Page 1 of 26 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY WASHINGTON, D.C. 20460

OFFICE OF
AIR AND RADIATION

Petroleum and Natural Gas Systems (Subpart W) of the Greenhouse Gas Reporting

Rule Docket: EPA-HQ-OAR-2009-0923

Title: Early Comment Submission Memo

Summary: This document contains comments submitted by e-mail to a separate tracking system prior to the official comm ent period. EPA decided to only respond to comments directly related to the April 2010 proposal.Page 2 of 26 Early Comment Submission Memo

EPA received these email submissions outsi de of the official comment period and responded to these questions where appropria te in the response to comments (RTC) document. EPA decided to only respond to co mments directly related to the current proposal. The email submissions are listed as follows and actual submission documents

are located below –

1. American Exploration and Production Council (EMAIL-0001) 2. Gas Processors Association (EMAIL-0002) 3. ERM-West, Yasmeen Sultana (EMAIL-0003) 4. Laclede Gas Company, Steve Donatiello (1/2) (EMAIL-0004) 5. Laclede Gas Company, Steve Donatiello (2/2) (EMAIL-0005) 6. Lindh & Associates, J.C. Solt (EMAIL-0006) 7. Anonymous (EMAIL-0007) 8. Emerson Process, Patrick Truesdale (EMAIL-0008) 9. EC/R Incorporated, Robert Vogt (EMAIL-0009)

10. Innovative Environmental Solutions , Thomas McGrath (EMAIL-0010) 11. Swanner Consulting & Reporting, LLC, Robin Swanner (EMAIL-0011) 12. Milan Steube, Milan Steube (EMAIL-0003)

American Exploration and Pr oduction Council (AXPC)

Comments to EPA Proposed Part 98 Subpart W

Docket EPA-HQ-OAR-2009-0923

RIN Number 2060-AP99

April 27, 2010

1. Aggregation of E&P Sites (Reporting Area)

A. Facility Definitions

Industry and regulators currently have a ve ry good understanding of what the term “facility” means in the O&G upstream sect or. Company representatives as well as state regulatory agencies have been using this term to apply current CAA requirements across the country. Our r ecommendation is that we rely on the current actively used definition of f acility that EPA change their proposed language to refer to a “thr eshold reporting area” or “r oll-up area threshold” to define a geographical area to which a thres hold can be applied th at is made up ofPage 3 of 26 oil and gas upstream facilities. This woul d help alleviate indus try concerns that the reporting rule definiti on of “facility” might impact perception of the CAA

definition.

For example, 98.238 ‘Onshore petroleum a nd natural gas production facility’

would read: ‘ Onshore petroleum and natural gas production reporting area means all petroleum or natural gas facili ties and equipment associated with all petroleum or natural gas production unde r common ownership or common control by an onshore petroleum and natural gas pr oduction owner or operator located in a single hydrocarbon basin as defined...’

The term reporting area could then be refe rred to in the definition of the source category; i.e., 98.230(2) ‘Onshore petr oleum and natural gas production’: Onshore petroleum and natural gas producti on reporting area mean s all facilities

associated with wells the production of petroleum or na tural gas including but not

limited to...

B. Upstream Production Sites Should Not Be Aggregated

EPA should not require aggregation of ups tream production sites. This imposes a disproportionate burden on our indus try by requiring data collection, recordkeeping, and reporting for hundreds of thousands of operated sites. As the rule is written, even very small operators will have to calc ulate and aggregate GHG emissions to determine if they must report or not report.

EPA states in the preamble that the information gathered by this rule would inform and are relevant to EPA’s carryin g out a wide variet y of Clean Air Act (CAA) provisions. It is understood that the GHG emissi on inventory data will be used to define future permitting and comp liance programs. For this reason, we do not agree with redefining the term “facility” in this part. If the information in this program will be used for other CAA programs, then it must be collected in a manner that is consistent with how it will be applied in those programs.

