Chevron 

• 

June 16, 2014 

Maria Pica Karp 

Vice President & 

General Manager 

Transmitted Via Email: oilandgas.whitepapers@epa.gov 

Mr. Chris Frantz 

Sector Policies and Programs Division 

Office of Air and Radiation - OAQPS 

I 09 T.W. Alexander Dr. D205-02 

Research Triangle Park, North Carolina 27711 

Dear Mr. Frantz, 

Chevron Government Affairs 

1401 Eye Street, NW 

Suite 1200 

Washington, DC 20005 

Tel 202 408 5800 

Fax 202 408 5845 

mpica@chevron.com 

Chevron U.S.A. Inc. ("Chevron") is an integrated energy enterprise involved in all aspects of the energy 

business: exploration, production, manufacturing, transportation, marketing, and research. Chevron is 

committed to conducting our operations safely and in a manner that protects the environment. Chevron is 

an active operator in the United States, with exploration and production operations in Alabama, 

California, Colorado, Gulf of Mexico, Louisiana, Michigan, New Mexico, Ohio, Oklahoma, 

Pennsylvania, Texas, Utah, West Virginia, and Wyoming. 

We appreciate the opportunity to provide feedback on the five "White Papers on Methane and VOC 

Emissions in the Oil and Natural Gas Sector" (white papers) released April IS, 2014, by EPA. Our 

comments respond to EPA's questions where we have relevant data and where we feel additional 

clarification in the papers would be valuable. 

Chevron appreciates EPA's effort to include stakeholder feedback in this early attempt to better 

understand these sources. We look forward to future engagements on this effort. We believe it is crucial 

that the EPA and other interested agencies work closely and collaboratively with industry stakeholders 

who bring real world expertise and experience to these very complex issues. Working together at early 

stages and consistently throughout the process will better inform EPA's inquiry objectives. 

As noted throughout these white papers, it is critical for EPA to develop the highest quality data to fully 

understand the quantification of emissions, and the efficacy, efficiency, applicability, and feasibility of 

various control technologies before making any decision regarding controls or requirements on the 

industry. We also appreciate EPA's commitment to work with industries across the economy to help 

ensure that the Agency is relying on the highest quality data in considering any future policy-making 

efforts. 

Significant and appropriate data is required due to the unique characteristics and variability across oil and 

gas operations. Each well is like a fingerprint as the formation pressure, depth, wellbore design, surface 

facilities, and nearby infrastructure all vary and all are factors that must be identified and considered. No 

two wells are the same, and no two formations are the same; each well will have its own design criteria. 

Consideration should be given to this variability when examining data. Further, for offshore facilities, it 
is important to note that it is generally considerably less cost-effective to implement the technologies 

listed in these papers. This is due to constraints in platform physical and structural design, construction 

and maintenance turnaround limitations, as well as labor and material cost differentials. 

We encourage EPA to consider the positive contributions that voluntary programs such as Natural Gas 

STAR and STRONGER (State Review of Oil and Natural Gas Environmental Regulations) can, and 

already are, making to reduce methane emissions from the oil and gas sector. The Natural Gas STAR 

program is a collaborative effort by the EPA and the oil and gas industry to encourage implementation of 

methane emissions reducing technologies. As a result, it provides an important opportunity to 

demonstrate new technologies and determine cost-effectiveness and feasibility in a wide range of basins. 

These programs help provide the cost-effectiveness and feasibility data in various operating basins, 

formations, and facility types called for in these papers. 

Additionally, the STRONGER Review program is finalizing state air regulatory program guidelines. 

EPA is a member of the STRONGER Board, and is providing program funding support. EPA should 

engage with STRONGER state, industry, and environmental stakeholders to support enhanced voluntary 

fugitive emissions measures as well as continuous state air regulatory program improvement. These 

programs enjoy support from industry, EPA, and the Department of Energy; and STRONGER includes 

representatives from environmental NGOs, state regulatory agencies, and industry on its board. 

