Matthew Todd

Regulatory and Scientific Affairs

1220 L Street, NW

Washington, DC 

20005-4070 USA

Telephone: 202-682-8319

Fax: 202-682-8031

Email: ToddM@api.org

www.api.org

June 13, 2014

Mr. Chris Frantz

US EPA 

109 T.W. Alexander Drive

Mail Code: #143-05

Research Triangle Park, NC 27709

Re: EPA VOC/Methane White Paper on Oil and Natural Gas Sector Compressors

Dear Mr. Frantz:

The American Petroleum Institute (API) appreciates the opportunity to provide feedback on EPA’s White 

Papers on Methane and Volatile Organic Compound (VOC) Emissions in the Oil and Natural Gas Sector.

On April 15, 2014, EPA released, for external peer review, white papers that focus on technical issues 

covering emissions and mitigation techniques targeting methane and VOCs from five separate emission 

sources. As noted in the Obama Administration’s Strategy to Reduce Methane Emissions, EPA will use 

the papers, along with the input from the peer reviewers and the public, to determine how to best 

pursue additional reductions from these sources. As described below, API does not believe additional 

methane controls should be required at this time. 

API represents over 590 oil and natural gas companies, leaders of a technology-driven industry that 

supplies most of America’s energy, supports more than 9.8 million jobs and 8 percent of the U.S. 

economy, and, since 2000, has invested nearly $2 trillion in U.S. capital projects to advance all forms of 

energy, including alternatives. Many of our members will be directly impacted by any policy decisions 

that may arise from this effort regardless of whether it informs either regulatory action by the federal 

government or states.

API provided technical feedback and expertise throughout the development of the New Source 

Performance Standard (NSPS) Subpart OOOO rule. Each source addressed by the white papers was 

considered for regulation during the development of the NSPS and EPA, ultimately, chose not to 

regulate them. While our understanding of emissions from oil and gas production continues to evolve,

the fundamental merits of requiring additional regulatory control of these sources is unchanged. As 

such, API continues to believe that no additional regulation of oil and gas production sources is 

necessary prior to the full implementation of the NSPS OOOO rule and a subsequent evaluation of 

emissions.
Page 2

Considering the potential for significant impact on our members that may arise from any policy decision 

stemming from the white papers, API has developed significant technical comments (see attached) to 

address a number of technical inaccuracies about the sources and the conclusions that have been 

drawn. Barring significant revision, API believes that the current white papers are simply insufficient to 

inform sound policy decisions and that simply posting comments on the current version will not result in 

an informed process. As such, API recommends the EPA take the following steps:

 Revise the white papers to correct any fundamental flaws or inaccuracies that were identified in 

response to peer review and stakeholder comment (e.g., improved source descriptions, 

improved understanding of emission quantification, misconceptions about emission mitigation 

options)

 Develop a response to comments document that clearly identify the changes the EPA makes to 

the revised white papers and explains the Agency’s rationale for those changes

 Identify emission studies in progress that will better inform EPA’s understanding of these source 

emissions and await the pending study reports

In recent years, there have been significant swings in the national emission estimates from oil and gas 

production sources, including those covered by the white papers, which indicate a necessity to continue 

collecting data to improve our understanding. Much of this learning will come from improved reporting 

under Subpart W of EPA’s Greenhouse Gas Reporting Program as well as current studies and others 

planned in the coming years, which involve taking direct measurements of the sources. EPA and industry 

would both be well served by allowing these studies to inform policy. 

Again, we appreciate the work by EPA to initiate these white papers and the opportunity to provide 

feedback on this effort. API and its members are dedicated to working with EPA to improve our 

collective understanding of these emissions and providing the technical operator experience that’s 

needed to do so. Recognizing the potential for these white papers to inform not only EPA but other 

government agency policy decisions, we request the opportunity to provide additional feedback to the 

Agency in response to any of our comments in advance. Furthermore, we again offer our experience and 

expertise as EPA moves into the policy evaluation phase of this effort.

Sincerely,

/s/

Matthew Todd

Cc: Peter Tsirigotis, EPA

David Cozzie, EPA

Bruce Moore, EPA
Comments on

Oil and Natural Gas Sector Compressors

By EPA Office of Air Quality Planning and Standards

June 2014

Prepared by

The American Petroleum Institute (API)
API Comments on Submitted to EPA

Oil & Natural Gas Sector Compressors June 13, 2014

Contents

A. Introduction ..........................................................................................................................................4

B. Process Descriptions.............................................................................................................................5

C. Emissions Data and Emissions Estimates..............................................................................................5

D. Available Compressor Emissions Mitigation Techniques....................................................................10

E. Summary .............................................................................................................................................16

F. Charge Questions................................................................................................................................16
API Comments on Submitted to EPA

Oil and Natural Gas Sector Compressors June 13, 2014

2

Executive Summary

The U.S. Environmental Protection Agency (EPA) has developed a draft document titled Oil and Natural

Gas Sector Compressors (referred to as “the White Paper”) to, as stated in the Preface, seek input and 

solidify its understanding of the methane and volatile organic compounds (VOCs) emissions from 

compressors in this industry sector. The American Petroleum Institute (API) hereby submits its input 

and comments in this document.

These comments generally follow the Table of Contents for the Compressors White Paper so that the 

reader can more readily associate them with the White Paper. This review mostly addresses 

reciprocating compressors. Additional answers to charge questions are only made if not previously 

covered in comments. 

In general, the White Paper simply reports emissions information and control technologies reported in 

various studies or papers without a meaningful critique or analysis of the data and recommendations 

provided in those studies/papers. These comments provide some of the needed critique. Following are 

the main findings from API’s review of the White Paper. 

 The White Paper should specifically note that the only emissions study which sampled a 

significant number of reciprocating compressors at oil and gas sites (1996 GRI/EPA) showed low 

vent rates from compressors located at oil and gas production sites. This result makes 

technological sense due to a combination of much lower cylinder suction pressures, smaller 

piston rod diameters, and higher speed (rpms) for compressors located at oil and gas sites. All of 

these parameters, most importantly lower suction pressures, contribute to lower vent rates 

from compressor rod packing from compressors at oil and gas production sites compared to 

compressors located at gathering and booster stations, gas processing plants, and transmission 

stations. 

