1 

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: Alternative Methodologies Memo 

Summary: This memo summarizes those methodologies considered and which 

alternative(s) were selected to reduce burden while maintaining the quality of data 

necessary to inform future policy. 
2 

Alternative Methodologies

Based on comments received on the April 2010 proposal, EPA evaluated alternative 

methodologies for several emission sources covered under subpart W. This memo 

summarizes those considered and which alternative(s) were selected to reduce burden 

while maintaining the quality of data necessary to inform future policy. EPA has made 

revisions to the methodologies for calculating GHG emissions in today’s final rule based 

on these analyses. Please see Section II.F, of the Preamble for the results of this 

evaluation. 

EPA evaluated the emission sources in each of the eight industry segments: offshore 

petroleum and natural gas production, onshore petroleum and natural gas production, 

onshore natural gas processing, onshore natural gas transmission compressions, natural 

gas storage, liquefied natural gas storage, liquefied natural gas import and export 

terminals, and onshore natural gas distribution. 

As a general note, data collection methodologies for the onshore petroleum and natural 

gas production industry segment and the offshore petroleum and natural gas production 

industry segment are often different. Data collection methodologies were carefully 

considered for these industry segments. As onshore production is responsible for the vast 

majority of greenhouse gas emissions in the oil and gas sector, the methodologies EPA 

chose for data collection for this segment are necessary to inform future policy. EPA also 

determined that in order to manage burden and considering emissions from offshore oil 

and gas operations are substantially less than onshore emission, the BOEMRE “GOADS” 

monitoring system overall is sufficiently rigorous to inform future policy. Therefore, 

GOADS is adequate for GHG data collection needs for offshore production. EPA 

performed a side by side comparison of the data requirements for each monitoring system 

(Exhibit B) while considering the reporting frequency and reporting costs. 

I. Evaluation of Each Emission Source

EPA focused on the methodologies which would reduce burden while not compromising 

the quality of the data needed to appropriately inform future greenhouse gas policy. The 

methodologies that received the most comments, and their respective emission sources, 

are listed below with the proposed methodology paraphrased from the April 2010 

proposal. 

A. Onshore Production and Processing Natural Gas Composition Sampling. 

Reporters would, in some cases be required to perform quarterly sampling of gas 

composition where continuous gas composition analyzers were not installed. 

B. Onshore Production Equipment Leak Emission Component Counts. 

Reporters would be required to perform a total count of the entire population of 

equipment components (valves, connectors, open ended lines, flanges, etc.) and 

update it each reporting year. 

C. Onshore Production Storage Tanks and Glycol Dehydrators Vents
3 

Reporters would be required to use the latest software package for E&P Tank to 

monitor stock tank emissions for all onshore production and the simulation 

software package GRI-GLYCalc Version 4.0 to estimate emissions from all 

glycol dehydrators. 

D. Onshore Production Pneumatic Pumps and High Bleed Pneumatic Device 

Venting. 

Reporters would have been required to obtain manufacturer pump curves for each 

specific pneumatic pump model in service in their operations and maintain a log 

of the volume of liquid pumped annually from each individual pump. For highbleed pneumatic devices, the proposed rule would have required reporters to 

obtain manufacturer bleed rates to estimate emissions. 

E. Reciprocating and Centrifugal Compressor Emissions from the Three Modes. 

Due to ambiguity in the proposed reporting requirements in the April 2010 

proposal, reporters may have interpreted the rule to require them to measure 

emissions from all compressors in each of three operating modes during each 

reporting year. 

F. Transmission Storage Tanks. 

Reporters would have been required to monitor emissions from transmission 

storage tanks with an optical gas imaging instrument for five minutes, and if 

emissions were observed to be continuous over that period to measure them at the 

tank vent using an appropriate meter. 

II. Decision Process to Determine Alternative Methodologies

EPA considered alternative methodologies proposed in comments submitted on the April 

2010 proposal as well as other methodologies demonstrated in the Natural Gas STAR 

Program for the above emission sources. The key consideration was to reduce burden 

while maintaining the quality of data necessary to inform future public policy. EPA also 

considered commenter recommendations such as equipment thresholds to exempt or 

streamline small emission sources, fewer measurements or samples per year, less costly 

screening equipment, and use of default emission factors. 

