centrifugal
compressors to estimate methane emissions for the 2011 baseline (over 2 Bcf [41,630
tons] methane).

3.7.1.2 Gas Processing

Reciprocating compressors emission factor updated to breakout emissions fromcompressor seals versus “other” compressor fugitives as discussed in Section 3.8.1.1.

3.7.1.3 Gas Transmission

Number of compressor stations revised from 1,808 to 1,768 (based on a change inpipeline miles included in the 2013 GHG Inventory using data obtained from the U.S.
Department of Transportation Pipeline and Hazardous Materials Safety Administration
indicating a lower value for transmission pipeline miles), resulting in an emissions
decrease of just over 2%.



Number of reciprocating compressors changed from 7,270 to 7,111 (based on changes tothe pipeline miles included in the 2013 GHG Inventory – see above), resulting in anemissions decrease of over 2%.



Number of centrifugal compressors revised from 654 to 648 (based on changes to thepipeline miles included in the 2013 GHG Inventory – see above), resulting in anemissions decrease of over 2%.

27

3.7.1.4 Gas Storage

Reciprocating compressors emission factor updated to breakout emissions fromcompressor seals versus “other” compressor fugitives as discussed in Section 3.8.1.1.

3.7.2 ICF Projections to 2018
Emissions projections are not the subject of this paper; therefore, the estimates of 2018
emissions produced in the ICF study are not presented here. However, the ICF study uses the
projections to evaluate emissions mitigation techniques for compressors, which are addressed inthis paper. Those mitigation techniques are discussed in detail in Section 4 of this paper. The
methodology the ICF study used to project emissions to 2018 is described here in order toprovide context for the later discussion of mitigation techniques.
The primary sources used for projecting onshore methane emissions for centrifugal andreciprocating compressors for 2018 included the INGAA Foundation North American Midstream
Infrastructure Through 2035-A Secure Energy Future report (ICF, 2011), an analysis of past
projected infrastructure change, FERC and ICF information on emission reductions anticipated
as a result of regulation (40 CFR Part 60, subpart OOOO).
The INGAA report provided yearly forecast information of incremental gathering
pipeline miles, gas processing plants and processing compressor counts that were used withexisting activity data from the 2013 GHG Inventory to estimate a regional activity factor for use
to make projections out to 2018. For the gathering and boosting segment, the activity factors
were estimated based on a ratio of pipeline miles in 2018 to pipeline miles in the ICF 2011baseline to obtain 2018 activity levels. For the gas processing segment, the activity factors were
estimated based on a ratio between the compressor count in 2018 and the compressor count in
the ICF 2011 baseline. For the gas transmission segment, projections out to 2018 were based on
an analysis of past pipeline infrastructure changes, where the change in the length oftransmission pipeline from 1990 to 2011 was used to establish an incremental value based ontrends that were then used to project the pipeline miles for 2018.

28

The new 2018 forecast of emissions for centrifugal and reciprocating compressors (for all
but production and transmission segments) were adjusted to account for emission reductions thatare expected as a result of the EPA’s NSPS, subpart OOOO.
Further information included in this study on mitigation or emission reduction options,methane control costs, and their estimates for the potential for VOC emissions co-control
benefits from their use is presented in Section 4 of this document.

4.0

AVAILABLE COMPRESSOR EMISSIONS MITIGATIONTECHNIQUES
Emissions mitigation options for reciprocating compressors involve techniques that limit
the leaking of natural gas past the piston rod packing, including replacement of the compressor
rod packing, replacement of the piston rod, and the refitting or realignment of the piston rod. The
EPA is also aware of new technologies that enable the emissions to be captured and either routed
to a combustion device or a useful process. Emission mitigation options for centrifugal
compressors limit the leaking of natural gas across the rotating shaft using a mechanical dry seal,or capture the gas and route it to a useful process or to a combustion device. A discussion ofthese techniques and their costs is presented in the following sections.
4.1

