## Chevron 

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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 ofAir and Radiation

- OAQPS I09 T.W

.AlexanderDr. D205-02 Research Triangle Park, North Carolina 27711

DearMr. 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 ofthe energy business: exploration, production, manufacturing, transportation, marketing, and research. Chevron is committed to conducting ouroperations safely and in a mannerthat protects the environment. Chevron is an active operator in theUnited States, with exploration and production operations in Alabama, California, Colorado, GulfofMexico, Louisiana, Michigan, NewMexico, Ohio, Oklahoma, Pennsylvania, Texas, Utah, WestVirginia, and Wyoming.

We appreciate the opportunity to provide feedback on the five "White Papers on Methane andVOC 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 dataand where we feel additional clarification in the papers would be valuable.
Chevron appreciates EPA'seffort to include stak eholderfeedback in this early attempt to better understand these sources. We look forward tofuture engagements on this effort. We believe it is crucial thatthe EPA and other interested agencies work closely and collaboratively with industry stakeholders who bringreal world expertise and experience to these very complex issues

. Workingtogether at early stages and consistently throughout the process will better inform EPA's inquiry objectives.
As noted throughoutthese white papers, it is critical for EPA to develop the highestquality data to fully understand the quantification ofemissions, 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'scommitmentto work with industries across the economy to help ensure thatthe Agency is relying on the highestquality data in considering anyfuture policy-making ef

forts. Significant and appropriate data is required due to the unique characteristics and variability across oil and gas operations. Each well is like a fingerprint asthe formation pressure, depth, wellbore design, surface facilities, and nearby infrastructure all vary and all are factors that mustbe identified and considered

. No two wells are the same, and no twoformations are the same; each well will have its owndesign criteria. Consideration should be given tothis variability when examining data

. Further, for offshore facilities, itis importantto note that it is generally considerably less cost-effective to implementthe 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 EPAtoconsiderthe positive contributions that voluntary programs such as Natural Gas STAR and STRONGER(State Review ofOil and Natural Gas Environmental Regulations) can, and already are, makingtoreduce methane emissions from the oil and gas sector. TheNatural 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 newtechnologies and determine cost-effectiveness and feasibility in a widerange ofbasins. 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 STRONGERReviewprogram is finalizing state air regulatory program guidelines. EPA is a member ofthe STRONGERBoard, and is providingprogram funding support. EPA should engage with STRONGER state, industry, and environmental stakeholders to supportenhanced voluntary fugitive emissions measures as well as continuous state air regulatory program improvement. These programs enjoy supportfrom industry, EPA, and the Department ofEnergy; and STRONGER includes representatives from environmental NGOs, state regulatory agencies, and industry on its board. STRONGERhas theflexibility torespond tothe unique characteristics ofeach basin, formation, and facility in which the oil and gas sector operates. ln addition tothe chargequestion responses that follow, we would like to provide comment on the ICF/EDF March 2014 paper, which is emphasized in each ofthe white papers. While we supportthe general methodology, we have concerns with various assumptions in the ICF/EDF paper. Forexample, someofthe labor costs cited are significantly belowcurrent labor costs for maintenance. The ICF/EDF st

udy utilizes a laborrate ofapproximately $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 benefitrate is 38% for exempt workers and 45% for non-exempt workers (Source: http:// professionals

.pr.doe

.gov/srs/pdf/laborrates fringe.pdf(accessed 4/2014))

. Additionally, it appears that ICF/EDF calculations allow for approximately 25 minutes oftravel 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 seemto ignore the costs ofa computer system and quality control.
Issues with CostAnalysis The cost ofimplementation ofthe various proposals in the ICF/EDF study is underestimated, thus not cost-effl