Equipment Thresholds 

Equipment thresholds focus more rigorous and reliable emission quantification on 

the largest emitters while still obtaining valuable activity data (e.g. number of 

pneumatic devices or dehydrators) for the entire equipment population. For 

emission sources with large, variable, one-time emissions and few events (e.g. 

unconventional well completions), EPA prioritized more accurate emissions 

quantification. For emission sources with small individual emissions in large, 

geographically dispersed populations (e.g. pneumatic devices), EPA is allowing 

component or equipment counts and applying emission factors. The activity data 

EPA receives from these small individual sources will be informative to future 

policy. 
4 

 Default Emission Factors

EPA considered default emissions factors for emissions sources with large 

geographically dispersed populations but small consistent emissions. 

 Alternative Leak Detection Tools

EPA evaluated less costly, less accurate leak detection and quantification tools for 

applicability to specific emission sources and whether those tools maintain the 

necessary performance standard to collect data to inform future public policy. 

 Reduce Measurement or Sample Frequency

EPA also considered reducing the required number of measurements or samples 

in a reporting year where the actual value measured remains reasonably consistent 

or a representative sample is appropriate. Representative samples reduce burden 

by allowing the reporters to directly measure only a representative portion of their 

emission sources instead of the entire population. The reporter would then 

develop a population factor based on their representative data of that emission 

source and apply it to the remaining or unmeasured emission sources. 

EPA revisited Chapter (4)(c)(ii) in the Technical Support Document (TSD) with these 

new burden reduction strategies and determined new, suitable methodologies for the 

emission sources above. Exhibit A shows the decision process for emissions source 

selection modified from Figure 1 in the Technical Support Document. The Figure 1 from 

the TSD has been modified, indicated by dashed lines and italic text (shown in Exhibit A 

below), to reflect the new decision process to re-evaluate the emission sources discussed 

in part I of this memo, except for transmission storage tanks. 

III. The Alternative Methodologies

Using the options and logic described above, EPA identified and evaluated several 

methodologies for consideration to inclusion in today’s final rule. Each methodology 

considered for emission sources in Subpart W can be found in Chapter 6 of the TSD. The 

alternative methodologies that were considered for the sources listed in part I of this 

memo are listed below and in other memos put into the rule making docket, EPA-HQOAR-2009-0923. Those adopted in today’s final rule are labeled “adopted,” while those 

not adopted are labeled “rejected.” 

A. Onshore Production and Processing Natural Gas Composition Analyses 

1. Natural Gas Composition Reduced Sample Analysis. [Adopted] 

Onshore production reporters would use their most recent field gas composition data 

during the reporting year. EPA determined that produced natural gas composition is 

sampled once or twice per year for allocation and royalties. Comments from industry 

received on the April 2010 proposed rule advise that they have found that the content 

of natural gas remains relatively constant by producing field. It is unnecessary to 

sample gas semi-annually or for every site, as the content changes over years, not 

months, and largely not by basin. Monthly gas samples are taken in fields that are 

still under development until the field stabilizes. Once the field stabilizes, those 
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samples are generally taken no more frequently than semi-annually. Once a wellhead 

stabilizes and is tied into a gathering system, it is not industry practice to sample the 

fuel more frequently than semi-annually. Quarterly composition samples, as it was 

required in the April 2010 proposal, imposed additional burden on operators to take 

more samples than they would have done without subpart W. This methodology 

allows reporters to use the natural gas composition data used for allocation and 

royalties, for Subpart W reporting; essentially placing no additional burden on the 

reporter. Natural gas processing reporters would sample their gas composition once 

per year, instead of quarterly. 

2. Default Natural Gas Composition by Segment. [Rejected] 

Reporters would use default natural gas compositions provided by EPA for their 

respective segments. The 1996 EPA/GRI study1

 provides average natural gas 

compositions by segment, which is used in the U.S. Inventory of Greenhouse Gas 

Emissions and Sinks. This would place negligible burden on industry; however, it 

would provide substantially less accurate data than actual natural gas composition 

samples from the onshore petroleum and natural gas production and onshore natural 

gas processing segments. 

B. Onshore Production Equipment Leak Emission Component Counts 

1. Representative Component Counts on Sub-Basin Entities. [Rejected] 

Reporters would count the number of components within a region defined by the 

reporter within the facility (basin), and then apply the counts across the reporting 

basin to calculate equipment leak emissions. Although, this reduces the burden to 

reporters, defining acceptable criteria for creating sub-basin entities that would be 

uniformly applied across all reporters in a basin proved to be an intractable solution, 

as every basin contains a wide variety of equipment and well characteristics, it is 

impossible to legally define what a “representative component count” or a “sub-basin 

entity” is in a regulatory context. Had EPA adopted this proposal, the intractability 

of this definition would have caused serious regulatory ambiguity raising risk on 

industry for meeting this obligation and making the consistency of enforcement by 

EPA nearly impossible. 