Reciprocating Compressor - Rod Packing Replacement

4.1.1 Description
The potential emission reduction options for reciprocating compressors include control
techniques that limit the leaking of natural gas past the piston rod packing. Reciprocating
compressor rod packing consists of a series of flexible rings that fit around a shaft to create a seal
against leakage. Rod packing emissions typically occur around the rings from slight movementof the rings in the cups as the rod moves, but can also occur through the “nose gasket” around thepacking case, between the packing cups, and between the rings and shaft (see Figure 2-1).
Mitigation options for these emissions include replacement of the compressor rod packing,29

replacement of the piston rod, and the refitting or realignment of the piston rod (U.S. EPA,
2006a).
The replacement of the rod packing is a maintenance task performed on reciprocating
compressors to reduce the leakage of natural gas past the piston rod. Over time, the packing rings
wear and allow more natural gas to escape around the piston rod. Regular replacement of theserings reduces VOC and methane emissions.
Like the packing rings, piston rods on reciprocating compressors also deteriorate. Rods
can wear “out-of-round” or taper when poorly aligned, which affects the fit of packing rings
against the shaft (and therefore the tightness of the seal) and the rate of ring wear. Replacing or
upgrading the rod can reduce reciprocating compressor rod packing emissions. Also, upgrading
piston rods by coating them with tungsten carbide or chrome reduces wear over the life of therod (U.S. EPA, 2006a).
4.1.2 EffectivenessAs discussed above, regular replacement of the reciprocating compressor rod packing canreduce the leaking of natural gas across the piston rod. The emission reductions are related to therate of deterioration and the frequency of replacement.

Subpart OOOO Technical Support Document (U.S. EPA, 2011b)

In the TSD for the subpart OOOO rulemaking, the expected emission reductions from a
rod packing replacement were calculated by comparing the average rod packing emissions withthe average emissions from newly installed and worn-in rod packing (U.S. EPA, 2011b). For
gathering and boosting compressors, the analysis calculated the potential methane emission
reductions by multiplying the number of new reciprocating compressors by the difference
between the average rod packing emission factor in Table 3-10 by the average emission factor
from a newly installed rod packing. The average rod packing emission factor used for gatheringand boosting compressors was developed from the Clearstone II study (Clearstone, 2006) using
rod packing measurement data (which was adjusted for the percent of time transmission
30

compressors are operating) (GRI/U.S. EPA, 1996). For wellhead reciprocating compressors, theanalysis calculated a percentage reduction using the transmission emission factor from the 1996
EPA/GRI report and the minimum emissions rate from a newly installed rod packing todetermine methane emission reductions. The emission reductions for the processing,transmission, and storage segments were calculated by multiplying the number of newreciprocating compressors in each segment and the difference between the average rod packing
emission factors in Table 3-10 (GRI/U.S. EPA, 1996) and the average emission factor fromnewly installed rod packing. Newly installed packing average methane emissions were assumed
to be 11.5 cubic feet per hour per cylinder (U.S. EPA, 2006a).

A summary of the estimated emission reductions for reciprocating rod packing
replacement for each of the oil and gas segments from the subpart OOOO TSD is shown in Table
4-1. The emissions of VOC were calculated using the methane emission reductions calculated
above and the gas composition (EC/R, 2011) for each of the segments.

Table 4-1. Estimated Annual Individual and Nationwide Emission Reductions from
Replacing Rod Packing in Reciprocating Compressors
Individual Compressor
Emission Reductions(tons/compressor-year)
Oil & Gas Segment

Methane

VOC

Production (Well Pads)

0.158

0.0439Gathering & Boosting

6.84

1.90

Processing

18.6

5.18

Transmission

21.7

0.600

Storage

21.8

0.604

31

Economic Rod Packing Replacement
The Natural Gas STAR Lessons Learned document titled “Reducing Methane Emissions
from Compressor Rod Packing Systems” (U.S. EPA, 2006a) states that a new, properly installed
rod packing system should leak approximately 11 to 12 standard cubic feet per hour (scfh) ofgas. The effectiveness of the system on minimizing leaks is reliant on the fit of, and wear to therod packing components (such as the rod packing material, the cups that hold it, and the pistonrod). As the rod packing system ages, the leak rates will increase. Eventually, the leak rate willreach a point where the amount of gas saved by replacing the rod packing will justify the cost of
performing the replacement. In some cases, the economic threshold for replacement can be as
low as 30 scfh of gas leakage. However, if the rod packing systems are not well maintained, theleakage rates can far exceed that value. In one instance, a Natural Gas STAR partner reported
emissions from an aging rod packing system to be as high as 900 scfh.

Updated rod packing components made from newer materials can also help improve thelife and performance of the rod packing system. Another potential option is replacing the bronze
metallic rod packing rings with longer lasting carbon-impregnated Teflon rings. Compressor rods
can also be coated with chrome or tungsten carbide to reduce wear and extend the life of thepiston rod (U.S. EPA, 2006a).