STRONGER has the flexibility to respond to the unique characteristics of each basin, formation, and 

facility in which the oil and gas sector operates. 

ln addition to the charge question responses that follow, we would like to provide comment on the 

ICF/EDF March 2014 paper, which is emphasized in each of the white papers. While we support the 

general methodology, we have concerns with various assumptions in the ICF/EDF paper. For example, 

some of the labor costs cited are significantly below current labor costs for maintenance. The ICF/EDF 

study utilizes a labor rate of approximately $40/ hr with a 10% overhead rate and a 30% fringe benefit 

rate. Typical overhead rates are 22% for a small construction business, while consulting firms regularly 

charge 100%. A typical fringe benefit rate is 38% for exempt workers and 45% for non-exempt workers 

(Source: http://professionals.pr.doe.gov/srs/pdf/laborrates fringe. pdf (accessed 4/20 14)). Additionally, it 

appears that ICF/EDF calculations allow for approximately 25 minutes of travel time to wellpads for Leak 

Detection and Repair activities. Many well sites are remote and take significantly longer than 25 minutes 

to reach. Record-keeping costs seem to ignore the costs of a computer system and quality control. 

Issues with Cost Analysis 

The cost of implementation of the various proposals in the ICF/EDF study is underestimated, thus not 

cost-e ffl ect1ve . . db fi to perceive ene Its. 

Capital and 0 Analysis must incorporate related installation, engineering, and permitting 

Operational costs (if applicable); and 

expenses 0 Realistic market labor costs 

Top-down 0 Projected emission reduction estimates are less certain than in a bottom-up 

approach accounting, particularly with respect to attribution amongst various potential 

sources. If relying on top-down emissions estimates, reductions may be 

significantly lower than estimated, lowering cost-effectiveness of various 

controls. 

Site specific 0 Relative mitigation costs and projected performance are highly variable, and 

estimation average values presented lose meaning in the context of local operators with 

costs based on geographical value chains. 

Benefits 0 Benefits are overstated in cases where the quality of gas is affected by the 

vapor recovery pressure and presence of contaminants (e.g. from seal oil). 

Dated baseline 0 Anticipated new data and analysis could create significant cost estimate 

fluctuations from 2011 EPA GHG Inventory. 
Review of Proposed Mitigation Measures 

Not all measures are feasible or cost-effective in all settings. 

Proposed Measure Review 

Leak Detection 0 Analysis must incorporate related installation, long-term maintenance, 

supervision, record-keeping and quality control; 

0 Actual current market labor costs; and 

0 Frequency, as per standardized best practice processes and practices, 

recognizing there may be limited value to high frequency detection at low 

emitting sites. 

Centrifugal 0 A retrofit scenario may face additional constraints due to space and 

Compressor operability concerns. 

Gas-driven to 0 Kimray Pump: application limited to locations with existing infrastructure. 

Non-gas driven 0 Solar: Space and cost implication to design a 24-hour/365-day operation at a 

pumps location with less abundant sunlight. The solar panel and storage system 

(Electric/Solar) may need to be overdesigned. 

High to low bleed 0 Industry comments indicated that the costs provided from Natural Gas STAR 

pneumatic devices and vendors are too low when applied across a wider range of operations. 

Plunger lifts 0 Lesson learned from the Natural Gas STAR Partners quotes higher CAPEX 

per well. 

0 Effectiveness of plunger lifts for horizontal wells has not been proven. 

We appreciate your time and consideration in examining the charge question responses that follow. We 

look forward to the opportunity to further discuss these items. If you have any questions, please contact 

Judy Blanchard in our Government Affairs' Washington, DC office at (202) 408-5858 or via email at 

jblanchard@chevron.com, or Vanessa Ryan in our Government Affairs office in San Ramon, our 

corporate headquarters at (925) 790-3803 or via email at vanessa.ryan@chevron.com. 

~~-------------- Maria Pica Karp 

Vice President and General Manager, Government Affairs 

Attachment: 

Chevron Response to White Paper Charge Questions 
Charge Question Responses 

I. Oil and Natural Gas Sector Compressors Charge Question Responses: 

Question 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"Iow emissions packing" for reciprocating compressors 

but has no detailed information on this technology. 