Future GHG permitting and compliance programs under the CAA will still rely on the definition of facility as found in 40 C.F.R. 52.21(b)(6):

Building, structure, facility, or installation means all of the pollutant-emitting activities which belong to the same i ndustrial grouping, are located on one or more contiguous or adjacent properties, and are under the control of the same person (or persons under common control) except the activities of any vessel. Pollutant-emitting activities shall be considered as part of the same industrial grouping if they belong to the same “Maj or Group” (i.e., which have the same first two digit code) as described in the Standard Industrial Classification
Manual, 1972, as amended by the 1977 Supplement (U. S. Government Printing Office stock numbers 4101–0066 and 003–005–00176–0, respectively).Page 4 of 26 In accordance with this definition a nd multiple case-by-case aggregation determinations by EPA and the states, most production operations across a single hydrocarbon basin cannot be aggregated in to one facility. If these production operations are not aggregated by basin, th en each facility or well site must individually be assessed for applicability to the future permitting and compliance programs. At this time, an applicab ility threshold of 25,000 metric tons CO 2 e or more per year has been proposed for permitting, and that threshold will apply at the facility level. If the purpose of this rule is to inform future rule-making, there is no benefit to collecting information for an aggregation of many small facilities that will not be subject to the future ru les. We request that this definition be

modified to be consistent with the de finition employed in other CAA programs.

C. If Upstream Production Sites are Aggregated

If EPA rejects important financial burden and CAA definition of “facility” arguments and retains aggregation of upstream production sites, it should take reasonable steps to mitigate the adverse financial burden to industry, especially very small operators. This would include:

• Exempting small sites using well define d screening thresholds such as (1) natural gas production sites with only wellhead fugitive emissions and produced water storage tank emissions, (2) any natural gas production site with less than 3 MMSCFD of pr oduction and less than 1 BOPD condensate production, and (3) oil stri pper wells producing less than 10

BOPD.

• Allowing the use of the API Compendi um for calculations of emissions from upstream production sites. (See Item 3 below).

2. Reporting of Emissions from Onshore Petroleum and Natural Gas Facilities

A. Basin Level Aggregation

EPA is seeking comment on whether to use “basin level” for aggregation as proposed, or “field level”. If EPA goe s forward with aggregation of upstream production sites, a “field le vel” approach would be much more practical for the following reasons:

• Some basins are very large (the Pe rmian Basin stretches from southeast

New Mexico and southwest Texas n early to Louisiana. Basins can typically cross state lines such that GHG reporting by basin would not

allow states or the EPA to determine which state the emissions are from. In addition, basins can cross multiple regional and district operating boundaries for companies making gathering of emissions information data

more difficult.Page 5 of 26 • EPA has overestimated the reduction in emissions coverage for field level aggregation versus basin level aggregation. Most large and small operators concentrate in producing from certain fi elds within a basin. The Barnett

Shale in Texas covers 24 counties. However, one large independent operates approximately 2,000 wells, but w ith 95% of those in just three or

four counties.

• The quality of emission estimates would be greater for emissions estimates

made on a field level rather than a ba sin level. Oil and gas characteristics and the method of separation and pro cessing are directly related to the field from which the oil and gas is produced. Fields are well defined by state oil & gas commission rules. Wh en wells are comingled, the percent of production from a particular field (s and or formation) can be assessed using royalty calculations to provide the percentage production from a particular field. The field which produ ces the majority of the oil and gas for a comingled well can be used as the field that a well reports under.

• Aggregation by basin level would comp licate efforts for simple auditing by EPA as it would be difficult to determine whether emissions reported are reasonable compared to emissions reported from other companies. EPA would not know how much produc tion came from various fields

within that basin.

• For all the above reasons, we suppor t the API’s proposed approach that would allow operators the flexibility to report at the basin level but allow them to identify rational “reporting units ” within a basin that have similar operations, equipment, fluid propert ies, and physical properties, and enable the use of “population averag e” emission factors and approaches for emission quantification. This woul d allow calculati on and reporting of emissions from reasonable “well groupi ngs” such as known fields within a basin or even by county within a basin.

B. Fugitive Emissions from Pipelines (s uch as flowlines or intra-facility gathering lines)

These emissions should be exempt from reporting for the same reasons that EPA exempted emissions from transmission lines. Gathering pipelines generally operate at much lower pressures than transmissions lines. The interconnecting pipelines consist mostly of welded conn ections and thousands of small metering

stations. EPA has underestimated the bur den to industry to obtain component counts on these pipeline fac ilities. In addition, many comp anies now have internal programs to find and fix leaks associated w ith these gathering pipelines as well as for the longer distance transmissions lines.Page 6 of 26 C. Emissions from Portable Non-self-pro pelled Equipment (such as well drilling and completion equipment, workove r equipment, gravity separation equipment, auxiliary non-transportation related equipment).