4.1.3 Cost of Controls
The Natural Gas STAR Lessons Learned document estimates the cost to replace thepacking rings on reciprocating compressors to be $1,620 per cylinder. The replacement of rod
packing for reciprocating compressors occurs on average every four years based on industry
information from the Natural Gas STAR Program. (U.S. EPA, 2006a)

The TSD for the subpart OOOO rulemaking used the above costs from the Natural Gas
STAR Lessons Learned document and operating factors from the GRI/EPA study to determine
the costs and gas savings from rod packing replacement (U.S. EPA, 2011b). The weighted hours,
on average, per year the reciprocating compressor is pressurized was calculated to be 98.9%
32

using the operating factors presented in Table 3-2 of this paper (GRI/EPA, 1996a). The
calculated years were assumed to be the equipment life of the compressor rod packing. Table 3-2
was used to estimate the average number of cylinders per compressor for each industry segment.
Information reviewed did not identify any annual or periodic maintenance costs for the rod
packing systems. Because replacement of rod packing systems reduces gas emissions, amonetary savings can be realized that is associated with the amount of gas saved withreciprocating compressor rod packing replacement. The savings were estimated using a natural
gas price of $4.00 per Mcf (U.S. EIA, 2010). This gas price was used to calculate the annual
savings using the methane emission reductions in Table 4-1. The savings over the usefulequipment life of the rod packing system was then calculated based on equipment life discussed
above. A summary of the estimated capital costs and estimated gas savings for each of the oiland gas segments is shown in Table 4-2.

Table 4-2. Capital Cost and Gas Savings for Reciprocating Compressor
Rod Packing Replacement
Capital Cost percompressor($2008)Gas Savings for
Equipment Life
per Compressor

Production$6,480$2,493Gathering & Boosting$5,346$1,669Processing$4,050$1,413

Transmission$5,346$1,669Storage$7,290$2,276

Oil and Gas Segment

The ICF International study (ICF, 2014) evaluated the effectiveness of replacing rod
packing systems in reciprocating compressors for existing sources to reduce methane emissions
assuming 98% control with timely replacement to minimize emissions. Their analysis assumed
capital costs of $2,000 every 3 years for replacement of the packing system, and revenue benefits
from reduction of methane emission losses of $3,500 (at $4.00/Mcf gas). The estimated payback

33period for this control option was estimated to be seven months. National emission reductions
were estimated to be 3.6 Bcf (74,934 tons) methane/yr. ICF estimated national annualized costsof replacing rod packing systems to be $22.3 million/yr and total initial capital costs to be an
estimated $182.3 million. ICF also estimated that VOC emissions would be reduced by 8
kilotons (or approximately 8,816 tons) at a cost of $2,784/ton of VOC reduced. ICF concluded
that replacing rod packing systems in reciprocating compressors can significantly reduce
methane emissions and increase savings.
4.2

Reciprocating Compressor – Gas Recovery

4.2.1 Description
The potential emission reduction options for reciprocating compressors include control
techniques that recover natural gas leaking past the piston rod packing. The EPA is aware of one
company, REM Technology, Inc., that has developed a system that captures the gas that would
otherwise be vented and routes it back to the compressor engine to be used as fuel (REM, 2012).
The vent gases are passed through a valve train that includes a demister and then are injected into
the engine intake air after the air filter. The EPA is aware that this technology has been deployedcommercially, but does not have any information on the extent it is used in the field.
Another method for capturing emissions from reciprocating compressor rod packing
vents is to manifold the vent line to a vapor recovery unit (VRU) system. A VRU is a simple
system designed to capture vented gas streams, usually from tanks, that would otherwise go to
the atmosphere. The main components of the system include a compressor and scrubber. If a
VRU system is already in place at a facility with reciprocating compressors, it is often possible
to route the vent streams to tanks, allowing the vented rod packing gas to be picked up by the
VRU. The recovered gas can then be sold or routed for fuel or other meaningful use onsite. If thegas cannot be used productively, it can also be sent to a flare system. While flaring may have ahigher cost than venting to the atmosphere, this practice can reduce methane and VOCemissions.

