9-1

6.0 COMPRESSORS

Compressors are mechanical devices that increase the pressure of natural gas by reducing its 

volume and allowing the natural gas to be transported from the production site to the consumer. 

The types of compressors that are used by the oil and gas industry are reciprocating and 

centrifugal compressors. This chapter discusses the causes the pollutant emissions from leaks 

from these compressors and provides emission estimates for reducing emission from these types 

of compressors. In addition, nationwide equipment leak emission estimates from new sources 

are estimated. Options for controlling leaks from these compressors are presented, along with 

costs, emission reductions, and secondary impacts. Finally, this chapter discusses considerations 

in developing regulatory alternatives for both reciprocating and centrifugal compressors.

6.1 Process Description

6.1.1 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. Emissions occur when natural gas leaks 

around the piston rod during compression of the natural gas in the cylinder. The compressor 

rod packing system consists of a series of flexible rings that seal the cylinder preventing the 

compressed gas from leaking. However, during operation of the compressor, the rings become 

worn and the packing system will need to be replaced to prevent excessive leaking from the 

compression cylinder. 

6.1.2 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 in the 

production and transmission systems. Many centrifugal compressors use wet seals around the 

rotating shaft to prevent natural gas from escaping from the compressor casing. The wet seals 

use oil which is circulated at high pressure to form a barrier against compressed natural gas 
9-2

leakage. However, the circulated oil absorbs the compressed natural gas and is released to the 

atmosphere during the recirculation process. Alternatively, dry seals can be used to replace the 

wet seals in centrifugal compressors. Dry seals prevent leakage by using the opposing force 

created by hydrodynamic groves and static pressure. This opposing force pushes the rings 

together around the piston rod and prevents the compressed natural gas from escaping. The rings 

also do not wear or need lubrication, because the rings are not in contact with each other. 

Therefore, operation and maintenance costs are lower for dry seals in comparison to wet seals.

6.2 Emissions Data and Emission Factors

6.2.1 Summary of Major Studies and Emissions Factors

There are a few studies that have been conducted that provide leak estimates from reciprocating 

and centrifugal compressors. These studies are provided in Table 6-2, along with the type of 

information contained in the study. 

6.2.2 Representative Reciprocating and Centrifugal Compressor Emissions

The methodology for estimating emission from reciprocating compressor seals was to use the 

methane emission factors referenced the EPA/GRI study1and use the methane to pollutant ratios 

developed in the gas composition memorandum.2 The emission factors in the EPA/GRI 

document were expressed in thousand standard cubic feet per cylinder (Mscf/cyl), and were 

multiplied by the average number of cylinder 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. A summary of the methane emission factors is presented in Table 6-2. Once the 

methane emissions were calculated, ratios were used to estimate volatile organic compounds 

(VOC) and hazardous air pollutants (HAP). The specific ratios that were used for this analysis 

were 0.278 pounds VOC per pound of methane and 0.105 pounds HAP per pound of methane for 

the production and processing segments, and 0.0277 pounds VOC per pound of methane and 

0.0.0008 pounds HAP per pound of methane for the transmission and storage segments. A 

summary of the reciprocating compressor emissions are presented in Table 6-3.
9-3

Table 6-1. Major Studies Reviewed for Consideration

Of Emissions and Activity Data

Report Name Affiliation Year of 

Report

Activity 

Data

Emissions 

Data

Control 

Information

Inventory of Greenhouse 

Gas Emissions and Sinks: 

1990-20081

U.S. 

Environmental 

Protection 

Agency

2010 Nationwide X

Greenhouse Gas 

Mandatory Reporting 

Rule and Technical 

Supporting Document2

U.S. 

Environmental 

Protection 

Agency

2010 Nationwide X

Methane Emissions from 

the Natural Gas Industry3

Gas Research 

Institute/U.S. 

Environmental 

Protection 

Agency

1996 Nationwide X

Natural Gas Star 

Program4,5

U.S. 

Environmental 

Protection 

Agency

2000-2010 Nationwide X X

 
9-4

Table 6-2. Methane Emission Factors for Reciprocating and Centrifugal Compressors 

Oil and Gas 

Industry 

Segment

Reciprocating Compressors Centrifugal Compressors

Methane 

Emission 

Factor (scf/hrcylinder)

Average 

Number of 

Cylinders

Pressurized 

Factor (% of 

hr/yr 

Compressor 

Pressurized)

Wet Seal 

Methane 

Emission 

Factor 

(scf/min)

Dry Seals 

Methane 

Emission 

Factor 

(scf/min)

Production 

(Well Pads)

0.271 4 100% N/Aa N/Aa

Gathering & 

Boosting

25.9 3.3 79.1% N/Aa N/Aa

Processing 57 2.5 89.7% 47.7 6

Transmission 57 3.3 79.1% 47.7 6

Storage 51 4.5 67.5% 47.7 6

a

 Centrifugal compressors were not found at oil and gas production facilities or gathering and 

boosting stations, therefore no emission factor data were published.
9-5

Table 6-3. Baseline Emission Estimates for Reciprocating and Centrifugal Compressors 

