Scott Crider

Vice President, Federal Government Affairs

1399 New York Avenue, NW

Suite 350

Washington, DC 20005-4733

Tel: 202.662.1704

Fax: 202.293.2887

Email: scrider@sempra.com

June 16, 2014

To: U.S. EPA Office of Air Quality Planning and Standards

Submitted via electronic mail: oilandgas.whitepapers@epa.gov

Re: Oil and Natural Gas Air Pollution Standards White Papers on Methane and VOC 

Emissions technical comments

Sempra Energy, on behalf of its subsidiaries, Southern California Gas Company, (SoCalGas) and 

Sempra U.S. Gas & Power,

1 supports the U.S. Environmental Protection Agency’s (EPA) efforts 

to promote clean energy in the United States and appreciates the opportunity to comment on 

EPA’s White Papers on Methane and VOC Emissions in the Oil and Natural Gas Sector. When 

considering methane emission studies, Sempra Energy requests that EPA employ a science-based 

approach that uses accurate and precise data when determining the source of, and measuring 

methane emissions, as further discussed in the attached comments. 

I. Background on Sempra Energy and Its Subsidiaries

Sempra Energy is a Fortune 500 energy services holding company based in San Diego, 

California. With nearly 17,000 employees worldwide, the Sempra Energy companies develop 

energy infrastructure, operate utilities, and provide related products and services to more than 31 

million consumers using a low-carbon model that prioritizes natural gas, energy efficiency, 

renewable power and innovative technologies. Sempra Energy supports efforts to reduce GHG 

emissions by transitioning to cleaner-burning fuels and renewable energy.

Our utility SoCalGas provides energy service to 20.9 million people through 5.8 million natural 

gas meters throughout Central and Southern California. The company’s service territory 

encompasses approximately 20,000 square miles. 

Our subsidiary Sempra U.S. Gas & Power develops clean power solutions in markets throughout 

the United States with a focus on zero and low-emission fuels. The company operates more than 

1,500 megawatts (MW) of renewable and natural gas-fueled power plants, including one of the 

largest photovoltaic solar facilities in the United States. Its natural gas and renewable plants 

combined generate power for nearly 1 million homes and businesses.

1 Sempra U.S. Gas & Power, LLC is not the same company as the California utilities 

San Diego Gas & Electric Company (SDG&E) or Southern California Gas Company 

(SoCalGas), and Sempra U.S. Gas & Power, LLC is not regulated by the California 

Public Utilities Commission.

 
U.S. EPA Office of Air Quality Planning and Standards

6/16/2014

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II. Natural Gas Transmission and Storage

Due to proactive efforts by the natural gas industry, emissions from the natural gas system 

overall are on a declining trend. These reductions are the result of advancements in natural gas 

sector technologies and best practices. Understanding the rate and location of emissions from the 

natural gas system, and the degree to which emissions can be reduced, is critical to ensure that 

regulators continue to include natural gas as a viable energy resource in future state energy and

greenhouse gas (GHG) reduction plans. 

We believe there are existing data gaps regarding the understanding of GHG emissions for 

transportation and storage sources and additional efforts are paramount for reconciling these data 

gaps. We support the effort to understand the sources of methane emissions and how those 

emissions are measured and reported, though we feel there is additional information available 

and forthcoming to support EPA in this endeavor. Furthermore, we respectfully suggest that EPA 

use caution and avoid placing excessive weight on the limited information obtained from 

previous studies as they may not have current scientific-based conclusions. For instance, the 

studies referenced in the EPA White Papers may not accurately reflect pipeline emissions 

because operating practices, as well as the efficiency of operating equipment, have improved 

over the last 20 years while referenced studies present findings on a limited set of data that is 

approximately two decades old. 

As discussed in the attached comments, there are several efforts currently underway to provide 

greater transparency on the factors that contribute to the overall methane leakage rate. The Gas 

Technology Institute (GTI) is updating the emissions factors for distribution pipes, meters and 

regulators. In addition, the Environmental Defense Fund (EDF) is conducting a series of studies 

on each area of the natural gas supply chain to develop a more science-based estimate of the 

methane leakage rate for the natural gas system. SoCalGas is directly involved in these efforts. 