34

4.2.2 Effectiveness
REM Technology estimates that the gas recovery system can result in the elimination ofover 99% of VOC and methane emissions that would otherwise occur from the venting of theemissions from the compressor rod packing (REM, 2013). The emissions that would have been
vented are combusted in the compressor engine to generate power. This technique is discussed
further in the Natural Gas STAR PRO Fact Sheet titled “Install Automated Air/Fuel Ratio
Controls” (U.S. EPA, 2011c). This document reported an average fuel gas savings of 78
thousand cubic feet per day (Mcfd) per engine with the gas recovery system installed.
If the facility is able to route rod packing vents to a VRU system, it is possible to recover
approximately 95-100% of emissions. If the gas is routed the gas to a flare, approximately 95%
of the methane and VOCs are reduced.
4.2.3 Cost of Controls
The EPA has not been able to obtain cost data on the REM technology. Some costs
would be mitigated by fuel gas savings, as using the captured gas to displace some of thepurchased fuel would require less fuel to be purchased in order to run the compressor engine.
For a VRU, assuming the proper equipment is already available at the facility, capturing
the rod packing gas would require minimal costs. The investment would only need to include thecost of piping and installation. While the EPA has not obtained a cost estimate specifically forrouting rod packing vents to a VRU, this process has been studied for dehydrators and would be
similar for rod packing systems. According to the Natural Gas STAR PRO Fact Sheet titled“Pipe Glycol Dehydrator to Vapor Recovery Unit” (U.S. EPA, 2011d), the cost for planning andinstalling additional piping is approximately $2,000. Routing to a VRU also provides additional
incentive as there is a value associated with recovered gas. However, the installation of a VRU to
only capture rod packing emissions may not be economically viable if an additional compressor
system is required. If the VRU is already present at the facility, the incremental cost to capture
the rod packing vent gas can be recovered from the value of the additional captured gas.

35

4.3

Centrifugal Compressor - Dry Seals

4.3.1 Description
Centrifugal compressor dry seals operate mechanically under the opposing force createdby hydrodynamic grooves and springs. The hydrodynamic grooves are etched into the surface ofthe rotating ring affixed to the compressor shaft. When the compressor is not rotating, thestationary ring in the seal housing is pressed against the rotating ring by springs. When thecompressor shaft rotates at high speed, compressed gas has only one pathway to leak down theshaft, and that is between the rotating and stationary rings. This gas is pumped between the rings
by grooves in the rotating ring. The opposing force of high-pressure gas pumped between therings and springs trying to push the rings together creates a very thin gap between the rings
through which little gas can leak (see Figure 2-3). While the compressor is operating, the rings
are not in contact with each other; therefore, they do not wear or need lubrication. O-rings seal
the stationary rings in the seal case.
Dry seals reduce emissions and, at the same time, they reduce operating costs andenhance compressor efficiency. Economic and environmental benefits of dry seals include:

Gas Leak Rates. Wet seals generate vented emissions during degassing of the circulatingoil. Gas separated from the seal oil before the oil is recirculated is usually vented to theatmosphere, bringing the total leakage rate for tandem wet seals to 47.7 scfm natural gas
per compressor (U.S. EPA/ICR, 2009) (U.S. EPA, 2011a, Annex 3, page A-153).



Mechanically Simpler. Dry seal systems do not require additional oil circulation
components and treatment facilities.



Reduced Power Consumption. Because dry seals have no accessory oil circulation pumps
and systems, they avoid “parasitic” equipment power losses. Wet seal systems require 50
to 100 kW per hour, while dry seal systems need about 5 kW of power per hour.

Improved Reliability. The highest percentage of downtime for a compressor using wet
seals is due to seal system problems. Dry seals have fewer ancillary components, whichtranslates into higher overall reliability and less compressor downtime.

36

Lower Maintenance. Dry seal systems have lower maintenance costs than wet seals
because they do not have moving parts associated with oil circulation (e.g., pumps,
control valves, relief valves, and the seal oil cost itself).

Elimination of Oil Leakage from Wet Seals. Substituting dry seals for wet seals
eliminates seal oil leakage into the pipeline, thus avoiding contamination of the gas anddegradation of the pipeline.