2. Facility-Level Population Emission Factors. [Rejected] 

Reporters would use default facility emission factors provided by EPA. The 2009 

API Compendium2

 provides “facility-level” population emission factors, which 

onshore production operators can use to determine equipment leak emissions per 

barrel of oil or cubic foot of natural gas produced. However the API Compendium 

“facility” is a well pad, and not a basin as defined in subpart W. Therefore this 

method would require counting the well pads in a basin. Although this method places 

 

1

 EPA/GRI. (1996) Methane Emissions from the Natural Gas Industry

<http://www.epa.gov/gasstar/tools/related.html> 

2

 API. (2009) Compendium of Greenhouse Gas Emission Methodologies for the Oil and Natural Gas 

Industry. pg. 6-5 <http://www.api.org/ehs/climate/new/upload/2009_GHG_COMPENDIUM.pdf> 
6 

little burden on the reporter, this method has a high level of uncertainty and does not 

provide EPA with sufficiently accurate activity data to inform policy. 

3. Average Component Counts per Major Equipment [Adopted] 

Reporters would count only the major pieces of production equipment (e.g., 

separators, compressors, heaters) in their basins and apply average component counts 

for each major equipment piece as provided in subpart W. EPA/GRI1

 and the 2009 

API Compendium2 provide default component counts for major production 

equipment. Since large equipment is easy to see and count and most companies 

should have documentation of large equipment at each well site at a central office, 

this would significantly reduce the burden for reporters to count each individual 

component (e.g., valve, connector, open ended line), but still improve activity data in 

that it would provide actual equipment counts. Population emission factors would be 

applied to the component count estimates to evaluate emissions. For more details 

please see “Equipment-Level Population Emission Factors for Onshore Production” 

in the rule making docket (# EPA-HQ-OAR-2009-0923). 

4. Leak Detection and Leaker Factor [Rejected] 

Reporters would be required to conduct a leak detection survey on equipment 

components to find leaks and apply leaker emission factors to quantify the volume of 

emissions. While this would provide the best possible data, it would be a substantial 

increase in burden on industry. 

C. Onshore Production Storage Tanks and Glycol Dehydrator Vents

1. Default Population Emission Factors. [Rejected] 

Reporters would use default storage tank and glycol dehydrator venting population 

factors provided by EPA for their respective segments. The 1996 EPA/GRI study3

and 2009 API Compendium2

 provide emission factors for produced crude oil and 

condensate sent to field storage tanks and average glycol dehydrator vents. This 

would place little burden on industry; however, it would provide less accurate data 

than an engineering model estimate. Onshore production storage tank emissions are 

highly variable and vary greatly depending on parameters such as the composition of 

the oil or condensate, the operating pressure of the separator or vessel upstream of the 

tank, and whether the storage tank has vapor recovery or flare controls. Glycol 

dehydrator reboiler venting emissions are also highly variable and dependent on 

parameters such as the glycol circulation rate, natural gas throughput, and 

composition of the gas. Population factors for glycol dehydrators and production 

storage tanks do not accurately capture the affect of each operating parameter on 

emissions, and hence are not sufficient to inform future public policy. 

2. Provide a Dehydrator Threshold for Monitoring Methods [Adopted] 

EPA determined a threshold that would capture approximately 80% of emissions 

from only a small percentage of large dehydrators and larger throughput tanks. 

 

3

 EPA/GRI. (1996) Methane Emissions from the Natural Gas Industry

<http://www.epa.gov/gasstar/tools/related.html> 
7 

Dehydrators and wellhead oil flow to tanks above this threshold would use more 

rigorous methodologies, such as simulation software, to estimate emissions and 

reporters below this threshold would use population emission factors to estimate 

emissions. Such a threshold would significantly reduce burden on reporters while 

maintaining a quality of data for the largest sources that would be acceptable for 

informing future policy. For more details please see “Equipment threshold for 

Dehydrators” and “Equipment Threshold for Tanks” in the rule making docket (# 

EPA-HQ-OAR-2009-0923). 