EPA should delete the reporting of emi ssions from these non-stationary and portable sources. EPA should simply use its own updated total emissions estimates for these sources. The huge a dded expense for industry to calculate, keep records, and report emissions from t housands of these sour ces is not justified by the small incremental emissions reporting accuracy EPA many be expecting from this approach. More specifically:

• Most wells are drilled and completed using contract service companies. EPA underestimates the difficulty of tracking equipment and estimating emissions from field portable equipmen t that are operated by third parties

even when stationed at a well site for more than 30 days. Complying with this requirement as proposed would be very resource intensive and complex since this equipment is of ten moved from well to well and between operators. In many cases, si te operators would not have the operational data to perform the needed calculations and/or the necessary records to certify the accuracy of GHG emissions data. When the well site operator does not control th e operation or maintenan ce of the equipment, it is not appropriate to require reporting and compliance tasks of the well site operator because they do not participate in engi ne maintenance or the

collection of fuel use data. All ot her Clean Air Act programs establish applicability based on whether a part y owns and/or ope rates a source
because it is not feasible for someon e who does not control the day-to-day operation of a source to collect the required information or monitor the source’s usage. Is any other industry s ector required to re port contractor’s emissions for this reporting rule?

• All of these activities are non-s tationary source and temporary

construction activities that should be excluded just as other construction activities (housing, commercial buildi ng, roadways, etc) are excluded. Requiring estimates of these emissions greatly increases the reporting burden on the oil and gas industry w ithout a corresponding increase in emissions reporting coverage. For instance, even using updated methodology from its Natural Gas Star work, EPA estimated that emissions from well completions would only represent 0.0004% and that

emissions from well workovers would only represent 0.04% of the 80% of fugitive and vented emissions from the onshore production sector (see Appendix A & B: Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry). As noted in Appendix A, EPA over

rode its own decision tr ee process when includi ng these sources that amount to such a miniscule part of emissions.Page 7 of 26 • The total number and type of wells completed in the U.S. is well known; therefore, EPA could easily obtain a reasonable estimate of those GHG emissions using the Natural Gas STAR data mentioned above. EPA could then add-on the emissions estimates for drilling and completing wells to the inventory.

• The vast majority of engines included in this category are fired by diesel fuel. Emissions from these non-road engines are exempt from reporting under Subpart C. Reporting GHG emissions from these engines under Subpart W would result in double coun ting of emissions since emissions

from the combustion of diesel fuel are reported by suppliers of petroleum products under Subpart MM.

3. Direct Measurement

Although EPA has reduced some direct measurement requirements from the first Subpart W proposal, EPA still chooses to ignore longstanding and accepted international protocols for emissions calcula tions that other count ries have adopted and currently use to calculate their oil and gas sector emissions. This includes Australia NGERS, EU-ETS, and Alberta for which all emissions are based on the API Compendium-IPIECA standards. EPA is assuming that better data will result from documenting and calculating emissions from ev ery single small component related to oil and gas production instead of using carefully documented emissions factors applied across larger units. This procedure ignores the rules of probability and statistics and rejects average values in favor of counting ever y bean. There is no

reason to believe that this burdensome method of data collection will produce an emissions number of greater value or validity than other accepted and proven techniques. The proposed rule is considerab ly more burdensome for onshore facilities

than offshore facilities where MMS GOA DS reporting standards are acceptable.

4. Economic Impact Analysis

We are in the process of evaluating the economic impact analysis provided by EPA. At this point it appears that EPA’s cost estimates for impact on the industry are low by one to several magnitudes . EPA fails to realize the massive amount of data collection and recordkeeping required to calcul ate emissions from the vast majority of some 700,000 well sites in the U.S. The only feasible alternative is to adopt simple threshold exemptions and simplify the data gathering requirements and calculations by use of widely accepted methodologies such as the API Compendium. Industry and the EPA would be much better served by sp ending resources to improve any emission factor methods that EPA feels is not repr esentative of actual emissions (e.g., well blowdowns).

We are particularly concerned with the re quirement to count all fugitive components on every well site and small pr oduction facility that we ope rate. This requirement isPage 8 of 26 very significant in terms of effort and cost. T hus, it is critical to us to receive relief on fugitive component inventory.

5. Minority Owners

Has the requirement for minority owners to sign-off on reported emissions been

removed?