4.3.2 EffectivenessThe emissions reduction effectiveness of the dry seals was calculated in the TSD for the
proposed subpart OOOO (U.S. EPA, 2011b) by subtracting the dry seal emissions from acentrifugal compressor equipped with wet seals. The centrifugal compressor emission factors in
Table 3-2 were used in combination with an operating factor of 43.6% for processing centrifugal
compressors and 24.2% for transmission centrifugal compressors. The operating factors are used
to account for the percent of time in a year that a compressor is in the operating mode. The
operating factors for the processing and transmission sectors are based on data in the EPA/GRI
study (GRI/EPA, 1996a). The wet seals emission factor is an average of 48 different wet seal
centrifugal compressors. The dry seal emission factor is based on information from the Natural
Gas STAR Program (U.S. EPA, 2006b). A summary of the emission reduction from thereplacement of wet seals with dry seals is shown in Table 4-3.
Table 4-3. Estimated Annual Centrifugal Compressor Emission Reductions from
Replacing Wet Seals with Dry Seals
Individual Compressor Emission Reductions(ton/compressor-year)
Oil & Gas Segment

Methane

VOC

Processing

199

18.0

Transmission/Storage

110

3.06

37

4.3.3 Cost of Controls
The price difference between a brand new dry seal and brand new wet seal centrifugal
compressor is small relative to the cost for the entire compressor. The analysis in the TSD for
proposed subpart OOOO assumed the additional capital cost for a dry seal compressor to be$75,000, with an equipment life of 10 years (U.S. EPA, 2011b).
The Natural Gas STAR Program estimated that the operation and maintenance savings
from the installation of dry seals is $88,300 annually in comparison to wet seals (U.S. EPA,
2006b). Monetary savings associated with the amount of gas saved with the replacement of wet
seals with dry seals for centrifugal compressors was estimated using a natural gas price of $4.00
per Mcf (U.S. EIA, 2010). This cost was used to calculate the annual gas savings using themethane emission reductions in Table 4-2. There is no gas savings cost benefits for transmission
and storage facilities, because it is assumed the owners of the compressor station do not own thenatural gas that is compressed at the station. A summary of the capital cost, annual operation andmaintenance cost and the natural gas savings for replacing wet seals with dry seals is presented
in Table 4-4. As shown in the table, there is a net savings after one year of operation without
considering any potential natural gas savings.
Table 4-4. Costs for Replacing Centrifugal Compressor Wet Seals with Dry Seals
Capital Cost
Oil and Gas Segment

per compressor($2008)Annual Operation and
Maintenance Savings($/compressor)

Annual Natural Gas
Savings($/compressor)

Processing$75,000$88,300$46,109

Transmission/Storage$75,000$88,300

0

The ICF International study (ICF, 2014) evaluated replacing a wet seal with a dry seal for
centrifugal compressors (assuming 97% control of methane emissions) as a control option using
their 2018 projected methane emission estimates (discussed in Section 3.8.2 of this document).
Their analysis assumed retrofit capital and annual operating costs of $400,000 and $17,500,
38

respectively, and annual product revenue benefits of $180,500 (assuming $4/Mcf of gas) due tothe reduction of product loss to the atmosphere. The report states that a dry seal retrofit is notcommon due to the high up-front costs and the downtime that would be required, and estimatesthat the payback period would be 29 months. The report also states that information fromvendors indicates that 90% of new centrifugal compressors are already equipped with dry seals.
4.4

Centrifugal Compressor - Wet Seal with a Flare

4.4.1 Description
Another emission reduction option for centrifugal compressors equipped with wet seals is
to route the emissions to a combustion device or capture the emissions and route them to a fuelsystem. A wet seal system uses oil that is circulated under high pressure between three rings
around the compressor shaft, forming a barrier against the compressed gas. The center ring is
attached to the rotating shaft, while the two rings on each side are stationary in the seal housing,pressed against a thin film of oil flowing between the rings to both lubricate and act as a leakbarrier. Compressed gas becomes absorbed and entrained in the fluid barrier and is removed
using a heater, flash tank, or other degassing technique so that the oil can be recirculated back to
the wet seal. The removed gas is either combusted, released to the atmosphere, or captured androuted to a process. The emission reduction technique investigated in this section is the use of
wet seals with the removed gas sent to an enclosed flare.
4.4.2 EffectivenessFlares have been used in the oil and gas industry to combust gas streams that have VOC
and methane constituents. A flare typically achieves 95% reduction of these compounds when
operated according to the manufacturer instructions. For this analysis, it was assumed that 100%of the entrained gas from the seal oil that is removed in the degassing process would be directed
to a flare that achieves 95% reduction of organic compounds. The wet seal emissions in Table 32 were used along with the control efficiency of the flare to calculate the emissions reductions
from this option. A summary of the emission reductions is presented in Table 4-5.