D. Pneumatic Pumps and High Bleed Device Venting

1. Default Population Emission Factors for High, Low, and Intermittent Bleed 

Devices. [Adopted] 

Reporters would count high, low, and intermittent bleed pneumatic devices and 

determine emissions using default population emission factors from the 2009 API 

Compendium2, and 1996 EPA/GRI1study. This reduces burden because operators no 

longer need to research and record manufacturer data to determine bleed rates for 

high-bleed pneumatic devices. Manufacturer bleed rates are known to underestimate 

emissions from high-bleed devices because they represent the bleed rate when the 

device is new. Pneumatic devices in the petroleum and natural gas industry have 

operational lifetimes well in excess of 10 years. Over that lifetime, pneumatic device 

internals wear resulting in higher bleed rates. Population factors, based on real 

industry sample data, would capture the effect of age on pneumatic device bleed rate, 

and hence, potentially better characterize the emissions from high-bleed pneumatic 

devices in industry. In addition, considering that pneumatic valve controllers are not 

readily recognized as high or low bleed without collecting manufacturer types and 

model numbers. For onshore production, to further manage burden, EPA is extending 

the pneumatic device count over a three year period. 

2. Default Population Emission Factors for Pneumatic Pumps [Adopted] 

Reporters would count pneumatic pumps at each well pad and determine emissions 

using default population emission factors from the 2009 API Compendium2

, and 1996 

EPA/GRI1 study. This reduces burden because operators no longer need to collect 

operating parameters for their pneumatic pumps to perform an engineering emission 

estimate. Although this would reduce the accuracy of emissions estimate, EPA has 

determined that activity data would adequately inform future public policy because 

reporters would still provide pneumatic pump counts. 

3. Default Population Emission Factors for Continuous and Intermittent Pneumatic 

Devices. [Rejected] 

Reporters would identify and count continuous and intermittent bleed pneumatic 

devices, not based on high and low bleed rates, and determine emissions using default 

population emission factors from the 2009 API Compendium2

, 1996 EPA/GRI1, or 

comparable study. This reduces burden because operators would no longer need to 

lookup and record manufacturer data nor would they be required to distinguish 

between high and low bleed pneumatic devices. EPA does not consider this method 
8 

adequate to inform future public policy because high bleed pneumatic devices vent 

several orders of magnitude more gas than low bleed devices. 

E. Reciprocating and Centrifugal Compressor Emissions from the Three Modes

1. Default Population Emission Factors For Each Compressor Mode. [Rejected] 

Reporters would count their compressors and determine the duration of time per 

calendar year that each compressor is in each operating mode. They would determine 

emissions using default population emission factors from the 2009 API 

Compendium2, 1996 EPA/GRI1, EPA Lessons Learned: Replacing Wet Seals with 

Dry Seals in Centrifugal Compressors4, or comparable studies. This would eliminate 

reporting burden from this emissions source since operators would no longer need to 

directly measure emissions from compressors in each mode. While limited data is 

available for emissions from reciprocating compressors in the operating mode, very 

little data exists for all centrifugal compressors in the operating mode, either wet or 

dry seals, and for all compressors in the shutdown depressurized mode (i.e. unit 

isolation valve leakage). What limited data that EPA has collected is compelling in 

that significant emissions were overlooked in the 1996 EPA/GRI study. EPA has 

determined that population emission factors do not sufficiently characterize emissions 

from each compressor mode to inform future public policy. 

2. Measure Compressor Emissions in the “As-Found” Mode [Adopted] 

Reporters would measure emissions from compressors once per year in the operating 

mode found during the measurement, with either a temporary meter, permanent 

meter, or acoustic leak detection device. The measured emissions rate for each mode 

and type of compressor would be aggregated to a reporter-level emission factor for 

application to each mode of operation for each compressor in the reporting year. 

EPA would not require operators to perform an unscheduled shutdown of 

compressors to measure emissions from the not-operating, depressurized mode; 

however, once every three years (the period during which EPA was informed by 

industry representatives that most compressors would be scheduled for a maintenance 

shutdown at least once) each compressor would have to be measured in the notoperating, depressurized mode. To develop robust emission factors plus account for 

leak repairs (not required by subpart W), reporters would combine all measurements 

in each mode for each type of compressor over a running three year period and use 

actual measurements on a compressor in the year it was measured. For more details 

please see “Compressor Modes and Threshold” in the rule making docket (# EPAHQ-OAR-2009-0923). 

F. Transmission Storage Tanks

1. Permit Acoustic Leak Detection on Scrubber Dump Valves. [Adopted] 

Reporters would be allowed, as a substitute for screening transmissions storage tank 

vents using an optical leak imaging camera, to screen individual scrubber dump 

valves annually using an acoustic leak detection device. This may reduce the burden 

 

4

 EPA. (2006). Lessons Learned: Replacing Wet Seals with Dry Seals in Centrifugal Compressors. Natural 

Gas STAR. <http://www.epa.gov/gasstar/documents/ll_wetseals.pdf> 
9 

for reporters with few scrubber dump valves since the capital cost for an optical 

imaging device is higher than that of an acoustic leak detection device and service 

providers with optical gas imaging equipment may be more expensive than those with 

alternative detection tools. However, for reporters with a large population of scrubber 

dump valves, manually screening each scrubber dump valve with an acoustic leak 

detection device can be more burdensome than simply viewing the condensate tank 

vent during the annual equipment leak survey using the optical leak imaging camera 

(required for inaccessible components). Further more, to reduce emissions 

measurement burden, EPA is allowing the alternative of quantifying through-valve 

leakage of scrubber dump valves with an acoustic detector with manufacturer’s 

calibrations for estimating leakage. For more details please see “Scrubber Dump 

Valves” in the rule making docket (# EPA-HQ-OAR-2009-0923). 