6. Annual Reporting

What is the rationale for annual reporting wh en experience with the U.S. Inventory of GHG emissions show very gradually changes in the total inventory on a year to year basis? For instance, even with the r ecent recession total inventory was only down about 2 to 3%. Has EPA given any thought to whether the large financial burden on industry should be required each and ev ery year when a biannual report could

suffice?

Gas Processors Association
Comments to EPA Proposed Part 98 Subpart W

Docket EPA-HQ-OAR-2009-0923

RIN Number 2060-AP99

April 27, 2010

1) Defining natural gas gathering system compression facilities as part of a gas processing plant is inappropriate.

The definition of a gas processing plant is well established in the context of the Clean Air Act and it does not incorporate stand alone gathering system compression facilities. Gas compression facilities, w hether in the gathering systems upstream of gas processing or in the natural gas transmission sector, are discreet and easily
identifiable facilities. These facilities have been treated as stand alone sites in all previous applications of the Clean Air Act, including all permitting programs and for GHG reporting under 40 CFR Part 98 Subpart C. Continuing this historical treatment of these facilities is not only the most appr opriate action, it will also eliminate the certain confusion that will result from a new definition solely for use in Subpart W of

Part 98.

Even the EPA appropriately recognizes the treatment of gathering system compressor stations as stand alone facilities. On page 26 of the Background Technical Support Document for the Petroleum and Natural Gas Industry, the EPA

states:Page 9 of 26 “Both gathering/boosting stations and natura l gas processing facilities have a well defined boundary within which all processes take place”.

Further, on page 18613 of the Subpart W preamble the EPA states that,

“For some segments of the industry ( e.g., onshore natural gas pr ocessing facilities, natural gas transmission compression facilit ies, and offshore petroleum and natural gas facilities), identifying the facility is cl ear since there are physical boundaries and ownership structures that lend themselv es to identifying scope of reporting and responsible reporting entities.”

In direct conflict to the above statements, the proposed Subpart W definition of Onshore Natural Gas Processing in §98.230(3) appears to require GHG emissions from gathering compression facilities and the gathering pipelines be rolled-up with gas processing plant emissions by stating (emphasis added):

“In addition, field gathering and/or boosting stat ions that gather and process natural gas from multiple wellheads, and compress and transport natural gas (including but not limited to flowlines or intra-facility gathering lin es or compressors) as feed to the natural gas processing plants are considered a part of the processing plant

. Gathering and boosting stations that send the natural gas to an onshore natural gas transmission compression facility, or natural gas distributi on facility, or to an end user are considered stand alone natural gas processing facilities. All residue gas compression equipment operated by a processing plant, whether inside or outside the processing plant fence, are considered part of natural gas processing plant.”

GPA strongly recommends the above text in §98.230(3) be deleted from the Onshore Natural Gas Processing source category definition and a new source category definition be included for “Onshore Natural Gas Gathering Compression”. Using the definition of Onshore Natural Gas Transmission as a template the source category definition for “Onshore Natural Gas Gathering Compression” should be:

“Onshore natural gas gathering compre ssion means any fixed combination of compressors that move natural gas from production fields or other compression facilities into natural gas processing facilities, other gathering compre ssion facilities, transmission pipelines, storage facilities, or other end us ers. In addition, natural gas gathering compressor facilities may in clude equipment for liquids separation, natural gas dehydration, and tanks for the storage of water and hydrocarbon liquids. “

GPA also suggests that the same GHGs and sources reported by processing plants under §98.232(d) be reported by gathering compression facilities.

In addition to the conflicts created by the proposed definition in Part 98, Subpart W regarding applicability of gathering compression facilities, the following issues arise from the proposed Subpart W definition of Onshore Natural Gas Processing in §98.230(3).

a) Increases the number of facilities subject to Subpart C for combustion GHG emissions by approximately 15 times, with no consideration for the size of each individual facility. This results from the fact that, numerically, there are typically 10-20 gathering compression facilities for every gas processing plant.Page 10 of 26 b) Gathering compression facilities are often not uniquely associated with a single gas plant, many gathering compression facilities have connections to multiple gas plants and gas is routed to a plant based on business needs and conditions. Associating any one gathering compression facility to an individual processing plant is not always possible.

c) Rolling-up gathering compression facility emissions with processing plant

emissions is in conflict with EPA’s as sessment of the impact of the proposed Subpart W. EPA inaccurately states in the proposed Subpart W preamble on page 18616,

“... there are a reasonable number of reporters . Most natural gas processing facilities proposed for inclusion in this supplemental proposed rulemaking would already be required to report under subpart C and/or subpart NN of the Final MRR.”