 The White Paper should note that the 2011 URS/UT study provided no measurements or 

emissions factors for the small reciprocating compressors located at oil and gas production sites. 

The White Paper correctly points out that the 2011 URS/UT centrifugal wet seal measurements 

are suspect and not useful due to technical complications during measurements.

 Going forward, EPA should rely on the GHGRP data as the primary source of measured 

emissions data and compare that data with existing emissions studies, such as the 1996 GRI/EPA 

study, and other wet seal emissions estimates from subsequent EPA Papers. EPA should use the 

2012, 2013 and later data to develop emissions factors for compressors in processing and other 

downstream applications based on a select number of variables such as compressor operating 

pressures, compressor frames (piston rod size), speed, etc. The GHGRP already uses emission 

factors for compressors in production, which is an appropriate approach (see discussion in the 

first bullet above). 

 The most important takeaway from the 2012 API/ANGA study, as mentioned in the White

Paper, is that the percentage of centrifugal compressors in all sectors of the industry that are 
API Comments on Submitted to EPA

Oil and Natural Gas Sector Compressors June 13, 2014

3

equipped with wet seals is much lower than the 80% assumed by EPA for the U.S. GHG 

Inventory. The API/ANGA data suggests only 21% wet seals in U.S. service. Initial review of 2011 

and 2012 GHGRP Subpart W data for the transmission sector suggests a range of 35-50% (the 

U.S. GHG Inventory assumes 90% wet seals for this segment). 

 The White Paper failed to mention the most important information from Table 6-7 in the July 

2011 TSD for the Subpart OOOO proposed rule, which is the VOC and methane control cost 

effectiveness data in $/ton. In short, the cost effectiveness for midstream sectors (i.e., 

processing, gathering & boosting) was less than $1,000 per ton of VOC, and EPA determined this 

to be sufficient to include a Subpart OOOO requirement to replace rod packing every 26,000 

hours for gas processing and gathering compression. The cost effectiveness for the production 

sector, even with cost of methane saved considered, was extremely high at approximately 

$56,000/ton of VOC and $16,000/ton of methane. Downstream sectors (transmission and 

storage) were excluded due to VOC cost effectiveness of $2,800 per ton or higher, and minimal 

VOC reductions. 

 The White Paper reports results from the 2014 ICF/EDF cost/benefit analysis of rod packing 

replacement (every 3 years instead of every 5 years) as providing a payback of seven months; 

however, the White Paper does not explain, or critique, the assumptions used by ICF in their 

cost/benefit analysis. In their cost/benefit analysis, ICF assumes a linear increase in vent rates 

for three years, from 11.5 scf/yr-cylinder to 57 scf/yr-cylinder, followed by an unspecified 

percentage linear increase for two years. This technique is a misuse of the 57 scf/hr/cylinder 

average emissions factor for compressors in the gas processing and transmission sectors 

obtained from the 1996 GRI/EPA study. The 57 scf/yr-cylinder factor is a statistical average from 

a large measured data set which, theoretically, should include emissions from rod packing at 

various years of life, from almost new to close to end of life. This average emissions factor 

should be applied in a cost/benefit analysis in the method used by EPA in the TSD for Subpart 

OOOO. In addition, it is inappropriate to presume linear vent range changes unless it is 

substantiated with real data. Vent rate changes over time due to wear are not likely to be 

linear.

 Any future EPA discussion of rod packing replacement cost effectiveness for the oil and gas 

production sector should consider, as mentioned on page 3-13 of the 2014 ICF/EDF Paper, (1) 

the remote location of these compressors, (2) that many of the compressors are leased rather 

than owned, and, most importantly, (3) that there is typically not a back-up compressor for use 

during downtime; therefore, one or more wells must be shut-in to replace rod packing on a 

compressor if replacement is done at intervals separate from other major maintenance. 

Therefore, the cost of lost production must be included in any future cost/benefit analysis for 

rod packing replacement for reciprocating compressors in the production sector. Alternatives 

to prescribed maintenance intervals, such as condition based maintenance where vent rates are 

monitored over time, should be considered.
API Comments on Submitted to EPA

Oil and Natural Gas Sector Compressors June 13, 2014

4

A. Introduction

The American Petroleum Association (API) appreciates the opportunity to present this set of comments 

on EPA’s pre-dissemination draft Oil and Natural Gas Sector Compressors, Report for Oil and Natural Gas 

Sector Compressor (U.S. EPA 2014, subsequently referred to in this document as “the EPA White Paper”, 

or “the White Paper”). 

The White Paper mentions that “over half of new oil wells drilled co-produce natural gas.” The term “coproduce natural gas” is a recently coined and inaccurate term unknown to industry and never before 

used to describe one of the three types of wells: oil wells (which may produce associated gas), natural 

gas wells, and natural gas condensate wells (which produce both natural gas and liquid condensate). 

In the Introduction, the White Paper groups compressors into four sectors: (1) oil and gas production 

(gathering and boosting), (2) processing, (3) transmission, and (4) storage. Some of the other sections 

group compressors into five sectors by separating “oil and gas production” from “gathering and 

boosting”. Five sectors are required because reciprocating compressors located at oil and gas 

production sites, such as gas lift compressors, flash gas compressors, and small gathering compressors, 

typically operate at a range of pressures much lower than those at gathering and boosting stations and 

are typically smaller frame compressors.

Compressors at production sites typically operate with the following cylinder suction pressures as low as 

1 to 5 psig (1st stage of flash gas compressors on low pressure towers), 15 to 100 psig (1st and 2nd stages 

of flash gas compressors and gas lift compressors), and 50 to 250 psig (1st and 2nd stages for gathering 

compressors). Final stage discharge pressures can be as high as 2,000 psig for gas lift compressors, but 

for the other compressors are typically in the range of 200 to 1,000 psig. Gathering and boosting station 

compressors typically operate with 1st stage cylinder suction pressures in the range of 150 to 500 psig 

and final stage discharge pressures of 500 to 1,500 psig. Cylinder suction and discharge pressure, 

primarily suction pressure, is the driving force behind rod packing leaks; therefore, a lower cylinder 

suction pressure significantly reduces the potential leakage rate. (See page 9, CPI- Mechanical Packing 

Design and Theory of Operation, attached.) Also, reciprocating compressors at production sites will 

typically have less capacity and power requirements than those at gathering and booster stations. 