IV. Offshore Production GOADS vs. Onshore Production Quantification 

Methodologies 

Offshore platforms reporters in the Gulf of Mexico Outer Continental Shelf are subject to 

the GOADS study conducted by BOEMRE in compliance with 30 CFR 250.302 through 

304. Reporters in state and non-Gulf of Mexico waters are not subject to GOADS. EPA 

has determined that the GOADS monitoring system, selected for the offshore petroleum 

and natural gas production industry segment, is adequate for GHG data collection needs 

for offshore production. In short, GOADS requires monthly data to be collected for an 

equivalent number of source activities. Exhibit B shows how the GOADS monitoring 

system data reporting requirements compare to the onshore petroleum and natural gas 

production data reporting requirements under subpart W. GOADS requires the monthly 

collection of this data on venting and flaring and starting 2010, the Bureau of Ocean 

Energy Management, Regulation, and Enforcement (BOEMRE) will require a meter on 

all flare headers. The onshore petroleum and natural gas production industry segment in 

subpart W, on the other hand, requires no permanent meter installations and only the 

annual reporting of emissions and activity data. EPA has selected the GOADS 

monitoring system for the offshore production segment because GOADS is an adequate, 

existing process for all platforms in the Federal Gulf of Mexico (GOM) to report 

emissions. Subpart W will expand that process to platforms in state and non-GOM 

Federal waters. Activity data collected under BOEMRE’s GOADS program is more 

extensive than the activity data that would be collected under subpart W using the 

onshore production reporting provisions. Since offshore reporters only collect activity 

data, EPA is relying on offshore Gulf of Mexico OCS reporters to submit accurate 

activity data to the BOEMRE so that it may accurately determine each platform’s 

emissions. 

V. Concluding Remarks

EPA evaluated alternative methodologies which may result in reductions to subpart W 

compliance burden. EPA sought the monitoring methodologies that provide appropriate 

data quality to inform future policy at the minimum cost to industry. After reviewing the 

alternative methodologies of this memo and others within the docket (# EPA-HQ-OAR-
10 

2009-0923), EPA determined that the changes stated in section II.E of the Preamble 

achieve this goal. 
11 

Exhibit A. Decision Process for Reevaluating Subpart W Quantification Methods. 

Is emissions source an equipment 

leak?

Is source accessible for

equipment leak detection

Use equipment leak 

detection and leaker 

emission factors to 

estimate emissions

No

No

Yes

No

Yes

No

Potentially exclude

Is equipment leak 

emissions source

geographically

dispersed?

Yes

Yes

Is source contributing to top 80% of

emissions from each segment?

Is (Are) the 

equipment leak 

emission source(s) 

associated with 

ifi i t?

Use equipmentlevel counts and 

equipment-level 

population factors to 

estimate emissions 

Yes

Use population 

emission factor 

and component 

count to estimate 

emissions 

No

Is the vented emission 

source geographically 

dispersed and large in 

population?

Can largest 

emitters be 

isolated?

No

Use Engineering Estimation method on 

the largest emitters and population 

emission factor and source count on rest

Yes

Yes

Use continuous 

or periodic 

monitoring 

What monitoring 

frequency is necessary? 

Representative 

Sample? 

No

No

Does an engineering 

estimate methodology 

exist?

Use population 

emission factor 

and source count 

to estimate 

emissions. 

Does credible

emission factor

exist? Yes

No

Use 

Engineering

Estimation 

method

Yes
Page 12 of 18 

Exhibit B. Offshore Petroleum and Natural Gas Production Monitoring (GOADS) 

vs. Onshore Petroleum and Natural Gas Production Monitoring Data Reporting 

Requirements 

 Data Reporting Requirements 

List of Sources Offshore Production (GOADS) Onshore Production (Subpart W) 

Amine Units 1) Type of amine used 

2) Inlet sour gas pressure 

3) Inlet gas temperature 

4) Equipped with flash tank? 

