EPA Responses to OMB- Petroleum and Natural Gas Systems 

1. Should EPA include a provision on whether reporting sources can submit a request to use 

alternative software, subject to EPA approval, so long as it is comparable to E & P and GlyCalc? 

EPA’s proposed rule allows for the use of engineering estimates of emissions instead of requiring the very 

costly direct measurement of emissions from a number of sources. For tanks and dehydrators, EPA points 

to widespread use in the industry of two software programs - E & P Tank for calculating emissions from 

storage tanks and GlyCalc for calculating emissions from dehydrators. The proposed rule mandates the 

use of these two programs for estimating emissions. E & P is free, and GlyCalc is available for a small 

fee, so cost may not be a concern. However, EPA has no mechanism in the rule for the industry to 

develop or use comparable software. Should EPA include a provision (or at least take comment) on 

whether reporting sources can submit a request to use alternative software, subject to EPA approval, so 

long as it is comparable to E & P and GlyCalc? This would encourage the development of alternative 

software and promote competition in the industry. It would also prevent the rule from becoming obsolete 

as new programs are developed, which as it stands now, would require an amendment to the rule. 

EPA Response: We agree that it would be valuable to solicit comment on additional and/or 

alternative software packages to GlyCalc and E&P. However, generally, across the broader 

mandatory reporting rule we have introduced the opportunity to petition EPA to use alternative 

methods only in very limited cases. We have incorporated many standards by reference in the 

mandatory reporting rule and there will be opportunities to update these packages and standards 

for other subparts (e.g., ASTM, ASME) through amendments. EPA proposes to add the following 

text in blue to the preamble to address the comment. “Emissions from sources such as tanks and 

glycol dehydrators can be reliably calculated using standard engineering first principle methods such as 

those available in E&P Tank and GlyCalc. The use of such standard and readily available software is a 

cost-effective way to uniformly estimate emissions that are representative for the two sources. To 

maintain standardization across reporters the proposed rule would require the use of E&P Tank for 

estimating the emissions from well-pad separator conditions when flashed to atmospheric pressure in any 

downstream stock tank, and GlyCalc for glycol dehydrators. 

E&P Tank is available for free and GlyCalc can be purchased at a small fee. Also, these two 

software models are widely used in the industry and the operation of the software is well understood. 

Using such software also addresses safety concerns that are associated with direct measurement from the 

two sources. For example, sometimes the temperature of the emissions stream for glycol dehydrator vent 

stacks is too high for operators to safely measure emissions. EPA seeks comment on whether there are 

additional or alternative software packages to E&P Tank and GlyCalc that should be required to be used 

to calculate emissions. 

2. How does EPA’s existing “Methane-to-Markets” partnership program intersect with and/or 

complement this proposed requirement that industry identify methane emissions? 

The preamble includes a very good discussion of the benefits of the rule, and points out that the primary 

GHG that is emitted from these sources is methane, a marketable product. The industry has an economic 

incentive to recover the methane and EPA explains that by identifying the sources of emissions in their 

systems, natural gas producers have an opportunity to reduce fugitive emissions and to return more gas to 

the marketplace. While this proposed rule does not mandate emission reductions, EPA has developed a 

voluntary partnership with the natural gas industry to identify and reduce methane losses and return the 

gas to the marketplace. How does EPA’s existing “Methane-to-Markets” partnership program intersect 

with and/or complement this proposed requirement that industry identify methane emissions? Has EPA 

considered adding a reference or discussion of this program in its benefits section? 

http://www.epa.gov/methanetomarkets/
EPA Response: The Methane to Markets Partnership is an international initiative that advances costeffective, near-term methane recovery and use as a clean energy source. The mandatory GHG reporting 

rule is only a domestic-based program. We agree with the intention behind the question and so Page 114 

of the preamble refers to EPA’s Natural Gas STAR Program, which is our domestic program that helps 

industry identify methane emissions. We are pasting the language below for your reference. Please let us 

know if this does not address your question. 