We believe the findings from these studies will better inform sound policies for addressing 

methane emissions from natural gas local distribution, and foster a more accurate public 

understanding of methane leakage rates.

III. Conclusion

Understanding the rate and location of methane emissions from the natural gas system is critical 

to the development of sound energy policies and GHG reduction plans. Please refer to the 

attached comments for responses to the questions stemming from the compressors, leaks and 

pneumatic devices white papers.

Thank you for considering Sempra Energy’s comments. Please contact me 

at scrider@sempra.com or 202-662-1704 if you have any questions.

Respectfully Submitted,

Scott B. Crider

Vice President, Federal Government Affairs
U.S. EPA Office of Air Quality Planning and Standards

6/16/2014

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Responses to charge questions from the Report for Oil and Natural Gas Sector Compressors as 

prepared by the U.S. EPA Office of Air Quality Planning and Standards

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.

In general, Sempra is in agreement with the intent of this white paper because it is based 

largely on the Natural Gas Star Program. We respectfully suggest that EPA use caution and 

avoid placing excessive weight on the limited information obtained from previous studies as 

they may not have current scientific-based conclusions. For instance, the studies currently 

used may not accurately reflect pipeline emissions because operating practices, as well as the 

efficiency of operating equipment, have improved over the last 20 years while referenced 

studies present findings on a limited set of data that is approximately two decades old.

Improved factors can be obtained from newer studies. Over the years, measurement 

procedures, technology and knowledge of the subject have improved. In Addition, an 

analysis of the last three years of Subpart W data could be used to better quantify the 

emissions and its level of contribution to total greenhouse gas emissions.

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

vented emissions from compressors in the oil and gas sector?

We believe there are newer and therefore more relevant studies in addition to current Subpart 

W data. Please refer to our comments regarding question 12.

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. 

We believe the Natural Gas Star Best Management Practices are still applicable, and 

comprehensive. We do not have any experience with “low emission packing” technologies 

beyond what is discussed in the white paper. 

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

emissions mitigation technologies discussed for reciprocating compressors and wet seal 

centrifugal compressors? 

We believe this paper appropriately characterized the emissions reductions achievable from 

the emissions mitigation technologies discussed for reciprocating compressors and wet seal 

centrifugal compressors. We respectfully suggest that emission factors from newer studies 

and current Subpart W data could be used to improve the accuracy of the estimates. 
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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? 

Although the capital and operating costs of the reduction technologies are derived from 

existing Natural Gas Star and other reports, they may be underestimated. The cost of 

replacing a packing ring (page 32), $1,500, only covers parts. In practice, it’s often not just 

the packing that is bad and in need of replacement. The rod, cross-head shoes and cross-head 

guides may also need refurbishment at the same time, thus raising the cost associated with 

“packing replacement”. The cost of labor should also be considered. While this cost is 

variable, it typically runs from $3,000 to $7,000. In addition, although the piston rod may 

need to be replaced, (mentioned at the top of page 30) this is not a common mitigation 

option, unless the rod is damaged. If the rod is slightly worn around the packing area, the 

surface of the rod is recoated with tungsten carbide and brought back to its original diameter.

While we do not change wet seals to dry, the costs, as reported in the paper, appear to 

significantly underestimate the total cost. We estimate the cost of retrofitting dry seals on an 

existing 7260 HP centrifugal compressor at about $250,000, rather than the reported $75,000.

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.

With the exception of the currency of the economic analysis cited, the Natural Gas Star Best 

Management Practices are still current and comprehensive.

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

impractical at certain existing centrifugal compressors?

As discussed in our comments to question five above, there are several factors that make the 

process both costly and time consuming and therefore impractical. 

8. Are there technical reasons why an operator would use a wet seal centrifugal compressor 

without a gas recovery system?