5) Flash tank temperature 

6) Flash tank pressure 

7) Destination of flash gas 

8) Number of absorber trays 

9) Inlet lean amine pressure 

10) Inlet lean amine temperature 

11) Lean amine volumetric flow rate 

12) Inlet lean amine content 

13) Inlet lean amine H2S concentration 

14) Inlet lean amine CO2 concentration 

15) Outlet height of vent 

16) Outlet diameter 

17) Exit velocity 

18) Exit temperature 

19) Outlet orientation (degrees) 

20) Flare present? 

21) Combustion temperature 

22) Combustion efficiency 

23) Installed control equipment 

24) Condenser temperature 

25) Condenser pressure 

25) Sulfur recovery efficiency 

1) Gas Throughput and 

2) Inlet CO2 Content or 

3) Outlet CO2 Content (may assume 

sales/pipeline CO2 requirements), or 

4) CEMS (where present), or 

5) Vent emissions measurement and 

composition (where applicable) 

Boilers/Heaters/Burners 1) Equipment elevation 

2) Hours operated 

3) Fuel type 

4) Fuel H2S content 

5) Fuel sulfur content 

6) Fuel heating value 

7) Max rated heat input 

8) Average heat input 

9) Max rated fuel usage 

10) Average fuel usage 

11) Total fuel used (engineering 

calculation) 

12) Exhaust outlet height 

13) Outlet inner diameter 

Subpart W methodology applied to all 

fuel combustion sources above a 

minimum threshold. For more details 

please see “Equipment Threshold for 

Small Combustion Units” in the rule 

making docket (# EPA-HQ-OAR-2009-

0923). 
Page 13 of 18 

14) Exit velocity 

15) Exit temperature 

16) Outlet orientation 

Diesel and Gasoline 

Engines 

1) Engine elevation 

2) Hours operated 

3) Fuel type 

4) Fuel sulfur content 

5) Fuel heating value 

6) Max rate horsepower 

7) Operating horsepower 

8) Max rated fuel usage 

9) Average fuel usage 

10) Total fuel usage (engineering 

calculation) 

11) Exhaust outlet height 

12) Outlet inner diameter 

13) Exit velocity 

14) Exit temperature 

15) Outlet orientation 

Subpart W methodology applied to all 

fuel combustion sources above a 

minimum threshold. For more details 

please see “Equipment Threshold for 

Small Combustion Units” in the rule 

making docket (# EPA-HQ-OAR-2009-

0923). 

Drilling Rigs For drilling on production platforms 

1) Hours operated 

2) Total diesel fuel usage 

3) Total gasoline fuel usage 

4) Total natural gas fuel usage 

Subpart W methodology applied to all 

fuel combustion sources above a 

minimum threshold. For more details 

please see “Equipment Threshold for 

Small Combustion Units” in the rule 

making docket (# EPA-HQ-OAR-2009-

0923). 

Combustion Flares 1) Hours operated 

2) Volume flared 

3) Flare gas H2S Concentration 

4) Is there a continuous pilot? 

5) Pilot fuel feed rate 

6) Flare combustion efficiency 

7) Smoking condition (level of soot 

emitted) 

8) Stack outlet elevation 

9) Stack inner diameter 

10) Average exit velocity 

11) Average combustion temperature 

12) Stack orientation 

1) Whether flare has a continuous flow 

monitor. 

2) Volume of gas sent to flare in cubic 

feet per year. 

3) Percent of gas sent to un-lit flare 

determined by engineering estimate and 

process knowledge based on best 

available data and operating records. 

4) Whether flare has a continuous gas 

analyzer. 

5) Flare combustion efficiency. 

Equipment leaks 1) Stream type 

2) Facility size 

3) Average VOC weight percentage of 

equipment leaks (averages provided given 

CH4 content) 

4) Equipment inventory 

- Centrifugal- wet seal 

1) Total count of major equipment (listed 

in Table W-1B of today’s final rule) by 

field. 
Page 14 of 18 

- Centrifugal- dry seal 

- Reciprocating- rod packing 

Glycol Dehydrators 1) Hours operated 

2) Glycol unit elevation 

3) Glycol type 

4) Glycol circulation rate 

5) Glycol pump type 

6) Glycol pump type 

7) Lean glycol H2O content 

8) Is the unprocessed gas saturated? 

9) Wet gas H2O content 

10) Wet gas temperature 

11) Wet gas pressure 

12) Cold separator temperature 

13) Cold separator pressure 

14) Unprocessed natural gas concentrations 

15) Equipped with flash tank? 