. . db fi ect1ve to perceive ene Its. Capital and 0 Analysis must incorporate related installation, engineering, and permitting Operational costs (ifapplicable); 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 respectto attribution amongst various potential sources. Ifrelying on top-down emissions estimates, reductions maybe significantly lower than estimated, lowering cost-effectiveness ofvarious controls. Site specific 0 Relative mitigation costs and projected performance are highly variable, and estimation average values presented lose meaning in the context oflocal operators with costs based on geographical value chains. Benefits 0 Benefits are overstated in cases wherethe quality ofgas is affected by the vapor recovery pressure and presence ofcontaminants (e.g. from seal oil). Dated baseline 0 Anticipated new data and analysis could create significant costestimate fluctuations from 2011 EPA GHG Inventory.Review ofProposed Mitigation Measures Not all measures are feasible orcost-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 widerrange ofoperations. Plunger lifts 0 Lesson learned from the Natural Gas STARPartners quotes higher CAPEX per well. 0 Effectiveness ofplunger lifts for horizontal wells has not been proven.
We appreciate yourtime and consideration in examiningthe charge question responses that follow. We look forward to the opportunity to further discuss these items. Ifyou have any questions, please contact Judy Blanchard in our Government Affairs' Washington, DC office at (202) 408-5858 orvia email at jblanchard@chevron.com, orVanessa Ryan in our GovernmentAffairs office in San Ramon, our corporate headquarters at (925) 790-3803 orvia email at vanessa.ryan@chevron.com.



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Maria Pica Karp Vice President and General Manager, Government Affairs

Attachment:
Chevron Response to White Paper Charge QuestionsCharge Question Responses
I. Oil and Natural Gas Sector Compressors Charge Question Responses: Question 3: Did this paper capture the full range oftechnologies 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"Iowemissions packing" for reciprocating compressors but has no detailed information on this technology. Response: There is little mention ofmaintenance practices that can impactreciprocating compressorrod packing life. Lubrication has significant impact on rod packing, i.e.