Compressors at production sites are typically driven by a gas-fired engine rated at 40-500 horsepower, 

while a compressor at a gathering or boosting station will typically be driven by a gas-fired engine rated 

at 500 to 3,500 horsepower. 

Therefore, the compressors at production sites are typically of a smaller frame size and driven by 

smaller engines with higher rpm (1,400 to 1,800 rpm) versus (800 to 1,200 rpm). These smaller 

compressor frames have piston rods that are smaller than the larger frame compressors (1.5 - 2 inches 

in diameter versus 2 – 3.5 inches in diameter). This reduces the effective area available for gas to leak 

past compressor seals, thereby reducing the potential leakage rate. In addition, rod packing leakage is 

generally considered slightly less at higher speeds (rpm). This combination of lower cylinder suction 

pressures (primarily), smaller piston rod diameters, and higher compressor rpm supports the low 
API Comments on Submitted to EPA

Oil and Natural Gas Sector Compressors June 13, 2014

5

measured vent rates from rod packing presented in the White Paper for reciprocating compressors at oil 

and gas production sites. 

The White Paper appropriately makes a distinction between “vented emissions” from compressor seals, 

the topic of the paper, and “leak emissions” from various compressor components, which are covered 

under another White Paper. An exception is for the U.S. GHG Inventory discussion (see comments in 

Section 3.4). The White Paper’s focus is primarily on emissions from rod packing vents and wet seals as it 

should be. It is appropriate to address other emissions (which may pass through vents) from leaking 

compressor components in the Equipment Leaks White Paper. 

API also recommends revisions to compressor definitions. For this white paper and existing and future 

EPA regulatory definitions, we suggest a more accurate definition of a reciprocating compressor: 

Reciprocating compressor means a positive-displacement machine in which the compressing and 

displacing element is a piston having a reciprocating motion within a cylinder. The pressure increase 

is achieved by reducing the volume of a fixed amount of gas.

We also suggest a more accurate definition of a centrifugal compressor: 

Centrifugal compressor means a dynamic machine in which one or more rotating impellers, usually 

shrouded on the sides, accelerate the flow of natural gas. The main gas flow is radial. The pressure 

increase is achieved by converting kinetic energy to static energy. 

B. Process Descriptions

The information provided in this White Paper is generally a high level overview. In the interest of clarity 

for policy makers and the public, EPA should provide additional detail in the process descriptions. 

Additional information is available in the literature and public domain, including in documents posted on 

the EPA Natural Gas Star website. The White Paper should note that reciprocating compressors may 

also be powered by electric motors.

C. Emissions Data and Emissions Estimates

In general, the studies/papers listed in Table 3-1 represent the most prominent documents available on 

emissions and emissions factors for compressors. However, the “Emissions Data” column of Table 3-1 

should have noted the difference between “studies”, which provide original or additional “emissions 

data”, versus “papers”, which just use existing emissions data for some purpose. Most of the emissions 

data cited in the studies/papers listed in Table 3-1 originates from the 1996 GRI/EPA study and is not 

original or new emissions data. In particular, Table 3-1 mislabels the 2014 ICF/EDF paper as a study; 

however, this paper is not a study because most of the information is simply compiled from earlier 

studies and references, including material from the Natural Gas Star website. Also, the White Paper 

should have provided a more detailed assessment/critique of each of the studies/papers cited and 
API Comments on Submitted to EPA

Oil and Natural Gas Sector Compressors June 13, 2014

6

mentioned that the papers do not necessarily present the emissions data in the same manner. If EPA 

did not intend to analyze the studies / papers, at a minimum, the “emissions” from the different 

references should have been tabulated to facilitate comparison.

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

(GRI/EPA, 1996a)

Though dated, this emissions study is currently the most reliable regarding reciprocating and centrifugal 

compressors. This is especially true for reciprocating compressors at oil and gas production sites as the 

GRI/EPA study measured emissions for a significant number of compressors. While Subpart W reporting 

provides alternative data, to date that compressor data has not been adequately compiled or analyzed. 

Other studies have a very small number or no rod packing vent measurements. The White Paper should 

note that emissions and emissions factors for reciprocating and centrifugal compressors in the gas 

processing, transmission, and storage sectors should be supplemented and upgraded with the vast 

amount of information being collected under Subpart W – i.e., three years of data, that includes

measurements for processing, transmission and storage sources, have been submitted to date. (See 

Section 3.3) 

1.2 Natural Gas Industry Methane Emission Factor Improvement Study, Final Report (URS/UT, 

2011)

The White Paper should note that the URS/UT study provided no measurements or emissions factors for 

the small reciprocating compressors located at oil and gas production sites. The White Paper does show 

in Table 3-4 that the sample size for reciprocating compressors at gas gathering and booster stations in 

the URS/UT study is very limited (15 measurements) and for gas transmission reciprocating compressors 

is even more limited (7 measurements of which only 2 were in operating mode); however, the White 

Paper should have stated that this means those particular emissions factors are statistically invalid and 

serve solely as example data for comparison to other data in the literature. In addition, the URS/UT 

study did not indicate which measurement techniques (e.g., Hi Volume Sampler, Enclosed Rotary Vane 

Anemometer, or Hand-held Wire Anemometer), were used for these particular compressor seal 

measurements. The URS/UT study recommended that, for future studies, protocols should be 

developed for the anemometer techniques, which suggests that there were possible issues with those 

measurements. 

The White Paper correctly points out that the URS/UT centrifugal wet seal measurements are suspect 

and not useful due to technical complications during measurements, one of which was whether the 

correct seal oil degassing vent(s) were measured during the study due to the complexity of the seal gas 

degassing systems. 

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

In Table 3-5, the White Paper shows that the 2012 greenhouse gas emissions reporting for Subpart W 

Natural Gas Systems provided data for 2,149 reciprocating compressors in the gas processing sector 

(54% direct measurement), 2,008 reciprocating compressors in the gas transmission sector (60% direct 
API Comments on Submitted to EPA

Oil and Natural Gas Sector Compressors June 13, 2014

7

measurement), and 309 reciprocating compressors in the storage sector (79% direct measurement). 