16) Flash tank temperature 

17) Flash tank pressure 

18) Destination of flash gas 

19) Uses stripping gas? 

20) Stripping gas flow rate 

21) Outlet height of vent 

22) Outlet diameter 

23) Exit velocity 

24) Exit temperature 

25) Outlet orientation (degrees) 

26) Flare present? 

27) Combustion temperature 

28) Combustion efficiency 

29) Installed control equipment 

30) Condenser temperature 

31) Condenser pressure 

For glycol dehydrators with throughputs 

greater than 0.04 MMscfd 

1) Natural gas throughput, engineering 

estimate 

2) Absorbent circulation pump type 

3) Stripper gas? 

4) Flash tank separator? 

5) Type of absorbent 

6) Wet gas temperature 

7) Operating hours 

8) Concentration of CH4 and CO2 

9) What vent gas controls are used? 

For glycol dehydrators with throughputs 

less than 0.04 MMscfd 

1) Count of glycol dehydrators 

2) Whether vent gas controls are used? 

For desiccant dehydrators 

1) Count of desiccant dehydrators 

2) Engineering estimation using gas 

pressure, vessel dimensions, time between 

refilling, and percent of packed vessel 

volume 

Loading Operations 1) Volume loaded 

2) Average elevation 

3) Storage tank paint color 

4) Storage tank paint condition 

5) Bulk liquid temperature 

6) Product Reid vapor pressure 

7) Average percent by weight of VOCs in 

tank vapor 

8) Average molecular weight of VOCs in 

tank vapor 

9) Outlet height of vent 

10) Outlet diameter 

11) Exit velocity 

N/A 
Page 15 of 18 

12) Exit temperature 

13) Outlet orientation (degrees) 

14) Flare present? 

15) Combustion temperature 

16) Combustion efficiency 

17) Installed control equipment 

18) Condenser temperature 

19) Condenser pressure 

Losses from Flashing 1) Type of vessel 

2) API gravity of stored oil 

3) Operating pressure of vessel 

4) Operating temperature of vessel 

5) Oil/condensate throughput 

6) Operating pressure immediately

upstream of vessel 

7) Operating temperature immediately

upstream of vessel 

9) Outlet height of vent 

10) Outlet diameter 

11) Exit velocity 

12) Exit temperature 

13) Outlet orientation (degrees) 

Included as an emission source, for crude 

oil and condensate storage tank flashing 

losses above a 10 barrel per day wellhead 

throughput. For more details please see 

“Equipment Threshold for Tanks” in the 

rule making docket (# EPA-HQ-OAR2009-0923). 

Mud Degassing 1) Days per month of drilling with mud 

2) Type of mud 

Not included as an emission source. 

Natural Gas Engines 1) Engine elevation 

2) Hours operated 

3) Manufacturer 

4) Model No. 

5) Engine stroke 

6) Engine burn (rich, lean, clean) 

7) Fuel H2S content 

8) Fuel heating value 

9) Max rated horsepower 

10) Operating horsepower 

11) Max rated fuel usage 

12) Average fuel usage 

13) Total fuel usage (engineering estimate) 

14) Outlet height of vent 

15) Outlet diameter 

16) Exit velocity 

17) Exit temperature 

18) Outlet orientation (degrees) 

Subpart W methodology applied to all 

fuel combustion sources. 

Natural Gas Turbines Same as Natural Gas Engines above Same as Natural Gas Engines above . 

Pneumatic Pumps 1) Manufacturer 

2) Model 

1) Count of natural gas driven pneumatic 

pumps 
Page 16 of 18 

3) Hours operated 

4) Pump elevation 

5) Vented or Flared? 

6) Outlet height of vent 

7) Outlet diameter 

8) Exit velocity 

9) Exit temperature 

10) Outlet orientation (degrees) 

Pressure/Level 

Controllers 

1) Service Type 

2) Manufacturer 

3) Model 

4) Number of this make-model 

5) Hours operated 

6) Equipment elevation 

1) Count of pneumatic high-bleed devices 

2) Count of pneumatic low-bleed devices 

3) Count of pneumatic intermittent bleed 

devices 

4) Default emission factors. 

Storage Tanks 1) Product throughput 

2) Tank elevation 

3) Tank orientation (horizontal/vertical) 

4) Average liquid height 

5) Tank dimensions 

6) Fixed or Floating Roof? 

7) Roof shape 

8) Roof height above shell 

9) Breather vent setting 

10) Breather vent vacuum setting 

11) Paint Color 

12) Paint condition 

13) Bulk liquid temperature 

14) Product type 

15) API gravity 

16) Product Reid vapor pressure 

17) Average percent of VOC in tank vapor 

18) Equipped with flash tank? 

