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 me thodologies 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 altern ative(s) were select ed to reduce burden while maintaining the quality of data necessa ry 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, ons hore petroleum and natural gas production, onshore natural gas processing, onshore natura l gas transmission compressions, natural gas storage, liquefied natural gas storag e, liquefied natural gas import and export terminals, and onshore natu ral gas distribution.

As a general note, data collection methodologi es for the onshore petroleum and natural gas production industry segment and the offs hore petroleum and natural gas production industry segment are often different. Data collection methodologies were carefully considered for these industry segments. As onshore production is res ponsible for the vast majority of greenhouse gas emissions in th e 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 th an onshore emission, the BOEMRE “GOADS” monitoring system overall is sufficiently rigorou s to inform future policy. Therefore, GOADS is adequate for GHG data collec tion needs for offshore production. EPA performed a side by side comparison of the data requirements for each monitoring system (Exhibit B) while consider ing the reporting frequenc y and reporting costs.

I. Evaluation of Each Emission Source EPA focused on the methodologies which woul d reduce burden while not compromising the quality of the data needed to appropria tely inform future greenhouse gas policy. The methodologies that received the most comment s, and their respective emission sources, are listed below with the proposed me thodology paraphrased from the April 2010 proposal.

A. Onshore Production and Processing Natural Gas Composition Sampling

. Reporters would, in some cases be require d to perform quarterly sampling of gas composition where continuous gas compos ition analyzers were not installed.

B. Onshore Production Equipment Leak Emission Component Counts

. Reporters would be required to perform a total count of th e entire population of equipment components (valves, connectors, open ended lines, flanges, etc.) and update it each reporting year.

C. Onshore Production Storage Tank s and Glycol Dehydrators Vents3 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 Pump s 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 logof the volume of liquid pumped annually from each individual pump. For highbleed pneumatic devices, the proposed ru le would have required reporters to

obtain manufacturer bleed rate s to estimate emissions.

E. Reciprocating and Centrifugal Comp ressor Emissions from the Three Modes

. Due to ambiguity in the proposed repor ting requirements in the April 2010 proposal, reporters may have interpreted the rule to requir e 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 optic al 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 Det ermine Alternative Methodologies EPA considered alternative methodologies pr oposed in comments submitted on the April 2010 proposal as well as othe r methodologies demonstrated in the Natural Gas STAR Program for the above emission sources. Th e 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 obtaini ng 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 pr ioritized 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 fact ors for emissions sources with large geographically dispersed populations but small consistent emissions.

Alternative Leak Detection Tools EPA evaluated less costly, less accurate l eak detection and quan tification 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 require d number of measurements or samples in a reporting year where the actual valu e measured remains reasonably consistent or a representative sample is appropriate . Representative samples reduce burden by allowing the reporters to directly meas ure only a representative portion of their

emission sources instead of the entire population. The repo rter would then develop a population factor based on their representative data of that emission source and apply it to the remaini ng or unmeasured emission sources.

EPA revisited Chapter (4)(c)( ii) in the Technical Support Document (TSD) with these new burden reduction strategies and determ ined new, suitable methodologies for the

emission sources above. Exhibit A shows the decision process for emissions source selection modified from Figure 1 in the T echnical 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 identif ied and evaluated several methodologies for consideration to inclusi on 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 memo s 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 labe led “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. C omments from industry received on the April 2010 propos ed 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 ga s samples are taken in fields that are still under development until the field stabi lizes. Once the field stabilizes, those5 samples are generally taken no more freque ntly 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; esse ntially placing no additional burden on the reporter. Natural gas pro cessing 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 study 1 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 L eak Emission Component Counts

1. Representative Component Counts on Sub-Basin Entities. [Rejected] Reporters would count the number of co mponents within a region defined by the reporter within the facility (basin), a nd then apply the counts across the reporting basin to calculate equipment leak emi ssions. Although, this reduces the burden to reporters, defining acceptable criteria for cr eating 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 “repre sentative component c ount” or a “sub-basin entity” is in a regulatory cont ext. Had EPA adopted this proposal, the in tractability

of this definition would have caused seri ous 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 em ission factors provided by EPA. The 2009 API Compendium 2 provides “facility-level” popula tion emission factors, which onshore production operators can use to de termine 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 s ubpart 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 re porter, this method has a high le vel 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/GRI 1 and the 2009 API Compendium 2 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 equipmen t 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 count s. 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 docke t (# EPA-HQ-OAR-2009-0923).

4. Leak Detection and Leaker Factor [Rejected] Reporters would be required to conduc t 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 be st possible data, it w ould be a substantial increase in burden on industry.