39

Table 4-5. Estimated Annual Centrifugal Compressor Emission Reductions from
Wet Seals Routed to a Flare
Individual Compressor Emission Reductions(tons/compressor-year)
Oil & Gas Segment

Methane

VOC

Processing

216

19.5

Transmission/Storage

120

3.32

4.4.3 Cost of Controls
The capital and annual costs of the enclosed flare were calculated using the methodology
in the EPA Control Cost Manual. (U.S. EPA, Cost) The heat content of the gas stream wascalculated using information from an the EPA study to estimate the composition of natural gas
previously developed for the analysis of subpart OOOO. (EC/R, 2011) A summary of the capitaland annual operation and maintenance costs for wet seals routed to a flare is presented in Table
4-6. There is no cost saving estimated for this option because the recovered gas is combusted.
Table 4-6. Costs for Centrifugal Compressor Wet Seals Routed to a FlareOil and Gas Segment

Capital Cost ($2008)

Annual Cost per Compressor

Processing$67,918$98, 329

Transmission/Storage$67,918$98,329

4.5

Centrifugal Compressor - Wet Seals with Gas Recovery for Use

4.5.1 Description
The final option for emissions reduction for wet seal centrifugal compressors is to capture
and reroute the emissions back into the process. Based on comments received during
development of subpart OOOO, in some cases gas may be routed back to the compressor suction
or fuel system.
40

4.5.2 EffectivenessThe emissions reductions for wet seal centrifugal compressors in the processing sector
and transmission and storage sectors are summarized in Table 4-7 using 95% control efficiency
for the capture system.
Table 4-7. Wet Seal Centrifugal Compressor Emission Reductions
at 95% Capture and Control
VOC
(tpy)

Methane(tpy)

Emissions Reductions Per Wet Seal Centrifugal Compressor –Natural Gas Processing

19.5

216

Emissions Reductions Per Wet Seal Centrifugal Compressor –Transmission/Storage

3.32

120

Source4.5.3 Cost of Controls
Natural Gas STAR estimated the cost of a system of this type in which the seal oil
degassing vents are routed to fuel gas or compressor suction to be $22,000 (U.S. EPA, 2009).
The estimated cost includes the installation of an intermediate pressure degassing drum, newpiping, gas demister/filter, and a pressure regulator for the fuel line. The capital and installation
costs were estimated using Guthrie’s modular method of equipment cost estimation (U.S. EPA,
2009). The annual operating and maintenance cost of the systems was assumed to be minimal(U.S. EPA, 2009).
Because this option results in natural gas capture, savings can be realized from the use of
the gas for beneficial purposes (e.g., the gas captured can replace other fuel that would have tobe purchased). The per unit annual savings from natural gas is calculated by taking the value ofthe gas that is not emitted and routed to a useful purpose as a result of the capture control. This
assumes that all gas that is not emitted is being routed for a useful purpose, which is reasonablegiven the available information on the destination of recovered seal oil degassing streams. Using
the methane reductions provided in Table 4-7, the value of the natural gas saved is estimated tobe $44,729 per year for centrifugal compressors equipped with one wet seal in the natural gas
41

processing sector and $24,849 per year for centrifugal compressors equipped with one wet seal
in the transmission/storage sector. These cost savings assume the value of the natural gas saved
is $4/Mscf and the natural gas has a methane content of 92.8%.
Natural Gas STAR estimated the potential cost benefit of installing a seal oil capturesystem that uses the captured gas to fuel onsite boilers and heaters (U.S. EPA, 2009). The report
estimates the potential gas savings from reduced site fuel gas consumption to be 63,000 Mscf/yr(U.S. EPA, 2009). At $4/Mscf, the potential cost savings from reduced fuel consumption would
be $252,000 per year, not including the capital cost of the seal oil gas capture system.
The ICF International study (ICF, 2014) calculated emission control cost curves ($/Mcfof methane reduced) using their 2018 projected methane emission estimates (discussed in
Section 3.8.2 of this document). The report evaluated the cost of preventing emissions from theuse of centrifugal compressors with wet seals by capturing the seal oil degassing stream from asmall disengagement vessel and recycling it back into the compressor suction (or for us as highpressure turbine fuel or low pressure fuel gas to heaters) (assuming up to 99% control of methane
emissions) using their 2018 projected methane emission estimates. Their analysis assumed
capital costs of $33,700 (for seal oil gas separator, seal oil gas demister for low quality gas, andseal oil gas demister for high quality gas), minimal annual operating costs, and annual productrevenue benefits per centrifugal compressor of $120,000 (assuming $4/Mcf of gas) due to the
reduction of product loss to the atmosphere. The estimated payback period for this control option
was estimated to be three months. In total, the study estimated that methane emissions would be
reduced by 19.1 Bcf (397,567 tons) methane/yr nationally. The study also estimated that VOCemissions would be reduced by 72,800 MT (or approximately 80,226 tons) nationally at a cost of$806/ton of VOC reduced.