Industry Segment/

Compressor Type Methane (Tons/yr) VOC (Tons/yr) HAP (Tons/yr)

Reciprocating Compressors

Production (Well Pads) 0.198 0.0549 0.00207

Gathering & Boosting 12.3 3.42 0.129

Processing 23.3 6.48 0.244

Transmission 27.1 0.0751 0.0223

Storage 28.2 0.782 0.0232

Centrifugal Compressors (Wet seals)

Processing 228 20.5 0.736

Transmission 126 3.50 0.104

Storage 126 3.50 0.104

Centrifugal Compressors (Dry seals)

Processing 28.6 2.58 0.0926

Transmission 15.9 0.440 0.0131

Storage 15.9 0.440 0.0131

The compressor emission factors for wet seals and dry seals are based on data collected in the 

GHG inventory. The wet seals methane emission factor was calculated based on a sampling of 

48 wet seal centrifugal compressors. The dry seal methane emission factor was based on test 

data collected in the Natural Gas Star program. The methane emissions were converted to VOC 

and HAP emissions using the same gas composition ratios that were used for reciprocating 

engines. A summary of the emission factors are presented in Table 6-2 and the individual 

compressor emission are shown in Table 6-3 for each of the oil and gas industry segments.
9-6

6.3 Nationwide Emissions from New Sources

6.3.1 Approach

Nationwide emission estimates for new sources were determined by calculating the annual 

number of new reciprocating and centrifugal compressors installed over the past few years and 

using that data to determine the expected number of new sources. The expected number of new 

sources would then be multiplied by the expected emissions per compressor using the emission 

data in Table 6-3. A summary of the number of new reciprocating and centrifugal compressors 

for each of the oil and gas segments is presented in Table 6-4.

6.3.2 Activity Data for Reciprocating Compressors

6.3.2.1 Wellhead Reciprocating Compressors

The number of wellhead reciprocating compressors was estimated using data from industry 

comments on Subpart W. The 2010 U.S. GHG Inventory reciprocating compressor activity data 

was not considered in the analysis because it does not distinguish between wellhead and 

gathering and boosting compressors. Therefore, data submitted to EPA during the subpart W 

comment period from nine basins supplied by the El Paso Corporation, the average number of 

new wellhead compressors per new well was calculated. The average wellhead compressors per 

well was multiplied by the total well completions determined from the HPDI® database between 

2007 and 2008, which came to 68,000 new well completions. This methodology estimates a 

total of 6,000 new reciprocating compressors located at well pads for 2008. A summary of the 

number of new reciprocating engines located at well pads is presented in Table 6-4.

6.3.2.2 Gathering and Boosting Reciprocating Compressors

The number of gathering & boosting reciprocating compressors was also estimated using data 

from industry comments on Subpart W. DCP Midstream stated on page 3 of its 2010 Subpart W 

comments that it operates 48 natural gas processing plants and treaters and 700 gathering system 

compressor stations. Using this data, there were an average of 14.583 gathering and boosting 

compressor stations per processing plant. The new gathering and boosting compressors was 

determined by taking the average difference between the number of processing plants for each
9-7

Table 6-4. Approximate Number of New Sources in the Oil and Gas Industry in 2008

Industry Segment Number of New Reciprocating 

Compressors

Number of New Centrifugal 

Compressors

Wellheads 6,000 0

Gathering and Boosting 210 0

Processing 375 16

Transmission 199

14

Storage 9

year in the 2010 U.S Inventory, which references the total processing plants in the Oil and Gas 

Journal. This was done for each year up to 2008. An average was taken of only the years with 

an increase in processing plants, up to 2008. The resulting average was multiplied by the 14.583 

ratio of gathering and boosting compressor stations to processing plants and the 1.5 gathering 

and boosting compressors per station yielding 210 new source gathering and boosting 

compressor stations and is shown in Table 6-4.

6.3.2.3 Processing Reciprocating Compressors

The number of new processing reciprocating compressors at processing facilities was estimated 

by averaging the increase of reciprocating engines at processing plants in the greenhouse gas 

inventory data for 2007, 2008, and 2009. The number of existing reciprocating compressors was 

4,458, 4,781, and 4,876 for the Years 2007, 2008, and 2009 respectively. This calculated to be 

655 new reciprocating compressors between 2007 and 2008, and 95 new reciprocating 

compressors between 2008and 2009. The average difference was calculated to be 209

reciprocating compressors and was used to estimate the number of new sources in Table 6-4.

6.3.2.4 Transmission and Storage Reciprocating Compressors
9-8

The number of new transmission and storage reciprocating compressors was estimated using the 

differences in the greenhouse gas inventory data for 2007, 2008, and 2009 and calculating an 

average of those differences. The number of existing reciprocating compressors at transmission 

stations was 6,799, 7,028, and 7,197 for the Years 2007, 2008, and 2009 respectively. This 

calculated to be 299 new reciprocating compressors between 2007 and 2008, and 169 new 

reciprocating compressors between 2008and 2009. The average difference was calculated to be 

199 reciprocating compressors and was used to estimate the number of new sources at 

transmission stations. The number of existing reciprocating compressors at storage stations was 

1,135, 1,178, and 1,152 for the Years 2007, 2008, and 2009 respectively. This calculated to be 

43 new reciprocating compressors between 2007 and 2008, and -26 new reciprocating 

compressors between 2008 and 2009. The average difference was calculated to be 9 

reciprocating compressors and was used to estimate the number of new sources at storage 

stations in Table 6-4.