19) Outlet height of vent 

20) Outlet diameter 

21) Exit velocity 

22) Exit temperature 

23) Outlet orientation (degrees) 

24) Flare present? 

25) Combustion temperature 

26) Combustion efficiency 

27) Installed control equipment? 

28) Condenser temperature 

29) Condenser pressure 

For wellhead gas-liquid separator with oil 

throughput greater than or equal to 10 

barrels per day 

1) Total volume of sales oil from all wells 

2) Total number of wells sending oil to 

separators off the well pads

3) Sales oil API gravity range 

4) Count of tanks on wellpads 

5) Count of tanks, both on and off well 

pads assumed to have emissions control 

measures: either vapor recovery system or 

flaring of tank vapors 

For wellhead gas-liquid separators and 

wells with throughput less than 10 barrels 

per day 

1) Count of wellhead separators 

2) Count of wells without wellhead 

separators 

3) Total volume of oil production 

4) Best estimate of fraction of production 

sent to tanks with assumed control 

measures: either vapor recovery system of 

flaring of tank vapors 

5) Count of stock tanks on well pads 

If wellhead separator dump valve is 

functioning improperly: 

1) Count of wellhead separators that dump 

valve factor is applied. 

Cold Vents 

(Includes Un1) Hours operated 2) Volume vented 

Included in specific equipment vents, ( 

such as tanks, dehydrators, compressor 
Page 17 of 18 

combusted Flare 

Emissions) 

3) Vent type 

4) Vent gas H2S concentration 

5) Vent gas VOC concentration 

6) Average molecular weight of VOCs 

7) Stack outlet elevation 

8) Stack inner diameter 

9) Average exit velocity 

10) Exit temperature 

23) Stack orientation (degrees) 

24) Flare present? 

25) Combustion temperature 

26) Combustion efficiency 

27) Installed control equipment? 

28) Condenser temperature 

29) Condenser pressure 

seals) including vents to a flare. 

Well Venting from 

Well Liquids 

Unloading 

Included as an un-named source to flare 

and cold vents. 

1) Count of wells vented to the 

atmosphere for liquids unloading 

2) Count of plunger lifts 

3) Collective number of unloading events 

4) Average casing diameter 

5) Average tubing diameter 

Gas Well Completions 

and Workovers with 

Hydraulic Fracturing 

Included as an un-named source to flare 

and cold vents. 

1) Count of completions with hydraulic 

fracturing in the calendar year 

2) Average flow rate of the measure well 

completion venting 

3) Count of workovers with hydraulic 

fracturing in the calendar year 

4) Number of days of gas venting to the 

atmosphere during backflow for 

completion 

5) Number of days of gas venting to the 

atmosphere during backflow for 

workovers 

6) Number of completions and workovers 

employing reduced emissions completions 

and engineering estimate based on best 

available data of the amount of gas 

recovered to sales 

Gas Well Completions 

and Workovers without 

Hydraulic Fracturing 

Included as an un-named source to flare 

and cold vents. 

1) Count of completions in calendar year 

2) Count of workovers in calendar year 

3) Number of days of gas venting to the 

atmosphere during backflow for 

completion 

4) Number of days of gas venting to the 

atmosphere during backflow for workover 
Page 18 of 18 

Blowdown Vent Stacks Included as an un-named source to flare 

and cold vents. 

Total number of blowdowns per 

equipment type in calendar year 

Well Testing Included as an un-named source to flare 

and cold vents. 

1) Number of wells tested per field in 

calendar year 

2) Average gas to oil ratio for each field 

3) Average number of days in the well is 

tested 

Associated Natural Gas 

Venting 

Included as an un-named source to flare 

and cold vents. 

1) Number of wells vented or flaring 

associated gas 

2) Average gas to oil ratio for each field 

Centrifugal and 

Reciprocating 

Compressor Vented 

Emissions 

Included under equipment leak factors. 1) Count of compressors 

2) Default emission factor for each type of 

compressor. 

EOR Injection Pump 

Blowdown 

Not presently applicable. 1) Pump capacity, in barrels per day. 

2) Volume of critical phase gas between 

isolation valves. 

3) Number of blowdowns per year. 

4) Critical phase EOR injection gas 

density. 

EOR Hydrocarbon 

Liquids Dissolved CO2 

Not presently applicable. 1) Volume of crude oil produced in 

barrels per year. 

2) Amount of CO2 retained in 

hydrocarbon liquids in metric tons per 

barrel, under standard conditions 

3) Annual throughput, using engineering 

estimate