However, the White Paper fails to explain just how significant this vast amount of data is or how EPA 

plans to use the data to develop emissions factors for reciprocating compressors based on thousands of 

measured data points, rather than the single or double digit measurement sample sizes of previous 

studies. The expansive GHGRP data are more representative of actual industry operations than data 

extrapolated from a few data points in various studies; however, EPA will need to apply appropriate 

quality assurance and quality control (QA/QC) to this data. Going forward, EPA should rely on the 

GHGRP data as the primary source of measured emissions data and compare that data with previous 

emissions studies, such as the 1996 GRI/EPA study, and other wet seal emissions estimates from 

subsequent EPA Papers. EPA should use the available data (i.e., three years of data have been submitted 

to date, starting with 2011 data submittals in 2012) and additional data (e.g., 2014 data to be submitted 

by March 31, 2015) to develop emissions factors for reciprocating compressors based on a select 

number of variables such as compressor operating pressures, compressor frames (piston rod size), 

speed, etc. These same comments apply to the vast amount of measured emissions data collected for 

centrifugal compressors in Table 3-6. 

While the White Paper presents the total methane emissions for reciprocating compressors in each 

industry sector, it fails to make any attempt to delve into the data to at least provide an average 

emissions factor for each sector (for each operating mode) that could be compared to emissions factors 

from other studies – including the “compressor-level” emission factor used of the U.S. GHG Inventory. 

For example, the data is not broken down into emissions from rod packing vents while operating, or in 

pressurized standby, or for emissions from blowdown vent leaks. EPA could have easily used gas 

composition data from the 1996 GRI/EPA study, or from the U.S. GHG Inventory, or some other 

reasonable gas composition assumption, to arrive at an average gas molecular weight and methane 

composition for each industry sector. This, along with the measured methane emissions data and 

number of compressors, could be used to arrive at average emissions factors for each operating mode 

for each industry sector reporting. For now, emissions factors per cylinder could be estimated using the 

1996 GRI/EPA data on number of cylinders per compressor for each sector. These average emissions 

factors would be very useful for comparison with previous studies and as data for future assessment of 

cost/benefit analysis for potential regulations or suggested control technologies. A better 

understanding of the data is also needed to more clearly identify data gaps that remain or conflicting 

information (e.g., comparisons between the U.S. GHG Inventory (primarily based on the original GRI/EPA 

study) and Subpart W reported data.

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

The White Paper should have noted that the emissions factors from the 1996 GRI/EPA study shown in 

Table 3-8, that were used for reciprocating and centrifugal compressors emissions in the 2012 U.S. GHG 

Inventory, include emissions from all sources associated with the compressors; including open-ended 

lines, pressure relief valves, blowdown open-ended lines, compressors seals, and miscellaneous 

(cylinder valve covers and fuel valves). It is important for common nomenclature to be used and to 

delineate which “emission sources” are included for various reports. For example, as discussed above, it 
API Comments on Submitted to EPA

Oil and Natural Gas Sector Compressors June 13, 2014

8

is appropriate for this White Paper to focus on rod packing venting from reciprocating compressors 

while compressor-related leaks (e.g., unit isolation valve leakage) are covered under the Equipment 

Leaks White Paper. The U.S. GHG Inventory and other documents include other compressor-related 

“leaks” within the emissions estimates / emission factors and various papers may not consistently 

address how emissions are presented. For example, depending on the industry segment and 

compressor type, emission factors used for the U.S. GHG Inventory are from different studies, including 

the 1996 GRI/EPA Study. The emission factors are a composite of different sources (e.g., rod packing 

venting in operating mode, isolation valve leakage in shutdown mode) that consider the emissions 

source and typical annual operating time for the related operating mode. API did not revisit these 

emissions factors to de-couple the different emission sources, but the emission factors include 

compressor emissions covered by this White Paper (e.g., rod packing) as well as leak sources. For 

Subpart W reporting, potential sources such as isolation valve leakage (shutdown mode) and blowdown 

valve leakage (operating mode) are included with compressor reporting, but it is our understanding that 

for these white papers leaks are intended to be addressed in the Leaks White Paper. The paper needs to 

explain these complicating factors. Without explanation or a warning of potential inconsistencies, a 

reader may confuse the emissions factors in Table 3-8 as just representing emissions from rod packing 

venting since those emissions are previously discussed and are the main focus of the White Paper.

Therefore, EPA should specifically state which emissions factors in Table 3-8 include other compressor 

emissions sources along with the rod packing vent emissions. 

As noted above, a tabular comparison of emissions for at least some of the cited studies / papers should 

have been included. For example, based on an initial review of 2011 and 2012 data for select segments, 

comparison of GHGRP Subpart W reported emissions and emissions from the U.S. GHG Inventory would 

show significant disparities for some source types and segments. While a subset of facilities (i.e., those 

exceeding the emissions threshold) report for Subpart W, that difference alone does not account for 

significant disparities. For example, centrifugal compressor emissions in the GHGRP are lower by over 

an order of magnitude compared to the U.S. GHG Inventory estimate. This type of comparison is 

necessary to identify data gaps. Additional analysis is then needed to attempt to understand the 

differences, or accept that additional effort is needed to discern the differences. Without a fundamental 

understanding of these emission issues, it is premature to formulate conclusions or assess mitigation 

implications. 

1.5 Development of the NSPS for Oil and Natural Gas Production (U.S. EPA, 2011b and U.S. EPA, 

2012b)

The White Paper accurately presents the emissions factors and the VOC and methane emissions 

obtained from the 1996 GRI/EPA study that were used in the TSD for NSPS Subpart OOOO. However, the 

White Paper should have noted that the emissions factor of 25.9 scf/hr-cylinder used for reciprocating 

compressors in the gathering and boosting sector is arguably too high. This factor was taken from the 

2006 Clearstone Engineering study and was reported as a “blended” factor for both gathering and 

boosting, and gas processing sectors. The Clearstone study did not indicate how many, if any, of the 

measurements were made on compressors in the gathering and boosting sector, but the inclusion of 
API Comments on Submitted to EPA

Oil and Natural Gas Sector Compressors June 13, 2014

9

measurements from the gas processing sector would likely bias the emissions factor high for the 

gathering and boosting sector. 