6.3.3 Activity Data for Centrifugal Compressors

The number of new centrifugal compressors in 2008 for the processing and transmission/storage 

segments was determined by taking the average difference between the centrifugal compressor 

activity data for each year in the 2008 U.S. Inventory . For example, the number of compressors 

in 1992 was subtracted from the number of compressors in 1993 to determine the number of new 

centrifugal compressors in 1993. This was done for each year up to 2008. An average was taken 

of only the years with an increase in centrifugal compressors, up to 2008, to determine the 

number of new centrifugal compressors in 2008. The result was 16 and 14 new centrifugal 

compressors in the processing and transmission segments respectively. A summary of the 

estimates for new centrifugal compressor is presented in Table 6-4.

6.3.4 Emission Estimates

Nationwide baseline emission estimates for new reciprocating and centrifugal compressors are 

summarized in Table 6-6 by industry segment. 
9-9

Table 6-5. Nationwide Baseline Emissions for New Reciprocating and Centrifugal 

Compressors 

Industry Segment/

Compressor Type Methane (Tons/yr) VOC (Tons/yr) HAP (Tons/yr)

Reciprocating Compressors

Production (Well Pads) 1,186 330 12.4

Gathering & Boosting 2,587 719 27.1

Processing 4,871 1,354 51.0

Transmission 529 14.6 0.435

Storage 113 3.13 0.0929

Centrifugal Compressors

Processing 3,640 329 11.8

Transmission/Storage 1,768 48.9 1.45

6.4 Control Techniques

The potential control options reviewed for reducing emissions from reciprocating engines 

include control techniques that limit the leaking of natural gas from the piston rod. This includes 

replacement of the compressor rod packing, replacement of the piston rod, and the refitting or 

realignment of the piston rod. 

The replacement of the rod packing is a maintenance task performed on reciprocating engines to 

reduce the leakage of natural gas from the piston rod. Over time the packing rings wear and 

allow natural gas to escape around the piston rod. Regular replacement of these rings reduces 

methane and VOC emissions, and allow for correct operation of the compressor. Therefore, this 

control technique was determined to be an appropriate option for reciprocating compressors.

Like the packing rings, piston rods on reciprocating engines also deteriorate. Piston rods, 

however, wear more slowly than packing rings, having a life of about 10 years. Rods wear “outof-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. An out-of-round shaft not only 
9-10

seals poorly, allowing more leakage, but also causes uneven wear on the seals, thereby 

shortening the life of the piston rod and the packing seal. 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 the rod. This analysis 

assumes operators will choose, at their discretion, when to replace the rod and hence, does not 

consider this control technique to be a practical control option for reciprocating compressors. A 

summary of these techniques are presented in the following sections.

Potential control options to reduce emission from centrifugal compressors include control 

techniques that limit the leaking of natural gas from the rotating shaft, or capture and destruction 

of the emissions using a flare. A summary of these techniques are presented in the following 

sections.

High rod packing emissions can also result from misaligned rod and rings. Therefore, although a 

reciprocating compressor may have high rod packing emissions it may not indicate the need to 

replace the rod or rings, but rather a need to refit the rings or realign the rod. It was determined 

that this control technique was not a reasonable control option for reciprocating compressors, 

because it is difficult to ascertain the alignment of the piston rod.

A control technique for limiting or reducing the emission from the rotating shaft of a centrifugal 

compressor is a mechanical dry seal system. This control technique uses rings to prevent the 

escape of natural gas from the rotating shaft. This control technique was determined to be a 

viable option for reducing emission from centrifugal compressors.

For centrifugal compressors equipped with wet seals, a flare was consider to be a reasonable 

option for reducing emissions from centrifugal compressors. Centrifugal compressors require 

seals around the rotating shaft to prevent natural gas from escaping where the shaft exits the 

compressor casing. The more common “beam” type compressors have two seals, one on each 

end of the compressor, while “over-hung” compressors have a seal on only the “inboard” (motor) 

side. These seals use oil, which is circulated under high pressure between three rings around the 

compressor shaft, forming a barrier against the compressed gas leakage. 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 leak 
9-11

barrier. The seal also includes “O-ring” rubber seals, which prevent leakage around the 

stationary rings. The oil barrier allows some gas to escape from the seal, but considerably more 

gas is absorbed by the oil under the high pressures at the “inboard” (compressor side) seal oil/gas 

interface, thus contaminating the seal oil. Seal oil is purged of the absorbed gas (using heaters, 

flash tanks, and degassing techniques) and recirculated back to the seal. The recovered gas 

would then be sent to a flare or other combustion device. 