“As the primary constituent of natural gas, methane is also an important energy source. As a 

result, methane emissions reductions can provide significant economic and environmental 

benefits. EPA has been working in collaboration with oil and natural companies in the U.S. as 

part of the Natural Gas STAR Program since 1993. Through this collaborative partnership 

program, EPA has identified over 120 proven, cost effective technologies and practices to reduce 

methane emissions across operations in all of the major industry sectors—production, gathering 

and processing, transmission, and distribution. The proposed reporting rule will increase 

knowledge of the location and magnitude of significant methane emissions sources in the oil and 

gas industry which can result in cross-cutting benefits on domestic energy supply, industrial 

efficiency and safety, and revenue generation.” 

3. A question was raised on the interagency call on whether EPA could provide the cost 

per ton by method (e.g., engineering calculations, direct measurement, emission 

factors). 

EPA Response: 

The direct measurement first year costs are relatively high at $.93/tonne. This is because one particular 

source, centrifugal wet seal vents, requires that a meter port be installed for each compressor. This cost is 

all apportioned in the first year, since drilling a port is a one time cost. The emissions from wet seals vary 

depending on the type and size of compressor and the wet seal characteristics. So each compressor has a 

different footprint of emissions that cannot be captured using generic emissions factors. Therefore, using 

7%

23%

6%

64%

Emissions 

Coverage

New Calculation 

Methodology

Sources Covered Cost 

($/tonne)

Engineering Estimate 

Monitored process operating 

parameters and either 

simulation models or emission 

factors

Major Vented Sources

Pneumatic device and pump vents, 

well venting for liquids unloading and 

completions and workovers, storage 

tanks, dehydrators

$0.09/tonne

(first year)

$0.05/tonne

(second year)

Direct Measurement

Meters depending on source 

e.g., flowmeter for once per 

year measurement

Major Vented Sources Compressor 

wet seal and rod packing vents, 

transmission condensate tanks, 

install meter for well venting optional

$0.93/tonne

(first year)

$0.16/tonne

(second year)

Leak Detection and 

“Leaking” Factor

Leak detection and apply a 

leaking factor to estimate 

actual emissions

Compressor and Significant NonCompressor Fugitives Compressor 

fugitives and non-compressor 

plant/station fugitives

$0.07/tonne

(first year)

$0.07/tonne

(second year)

Equipment Count and 

Population Factor

GRI emission factors to 

estimate potential emissions; 

GOADS for Offshore

Minor Fugitive Sources & Offshore 

Production surface equipment 

fugitives, LDC mains, service lines, 

vaults, and other inaccessible 

sources 

$0.40/tonne

(first year)

$0.06/tonne

(second year)

7%

23%

6%

64%

Emissions 

Coverage

New Calculation 

Methodology

Sources Covered Cost 

($/tonne)

Engineering Estimate 

Monitored process operating 

parameters and either 

simulation models or emission 

factors

Major Vented Sources

Pneumatic device and pump vents, 

well venting for liquids unloading and 

completions and workovers, storage 

tanks, dehydrators

$0.09/tonne

(first year)

$0.05/tonne

(second year)

Direct Measurement

Meters depending on source 

e.g., flowmeter for once per 

year measurement

Major Vented Sources Compressor 

wet seal and rod packing vents, 

transmission condensate tanks, 

install meter for well venting optional

$0.93/tonne

(first year)

$0.16/tonne

(second year)

Leak Detection and 

“Leaking” Factor

Leak detection and apply a 

leaking factor to estimate 

actual emissions

Compressor and Significant NonCompressor Fugitives Compressor 

fugitives and non-compressor 

plant/station fugitives

$0.07/tonne

(first year)

$0.07/tonne

(second year)

Equipment Count and 

Population Factor

GRI emission factors to 

estimate potential emissions; 

GOADS for Offshore

Minor Fugitive Sources & Offshore 

Production surface equipment 

fugitives, LDC mains, service lines, 

vaults, and other inaccessible 

sources 

$0.40/tonne

(first year)

$0.06/tonne

(second year)
emissions factors will result in erroneous reporting at a facility level. Using temporary meters instead of a 

permanent one gives a good one time snapshot of the actual emissions without the large capital cost for 

installing permanent meter on each compressor vent. This monitoring method is also important because 

wet seal emissions contribute to 8 percent of the total national process emissions from the 6 sectors 

(offshore prod, processing, transmission, LNG import, LNG storage, and underground storage) where wet 

seals are an emissions source.