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

2012)

The most important takeaway from this study, as mentioned in the White Paper, is that the percentage 

of centrifugal compressors in all sectors of the industry that are equipped with wet seals is much lower 

than the 80% assumed by EPA for the U.S. GHG Inventory. The API/ANGA data suggests only 21% wet 

seals in U.S. service. Data from the GHG reporting for Subpart W suggests a range of 35-50%. There are 

some differences in the first two reporting years and for different segments, but the GHGRP data 

consistently shows a much smaller relative population than assumed by EPA in the U.S. GHG Inventory. 

In addition, the disparity in activity data alone does not account for differences between the U.S EPA 

GHG Inventory and Subpart W reports for centrifugal compressors. For example, EPA uses compressor 

count as the activity data in the U.S. GHG Inventory. Thus, Subpart W data can be normalized into a 

simple emission factor (i.e., total Subpart W centrifugal compressor emissions divided by total Subpart 

W centrifugal compressor count) and scaled using the U.S. GHG Inventory compressor count for 

comparison of “national” estimates. For example, an initial review of 2011 data for the transmission 

segment shows that Subpart W centrifugal compressor emissions scaled up to a national estimate (using 

the compressor count from the U.S. GHG Inventory) are 20 times lower than the U.S. GHG Inventory 

estimate. At this time, the reason for this significant disparity is not clear. As noted above, better 

understanding of emissions issues, and how this translates to U.S. GHG Inventory implications, is needed 

to understand the relative significance of different sources.

1.7 Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil and 

Natural Gas Industries (ICF International, 2014)

In general, this paper lacks the clarity and transparency for the public to understand how many of the 

calculations and suggested answers were arrived at. While this paper acknowledges that emission 

mitigation cost and performance are highly site- specific and variable, it nevertheless presents only 

estimated average values and generally does not address ranges of emission mitigation costs and 

performance, or parameters impacting costs and performance. The paper identifies its list of the largest 

emitting sources, and then introduces costs and reductions from a single mitigation approach for each. 

Clearly, there is more than one technology or practice available in many cases. The paper generally 

relies on existing information (e.g., from the Natural Gas Star program), but in some cases introduces

new projections (e.g., for activity data or equipment counts) to estimate reductions and costs. While 

the paper has not been thoroughly scrutinized by API, a cursory review provides examples where the 

paper makes assumptions that are incomplete and sometimes incorrect and that indicate a limited 

understanding of oil and gas operations or uses gross indicators (e.g., miles of pipe) to formulate activity 

data projections. 
API Comments on Submitted to EPA

Oil and Natural Gas Sector Compressors June 13, 2014

10

Two simple examples are provided: 

 The paper uses unit counts to estimate reciprocating engine and turbine emissions but does not 

appear to consider size implications on fuel use or emissions (e.g., average size for rich burn 

engine population is likely smaller than lean burn engines; turbines are likely larger than 

reciprocating engines); 

 The paper estimates that 85% of transmission compressor stations report under Subpart W, and 

inaccuracy is evident based on a quick review of Subpart W data available from EPA, and a 

rudimentary understanding of the transmission compressor segment or U.S. GHG Inventory 

activity data. In 2012, 462 transmission compressor stations reported under Subpart W, while 

the transmission facility count for the U.S. GHG Inventory is 1,799 – or 26% reporting under 

Subpart W compared to 85% estimated in the ICF paper. 

These limited examples raise questions about the overall efficacy of the paper and the numerous 

assumptions used for the emission, reduction, and cost calculations.

D. Available Compressor Emissions Mitigation Techniques

In general, the White Paper identifies the known effective and relevant emissions mitigation 

technologies. However, the paper fails to mention or describe a “Conditions-based Rod Packing 

Maintenance Program” as an alternative to mandatory replacement of rod packing on a pre-determined 

interval such as 26,000 hours. 

4.1 Reciprocating Compressor – Rod Packing Replacement

4.1.1 Description

The White Paper should make a distinction between “rod packing replacement” and “rod packing 

maintenance.” It is not always necessary to replace all rod packing components to restore performance; 

therefore, the prescriptive nature of the term “replacement” can result in the wasteful discard of 

functioning components and equipment, and may preclude innovations in rod packing design or 

materials by manufacturers and rod packing maintenance methods by operators. For instance, suppose 

a rod packing manufacturer develops a better design or finds a new material that allows more effective 

emissions control for years longer than conventional rod packing, but at a substantial increase in initial 

cost of the packing. With a mandatory time interval for rod packing “replacement”, an operator has no 

incentive to use the more expensive packing with improved emissions control. Nor do operators have an 

incentive to institute innovative rod packing maintenance programs. Therefore, the White Paper should 

state that any existing or future discussion of regulations regarding rod packing should use the term 

“maintenance” rather than “replacement.”

As mentioned in the White Paper, rod packing maintenance is inherent to industry operations. However, 

the White Paper fails to mention rod packing maintenance/replacement control techniques other than a 

mandatory rod packing replacement at a set time interval. A more cost-effective technique, which some 
API Comments on Submitted to EPA

Oil and Natural Gas Sector Compressors June 13, 2014

11

operators were previously using before Subpart OOOO or continue to use for units not subject to 

Subpart OOOO, is what could be described as a “Conditions-based Rod Packing Maintenance Program.” 

For instance, some operators periodically measure rod packing vent rate to provide a warning of 

excessive rod packing leakage and repair/replace the rod packing based on vent rate increases, which 

can result in rod packing maintenance within a time frame that may be earlier or longer than 26,000 

hours. 

An example of this approach is found in the Natural Gas STAR lessons learned document “Reducing 

Methane Emissions from Compressor Rod Packing System 

(http://www.epa.gov/gasstar/documents/ll_rodpack.pdf). Using this technique, rod packing gas venting 

is periodically monitored and the value of the incremental leaked gas (relative to postmaintenance/replacement leak rates) is compared to the discounted rod packing 

maintenance/replacement cost. When the incremental lost gas value exceeds the 

maintenance/replacement cost, the rod packing maintenance/replacement is cost-effective and 

performed. This approach is one way to define the condition that triggers maintenance. Another option 

is to set the maintenance/replacement decision based on a defined leak rate or increase in leak rate 

over time. This could be based on a predetermined cost effectiveness determination or historical data 

that shows a certain vent rate (or relative increase) is indicative of wear that warrants maintenance. One 

of the advantages of such a program is that as natural gas prices increase, the program acknowledges 

the increased value of the gas for a maintenance/replacement determination. 