6.4.1 Reciprocating Compressor Rod Packing Replacement

6.4.1.1 Description

Reciprocating compressor rod packing consists of a series of flexible rings that fit around a shaft 

to create a seal against leakage. As the rings wear, they allow more compressed gas to escape, 

increasing rod packing emissions. Rod packing emissions typically occur around the rings from 

slight movement of the rings in the cups as the rod moves, but can also occur through the “nose 

gasket” around the packing case, between the packing cups, and between the rings and shaft. If 

the fit between the rod packing rings and rod is too loose, more compressed gas will escape. 

Periodically replacing the packing rings ensures the correct fit is maintained between packing 

rings and the rod. Packing rings are typically made out of bronze; however, this material is 

gradually being replaced by carbon-impregnated Teflon. Teflon rings are expected to last about 

one year longer than conventional bronze rings. 

6.4.1.2 Effectiveness

As discussed above, regular replacement of the reciprocating compressor rod packing can reduce 

the leaking of natural gas from the piston rod. The potential emission reductions were calculated 

by comparing the average rod packing emissions with the average emissions from newly 

installed rod packing. Since the estimate for newly installed rod packing was intended for larger 

processing and transmission compressors, this analysis uses the estimate to calculate reductions 

from only gathering and boosting compressors and not wellhead compressor which are known to 

be smaller. The calculation for gathering and boosting reductions is shown in the Equation 1

below.
9-12

6

&

&

&

10

Comp E E C O 8760

R

G B New

G B

G B New

W P

Equation 1

where,

G B RWP& = Potential methane emission reductions from gathering and boosting compressors 

switching from wet seals to dry seals, in million cubic feet per year (MMcf/year);

G B CompNew& = Number of new gathering and boosting compressors;

EG&B = Methane emission factor for gathering and boosting compressors in Table 6-2, in 

cubic feet per hour per cylinder;

ENew = Average emissions from a newly installed rod packing, assumed to be 11.5 cubic 

feet per hour per cylinder3for this analysis;

C = Average number of cylinders for gathering and boosting compressors in Table 6-2; 

O = Percent of time during the calendar year the average gathering and boosting 

compressor is in the operating and standby pressurized modes, 79.1%;

8760 = Number of days in a year;

106 = Number of cubic feet in a million cubic feet.

For wellhead reciprocating compressors, this analysis calculates 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 to determine methane emission reductions. The 

calculation for wellhead compressor reductions is shown in Equation 2 below.

Trans

Well Trans New

Well

New

Well E

Comp E C O E E

R 6

10

8760

Equation 2

where,

RWell = Potential methane emission reductions from wellhead compressors switching 

from wet seals to dry seals, in million cubic feet per year (MMcf/year);

Well CompNew = Number of new wellhead compressors;

EWell = Methane emission factor for wellhead compressors from Table 6-2, cubic feet per 

hour per cylinder;

C = Average number of cylinders for wellhead compressors in Table 6-2; O = Percent of 

time during the calendar year the average gathering and boosting compressor is in the 

operating and standby pressurized modes, 100%;

ETrans = Methane emissions factor for transmission compressors from Table 6-2 in cubic 

feet per hour per cylinder;

ENew = Average emissions from a newly installed rod packing, assumed to be 11.5 cubic 

feet per hour per cylinder4for this analysis;
9-13

8760 = Number of days in a year;

106 = Number of cubic feet in a million cubic feet.

The emission reductions for the processing, transmission, and storage segments were calculated 

by multiplying the number of new reciprocating compressors in each segment by the difference 

between the average rod packing emission factors in Table 6-2 by the average emission factor

from newly installed rod packing. This calculation, shown in the Equation 3 below, was 

performed for each of the natural gas processing, transmission, and storage/LNG sectors.

6

&

10

Comp E E C O 8760

R

G B New

PTS

New

PTS

Equation 3

where,

RPTS = Potential methane emission reductions from processing, transmission, or storage

compressors switching from wet seals to dry seals, in million cubic feet per year 

(MMcf/year);

PTS CompNew = Number of new processing, transmission, or storage compressors;

EG&B = Methane emission factor for processing, transmission, or storage compressors in 

Table 6-2, in cubic feet per hour per cylinder;

ENew = Average emissions from a newly installed rod packing, assumed to be 11.5 cubic 

feet per hour per cylinder5for this analysis;

C = Average number of cylinders for processing, transmission, or storage compressors in 

Table 6-2; 

O = Percent of time during the calendar year the average processing, transmission, or 

storage compressor is in the operating and standby pressurized modes, 89.7%, 79.1%, 

67.5% respectively;

8760 = Number of days in a year;

106 = Number of cubic feet in a million cubic feet.