In fact, this proposal will increase the number of facilities subject to Subpart C for compression GHG emissions by approximately 15 times. One GPA member company that has about 45 facilities subject to Subpart C reporting for 2010 would have over 700 facilities subject to Subpart C as a result of this proposal. This level of reporting with no consideration for individual facility emission levels is neither reasonable nor appropriate.

d) EPA makes the following conclusion on page 18619 in the preamble to the proposed Subpart W,

“... requiring only a small fraction of total facilities to report.”

The proposed Subpart W in fact increases coverage of gas gathering and processing facilities to nearly 100% regardless of facility size, which is unduly burdensome and neither reasonable nor appropriate.

e) Gathering compression facilities are typically small facilities and widely dispersed, many of these compression facilities have only 1 or 2 compressors. Significantly sized facilities are already subject to Subpart C reporting if the combustion emissions exceed 25kTon/year and individual compression facilities that exceed 25kTons/year including Subpart W emissions would also begin reporting as required. The proposed Subpart W, however, treats these small and widely dispersed facilities as if they are the same size and complexity of a gas processing plant. Examples of proposed requirements that may be appropriate for processing plants but unduly burdensome for small and widely dispersed gathering compression facilities include: collecting extensive data and modeling tank emissions, compressor rod packing vents, leak detection using optical imaging or population factors, and quarterly sampling of gas streams.

2) Proposed calculation for gathering pipelines is impractical.

EPA is proposing to not include reporting of fugitive emissions from natural gas transmission pipelines due to the dispersed nature of the fugitive emissions and the fact that once leaks are found, the emissions are generally addressed quickly. EPA fails to use this same l ogic for natural gas gathering pipelines

, which are significantly more dispersed than transmission pipelines. GasPage 11 of 26 gathering lines are generally much sma ller diameter and typically operate at much lower pressures than transmissions lines, resulting in a lower potential for emissions. Some gathering pipelines even operate on a vacuum. It is also important to note that many gathering and processing companies have implemented robust programs to find and fix pipelines leaks. Contrary to the transmission pipelines, EPA appears to propose that gas processing plants and producers conduct a physical count of piping components on gathering lines and use population factors to determine emissions. Operators then apply another factor (scf/hour/mile) to calculate GHG emissions from the pipeline segments.

GPA estimates that there are over 250,000 miles of gathering pipelines in the gathering & processing sector, and hundreds of thousands meter and valve settings, that would require physical component counts. Even more impractical, is the requirement to conduct compositional analysis at these sites to determine methane and CO2 concentrations. Further, operators would have to track blowdowns and changes in small meter runs and pipe segments in these hundreds of thousands of insignificant locations to report GHGs as required by proposed Subpart W.

EPA has significantly underestimated the burden to industry to obtain the information to calculate the emission estimate for gathering pipelines. It is also noted that the emission factor for the gathering pipeline segments (2.81scf/hour/miles) is derived fr om an unexplained total pipeline emission estimate of 6.6 Bscf (see TSD page 147-148). GPA suggests that if EPA has already established this emission estimate, they should simply add it to the rolled-up GHG inventory for the natural gas industry rather than requiring operators to expend significant resources re-creating the exact same number.

GPA recommends that, consistent with treatment of transmission pipelines, gathering pipelines and flow lines be excluded from fugitive reporting due to the disperse nature of the emissions and the impracticality of the requirements of proposed Subpart W.

3) Proposed effective date is impractical.

It appears EPA is targeting publication of the finalized Subpart W in late 3 rd
quarter or early 4 th quarter 2010, with an effective date of January 1, 2011. If the rule is finalized as proposed, there will be certain monitoring that will not be practical to implement prior to January 1, 2011 and adequate time will not be allowed for the regulated community to do basic planning for implementation of

the new rule.