Response: 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, 

compressed gas composition. Routine rod packing monitoring by operations and 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. 

Question 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? 

Response: As a whole, the costs in the report are low based on real world experience with vendors and 

installation. For 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, but it is 

unclear what makes up this cost (i.e. materials, labor, etc.). Actual costs are multiples greater, especially 

ifthere 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 as opposed to current year value. Also, 

it is not clear whether the cost presented in the paper is based upon a presumption that the units are 

already down and isolated for maintenance. If so, the cost included in the paper likely just 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 cost stated for rod packing replacement does 

not appear to cover this. 

Two options are discussed for reciprocating compressors gas recovery: REM Technology and a Vapor 

Recovery Unit (VRU) system. Our experience is that the REM technology is sound when applied 

correctly, but the payout on fuel savings alone is too long to meet 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 cost associated with controls and safeguards. Please note that 

to implement this technology offshore would be considerably more expensive. New technologies, such as 

REM, to capture rod packing emissions need to be field tested more or enough data needs to be collected 

before recommending or prescribing this technology. 

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

reciprocating compressors impractical? 

Response: For REM technology, it is a concern if the compressed gas quality is substantially different 

than the fuel gas, especially in situations where the compressed gas is sour. In situations where the 

compressed gas is sour gas, there are safety, environmental, and equipment reliability issues 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 system, alternate route for vapors/emissions when VRU goes down, 
and the potential cross contamination if compressing multiple gases. If the emissions are to be routed to a 

flare system, the controls and safeguards required for routing the stream to a VRU would also be required. 

There would also be concerns with backflow, overpressure, contamination, and introduction of air during 

flaring events. 

Question 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? 

Response: 40 CFR 98 Subpart W requires facilities in the oil and gas industry to test compressor rod 

packing emissions annually. The emissions information gathered during this testing should improve the 

understanding of vented emissions from these compressors. 

II. Oil and Natural Gas Sector Leaks Charge Question Responses: 

Question I: 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? 

Response: We do not have access to the two cited "forthcoming publications" by Brantley, et al. on DJ 

Basin and mobile measurements. We respectfully suggest that studies that are not publicly available not 

be included or considered in the whitepapers. 

Question 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? 

Response: Although in principle the overall methodology of emission detection can be applied to both oil 

and natural gas systems, the procedures should account for the inherent variability- methane and VOC 

leakage rates, probabilities of occurrence, equipment types, etc. -between oil and natural gas operations. 

For example, the decline rate in oil and associated gas may not be the same. 

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

discuss efficacy, cost and feasibility for various applications. 

Response: Despite broad claims by many vendors, many optical gas imaging (OGI) cameras are not yet 

reliable in quantifying leaks or in determining exact gas composition. As the documents indicated, OGis 

will need to be coupled with ambient/mobile monitoring for effective quantification of leaks. Therefore, 

all leak detection economic estimates should reflect this fact when estimating costs. 

Contrary to what is stated in the paper, ambient/mobile monitoring can be more expensive for installation 

and maintenance and at the same time may not provide the accurate, verified results. The ambient 

/mobile monitoring equipment sensing the methaneNOC concentration from fugitive leaks will be 

dependent on several factors such as quantity of the leak, wind speed, wind direction, elevation of the 

plume and location of the monitor. 

Ill. Oil and Natural Gas Sector Liquids Unloading Processes Charge Question Responses: 

Question I: Please comment on the national estimates of methane emissions and methane emission 

factors for liquids unloading presented in this paper. Please comment on regional variability and the 

factors that influence regional differences in VOC and methane emissions from liquids unloading. What 

factors influence frequency and duration of liquids unloading (e.g., regional geology)? 