A summary of the potential emission reductions for reciprocating rod packing replacement for 

each of the oil and gas segments is shown in Table 6-6. The emissions of VOC and HAP were 

calculated using the methane emission reductions calculated above the gas composition6for each 

of the segments. Reciprocating compressors in the processing sector were assumed to be used to 

compress production gas.
9-14

Table 6-6. Estimated Annual Reciprocating Compressor Emission Reductions from Replacing Rod Packing

Oil & Gas Segment

Number of

New Sources 

Per Year

Individual Compressor Emission Reductions 

(Tons/yr) Nationwide Emission Reductions (Tons/yr)

Methane VOC HAP Methane VOC HAP

Production (Well 

Pads) 6,000 0.158 0.0439 0.00165 947 263 9.91

Gathering & 

Boosting 210 6.84 400 0.0717 1,437 400 15.1

Processing 375 18.6 5.18 0.195 3,892 1,082 40.8

Transmission 199 21.7 0.600 0.0178 423 11.7 0.348

Storage 9 21.8 0.604 0.0179 87.3 2.42 0.0718
9-15

6.4.1.3 Cost Impacts

Costs for the replacement of reciprocating compressor rod packing were obtained from a Natural 

Gas Star Lessons Learned document7 which estimated the cost to replace the packing rings to be 

$1,620 per cylinder. It was assumed that rod packing replacement would occur during planned 

shutdowns and maintenance and therefore, no travel costs will be incurred for implementing the 

rod packing replacement program. In addition, no costs were included for monitoring because 

the rod packing placement is based on number of hours that the compressor operates in the 

pressurized mode. The replacement of rod packing for reciprocating engine occurs on average 

every four years based on industry information from the Natural Gas Star program. The cost 

impacts are based on the replacement of the rod packing every three years or 26,000 hours that 

the reciprocating compressor operates in the pressurized mode. This calculates to an average of 

3 years for production compressors, 3.8 years for gathering and boosting compressors, 3.3 years 

for processing compressors, 3.8 years for transmission compressors, and 4.4 years for storage 

compressors using the pressurized factors in Table 6-2. The calculated years were assumed to be 

the equipment life of the compressor rod packing and were used to calculate the capital recovery 

factor for each of the segments. Assuming an interest rate of 7%, the capital recovery factors 

were calculated to be 0.3848, 0.3122, 0.34901, 0.3122, and 0.2720 for the production, gathering 

and boosting, processing, transmission, and storage sectors, respectively. The capital costs were 

calculated using the average rod packing cost of $1,620 and the average number of cylinders per 

segment in Table 6-2. The annual costs were calculated using the capital cost and the capital 

recovery factors. A summary of the capital and annual costs for each of the oil and gas segments 

is shown in Table 6-7.

Monetary savings associated with the amount of gas saved with reciprocating compressor rod 

packing replacement was estimated using a natural gas price of $4.00 per Mcf.8 This cost was 

used to calculate the annual cost with gas savings using the methane emission reductions in 

Table 6-6. The annual cost with savings is shown in Table 6-7 for each of the oil and gas 

segments. The cost effectiveness for the reciprocating rod packing replacement option is 

presented in Table 6-7. There are no gas savings cost benefits for transmission and storage 

facilities, because they do not own the natural gas that is compressed at their compressor 

stations.
9-16

6.4.1.4 Secondary Impacts

The reciprocating compressor rod packing replacement is an option that prevents the escape of 

natural gas from the piston rod. No wastes should be created, no wastewater generated, and no 

electricity needed. Therefore, there are no secondary impacts expected due to the replacement of 

reciprocating compressor rod packing.

6.4.2 Centrifugal Compressor Dry Seals

6.4.2.1 Description

Centrifugal compressor dry seals operate mechanically under the opposing force created by 

hydrodynamic grooves and static pressure. The hydrodynamic grooves are etched into the 

surface of the rotating ring affixed to the compressor shaft. When the compressor is not rotating, 

the stationary ring in the seal housing is pressed against the rotating ring by springs. When the 

compressor shaft rotates at high speed, compressed gas has only one pathway to leak down the 

shaft, 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 the 

rings and springs trying to push the rings together creates a very thin gap between the rings 

through which little gas can leak. While the compressor is operating, the rings are not in contact 

with each other, and therefore, do not wear or need lubrication. O-rings seal the stationary rings 

in the seal case. 

Dry gas seals substantially reduce methane emissions. At the same time, they significantly 

reduce operating costs and enhance compressor efficiency. Economic and environmental 

benefits of dry seals include:

Gas Leak Rates. During normal operation, dry seals leak at a rate of 0.5 to 3 scfm across 

each seal, depending on the size of the seal and operating pressure. While this is 

equivalent to a wet seal’s leakage rate at the seal face, wet seals generate additional 

emissions during degassing of the circulating oil. Gas from the oil is usually vented to 

the atmosphere, bringing the total leakage rate for dual wet seals to between 40 and 200 

scfm, depending on the size and pressure of the compressor.
9-17

Table 6-7. Cost Effectiveness for Reciprocating Compressor Rod Packing Replacement

Oil and Gas 

Segment

Capital Cost 

($2008)

Annual Cost per Compressor 

($/yr) VOC Cost Effectiveness ($/Ton) Methane Cost Effectiveness ($/Ton)

Without 

savings With savings Without savings With savings Without savings With savings

Production $6,480 $2,493 $2,457 $56,847 $56,013 $15,802 $15,570

Gathering & 

Boosting $5,346 $1,669 $83 $877 $43 $244 $12

Processing $4,050 $1,413 -$2,903 $273 -$561 $76 -$156

Transmission $5,346 $1,669 N/A $2,782 N/A $77 N/A

Storage $7,290 $2,276 N/A $3,766 N/A $104 N/A
9-18

Mechanically Simpler. Dry seal systems do not require elaborate 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 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, which 

translates into higher overall reliability and less compressor downtime.