A specific example of the impracticality of a January 1, 2011 implementation date is related to the requirement to conduct an annual survey using as optical gas imaging instrument at each gas plant and gathering compressor station. Under the currently proposed Subpart W, m any companies will have hundreds of individual facilities to survey, which w ill require they commence surveys in January 2011 in order to accomplish the work in 2011. Today few companies or consultants own optical imaging equipment, which can cost over $100,000 for one instrument. The result is companies and consultants will have to purchase the equipment, conduct training, and gain sufficient experience in a very shortPage 12 of 26 period prior to January 1, 2011. Not only is that impractical, but GPA questions the ability of suppliers to provide enough optical imaging cameras to conduct the required surveys in 2011. Another example is related to Acid Gas Removal Vents which are required to have gas meters into and out of AGR unit. Not all AGR units employ this metering today and it is impractical to expect meters to be specified, purchased and installed in a period of three months or less. Similar examples exist with compressor seal vents and rod packing vents, on which many operators will elect to install permanent meters; and on flares which some operators will elect to install additional metering. In both cases it is impractical to expect installation within a few months, by January 1, 2011. As a result, GPA

recommends EPA allow use of best available data for the first half of 2011 for all sources subject to the new Subpart W.

4) Screening Criteria and Levels are Necessary to Establish the Requirement to Report under Subpart W.

Based on the currently proposed calculation methods in Subpart W, emissions from many of the GHG sources are unpredictable, which will make determining applicability relative to the 25kTon/yr threshold impractical. In particular, emissions from the following sources cannot be predicted: blowdowns, flares, compressor vents & seal, and fugitive leaks. Due to the unpredictable nature of these sources, a facility will not be able to establish applicability to Subpart W reporting until well into a calendar year and perhaps not until the end of a calendar . Also, for compressor vents & seals and fugitive leaks, a facility will not
be able to determine emissions from the sources until the direct detection and measurement is completed. In order for the regulated community to establish applicability of the GHG reporting rule, specifically for Subpart W, screening

criteria need to be established that allows this determination to be made with certainty in January of each calendar year.

5) Minimum thresholds should be applied for equipment level applicability

and calculations.

The EPA does not incorporate thresholds for applicability or for using simplified calculations at the equipment level. As a result, in many cases complex process models and simulations are required for equipment with minimal GHG emissions.

The first example is related to tanks, for which the same annual calculation method is prescribed regardless of the tanks throughput, for example a tank that fills at a rate of 1 barrel/day versus a tank that fills at a rate of 100 barrels/day. In this particular example, the prescribed method requires analysis of the separator liquid and collection of numerous operating parameters. The liquid analysis is expensive and often the sample is difficult or impossible to collect, even with higher liquid production rates, and should not be required for tanks with minimal throughput. Across the natural gas industry, there are thousands of tanks associated with very low liquid production rates and, therefore, minimal GHG emissions. GPA recommends that tanks with a throughput of less than 5 barrels/day be excluded from reporting under Subpart W. If an exclusion cannot be provided, GPA recommends tanks below the 5 barrel/day threshold be allowed to use the appropriate emission factor from the API Compendium ofPage 13 of 26 Greenhouse Gas Emission Methodologies for the Oil and Gas Industry (API Compendium) in place of conducting modeling using process simulations.

The next example is related to gas dehydration units, which are required by the proposed Subpart W to estimate annual emissions using the GLYCalc processes simulator. As with tanks, there are thousands of very small dehydration units operating across the natural gas industry with minimal GHG emissions. GPA recommends that dehydration units with a throughput of less than 10 million scf/day be excluded from reporting under Subpart W. If an exclusion cannot be provided, GPA recommends dehydration units below the 10 million scf/day threshold be allowed to use the appropriate emission factor from the API Compendium in place of conducting modeling using process simulations.

The final example is related to blowdown vent stacks. There are a limited number of tasks in the natural gas industry that result in blowing down significant volumes of natural gas to the atmosphere. These activities are limited to blowing down compressors, process vessels and piping. There are other tasks in the natural gas industry that result in bl owing down very small and insignificant volumes of natural gas, such as blowdowns from sight glasses and small tubing. Without thresholds which limit the blowdowns that must be recorded, calculated, and reported, this portion of the proposed Subpart W will be unmanageable. GPA recommends that GHGs only from the following blowdowns be reported: 1) all compressor blowdowns and 2) blowdowns from process vessels & piping with a physical volume of 50 cubic feet and larger.

6) Direct measurement is not appropriate for any sources.