A gas recovery system is technically possible, though more study is needed to determine the 

economic implications. As described in the white paper, this requires the installation of a 

smaller compressor to increase the pressure of the vented natural gas to a minimum of the 

fuel pressure of the pipeline compressor driver (turbine). In addition to the capital costs to 

install the compressor, analysis should also include ongoing costs to power and maintain the 

compressor, as well as the greenhouse gas emissions generated by its operation. It is unclear 

at this time whether the 95% or 99% reduction efficiency discussed in the white paper would 

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

reciprocating compressors impractical?

As discussed above in question eight, the technical limitations make the installation of gas 

capture systems at certain reciprocating compressors impractical. 

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

Sempra’s regulated utility, Southern California Gas Company, has implemented many 

Natural Gas Star Best Management Practices, some of which relate to reciprocating 

compressor packing. Subpart W measurements indicate actual emissions are lower than 

published emission factors for reciprocating compressors, which indicates that the actual 

payback period is much longer than the published value.

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?

We are not aware of situations where new wet seal centrifugal compressors are being 

installed in the field. It is our understanding that most new systems have dry seal, which is 

what we would specify.

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?

There are ongoing and 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. For instance, more accurate data has been obtained in the past three years for 

Subpart W reporting. The Environmental Defense Fund is sponsoring studies on methane 

emissions from the natural gas system: Conestoga-Rovers & Associates and Washington 

State University have conducted a study on the distribution sector, and Colorado State 

University has conducted a study on transmission and storage. Results are expected to be 

released later this year.
U.S. EPA Office of Air Quality Planning and Standards

6/16/2014

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Responses to charge questions from the Report for Oil and Natural Gas Sector Leaks as 

prepared by the U.S. EPA Office of Air Quality Planning and Standards

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

VOC and methane emissions from leaks in the oil and natural gas sector? 

No comment.

2. Please comment on the approaches for quantifying emissions and on the emission factors 

used in the data sources discussed. Please comment on the national estimates of emissions 

and emission factors for equipment leaks presented in this paper. Please comment on the 

activity data used to calculate these emissions, both on the total national and regional 

equipment counts.

No comment.

3. Are the emission estimating procedures and leak detection methods presented here equally 

applicable to both oil and gas production, processing, and transmission and storage sectors? 

We do not believe the emission estimating procedures and leak detection methods presented 

here equally apply to both oil and gas production, processing and transmission and storage 

sectors.

Oil and gas production, processing, transmission and storage sectors all fall under different 

GHG reporting categories which reflect different operating environments and equipment. For 

example, transmission has miles of buried pipe between above ground stations whereas 

storage is within a small geographical area with mainly aboveground piping. In addition, our 

storage facilities are located at areas where there is high temperature and high winds. Finally, 

our storage facilities operate at a range of 40 lbs. to 3000 lbs. pressure whereas the other 

sectors tend to operate at approximately 500 lbs. or less.

4. Are there ongoing or planned studies that will substantially improve the current 

understanding of VOC and methane emissions from leaks and available techniques for 

detecting those leaks? Please list the additional studies you are aware of. 

The Environmental Defense Fund is conducting studies on quantifying the amount of 

methane lost across today’s U.S. natural gas supply chain, including production, gathering 

lines and processing facilities, long-distance pipelines and storage, and local utility 

distribution. 

Further information on the studies can be found on the EDF website: 

http://www.edf.org/methaneleakage

5. Are there types of wells sites, gathering and boosting stations, processing plants, and 

transmission and storage stations that are more prone to leaks than others? Some factors that 

could affect the potential for leaks are the number and types of equipment, the maintenance 
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of that equipment, and the age of the equipment, as well as factors that relate to the local 

geology. Please discuss these factors and others that you believe to be important. 

With regard to above ground storage equipment, based upon our experience and internal 

company standards and practices which includes but is not limited to daily inspections, 

routine maintenance and repair, if established maintenance procedures and protocols are 

followed, there are no differences in the number and types of equipment, the age or geology 

that impacts the potential for leaks in the fields Sempra’s utility, SoCalGas operates.

6. Did this paper capture the full range of technologies available to identify leaks at oil and 

natural gas facilities? 

The paper captures the full range of existing technologies available to identify leaks beyond 

soap tests, visual, audible and smell.