Response: Regarding Table 2-2, and Section 2.5, it is very important to keep in mind the Best Available 

Monitoring Methods (BAMM) nature of this data for Methods 2 and 3. Without a clear understanding of 

assumptions taken by each company in their estimations, this aggregate data should not be considered. 
Table 2-4 is not Subpart W data. Data will be more reliable if the Subpart W data starting with the 2013 

actual data (reported March 2014 and forward) is utilized, as BAMM methods are not frequently applied 

as in earlier years. In Section 2-4, we agree that the various factors and data spread for liquids unloading 

citing duration, depth, pressure, and frequency varies, and this data should be used with caution. For 

greenhouse gas data, a reporter is allowed to use composition for the gas across the sub-basin area. As a 

result, only one value for CH4 and C02 mole percent is used in each sub-basin, which could skew the 

data. 

Many factors influence the frequency and duration of liquids unloading such as geology, depth, formation 

characteristics, infrastructure, and duration and frequency of well blowdowns. 

Question 2: Is there further information available on VOC or methane emissions from the various liquids 

unloading practices and technologies described in this paper? 

Response: This paper notes that the ICF/EDF study relied on the EPA 2013 GHG Inventory and the Allen 

et a] 2013 study to update its information. However, one of the conclusions from the Allen et al 2013 

study is that there were not enough unloading measurements to draw any substantial conclusions. Given 

this finding, it is not clear why ICFIEDF uses this data given that the basis of the calculation is not 

supported by the Allen et al 2013 study. In fact, the white paper reproduces the caution listed by the 

Allen et al paper about there being insufficient data to characterize emissions. 

Question 3: Please comment on the types of wells that have the highest tendency to develop liquids 

loading. It is the EPA's understanding that liquids loading becomes more likely as wells age and well 

pressure declines. Is this only a problem for wells further down their decline curve or can wells develop 

liquids loading problems relatively quickly under certain situations? Are certain wells (or wells in certain 

basins) more prone to developing liquids loading problems, such as hydraulically fractured wells versus 

conventional wells or horizontal wells versus vertical wells? 

Response: As wells age, downhole pressure declines, requiring some artificial means of boosting the 

downhole pressure. Some gas formations have a natural water drive. As the well declines, more water is 

produced, therefore those wells need a system (plunger lift, gas lift valves, etc.) to keep the well bore 

flowing. 

Liquids unloading is mainly an activity done for gas wells, if heavier liquids cannot be removed from the 

well bore the gas cannot get to the surface as the pressure against the formation is too great therefore not 

allowing the produced streams into the well bore for production. 

Question 4: Did this paper capture the full range offeasible liquids unloading technologies and their 

associated emissions? Please comment on the costs of these technologies. Please comment on the 

emission reductions achieved by these technologies. How does the well's life cycle affect the applicability 

of these technologies? 

Response: This paper did not include any mention of gas lift with side mandrels. For this configuration, 

gas is injected down the casing tubing annulus and enters the tubing through a series of valves. The gas is 

injected at the bottom of the column of fluid, and pushes the fluid and produced gas up to the surface for 

production. A portion of the gas is recycled for the gas lift operation, usually into a closed system, 

occasionally the tubing valves in the well must be filled with fluid to allow for the tubing to be pulled for 

repairs to be made. During this time, gas is routed for a short period of time to the atmosphere. 

Question 6: In general, please comment on the ability of plunger lift systems to perform liquids unloading 

without any air emissions. Are there situations where plunger lifts have to vent to the atmosphere? Are 

these instances only due to operator error and malfunction or are there operational situations where it is 

necessary in order for the plunger lift to effectively remove the liquid buildup from the well tubing? 
Response: Yes, there are situations where plunger lifts must vent to the atmosphere. Plungers which will 

not come to surface must be manipulated in ordered to get the liquids from the formation to the surface so 

the well can regain gas flow. Depending on the design of the system and infrastructure availability, some 

vent while others put into closed systems. 

Question 7: Based on anecdotal experience provided by industry and vendors, the blowdown of a well 

removes about 15% of the liquid, while a plunger lift removes up to 100% (BP, 2006). Please discuss the 

efficacy of plunger lifts at removing liquids from wells and the conditions that may limit the efficacy. 