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).

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 and 

degradation of the pipeline.

Centrifugal compressors were only found in the processing and transmission sectors based on 

information in the greenhouse gas inventory.

9

 Therefore, it was assumed that new compressors 

would be located in these sectors only. 

6.4.2.2 Effectiveness

The control effectiveness of the dry seals was calculated by subtracting the dry seal emissions 

from a centrifugal compressor equipped with wet seals. Using the centrifugal compressor 

emission factors in Table 6-2 and 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.10 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 Natural Gas Star 

program.

11

 A summary of the emission reduction from the replacement of wet seals with dry 

seals is shown in Table 6-8.
9-19

Table 6-8. Estimated Annual Centrifugal Compressor Emission Reductions from Replacing Wet Seals with Dry Seals

Oil & Gas Segment

Number of 

New Sources 

Per Year

Individual Compressor Emission Reductions 

(Tons/yr) Nationwide Emission Reductions (Tons/yr)

Methane VOC HAP Methane VOC HAP

Transmission/Storage 16 199 18.0 0.643 3,183 287 10.3

Storage 14 110 3.06 0.0908 1,546 42.8 1.27
9-20

6.4.2.3 Cost Impacts

The price difference between a brand new dry seal and brand new wet seal centrifugal 

compressor is insignificant relative to the cost for the entire compressor. General Electric (GE) 

stated that a natural gas transmission pipeline centrifugal compressor with dry seals cost between 

$50,000 and $100,000 more than the same centrifugal compressor with wet seals. However, this 

price difference is only about 1 to 3 percent of the total cost of the compressor. The price of a 

brand new natural gas transmission pipeline centrifugal compressor between 3000 and 5000 

horsepower runs between $2 million to $5 million depending on the number of stages, desired 

pressure ratio, and gas throughput. The larger the compressor, the less significant the price 

difference is between dry seals and wet seals. This analysis assumes the additional capital cost 

for a dry seal compressor is $75,000. The annual cost was calculated as the capital recovery of 

this capital cost assuming a 10-year equipment life and 7% interest and came to $10,678 per 

compressor. The Natural Gas Star program estimated that the operation and maintenance 

savings from the installation of dry seals is $88,300 in comparison to wet seals. Monetary 

savings associated with the amount of gas saved with reciprocating compressor rod packing 

replacement was estimated using a natural gas price of $4.00 per Mcf.12 This cost was used to 

calculate the annual cost with gas savings using the methane emission reductions in Table 6-8. 

A summary of the capital and annual costs for dry seals is presented in Table 6-9. The methane 

and VOC cost effectiveness for the dry seal option is also shown in Table 6-9. There is no gas 

savings cost benefits for transmission and storage facilities, because they do not own the natural 

gas that is compressed at their compressor stations.
9-21

Table 6-9. Cost Effectiveness for Centrifugal Compressor Dry Seals

Oil and Gas Segment

Capital 

Cost 

($2008)

Annual Cost per Compressor 

($/yr) VOC Cost Effectiveness ($/Ton) Methane Cost Effectiveness ($/Ton)

Without savings With O&M and 

gas savings Without savings

With O&M 

and gas 

savings

Without 

savings

With O&M and 

gas savings

Processing $75,000 $10,678 -$123,730 $595 -$6,892 $54 -$622

Transmission/Storage $75,000 $10,678 -$77,622 $3,495 -$25,405 $97 -$703
9-22

6.4.1.4 Secondary Impacts

Dry seals for centrifugal compressors are an option that prevents the escape of natural gas from 

the rotating compressor shaft. No wastes should be created, no wastewater generated, and no 

electricity needed. Therefore, there are no secondary impacts expected due to the installation of 

dry seals on centrifugal compressors.

6.4.2 Centrifugal Compressor Wet Seals with a Flare

6.4.3.1 Description

Wet seals are another option to limit the escape of natural gas from the rotating shaft of the 

centrifugal compressor. The seal uses a fluid 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 

leak barrier. Compressor gas become entrained in the fluid barrier and is removed using a heater, 

flash tank, or other degassing technique and recirculated back to the wet seal. The removed gas 

is either flared or released to the atmosphere. The control technique investigated in this 

document is the use of wet seals with the removed gas sent to an enclosed flare. 