4.1.2 Effectiveness

The White Paper notes the use of an emissions factor of 11.5 scf/hr per cylinder for newly installed rod 

packing that was obtained from EPA Natural Gas STAR presentations. We have not found any 

documentation by EPA Natural Gas STAR supporting this emissions factor; however, we also do not have 

a better emissions factor to suggest for a generic set of rod packing since, as mentioned above, there 

are many variables that can affect the potential leakage rate from a reciprocating compressor. 

The VOC and methane emissions reductions for the gathering and boosting sector shown in Table 4-1 

are arguably too high since they are based on an average emissions factor of 25.9 scf/hr-cylinder based 

on the 2006 Clearstone Engineering study. (See comment in Section 3.5). 

4.1.3 Cost of Controls 

The White Paper correctly explains that the Technical Support Document (TSD) for the Subpart OOOO 

proposed rule used a cost estimate of $1,620 per cylinder to replace rod packing (per EPA Natural Gas 

STAR), applied the GRI/EPA data for number of cylinders for compressors in each sector, and assumed 

that rod packing was typically replaced at a 4 year interval for all sectors (per EPA Natural Gas STAR). 

The White Paper makes an error in Table 4-2, which extracts data from Table 6-7 in the TSD for Subpart 

OOOO. The dollar amounts shown under the column “Gas Savings for Equipment Life per Compressor” 

are actually the dollar amounts of “Annual Cost per Compressor ($/compressor-year) – Without Savings” 

from Table 6-7 in the TSD for Subpart OOOO. 
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The White Paper failed to mention the most important information from Table 6-7 in the Subpart OOOO 

TSD, which is the VOC and methane control cost effectiveness data in $/ton. In short, the cost 

effectiveness for midstream operations, including gas processing and gathering & boosting, was less 

than $1,000 per ton of VOC. EPA determined that this warranted including a Subpart OOOO 

requirement to replace rod packing every 26,000 hours for processing and gathering. The cost 

effectiveness for the production sector, even with cost of methane saved considered, was extremely 

high at approximately $56,000/ton of VOC and $16,000/ton of methane and EPA concluded that Subpart 

OOOO control was not warranted for production compressors. Downstream operations (transmission, 

storage) were excluded from Subpart OOOO due to VOC cost effectiveness of $2,800 per ton or higher 

and minimal VOC reductions. 

The White Paper reports results from the 2014 ICF/EDF cost/benefit analysis of rod packing replacement 

(3 years instead of every 5 years) as providing a payback of seven months; however, the White Paper 

does not explain, or critique, the assumptions used by ICF for their cost/benefit analysis. ICF uses an 

estimated cost for replacing rod packing of $5,000 per cylinder, which we agree is more accurate than 

the EPA cost of $1,620 per cylinder. However, ICF assumes an emissions factor of 57 scf/h-cylinder, 

which is the emissions factor for the processing and transmission sectors in the TSD for Subpart OOOO 

(based on 1996 GRI/EPA data). In their analysis, ICF assumes a linear increase in methane emissions 

from 11.5 scf/yr-cylinder (new) to 57 scf/yr-cylinder (70% increase/yr for 3 years) and a linear increase 

from 57 scf/hr/cylinder out to 5 years. This “failure mode” may not apply for rod packing wear and it is 

inappropriate to assume linear increases in vent rate unless that assumption is supported with realworld data. 

In addition, ICF fails to clearly state whether the same 70% rate of increase is used for the final 2 years, 

or if a higher rate of linear increase was assumed. If 70%/year is assumed, then the final vent rate would 

be 165 scf/hr-cylinder, or 660 scf/hr for a compressor with 4 cylinders. This assumption of a linear 

increase for three years, from 11.5 scf/yr-cylinder to 57 scf/yr-cylinder, followed by an unspecified 

percentage linear increase for two years, represents a misuse of an average emissions factor. The 57 

scf/yr-cylinder factor is a statistical average from a large measured data set which, theoretically, should 

include emissions from rod packing at various years of life, from almost new to close to end of life; 

therefore, the average emissions factor should be applied in a cost/benefit analysis in the method used 

by EPA in the TSD for Subpart OOOO. 

The White Paper should explain the variability and sensitivity of replacement cost analysis, given the 

limitations of the assumptions used by ICF. Many of the assumptions used by ICF are questionable, and 

in some cases incorrect. Given the incorrect and questionable assumptions made by ICF in their rod 

packing replacement cost analysis, the White Paper should have pointed out these questionable 

assumptions, and that the ICF analysis is not a correct or informative analysis, especially for 

reciprocating compressors in the production sector.

Any future EPA discussion of rod packing replacement cost effectiveness for the oil and gas production 

sector should consider the following circumstances as mentioned on page 3-13 of the 2014 ICF/EDF 

Paper:
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(1) the remote location of these compressors,

(2) that many of the compressors are leased rather than owned, and, most importantly, 

(3) that there is typically not a back-up compressor for use during downtime and one or more wells 

must be shut-in to replace rod packing on a compressor, if replacement is done at intervals 

separate from other major maintenance. 

Therefore, the cost of lost production must be included in any future cost/benefit analysis for rod 

packing replacement for reciprocating compressors in the production sector. As discussed elsewhere in 

these comments, the analysis should also consider that smaller compressors and lower pressures 

typically result in lower vent rates for units in production.

4.2 Reciprocating Compressor – Gas Recovery

The use of a vapor recovery unit or units (VRU) to collect rod packing vent emissions can be very 

complex, especially when multiple compressors are involved. Therefore, the White Paper should note 

that any cost/benefit analysis and safety review would need to be performed by an individual operator 

on a site-specific case by case basis.

API does not have cost data for the REM Technology. However, the White Paper should note that the 

REM technology not only requires a vented vapor recovery and injection system, but also requires a 

specialized fuel/air ratio control system for at least one compressor engine using the vented gas in order 

to handle the highly variable vent rates and high Btu content of the vented gas. Applicability of this 

technology would also require a site-specific analysis that would require a case by case cost/benefit 

analysis and safety review. Case-specific analysis would need to consider safety risks and compatibility 

of the recovered gas with the fuel gas. 