7. Please comment on the pros and cons of the different leak detection technologies. Please 

discuss efficacy, cost and feasibility for various applications. 

Based on our experience, we agree with the report on the cons regarding LDIR and Optical 

cameras as they do not quantify emissions and the accuracy of such devices are extremely 

sensitive to ambient environmental conditions such as heat and wind.

SoCalGas experience supports EPA Method 21 as the most efficient and effective 

methodology for leak detection because it allows detection and quantification in one step.

8. Please comment on the prevalence of the use of the different leak detection technologies at 

oil and gas facilities. Which technologies are the most commonly used? Does the type of 

facility (e.g., well site versus gathering and boosting station) affect which leak detection 

technology is used?

The most efficient and effective methodology for leak detection in Storage is EPA Method 

21.

9. Please provide information on current frequencies of revisit of existing voluntary leak 

detection programs in industry and how the costs and emission reductions achieved vary with 

different frequencies of revisit. 

The current program at Sempra’s utility, SoCalGas of daily inspections, routine maintenance, 

repair and other regulatory required inspections identifies leaks to be addressed. Increasing 

the frequency of leak detection surveys does not necessarily correlate to a reduction of leaks, 

and would result in an operational burden 

10. Please comment on the potential for using ambient/mobile monitoring technologies in 

conjunction with OGI technology. This would be a two-phase approach where the 

ambient/mobile monitoring technology is used to detect the presence of a leak and the OGI 
Responses to charge questions from the Report for Oil and Natural Gas Sector Leaks

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technology is used to identify the leaking component. Please discuss efficacy, cost and 

feasibility.

Sources of methane emissions other than natural gas, including biogenic and naturally 

occurring thermogenic sources must be ruled out. Isotopic fingerprinting may not be able to 

differentiate among two petrogenic sources, so an additional tracer, such as helium, should be 

used. It should be noted that using this technique can be time consuming and costly, 

especially in populated areas where many other emission sources can exist that require labor 

to investigate and screen out “false positive” indications.

With regard to transmission pipelines, mobile monitoring can be used in conjunction with 

OGI technology. These technologies are currently available on both land-based vehicle and 

aerial platforms. Mobile technologies used in this manner measure atmospheric levels of 

methane and identify locations where the measured level is significantly above naturally 

occurring background levels of methane. Various techniques may then be employed to 

identify the local source causing the increased atmospheric methane level, which may or may 

not have been emitted from a pipeline facility. Once a pipeline emission source is located, the 

OGI technology, along with any of the methods for determining mass flow rates, can then be 

utilized.

Currently there are no mobile technologies available that are capable of quantifying emission 

rates, even from known sources of emissions. While this method may serve a purpose for 

assessing emissions from a facility or upwind source, it should not be considered a “leak 

detection” technique”. Ambient / mobile monitoring does not fulfill the functional 

requirement to identify the leak source and should not be identified as a leak detection 

technology.

From Sempra’s perspective, facility application mobile monitoring is not considered to be a 

viable or necessary tool because existing requirements and practices capture emission 

sources. 

11. Please comment on the cost of detecting a leak when compared to the cost to repair a leak. 

Multiple studies described in this paper suggest that detecting leaks is far more costly than 

repairing leaks and, due to generally low costs of repair and the subsequent product recovery, 

it is almost always economical to repair leaks once they are found. Please comment on this 

overall conclusion. 

The cost of detecting a leak is far cheaper than repairing a leak. Factors that should be

addressed include but are not limited to:

a. Labor/material/administrative costs

b. Valve replacement costs

c. Amounts of gas blown to atmosphere necessary to conduct certain repairs

d. System outages which impact the availability of equipment and potentially 

impact the availability of gas to customers
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12. If the conclusion is correct that it is almost always economical to repair leaks once they are 

found, then how important is the quantification of emissions from leaks when implementing 

a program to detect and repair leaks? 

As mentioned, the cost of detecting a leak is far cheaper than repairing one. Regardless of 

economic considerations, quantification of emissions from leaks is necessary to determine an 

appropriate response to a leak.