6.4.3.2 Effectiveness

Flares have been used in the oil and gas industry to combust gas streams that have VOC and 

HAP. A flare typically achieves 95% reduction of these compounds when operated according to 

the manufacturer instructions. For this analysis, it was assumed that the entrained gas from the 

seal fluid that is removed in the degassing process would be directed to a flare that achieves 95% 

reduction of methane, VOC, and HAP. The wet seal emissions in Table 6-5 were used along 

with the control efficiency to calculate the emissions reductions from this option. A summary of 

the emission reductions is presented in Table 6-10.
9-23

Table 6-10. Estimated Annual Centrifugal Compressor Emission Reductions from Wet Seals Routed to a Flare

Oil & Gas Segment

Number of 

New Sources 

Per Year

Individual Compressor Emission Reductions 

(Tons/yr) Nationwide Emission Reductions (Tons/yr)

Methane VOC HAP Methane VOC HAP

Transmission/Storage 16 216 19.5 0.699 3,640 329 11.8

Storage 14 120 3.32 0.0986 1,768 48.9 1.45
9-24

6.4.3.3 Cost Impacts

The capital and annual cost of the enclosed flare calculated using the methodology in the EPA 

Control Cost Manual.13 The heat content of the gas stream was calculated using information 

from the gas composition memorandum.14 A summary of the capital and annual costs for wet 

seals routed to a flare is presented in Table 6-11. The methane and VOC cost effectiveness for 

the dry seal option is also shown in Table 6-11. There are no gas savings cost benefits for this 

option because the recovered gas is combusted.

6.4.3.4 Secondary Impacts

There are secondary impacts with the option to install wet seals with a flare. The combustion of 

the recovered gas creates secondary emissions of hydrocarbons. nitrogen oxide (NOX), carbon 

dioxide (CO2), and carbon monoxide (CO) emissions. A summary of the estimated secondary 

emission are presented in Table 6-11. No other wastes should be created or wastewater 

generated. 

Table 6-11. Secondary Impacts from Wet Seals Equipped with a Flare

Industry Segment

Total 

Hydrocarbons 

(Tons/yr)

Carbon 

Monoxide 

(Tons/yr)

Carbon 

Dioxide 

(Tons/yr)

Nitrogen 

Oxides 

(Tons/yr)

Particulate 

Matter 

(Tons/yr)

Processing 0.0289 0.0205 7.33 0.00377 Negligible

Transmission/Storage 0.00960 0.00889 3.18 0.00163 Negligible
9-25

Table 6-12. Cost Effectiveness for Centrifugal Compressor Wet Seals Routed to a Flare

Oil and Gas Segment

Capital 

Cost 

($2008)

Annual Cost per Compressor 

($/yr) VOC Cost Effectiveness ($/Ton) Methane Cost Effectiveness ($/Ton)

Without savings With gas 

savings Without savings With gas savings

Without 

savings With gas savings

Processing $67,918 $103,371 N/A $5,299 N/A $478 N/A

Transmission/Storage $67,918 $103,371 N/A $31,133 N/A $862 N/A
9-26

6.5 Regulatory Options

The affected facility definition for 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. A centrifugal Compressor is defined as a piece of equipment that 

compresses a process gas by means of mechanical rotating vanes or impellers. Therefore these 

types of compressor would be subject to a New Performance Standard (NSPS) at the time of 

installation. The following Regulatory options were evaluated:

Regulatory Option 1: Require replacement of the reciprocating compressor rod packing 

based on 26,000 hours of operation while the compressor is pressurized.

Regulatory Option 2: Require all centrifugal compressors to be equipped with dry seals.

Regulatory option 3: Require centrifugal compressors equipped with a wet seal to route 

the recovered gas emissions to a flare.

6.5.1 Evaluation of Regulatory Options

The first regulatory option for replacement of the reciprocating compressor rod packing based on 

the number of hours that the compressor operates in the pressurized mode was described in 

Section 6.4.1. The VOC cost effectiveness from $56,847 for reciprocating engines located at 

production pads to $273 for reciprocating compressors located at processing plants. The VOC 

cost effectiveness for the gathering and boosting, transmission, and storage segments were $877, 

$2,782, and 3,766 respectively. Based on these cost effectiveness values, Regulatory Option 1 

was accepted for the processing, gathering and boosting, transmission, and storage segments and 

rejected for the production segment. 

The second regulatory option would require all centrifugal compressors to be equipped with dry 

seals. As presented in Section 6.4.2, dry seals are effective at reducing emissions from the 

rotating shaft of a centrifugal compressor. Dry seals also reduce operation and maintenance 

costs in comparison to wet seals. In addition, a vendor reported in 2003 that 90% of new 

compressors that were sold by the company were equipped with dry seals. Another vendor 

confirmed in 2010 that the rate at which new compressor sales have dry seals is still 90%; thus, it 
9-27

was assumed that from 2003 onward, 90% of new compressors are equipped with dry seals. The 

VOC cost effectiveness of dry seals was calculated to be $595 for centrifugal compressors 

located at processing plants, and $3,495 for centrifugal compressors located at transmission or 

storage facilities. Therefore, Regulatory Option 2 was accepted as a regulatory option for 

centrifugal compressors located at processing, transmission, or storage facilities.

The third regulatory option would allow the use of wet seals if the recovered gas emissions were 

routed to a flare. Centrifugal compressors with wet seals are commonly used in high pressure 

applications over 3,000 pounds per square inch (psi). None of the applications in the oil and gas 

industry operate at these pressures. Therefore, it does not appear that any facilities would be 

required to operate a centrifugal compressor with wet seals. The VOC control effectiveness for 

the processing and transmission/storage segments were $5,299 and $31,133 respectively. 