4.3 Centrifugal Compressor – Dry Seals

This section generally compares dry seals with wet seals, but is titled “Dry Seals”. The White Paper 

should have clearly described that information and analysis presented is associated with reductions 

based on a comparison between wet and dry seals. As discussed below, there is uncertainty regarding 

centrifugal compressor emissions, especially wet seal emissions, and discrepancies in emission estimates 

will affect the analysis of emission reduction effectiveness and cost effectiveness. For example, Subpart 

W reporting indicates centrifugal compressor methane emissions much lower than the U.S. GHG 

Inventory estimate. In fact, the emissions comparison to the U.S. GHG Inventory from this source 

appears to be more disparate (on a relative basis) than any other Subpart W source.

4.3.1 Description

API generally agrees with the description of dry seals, but the White Paper should more clearly indicate 

that performance implications (e.g., “Dry seals reduce emissions...”) are based on comparison to wet 

seal systems that include vent emission from oil degassing. 
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In addition, it is evident that dry seals are standard for new centrifugal units as wet seal technology has 

been replaced. For example, the primary manufacturer of industrial scale turbines that are frequently 

used in compression service uses dry seals for new turbines, and this has been the case for a decade or 

longer. For affected segments, Subpart OOOO also motivates operators to install dry seal units, which 

are exempt from Subpart OOOO (while wet seal units are subject to Subpart OOOO). Introductory text 

in the centrifugal compressor section should have described the current status of dry seal and wet seal 

configurations for centrifugal compressors.

4.3.2 Effectiveness

The effectiveness description is based on older data from the GRI/EPA study and some more recent 

information from EPA data on centrifugal compressor emissions. Additional detail should be included 

on the emission reduction calculations presented in Table 4-3. In addition, the effectiveness section 

does not discuss significant disparities in emissions reported for Subpart W. The Subpart W data 

indicates a lower population of wet seal units than the U.S. GHG Inventory. For example, the U.S. GHG 

Inventory estimates the wet seal units comprise 80% of the total inventory, including 73% for gas 

processing, 91% for transmission, and 71% for storage. An initial review of Subpart W for the 

transmission segment indicates less than 40% of centrifugal units reported for 2011 included wet seals 

with a marginally higher number reported for 2012 – these levels are much lower than the 91% 

prevalence estimated for this segment in the U.S. GHG Inventory.

In addition, Subpart W requires measurement of wet seal vent rates for processing, transmission and 

storage. Although the population of wet seal degassing vent measurements is lower than other 

compressor-related measurements, an initial review for 2011 and 2012 reporting indicates there are 

over 150 measurements of wet seal oil degassing vents in operating mode. The White Paper should 

have considered these data, or at least the general implications. 

The Subpart W reported data for 2011 indicates centrifugal compressor emissions that are over a factor 

of 20 times lower than the U.S. GHG Inventory estimate. This is due in part to a subset of sources 

reporting. However, the U.S. GHG Inventory estimate uses activity data based on compressor count, 

and Subpart W data could be reviewed to identify the apparent unit-level emission factor (i.e., total 

emissions divided by total units). A detailed analysis has not been completed but an initial estimate 

from a subset of data indicates a difference of more than an order of magnitude.

Clearly, there is significant uncertainty regarding emissions from centrifugal compressors; thus there is 

significant uncertainty regarding the emission reductions that can be realized. The reason for the 

differences between the U.S. GHG Inventory and Subpart W reporting must be determined, as there 

appears to be a significant data gap for emissions and reductions available from centrifugal 

compressors. Since new units that are installed will include dry seals, it may be reasonable to conclude 

that this emissions source warrants limited attention.
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4.3.3 Cost of Controls

API is not aware of the prevalence of replacing wet seals with dry seals for existing turbines, but this 

does not appear to be a common practice. Similarly, cost data was not gathered, but the costs 

presented in Table 4-4 appear questionable. For example, annual O&M costs in Table 4-4 for wet seals 

are higher than the $75,000 capital cost for replacement. Annual O&M costs appear to be overestimated and capital costs appear to be under-estimated. The ICF costs presented in the same section, 

but not in the table, show capital costs and O&M costs that are very different than the costs in Table 4-

4, with ICF capital costs over 5 times higher (i.e., $400,000) and operating costs 5 times lower than the 

Table 4-4 costs. A cost estimate was not available, but capital cost for replacing wet seals with dry seals 

is well in excess of the $75,000 cost in Table 4-4, and possibly in excess of the estimate from ICF. 

Turbine manufacturers should be contacted to confirm costs. In addition, it appears that the costs are 

based on three different years. Differences in reported costs are not highlighted or explained. The 

White Paper credibility is questionable if such disparities are not understood, explained, and/or 

corrected. As noted above, there is uncertainty regarding emission levels (based on recent Subpart W 

reporting) and if emissions are over-estimated, than the associated savings based on natural gas costs 

are also over-estimated. If EPA continues to be interested in wet seal emissions, the many data gaps 

related to emissions and costs must be addressed prior to justifying regulatory changes.

4.4 And 4.5 Centrifugal Compressor – Wet seals with a flare or gas recovery for use

Sections 4.4 and 4.5 of the White Paper discuss capturing wet seal degassing vent emissions and either 

using the recovered gas or sending the gas to flare. As noted above, existing information from the U.S. 

GHG Inventory is not consistent with emission reporting for Subpart W. Until the emissions are better 

understood (i.e., the differences are explained and the current best estimate is defined), estimates of 

reductions in Tables 4-5 and 4-7 cannot be trusted. The tables would appear to significantly overestimate reductions if recent Subpart W measurements are more indicative of current operations. As an 

example, the White Paper emission factor in Table 3-8 for wet seal centrifugal compressors is 51,370 

SCF per compressor per day. For a compressor operating 30% of the time, this equates to 5.6 million 

annual SCF. Initial review of a subset of reporting turbines in 2011 shows 68 wet seal vent 

measurements from a population of over 500 centrifugal compressors, including 186 with wet seals. 

Subpart W presents annual emissions, and the average vent rate for these 68 units was 560,000 SCF – or 

an order of magnitude lower than the estimate based on the U.S. GHG Inventory emission factor. The 

basis for this discrepancy is not clear at this point. If current emissions are more consistent with this 

average value from Subpart W data, then emission reductions would be over-estimated by a factor of 

10. 