- properrate, type, pre and post lube, compressed gas composition. Routine rod packing monitoring by operations and maintenance personnel, orautomated monitoringtechniques and systems are available. Low emission packing will likely work well in some applications, iffully 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 ofvented 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. Forreciprocating compressorrod packing replacement, the estimated costtoreplace 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 packingring replacement cost seems to be based on 2006 dollars as opposed to currentyear value. Also, it is not clear whether the costpresented in the paper is based upon a presumption that the units are already down and isolated for maintenance. Ifso, the cost included in the paper likelyjustrepresents the incremental cost ofreplacing reciprocating compressorrod packing. There is no indication ofwhetherthe packing case and compressorrod required maintenance, but cost stated for rod packingreplacement does not appearto coverthis.
Two options are discussed for reciprocating compressors gas recovery: REMTechnology and a Vapor Recovery Unit (VRU) system. Ourexperience is that the REM technology is sound when applied correctly, butthepayout onfuel savings alone is too long to meet economic thresholds. The cost ofa VRU Gas Recovery system would be significantlyhigherthan shown in the white paper because the paper does not appearto address any ofthe cost associated with controls and safeguards. Please note that to implementthis technology offshore would be considerably more expensive. Newtechnologies, 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 ofgas capture systems at certain reciprocating compressors impractical? Response: For REM technology, it is a concern ifthe 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 equipmentreliability issues that haveto be addressed and mitigated before this type ofsystem can be utilized. With regards to the VRU system, the very low pressure on reciprocating compressor distance pieces (typically inches ofwater) makes routing these emissions to a VRU infeasible, unless the VRU is located in the immediate vicinity ofthe compressor. Therequired controls and safeguards must be given serious evaluation. Specific areas ofconcern 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 ifcompressing multiple gases. Ifthe 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 ofair during flaring events. Question 12: Are there ongoing orplanned studies thatwill substantially improve the current understanding ofvented VOC and methane emissions from reciprocating and centrifugal compressors and available techniques for increased productrecovery 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 ofvented emissions from these compressors. II. Oil and Natural Gas SectorLeaks 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 "forthcomingpublications" 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 ofemission detection can be applied to both oil and natural gas systems, the procedures should account for the inherentvariability- methane and VOC leakage rates, probabilities ofoccurrence, equipmenttypes, etc. -between oil and natural gas operations. Forexample, the decline rate in oil and associated gas may not bethe same. Question 7: Please comment on the pros and cons ofthe 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 ofleaks. 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 atthe sametime 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 ofthe leak, wind speed, wind direction, elevation ofthe plume and location ofthe monitor.
Ill. Oil and Natural Gas SectorLiquids Unloading Processes Charge Question Responses: Question I: Please comment on the national estimates ofmethane 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 ofliquids unloading (e.g., regional geology)? Response: Regarding Table 2-2, and Section 2.5, it is very importantto keep in mind the BestAvailable Monitoring Methods (BAMM) nature ofthis 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 SubpartW data. Data will be more reliable ifthe 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 earlieryears. 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 ofliquids unloading such as geology, depth, formation characteristics, infrastructure, and duration and frequency ofwell blowdowns. Question 2: Is there further information available onVOC ormethane 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 eta] 2013 study to update its information. However, one ofthe conclusions from the Allen etal 2013 study is thatthere were not enough unloading measurements to draw any substantial conclusions. Given this finding, it is not clearwhy ICFIEDF uses this data given thatthe basis ofthe calculation is not supported by the Allen et al 2013 study. Infact, the white paperreproduces the caution listed by the Allen etal paper aboutthere being insufficient data to characterize emissions. Question 3: Please comment onthe types ofwells thathave the highest tendencyto develop liquids loading. Itis 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 orhorizontal wells versus vertical wells? Response: As wells age, downhole pressure declines, requiring some artificial means ofboostingthe 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, ifheavier liquids cannot be removed from the wellbore the gas cannot gettothe surface as thepressure against the formation is too greattherefore 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 ofthese technologies. Please comment on the emission reductions achieved by these technologies. How does the well's life cycle affect the applicability ofthese technologies? Response: This paper did not include any mention ofgas lift with side mandrels. Forthis configuration, gas is injected down the casing tubing annulus and enters the tubingthrough a series ofvalves. The gas is injected at the bottom ofthe column offluid, and pushes the fluid and produced gas up tothe surface for production. A portion ofthe 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 thetubingto be pulled for repairs to be made. During this time, gas is routed for a short period oftime to the atmosphere. Question 6: In general, please comment onthe ability ofplunger lift systems to perform liquids unloading without any air emissions. Arethere situations where plunger lifts have to ventto the atmosphere? Are these instances only due to operator error and malfunction or are there operational situations where it is necessary in orderfor the plunger liftto 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 theformation to the surface so the well can regain gas flow. Depending on the design ofthe 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 ofa well removes about 15% ofthe liquid, while a plunger lift removes up to 100% (BP, 2006). Please discuss the efficacy ofplunger 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 ofthe tubing prevents liquids from gathering in the tubing which would hamper flow. In a plunger lift system, liquids unloading ofwater usually occurs, oris needed, when the plunger malfunctions orbecomes 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 offthe well by getting a pressure differential to push the liquids out. Usually this is done into a tank and the gas vents tothe 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 ifa pressure solution is not successful. Question 9: Please comment on the on the pros and cons ofinstalling a "smart" automation system as part ofa 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: TheEPA 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 ofany instances where combustion devices/flares are used during liquids unloading operations to reduce VOC or methane emissions. Please comment on the feasibility ofthe use ofcombustion devices/flares during liquids unloading operations. Please be specific to the types ofwells where combustion devices/flares are feasible. Are there operational ortechnical situations where combustion devices/flares could not be used? Response: We are not aware ofany flaring with regardto plunger lift operations. For any combustion device one would have to have a scrubber (additional cost) ahead ofthe flare orcombustor in orderto be sure no liquid goes over the top ofthe flare orcombustor. Question 12: Given that liquids unloading may only be required intermittently at many wells, is the use ofa 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 makingthe set up to control somewhat burdensome for the amount ofemissions 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 ofwells chooseto perform blowdowns instead ofemploying one ofthesetechnologies? Are there technical reasons other than cost that preclude the use ofthese technologies at certain wells? Response: Non plunger lift gas wells must also be unloaded, ifliquids build up in the wellbore. These wells are nottypically automated and require a manual solution to regain flow. In many cases these wells are blown to the atmosphere; however, ifa production location is near, there may be options to route the flow to a separatorand 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 ofassociated gas emissions in this paper, and on other available information thatwould enable estimation ofassociated gas emissions from hydraulically fractured oil wells atthe 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 ofemissions 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 ofproduction and assumes flowback emissions increase linearly overthefirst 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. Fewerdays offlowbackwould indicate lower emissions. Further, the Brandt study did not cover emission from oil wells, it only covered natural gas. Chevron respectfully recommends thatthe 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 ofpipeline 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 ofinfrastructure that results in the flaring orventing ofassociated gas? Response: Chevron supports API in noting one ofthe 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 ofinfrastructure wherever it is economically viable. This would allow for sale ofa majority ofthe 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 ofemission rates that have been observed in direct measurement studies ofpneumatic controller emissions (e.g., Allen etal., 2013 and Prasino 2013). Are these differences driven purely by the design ofthe monitored controllers or are there operational characteristics, such as supply pressure, thatplay a crucial role in determining emissions? Response: Ifthe measurement devices used in the studies referenced in the white paper are notwell calibrated and maintained between usages, then emission release rate data could vary. Utilizingthe same measurement equipment from testtotest 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: • Controllertypes