Therefore, Regulatory Option 3 was rejected due to the high VOC cost effectiveness.

6.5.2 Nationwide Impacts of Regulatory Options

Tables 6-13 and 6-14 summarize the impacts of the selected regulatory options by industry 

segment. Regulatory Option 1 is estimated to affect 210 reciprocating compressor at gathering 

and boosting stations, 209 reciprocating compressors at processing plants, 20 centrifugal 

compressors at transmission facilities, and 4 reciprocating compressors at underground storage 

facilities. A summary of the capital and annual costs and emission reductions for this option is 

presented in Table 6-13.

Regulatory Option 2 is expected to affect 16 centrifugal compressors in the processing segment 

and 14 centrifugal compressors in the transmission and storage segments. A summary of the 

capital and annual costs and emission reductions for this option is presented in Table 6-14.
9-28

Table 6-13. Nationwide Cost Impacts for Regulatory Option 1

Oil & Gas Segment

Number of 

New Sources 

Per Year

Nationwide Emission Reductions Total Nationwide Costs

VOC 

(Tons/yr)

Methane 

(Tons/yr)

HAP 

(Tons/yr)

Capital Cost 

($)

Annual Cost 

w/o Savings 

($/yr)

Annual Cost 

w/ Savings 

($/yr)

Gathering & Boosting 210 400 1,437 15.1 $1,122,660 $350,503 $17,337

Processing 209 1,082 3,892 40.8 $846,450 $295,397 -$606,763

Transmission 20 11.7 423 0.348 $104,247 $32,547 $32,547

Storage 4 2.42 87.3 0.0718 $29,160 $9,104 $9,104
9-29

Table 6-14. Nationwide Cost Impacts for Regulatory Option 2

Oil & Gas Segment

Number of 

New Sources 

Per Year

Nationwide Emission Reductions1 Total Nationwide Costs1

VOC 

(Tons/yr)

Methane 

(Tons/yr)

HAP 

(Tons/yr)

Capital Cost 

($)

Annual Cost 

w/o Savings 

($/yr)

Annual Cost 

w/ Savings 

($/yr)

Production (Well Pads) 0 0 0 0 0 0 0

Gathering & Boosting 0 0 0 0 0 0 0

Processing 16 118 422 4.42 $100,196 $14,266 -$120,144

Transmission/Storage 14 3.24 117 0.0962 $50,098 $7,133 -$37,017

1

The nationwide emission reduction and nationwide costs are based on the emission reductions and costs for 2 centrifugal 

compressors with wet seals located a processing facility and 1 centrifugal compressor equipped with wet seal located at a transmission 

or storage facility.
9-30

6.6 References

 

1 National Risk Management Research Laboratory. GRI/EPA Research and Development, 

Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks. 

Prepared for the U.S. Department of Energy, Energy Information Administration. EPA600/R-96-080h. June 1996.

2 Memorandum to Bruce Moore, U.S. Environmental Protection Agency from Heather 

Brown, EC/R. Gas Composition Methodology. July 2011.

3

EPA (2006). Lessons Learned: Reducing Methane Emissions from Compressor Rod 

Packing Systems. Natural Gas STAR. Environmental Protection Agency.

4

EPA (2006). Lessons Learned: Reducing Methane Emissions from Compressor Rod 

Packing Systems. Natural Gas STAR. Environmental Protection Agency.

5

EPA (2006). Lessons Learned: Reducing Methane Emissions from Compressor Rod 

Packing Systems. Natural Gas STAR. Environmental Protection Agency.

6 Memorandum to Bruce Moore, U.S. Environmental Protection Agency from Heather 

Brown, EC/R. Gas Composition Methodology. July 2011.

7

EPA (2006). Lessons Learned: Reducing Methane Emissions from Compressor Rod 

Packing Systems. Natural Gas STAR. Environmental Protection Agency.

8 U.S. Energy Information Administration. Annual U.S. Natural Gas Wellhead Price. 

Energy Information Administration Natural Gas Navigator. Retrieved online on 

December 12, 2010 at <http://www.eia.doe.gov/dnav/ng/hist/n9190us3a.htm>

9

EPA, Inventory of Greenhouse Gas Emissions and Sinks: 1990-2008

10 National Risk Management Research Laboratory. GRI/EPA Research and Development, 

Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks. 

Prepared for the U.S. Department of Energy, Energy Information Administration. EPA600/R-96-080h. June 1996.

11 EPA (2006). Lessons Learned: Reducing Methane Emissions from Compressor Rod 

Packing Systems. Natural Gas STAR. Environmental Protection Agency.

12 U.S. Energy Information Administration. Annual U.S. Natural Gas Wellhead Price. 

Energy Information Administration Natural Gas Navigator. Retrieved online on 

December 12, 2010 at <http://www.eia.doe.gov/dnav/ng/hist/n9190us3a.htm>

13 EPA Air Pollution Control Cost Manual - Sixth Edition, (EPA 452/B-02-001)
9-31

 

14 Memorandum to Bruce Moore, U.S. Environmental Protection Agency from Heather 

Brown, EC/R. Gas Composition Methodology. July 2011.