5.0

SUMMARY
The EPA has used the data sources, analyses and studies discussed in this paper to form

the Agency’s understanding of vented VOC and methane emissions from centrifugal andreciprocating compressors and the applicable emissions mitigation techniques. The following are42

characteristics the Agency believes are important to understanding this source of VOC andmethane emissions:

Reciprocating compressors may be found throughout the oil and natural gas sector.
Centrifugal compressors are predominantly used in the processing and transmission
segments.

The net 2012 methane emissions reported for compressors for the 2014 GHG Inventory
were 86,259 MT for the natural gas production segment, 724,295 MT for the natural gas
processing segment, and 1,261,080 MT for the natural gas transmission and storage
segment, for a total of 2,071,633 MT of methane.



Reciprocating compressor emissions may be controlled by periodic replacement of rod
packing systems. Additionally, new technologies are being used that capture theseemissions and route them back to the process, both reducing emissions and providing an
economic benefit.

Centrifugal compressor emissions may be controlled by using dry seals in place of wet
seals. Dry seal centrifugal compressors have lower emissions, require less maintenance,
and are more energy efficient that wet seal centrifugal compressors and the cost of thetwo technologies is similar.

When wet seal centrifugal compressors are used, it may be feasible to capture emissions
from the seal oil and route the recovered gas back to the compressor or another process,or combust the gas. Routing the gas back to a process reduces the loss to the atmosphereand reduces the destruction of natural gas.

6.0

CHARGE QUESTIONS FOR REVIEWERS

1. Please comment on the national estimates of methane emissions and methane emission
factors for vented compressor emissions presented in this paper. Please comment on theactivity data and the methodologies used for calculating emission factors presented in thispaper.

43

2. Did this paper appropriately characterize the different studies and data sources that quantify
vented emissions from compressors in the oil and gas sector?
3. Did this paper capture the full range of technologies available to reduce vented emissions
from reciprocating compressors and wet seal centrifugal compressors at oil and gas facilities?
In particular, are there other options for reducing emissions at existing reciprocating or
centrifugal compressors? For example, the EPA is aware of “low emissions packing” forreciprocating compressors but has no detailed information on this technology.
4. Did this paper appropriately characterize the emissions reductions achievable from theemissions mitigation technologies discussed for reciprocating compressors and wet seal
centrifugal compressors?
5. Did this paper appropriately characterize the capital and operating costs for the technologies
discussed for reduction of vented emissions from reciprocating compressors and wet seal
centrifugal compressors?
6. If there are emissions mitigation options for reciprocating and centrifugal compressors thatwere not discussed in this paper, please comment on the pros and cons of those options.
Please discuss the efficacy, cost and feasibly for both new and existing compressors.
7. Are there technical limitations that make the replacement of wet seals with dry seals
impractical at certain existing centrifugal compressors?
8. Are there technical reasons why an operator would use a wet seal centrifugal compressor
without a gas recovery system?
9. Are there technical limitations that make the installation of gas capture systems at certain
reciprocating compressors impractical?
10. Please comment on the prevalence of the different emission mitigation options in the field.
11. Given the substantial benefits of dry seal systems (e.g., lower emissions, less maintenance,and higher efficiency), are you aware of situations where new wet seal centrifugal
compressors are being installed in the field? If so, are there specific applications that require
wet seal compressors?
12. Are there ongoing or planned studies that will substantially improve the current
understanding of vented VOC and methane emissions from reciprocating and centrifugal
compressors and available techniques for increased product recovery and emissions
reductions?
44

7.0

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47