Response: A plunger lift system does not eliminate all liquids unloading. The plunger lift allows for gas 

production to occur and the constant sweeping of the tubing prevents liquids from gathering in the tubing 

which would hamper flow. In a plunger lift system, liquids unloading of water usually occurs, or is 

needed, when the plunger malfunctions or becomes damaged or automation issues occur. When this 

happens the wellbore may fill with liquids and pressures may increase, preventing the gas from flowing to 

the well bore and producing. A manual effort must be made to unload the liquids off the well by getting a 

pressure differential to push the liquids out. Usually this is done into a tank and the gas vents to the 

atmosphere. Once all the water is evacuated from the wellbore the plunger may then return to normal 

operation. In some cases the tubing would need to be pulled to retrieve the stuck plunger if a pressure 

solution is not successful. 

Question 9: Please comment on the on the pros and cons of installing a "smart" automation system as part 

of a plunger lift system. Do these technologies, in combination with customized control software, 

improve performance and reduce emissions? 

Response: Automated systems are not feasible for existing operations. Although they save gas and 

maintenance, operators would need to design a system from scratch which is costly and requires 

significant advanced planning time. 

Question II: The EPA is aware that in areas where the produced gas has a high H2S concentration 

combustion devices/flares are used during liquids unloading operations to control vented emissions as a 

safety precaution. However, the EPA is not aware of any instances where combustion devices/flares are 

used during liquids unloading operations to reduce VOC or methane emissions. Please comment on the 

feasibility of the use of combustion devices/flares during liquids unloading operations. Please be specific 

to the types of wells where combustion devices/flares are feasible. Are there operational or technical 

situations where combustion devices/flares could not be used? 

Response: We are not aware of any flaring with regard to plunger lift operations. For any combustion 

device one would have to have a scrubber (additional cost) ahead of the flare or combustor in order to be 

sure no liquid goes over the top of the flare or combustor. 

Question 12: Given that liquids unloading may only be required intermittently at many wells, is the use 

of a mobile combustion device/flare feasible and potentially less costly than a permanent combustion 

device/flare? 

Response: For wells that require intermittent unloading, the only time gas would go to atmosphere would 

be when the plunger is not operating. A quick flow back may only be minutes, thus making moving a 

portable device in, igniting it, and using it requires significant effort with potentially a very low reduction 

in emissions. There are safety issues for operating combustion equipment. Timing could be an issue as 

many wells only need unloading for minutes and not hours making the set up to control somewhat 

burdensome for the amount of emissions reduced. 

Question 13: Given that there are multiple technologies, including plunger lifts, downhole pumps and 

velocity tubing that are more effective at removing liquids from the well tubing than blowdowns, why do 

owners and operators of wells choose to perform blowdowns instead of employing one of these 
technologies? Are there technical reasons other than cost that preclude the use of these technologies at 

certain wells? 

Response: Non plunger lift gas wells must also be unloaded, if liquids build up in the well bore. These 

wells are not typically automated and require a manual solution to regain flow. In many cases these wells 

are blown to the atmosphere; however, if a production location is near, there may be options to route the 

flow to a separator and separate the liquid and gas and sell the gas during the unloading. This is 

dependent on access to infrastructure. 

IV. Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions and Associated Gas 

during Ongoing Production Charge Question Responses: 

Question 12: Please comment on estimates of associated gas emissions in this paper, and on other 

available information that would enable estimation of associated gas emissions from hydraulically 

fractured oil wells at the national- and the well-level. 

Response: We respectfully urge EPA to rely on actual measurements when they are available. For 

example, in section 3.6, EPA referenced the Brandt study as a source of emissions from completions, but 

the Brandt study relied on emissions estimations as opposed to actual emissions measurements. This is 

problematic because Brandt's method is based on a daily rate of production and assumes flow back 

emissions increase linearly over the first nine days until the peak is measured. The Allen et al 2013 study 

did not find many completions that lasted for nine days as most completions are significantly shorter. 

Fewer days offlowback would indicate lower emissions. Further, the Brandt study did not cover 

emission from oil wells, it only covered natural gas. 

Chevron respectfully recommends that the white paper ensure that all references be peer-reviewed, widely 

available, and be reports that have received comments from multiple stakeholder, such as the Greenhouse 

Gas Reporting Program and the APIIANGA survey. 