Until disparities in available information on emissions are addressed, presentations of reductions or 

costs (that include savings from recovered gas) are inappropriate. It is essential to address data gaps on 

wet seal emissions before any further consideration of whether wet seal emission reductions should be 

pursued. Since wet seal technology is not likely in new installations, there may be other data gaps that 

are more important to address.
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Thus, several questions posed in the White Paper regarding challenges with reducing degassing vent 

emissions are premature because emissions first need to be understood. If mitigation is assessed at a 

later date, recovery and use (or flaring) of wet seal emissions should consider the case-specific nature of 

the analysis, as site conditions would likely effect costs. At some sites, a vapor recovery system may be 

a very complex undertaking and introduce safety risks. Factors to consider include the availability of a 

current vapor recovery system (and flare), site-specific emissions and typical unit utilization, and issues, 

including safety, associated with system design and the end point for usage (e.g., system pressures, 

compatibility with fuel gas).

E. Summary 

No specific comments. 

F. Charge Questions

1. Please comment on the national estimates of methane emissions and methane emission factors for 

vented compressor emissions presented in this paper. Please comment on the activity data and the 

methodologies used for calculating emission factors presented in this paper.

2. Did this paper appropriately characterize the different studies and data sources that quantify vented 

emissions from compressors in the oil and gas sector? 

3. Did this paper capture the full range of technologies available to reduce vented emissions from 

reciprocating compressors and wet seal centrifugal compressors at oil and gas facilities? In particular, 

are there other options for reducing emissions at existing reciprocating or centrifugal compressors? For 

example, the EPA is aware of “low emissions packing” for reciprocating compressors but has no detailed 

information on this technology. 

There is little mention of maintenance practices that can impact reciprocating compressor rod 

packing life. Lubrication has significant impact on rod packing, i.e. - proper rate, type, pre and post 

lube, and lubrication based on compressed gas composition. Routine rod packing monitoring by 

operations & maintenance personnel or automated monitoring techniques and systems are 

available. Low emission packing will likely work well in some applications, if fully evaluated and 

designed properly on a case-by-case basis.

4. Did this paper appropriately characterize the emissions reductions achievable from the emissions 

mitigation technologies discussed for reciprocating compressors and wet seal centrifugal compressors? 

5. Did this paper appropriately characterize the capital and operating costs for the technologies 

discussed for reduction of vented emissions from reciprocating compressors and wet seal centrifugal 

compressors? 

As a whole, the control costs cited in the report seem to be low. 
API Comments on Submitted to EPA

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With regards to reciprocating compressor rod packing replacement, the estimated cost to replace 

the packing rings for a reciprocating compressor included in the White Paper is $1,620 per cylinder 

and it is unclear what makes up this cost, i.e. materials, labor, etc. An estimated cost of $5,000 per 

cylinder, as cited in the 2014 ICF/EDF paper is likely more representative, especially if there are any 

packing case and rod repairs associated with the replacement. The $1,620 per cylinder packing 

ring replacement cost seems to be based on 2006 dollars. It is not clear if any attempt was made 

to bring cost to a current year value, i.e. – 2006 dollars escalated to 2014. Also, it is not clear 

whether the cost presented in the paper is based on the compressor already being down and 

isolated for maintenance. If so, the cost included in the paper likely represents the incremental 

cost of replacing reciprocating compressor rod packing. There is no indication of whether the 

packing case and compressor rod required maintenance, but the cost stated for rod packing 

replacement does not appear to cover this.

Two options are discussed for reciprocating compressor rod packing vent gas recovery: REM 

Technology and a Vapor Recovery Unit (VRU) system. In 2012, an API member received a quote for 

installing a REM technology SlipStream Control System at an onshore gas plant. The January 2012 

proposal was $50,000 and this did not represent the total project cost which would have likely 

been $60,000. The technology is sound when applied correctly, but, for this project, the payout on 

fuel savings alone was too long to the company’s economic thresholds. The cost of a VRU Gas 

Recovery system would be significantly higher than shown in the white paper because the paper 

does not appear to address any of the costs associated with controls and safeguards. 

6. If there are emissions mitigation options for reciprocating and centrifugal compressors that were not 

discussed in this paper, please comment on the pros and cons of those options. Please discuss the 

efficacy, cost and feasibly for both new and existing compressors. 

7. Are there technical limitations that make the replacement of wet seals with dry seals impractical at 

certain existing centrifugal compressors? 

8. Are there technical reasons why an operator would use a wet seal centrifugal compressor without a 

gas recovery system? 

9. Are there technical limitations that make the installation of gas capture systems at certain 

reciprocating compressors impractical? 

With regards to the REM Technology, if the compressed gas quality is substantially different than 

the fuel gas, it can be a concern, especially in situations where the compressed gas is sour. In 

situations where the compressed gas is sour gas, there are additional safety, environmental, and 

equipment reliability concerns that have to be addressed and mitigated before this type of system 

can be utilized.

With regards to the VRU system, the very low pressure on reciprocating compressor distance 

pieces, typically inches of water, makes routing these emissions to a VRU infeasible unless the VRU 

is located in the immediate vicinity of the compressor. The required controls and safeguards must 

be given serious evaluation. Specific areas of concern are: minimizing any pressure buildup in the 

compressor distance piece, avoiding getting air into the VRU system, alternate route for 

vapors/emissions when VRU goes down, and the potential cross contamination of compressing 

multiple gases. If the emissions are to be routed to a flare system, the controls and safeguards 
API Comments on Submitted to EPA

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required for routing the stream to a VRU would also be required. There are also concerns with 

backflow, overpressure, contamination, and introduction of air during flaring events.

10. Please comment on the prevalence of the different emission mitigation options in the field. 

11. Given the substantial benefits of dry seal systems (e.g., lower emissions, less maintenance, and 

higher efficiency), are you aware of situations where new wet seal centrifugal compressors are being 

installed in the field? If so, are there specific applications that require wet seal compressors? 

12. Are there ongoing or planned studies that will substantially improve the current understanding of 

vented VOC and methane emissions from reciprocating and centrifugal compressors and available 

techniques for increased product recovery and emissions reductions? 

As mentioned above, 40 CFR 98 Subpart W requires facilities in the oil and gas industry to test 

compressor rod packing emissions annually. The current emissions information gathered during 

this testing should improve the understanding of vented emissions from these compressors.