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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 comment period. EPA decided to only respond to 

comments directly related to the April 2010 proposal. 
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Early Comment Submission Memo 

EPA received these email submissions outside of the official comment period and 

responded to these questions where appropriate in the response to comments (RTC) 

document. EPA decided to only respond to comments 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 Production 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 very good understanding of what the term 

“facility” means in the O&G upstream sector. Company representatives as well 

as state regulatory agencies have been using this term to apply current CAA 

requirements across the country. Our recommendation is that we rely on the 

current actively used definition of facility that EPA change their proposed 

language to refer to a “threshold reporting area” or “roll-up area threshold” to 

define a geographical area to which a threshold can be applied that is made up of 
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oil and gas upstream facilities. This would help alleviate industry concerns that 

the reporting rule definition of “facility” might impact perception of the CAA 

definition. 

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

would read: ‘Onshore petroleum and natural gas production reporting area 

means all petroleum or natural gas facilities and equipment associated with all 

petroleum or natural gas production under common ownership or common control 

by an onshore petroleum and natural gas production owner or operator located in 

a single hydrocarbon basin as defined...’ 

The term reporting area could then be referred to in the definition of the source 

category; i.e., 98.230(2) ‘Onshore petroleum and natural gas production’: 

Onshore petroleum and natural gas production reporting area means all facilities 

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

limited to... 

B. Upstream Production Sites Should Not Be Aggregated

EPA should not require aggregation of upstream production sites. This imposes a 

disproportionate burden on our industry 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 calculate 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 carrying out a wide variety of Clean Air Act 

(CAA) provisions. It is understood that the GHG emission inventory data will be 

used to define future permitting and compliance 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 industrial 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 “Major 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). 
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In accordance with this definition and multiple case-by-case aggregation 

determinations by EPA and the states, most production operations across a single 

hydrocarbon basin cannot be aggregated into one facility. If these production 

operations are not aggregated by basin, then each facility or well site must 

individually be assessed for applicability to the future permitting and compliance 

programs. At this time, an applicability threshold of 25,000 metric tons CO2e 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 rules. We request that this definition be 

modified to be consistent with the definition 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 defined 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 production and less than 1 BOPD 

condensate production, and (3) oil stripper wells producing less than 10 

BOPD. 

• Allowing the use of the API Compendium 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 goes forward with aggregation of upstream 

production sites, a “field level” approach would be much more practical for the 

following reasons: 

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

New Mexico and southwest Texas nearly 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. 
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• 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 fields within a basin. The Barnett 

Shale in Texas covers 24 counties. However, one large independent 

operates approximately 2,000 wells, but with 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 basin level. Oil and gas characteristics 

and the method of separation and processing are directly related to the 

field from which the oil and gas is produced. Fields are well defined by 

state oil & gas commission rules. When wells are comingled, the percent 

of production from a particular field (sand or formation) can be assessed 

using royalty calculations to provide the percentage production from a 

particular field. The field which produces 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 complicate 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 production came from various fields 

within that basin. 

• For all the above reasons, we support 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 properties, and physical properties, and 

enable the use of “population average” emission factors and approaches 

for emission quantification. This would allow calculation and reporting of 

emissions from reasonable “well groupings” such as known fields within a 

basin or even by county within a basin. 

B. Fugitive Emissions from Pipelines (such 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 connections and thousands of small metering 

stations. EPA has underestimated the burden to industry to obtain component 

counts on these pipeline facilities. In addition, many companies now have internal 

programs to find and fix leaks associated with these gathering pipelines as well as 

for the longer distance transmissions lines. 
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C. Emissions from Portable Non-self-propelled Equipment (such as well drilling 

and completion equipment, workover equipment, gravity separation 

equipment, auxiliary non-transportation related equipment).

EPA should delete the reporting of emissions from these non-stationary and 

portable sources. EPA should simply use its own updated total emissions 

estimates for these sources. The huge added expense for industry to calculate, 

keep records, and report emissions from thousands of these sources 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 equipment 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 often moved from well to well and 

between operators. In many cases, site 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 the operation or maintenance of the equipment, it 

is not appropriate to require reporting and compliance tasks of the well site 

operator because they do not participate in engine maintenance or the 

collection of fuel use data. All other Clean Air Act programs establish 

applicability based on whether a party owns and/or operates a source 

because it is not feasible for someone 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 sector required to report contractor’s 

emissions for this reporting rule? 

• All of these activities are non-stationary source and temporary 

construction activities that should be excluded just as other construction 

activities (housing, commercial building, roadways, etc) are excluded. 

Requiring estimates of these emissions greatly increases the reporting 

burden on the oil and gas industry without 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 tree process when including these sources that 

amount to such a miniscule part of emissions. 
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• 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 counting 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 calculations that other countries 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 every 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 every 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 considerably more burdensome for onshore facilities 

than offshore facilities where MMS GOADS 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 calculate 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 spending resources to improve any emission 

factor methods that EPA feels is not representative of actual emissions (e.g., well 

blowdowns). 

We are particularly concerned with the requirement to count all fugitive components 

on every well site and small production facility that we operate. This requirement is 
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very significant in terms of effort and cost. Thus, 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 when 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 recent 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 every 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, whether 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 appropriate 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: 
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“Both gathering/boosting stations and natural 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 processing facilities, 

natural gas transmission compression facilities, and offshore petroleum and natural gas 

facilities), identifying the facility is clear since there are physical boundaries and 

ownership structures that lend themselves 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 stations 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 lines 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 distribution 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 compression means any fixed combination of 

compressors that move natural gas from production fields or other compression facilities 

into natural gas processing facilities, other gathering compression facilities, transmission 

pipelines, storage facilities, or other end users. In addition, natural gas gathering 

compressor facilities may include 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. 
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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 assessment 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 logic for natural gas gathering pipelines, 

which are significantly more dispersed than transmission pipelines. Gas 
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gathering lines are generally much smaller 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 from 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 3rd

quarter or early 4th 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, many companies will have hundreds of 

individual facilities to survey, which will 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 short 
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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 of 
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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 blowing 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 indicates 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 gathering and processing sector, direct 

measurement is generally proposed to be limited to compressor wet seal vents 

and rod packing venting. The current proposal potentially requires direct 
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measurement of compressor rod packing 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 process 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 models 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 detailed 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 particularly 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 operator 
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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. 
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