GPA feels that direct measurement is not appropriate for any sources for the purposes of GHG emission inventories, consistent with other emission inventory practices. Although EPA has reduced direct measurement requirements in the current proposal for Subpart W, EPA continues to employ methods that ignore longstanding and accepted international protocols for emission inventory calculations. The API Compendium in particular has been accepted as an international standard for estimating GHG emissions across the oil and gas industry. For example, Australia NGERS, EU-ETS, and Alberta emission inventories are all based on the API Compendium. EPA is assuming that a significant increase in overall accuracy will result by requiring more complex and costly estimation of GHG emissions from even the smallest sources within the natural gas gathering and processing industry. This assumption is made while overlooking the EPA’s own data that i ndicates the natural gas gathering and processing industry emits only a very small fraction of the total US GHG emissions annually. In addition, the currently proposed Subpart W ignores the standards of statistical averaging.

While GPA supports the full use of the API Compendium to calculate GHG emissions for all sources covered by the proposed Subpart W, at a minimum we suggest the application of the API Compendium in place of any direct measurement methods. For the gas gat hering and processing sector, direct measurement is generally proposed to be lim ited to compressor wet seal vents and rod packing venting. The current proposal potentially requires directPage 14 of 26 measurement of compressor rod packi ng vents from every cylinder of a compressor in cases where the vent lines are not tied to a common line, which is a common practice in gathering compression facilities and production facilities. The prescribed methods for these sources is flawed by assuming a snapshot measurement applied across an entire year is more accurate than an emission
factor based on well documented and controlled studies.

7) EPA’s estimated cost impact appears to be at least an order of magnitude

low.

GPA is evaluating the economic impact of the proposed Subpart W and will compare the results to the analysis provided by EPA. However, preliminary indications are that the EPA’s cost estimates are at least one order of magnitude low. EPA has failed to recognize the full impact of requiring reporting at all facilities and pipelines in the natural gas gathering and processing sector.

To demonstrate the disparity in EPA’s cost estimate, the following cost estimates from one GPA member company are presented. These costs are only for this one company, an independent gathering and processing company with no production. Their estimated first year costs for initial implementation of the proposed Subpart W are approximately $80 million and their ongoing annual costs for recording, measuring, calculating, and reporting are estimated to be $9.5 million. To emphasize, these are the estimated costs for only one GPA member company to comply with the proposed Subpart W. This compares to EPA’s estimate for all companies in all segments of the natural gas industry covered by Subpart W of $56 million for the first year costs and $21.4 million for ongoing annual costs.

8) Additional engineering estimation methods should be included.

EPA has specifically identified two proc ess simulation models in the proposed Subpart W, GRI-GLYCalc for estimating dehydrator emissions and E&P Tanks for estimating production and processing tank emissions. Many companies use more sophisticated process simulation m odels for some facilities to estimate emissions from tanks and acid gas removal units (AGR unit). The two most common are AspenTech’s HYSYS process simulator and Bryan Research and Engineering’s ProMax process simulator. These process simulators are widely accepted as the gold standards for deta iled process design and optimization in the gas processing, chemical and refining industries

GPA recommends that HYSYS be identified as an acceptable method for calculating GHG emissions from tanks, in addition to E&P Tanks. The use of HYSYS for tank calculations is particula rly important due to recognized difficulty in collecting acceptable separator liquid samples when using E&P Tanks. In some case, the success rate for collecting acceptable separator liquid samples can be as low as 10%. HYSYS provides the flexibility to use extend gas analysis

to model tank emission.

GPA further recommends that ProMax be identified as an acceptable method for calculating GHG emissions AGR units. In addition, GPA recommends that other mass balance calculations be allowed for AGR units. For example, an operatorPage 15 of 26 typically has metered volumes and composition analysis of gas entering an AGR unit and can conservatively assume 100% of the CO2 is removed (in some cases a few percent of the CO2 may not be removed). A simple calculation will provide
accurate CO2 emissions from the AGR unit without the need for downstream metering or analysis. In other cases, operators may have meters and analysis on the AGR vent line and can provide a direct calculation of the CO2 emissions, again without the need for downstream metering or analysis. Subpart W should provide flexibility for any of these methods to estimate the GHG emissions from
AGR vents.Page 16 of 26Page 17 of 26Page 18 of 26Page 19 of 26Page 20 of 26Page 21 of 26Page 22 of 26Page 23 of 26Page 24 of 26Page 25 of 26Page 26 of 26