13. Please comment on the state of innovation in leak detection technologies. Are there new 

technologies under development that are not discussed in this paper? Are there significant 

advancements being made in the technologies that are not described in this paper?

The U.S. Department of Energy’s Advanced Research Projects Agency-Energy (ARPA-E) is 

soliciting applications for MONITOR, to fund development of innovative, new approaches to 

methane sensing in order to reduce associated costs to the point that widespread 

implementation is feasible (https://arpa-e-foa.energy.gov). Similarly, EDF is soliciting 

proposals for the “Methane Detectors Challenge” to fund development and 

commercialization of low cost, methane detection technologies to help minimize methane 

emissions in the oil and gas industry 

(http://www.edf.org/sites/default/files/mdc_rfp_final.pdf.).
U.S. EPA Office of Air Quality Planning and Standards

6/16/2014

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Responses to charge questions from the Report for Oil and Natural Gas Sector Pneumatic 

Devices as prepared by the U.S. EPA Office of Air Quality Planning and Standards

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

emissions from pneumatic controllers and pneumatic pumps in the oil and gas sector? 

No comment.

2. Please discuss explanations for the wide range of emission rates that have been observed in 

direct measurement studies of pneumatic controller emissions (e.g., Allen et al., 2013 and 

Prasino 2013). Are these differences driven purely by the design of the monitored controllers or 

are there operational characteristics, such as supply pressure, that play a crucial role in 

determining emissions?

No comment.

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

pneumatic controllers and pneumatic pumps oil and gas facilities? 

No comment.

4. Please comment on the pros and cons of the different emission reduction technologies. Please 

discuss efficacy, cost and feasibility for both new and existing pneumatics. 

In many instances, physical asset protection and public safety considerations outweigh marginal

reduction in GHG attainable by use of less-reliable assets. Electric controllers are not as reliable 

as pneumatics in practical remote pipeline applications; and where two forms of overpressure 

protection system are required and prudent for pipeline operations, one of the forms should be a

fully-autonomous pneumatic control, which is not impacted by grounding, lightning strikes or 

other electrical issues. This is also the case for critical pipeline valve operations. 

5. Please comment on the prevalence of the different emission control technologies and the 

different types of pneumatics in the field. What particular activities require high bleed pneumatic 

controllers and how prevalent are they in the field? 

No comment.

6. What are the barriers to installing instrument air systems for converting natural gas-driven 

pneumatic pumps and pneumatic controllers to air-driven pumps and controllers? 

The principal barriers to installing instrument air systems for converting natural gas-driven 

pneumatic pumps and pneumatic controllers to air-driven pumps and controllers are cost and 

reliability. Using existing gas pressure to control gas in the pipeline does not depend on an air 

compressor and electric systems to remain functional. When you use natural gas-driven 

controllers, you are assured that in every instance you have gas in the pipeline, you have gas 

pressure available for the control system. This is not always the case using air-driven pumps and 

controllers. Relying on a local compressor, served from the electric grid, introduces two 

additional major points of failure into an overall risk/reliabilty model. In a large station 
Responses to charge questions from the Report for Oil and Natural Gas Sector Pneumatic 

Devices

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(compressor station), building the electical and air compressor redundancy makes some sense,

but at a remote valve station, it lacks technical or economic rationale.

7. Are there situations where it may be infeasible to use air driven pumps and controllers in place 

of natural gas-driven pumps and controllers even where it is feasible to install an instrument air 

system? 

No comment.

8. Did this paper correctly characterize the limitations of electric-powered pneumatic controllers 

and pneumatic pumps? 

No comment. 

Are these electric devices applicable to a broader range of the oil and gas sector than this paper 

suggests? 

No comment.

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

of VOC and methane emissions from pneumatic controllers and pneumatic pumps and available 

techniques for increased product recovery and emissions reductions? 

The Environmental Defense Fund sponsored a study conducted by the University of Texas on 

natural gas production, released in 2013. A second phase of the project will focus on pneumatics. 

A link to the UT study can be accessed by: www.edf.org/climate/methane-studies/UT-study-faq.