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 r eciprocating 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 additio n, 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 consideratio ns 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 c ylinder 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 veloc ity 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 ga s from escaping from the compressor casing. The wet seals use oil which is circulated at high pressure to form a barrier against compressed natural gas9

- 2

leakage. However, the circulated oil absorbs the compressed natural gas and is released to the atmosph ere 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 l ower 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 comp ressors. 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 se als was to use the
methane emission factors referenced the EPA/GRI study 1 and 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 aver a ge 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 me thane 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 emissio ns 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

- 2008 1 U.S. Environmental Protection Agency 2010 Nationwide X

Greenhouse Gas Mandatory Reporting Rule and Technical Supporting Document 2 U.S. Environmental Protection Agency 2010 Nationwide X

Methane Emissions from the Natural Gas Industry 3 Gas Research Institute/U.S. Environmental Protection Agency 1996 Nationwide X

Natural Gas Star Program

4,5 U.S.

Environmental Protection Agency 2000

- 2010 Nationwide X X9

- 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/hr

cylinder) 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/A a N/A a

Gathering & Boosting 25.9 3.3 79.1% N/A a N/A a

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 t o 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 a nd 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 dat a 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 s ubpart W

comment perio d 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 we ll 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 re ciprocating 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. DC P 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 sta tions per processing plant. The new gathering and boosting compressors was determined by taking the average difference between the number of processing plants for each9

- 7

Table 6

- 4 . Approximate N umber of New Sources in the Oil and Gas Industry in 2008

Ind ustry 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 aver age 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 2 007, 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

com pressors 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 Compressors9

- 8

The number of new transmission and storage reciprocating compressors was estimated u sing 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 trans mission
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 differenc e 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, an d 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 estima te the number of new sources at storage
stations in Table 6

- 4

.

6 .3. 3 Activity Data for Centrifugal Compressors

T he number of new centrifugal compressors in 2008 for the processing and transmission/storage segments was determined by taking the average diffe rence 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 i n 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

comp ressors 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

Cen trifugal Compressors Processing 3,640 329 11.8 Transmission/Storage 1,768 48.9 1.45

6 .4 Control Techniques

The p otential control options reviewed for reducing emission s from reciprocating engines
include control techniques that limit the leaking of n atural 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 o f 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 a bout 10 years. Rods 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. An out

- of

- round shaft not only9

- 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 recip rocating 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 m ay 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 compr essors, 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 c entrifugal 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

com pressor 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 flowi ng between the rings to both lubricate and act as a leak9

- 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 absor bed 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 sh aft 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, bu t 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 pack ing 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

on e 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 cal culated by comparing the average rod packing emission s 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 E quation 1
below.9

- 12 Equation 1

where,

= Potential methane emission reductions from gathering and boosting compressors switching from wet seals to dry seals, in million cubic feet per year (MMcf/year) ;

= Number of new gathering and boosting compressors ; E G&B = Methane emission factor for gathering and boosting compressors in Table 6

- 2 , in cubic feet per hour per c ylinder ; E New = Average emissions from a newly installed rod packing, assumed to be 11.5 cubic feet per hour per cylinder 3 for 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 ; 10 6 = 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 mini mum 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.

Equation 2
where,

= Potential methane emission reductions from wellhead compressors switching from wet seals to dry seals , in million cubic feet per year (MMcf/year) ;

= Number of new wellhead compressors ; E Well = Methane emission factor for wellhead compressors from Table 6

- 2 , cubic feet per hour per c ylinder ; 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 compr essor is in the operating and standby pressurized modes, 100%; E Trans = Methane emissions factor for transmission compressors from Table 6

- 2 in cubic feet per hour per cylinder ; E New = Average emissions from a newly installed rod packing, assumed to be 11. 5 cubic feet per hour per cylinder 4 for this analysis;9

- 13

8760 = Number of days in a year ; 10 6 = Number of cubic feet in a million cubic feet

. Th e 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 E qua tion 3 below, was performed for each of the natural gas processing, transmission, and storage/LNG sectors.

Equation 3

where,

= 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);

= Number of new processing, transmission, or storage compressors; E G&B = Methane emission factor for processing, transmission, or storage compressors in Table 6

- 2, in cubic feet per hour per cylinder; E New = Average emissions from a newly installed rod packing, assumed to be 11.5 cubic feet per hour per cylinder 5 for this anal ysis ; 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 ; 10 6 = 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 composition 6 fo r 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 0.07189

- 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 document 7 which estimate d 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 pro duction, 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 we re 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 compre ssor rod packing replacement was estimated using a natural gas price of $4.00 per Mcf. 8 Th is 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 natu ral 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 ge nerated, 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 mech anically 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 betwe en 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/A9

- 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 powe r 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 c ompressors 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 contro l 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 cen trifugal compressors and 24.2% for transmission centrifugal compressors. The operating factor s 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 sect ors 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 red uction 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 Compr essor 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 1.279

- 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 pipel ine 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 betwee n 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 tha t 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

- $6 22

Transmission/Storage $75,000 $10,678

- $77,622 $3,495

- $25,405 $ 9 7

- $7039

- 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
elec tricity 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 r emoved 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 manufa cturer instructions. For this analysis, it was assumed that the entr a ined 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 1.459

- 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

t he 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 co mbustion of the recovered gas creates secondary emissions of hydrocarbons. nitrogen oxide (NO X )
, carbon dioxide (CO 2 ), 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 Negligible9

- 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 $3 1
, 133 N/A $ 862 N/A9

- 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 c entrifugal 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 wo uld 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 Eva luation 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 effectiven ess 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 req uire 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 com

parison 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, it9

- 27

was assumed that from 2003 onward, 90% of new compressors a re 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 compres sors 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 opera

te 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 resp ectively. 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 plan ts, 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 T able 6

- 14.9

- 28 Table 6

- 13 . Nationwide Cost Impacts for R egulatory 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 $1 04,247 $ 32,547 $ 32,547

Storage 4 2.42 87.3 0.0718 $ 29,160 $ 9,104 $ 9,1049

- 29 Table 6

- 14 . Nationwide Cost Impacts for Regulatory Option 2

Oil & Gas Segment Number of New Sources Per Year Nationwide Emission Reductions 1 Total Nationwide Costs 1

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 1 18 422 4.42 $ 100,196 $ 14
, 266

- $ 120
, 144

Transmission

/Storage 14 3.24 117 0.0962 $ 50
, 098 $ 7,133

- $3 7 , 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 tra nsmission 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. EPA

600/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: Red ucing 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 Com

position 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 Rese arch 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. EPA

600/R

- 96

- 080h. June 1996.

11 EPA (2006). Lesso ns 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.