- different types ofthe controllers result in different emissionrelease rates• Controller application • Inlet supply pressure • Amount offouling orwearto the components in the controllers, such as nozzle, flapper, bellows, etc. • Improper installation ofcontroller components, such as the nozzle orflapper Question 4: Please comment on the pros and cons ofthe different emission reduction technologies. Please discuss efficacy, cost and feasibility for both new and existing pneumatics. Response: Lowbleed and zero bleed devices are only available to replace a limited number ofexisting controllers. They are not available to replace all existing controllers. The actuator being controlledby any pneumatic device would still produce the same amount ofemissions, with orwithout a low-bleed controller installed and therefore, much ofthetotal instrument gas usage would remain unchanged. With regards to new pneumatic devices, a best practice where applicable, would be installation oflow-bleed devices.
The abilityto 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 ofreliability with air compression systems that can be achieved with instrument gas systems, additional maintenance ofthe 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 ofan instrument air system. Some new technologies that are mentioned in the paper such as "GEEnergy Technology" to replace continuous bleed with zero bleed controller need to be field tested or enough data needs to be collected before recommending orprescribing 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 aircompression equipment on some offshore facilities. Unmanned offshore facilities would require more operatorvisits to maintain reliability, thus more transportation fuel use, by helicopter and boatto maintain a power generation system and an instrument air system. Total emissions could actually increase. Question 7: Arethere situations where it may be infeasible to use air driven pumps and controllers in place ofnatural gas-driven pumps and controllers even where it is feasible to install an instrument air system? Response: Yes. Foreach instrument air system installation, there must also be a reliable power generation system, which does not exist on many offshore facilities or atremote onshore facilities. Question 8: Did this paper correctly characterize the limitations ofelectric-powered pneumatic controllers and pneumatic pumps? Are these electric devices applicable to a broaderrange ofthe oil and gas sector than this paper suggests?Response: This paper seems to correctly characterize the limitations ofelectric-powered pneumatic controllers and pneumatic pumps and their applicable range in the oil and gas sector. Question 9: Arethere ongoing orplanned studies thatwill substantially improve the current understanding ofVOC and methane emissions from pneumatic controllers and pneumatic pumps and available techniques for increased productrecovery and emissions reductions? Response: Regarding ongoing studies ofpneumatics that will substantially improve the current understanding ofVOC and methane emissions from pneumatic controllers, we would like to note the second phase ofthe UT/EDF study led byDr. David Allen. While we expect Dr. Allen will respond directly to this question as a peerreviewer ofthese papers, we do believe this study will improve our current understanding by growing the sample size ofcontrollers from the 2013 Allen eta] study.