Question 13: Please comment on availability of pipeline infrastructure in hydraulically fractured oil 

formations. Do all tight oil plays (e.g., the Permian Basin and the Denver-Julesberg Basin) have a similar 

lack of infrastructure that results in the flaring or venting of associated gas? 

Response: Chevron supports API in noting one of the most effective actions that could be taken by the 

EPA and other agencies in the federal government would be to reduce the unnecessary delays in the 

review and approval processes and allow construction of infrastructure wherever it is economically 

viable. This would allow for sale of a majority of the stranded gas that is currently produced and flared. 

V. Oil and Natural Gas Sector Pneumatic Devices Charge Question Responses: 

Question 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? 

Response: If the measurement devices used in the studies referenced in the white paper are not well 

calibrated and maintained between usages, then emission release rate data could vary. Utilizing the same 

measurement equipment from test to test would be a best practice. Differences in measurement! vapor 

capture techniques from study to study could also produce variance in emission release rate data. 

With regards to the controllers, the following operational characteristics will impact emissions: 

• Controller types - different types of the controllers result in different emission release rates 
• Controller application 

• Inlet supply pressure 

• Amount of fouling or wear to the components in the controllers, such as nozzle, flapper, 

bellows, etc. 

• Improper installation of controller components, such as the nozzle or flapper 

Question 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. 

Response: Low bleed and zero bleed devices are only available to replace a limited number of existing 

controllers. They are not available to replace all existing controllers. The actuator being controlled by 

any pneumatic device would still produce the same amount of emissions, with or without a low-bleed 

controller installed and therefore, much of the total instrument gas usage would remain unchanged. With 

regards to new pneumatic devices, a best practice where applicable, would be installation of low-bleed 

devices. 

The ability to replace high bleed controllers with low bleed models will depend on several process and 

operational parameters such as controller's function, pressure, and its location in the facility. 

Converting an existing pneumatic device from natural gas to instrument air is only viable where reliable 

electric power is available. To maintain the level of reliability with air compression systems that can be 

achieved with instrument gas systems, additional maintenance of the air system and additional operator 

surveillance is required. To maintain reliability, an air system requires more operator visits to well 

site/facility locations than a gas system requires. This additional transportation may contribute more to 

total emissions than reduction gains from installation of an instrument air system. 

Some new technologies that are mentioned in the paper such as "GE Energy Technology" to replace 

continuous bleed with zero bleed controller need to be field tested or enough data needs to be collected 

before recommending or prescribing this technology. Voluntary programs such as Natural Gas STAR 

could provide an opportunity to field test these technologies. 

Question 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? 

Response: Instrument air systems require a reliable power source to operate, which is an issue for remote 

locations onshore and offshore oil & gas facilities. Space and weight limitations prohibit installation of 

additional-power generation equipment and/or air compression equipment on some offshore facilities. 

Unmanned offshore facilities would require more operator visits to maintain reliability, thus more 

transportation fuel use, by helicopter and boat to maintain a power generation system and an instrument 

air system. Total emissions could actually increase. 

Question 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? 

Response: Yes. For each instrument air system installation, there must also be a reliable power generation 

system, which does not exist on many offshore facilities or at remote onshore facilities. 

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

and pneumatic pumps? Are these electric devices applicable to a broader range of the oil and gas sector 

than this paper suggests? 
Response: This paper seems to correctly characterize the limitations of electric-powered pneumatic 

controllers and pneumatic pumps and their applicable range in the oil and gas sector. 

Question 9: Are there ongoing or planned studies that will substantially improve the current 

understanding ofVOC and methane emissions from pneumatic controllers and pneumatic pumps and 

available techniques for increased product recovery and emissions reductions? 

Response: Regarding ongoing studies of pneumatics that will substantially improve the current 

understanding ofVOC and methane emissions from pneumatic controllers, we would like to note the 

second phase of the UT/EDF study led by Dr. David Allen. While we expect Dr. Allen will respond 

directly to this question as a peer reviewer of these papers, we do believe this study will improve our 

current understanding by growing the sample size of controllers from the 2013 Allen eta] study.