C. Onshore Production Storage Tank s 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 resp ective segments. The 1996 EPA/GRI study 3
and 2009 API Compendium 2 provide emission factors for produced crude oil and

condensate sent to field stor age tanks and average glycol dehydrator vents. This would place little burden on industry; howev er, it would provide less accurate data than an engineering model estimate. On shore production storage tank emissions are highly variable and vary greatly depending on parameters such as the composition of the oil or condensate, the opera ting pressure of the separato r 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 circ ulation rate, natura l gas throughput, and composition of the gas. Population fact ors for glycol dehydrators and production storage tanks do not accurately capture th e 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 us e population emission factors to estimate emissions. Such a threshold would signi ficantly reduce burden on reporters while maintaining a quality of data for the larg est sources that would be acceptable for informing future policy. For more detail s please see “Equipment threshold for Dehydrators” and “Equipment Threshold fo r Tanks” in the rule making docket (# EPA-HQ-OAR-2009-0923).

D. Pneumatic Pumps and High Bleed Device Venting

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

Devices. [Adopted] Reporters would count high, low, and intermittent bleed pneumatic devices and determine emissions using default popul ation emission factors from the 2009 API Compendium 2 , and 1996 EPA/GRI 1 study. This reduces burden because operators no longer need to research and record manufacturer data to determine bleed rates for high-bleed pneumatic devices. Manufactur er 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 ra tes. Population factors, based on real industry sample data, would cap ture the effect of age on pne umatic 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 f actors from the 2009 API Compendium 2 , and 1996

EPA/GRI 1 study. This reduces burden because op erators no longer need to collect operating parameters for their pneumatic pum ps to perform an engineering emission estimate. Although this would reduce the ac curacy of emissions estimate, EPA has determined that activity data would adequa tely 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 con tinuous and intermittent bleed pneumatic devices, not based on high and low bleed rate s, and determine emissions using default population emission factors from the 2009 API Compendium 2 , 1996 EPA/GRI 1 , or comparable study. This reduces burden because operators would no longer need to lookup and record manufacturer data nor w ould they be required to distinguish between high and low bleed pneumatic devi ces. EPA does not consider this method8 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 Comp ressor 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 Compendium 2 , 1996 EPA/GRI 1 , EPA Lessons Learned: Replacing Wet Seals with Dry Seals in Centrifugal Compressors 4 , 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 reciprocati ng 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 comp ressors 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 ove rlooked 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 co mpressors once per year in the operating mode found during the measur ement, 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 pe riod during which EPA was informed by industry representatives that most compresso rs would be scheduled for a maintenance shutdown at least once) each compressor w ould 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 Threshol d” 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 camer a, to screen individual scrubber dump valves annually using an acoustic leak de tection 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/gasst ar/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 equipmen t may be more expensive than those with alternative detection tools. However, for reporters with a larg e population of scrubber dump valves, manually screening each scrubbe r dump valve with an acoustic leak

detection device can be more burdensome than simply viewing the condensate tank vent during the annual equipment leak surv ey using the optical leak imaging camera (required for inaccessible components). Further more, to reduce emissions measurement burden, EPA is allowing the alternative of quant ifying through-valve leakage of scrubber dump valves with an acoustic detector with manufacturer’s calibrations for estimating leakage. Fo r more details pleas e 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 Me xico 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 Mexi co waters are not subject to GOADS. EPA has determined that the GOADS monitoring sy stem, selected for the offshore petroleum and natural gas production industry segment, is adequate for GHG data collection needs for offshore production. In short, GOADS requi res 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 flar ing and starting 2010, the Bureau of Ocean Energy Management, Regulation, and Enfor cement (BOEMRE) will require a meter on all flare headers. The onshore petroleum a nd natural gas production industry segment in subpart W, on the other hand, requires no pe rmanent meter installations and only the annual reporting of emissions and activ ity 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 pr ocess 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 collect ed under subpart W using the onshore production reporting pr ovisions. Since offshore repor ters 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 whic h may result in reductions to subpart W compliance burden. EPA sought the monitori ng methodologies that provide appropriate data quality to inform future policy at the mi nimum cost to industry. After reviewing the alternative methodologies of this memo a nd 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 Reeval uating Subpart W Quantification Methods.

Is emissions source an equipment leak?

Is source accessible fo r equipment leak detection

Use equipment leak

detection and leaker

emission factors to

estimate emissions N o N o Yes N o Yes N o Potentially exclude

Is equipment leak

emissions source geographically dispersed? Yes Yes Is source contributing to top 80% o f 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 N o

Is the vented emission source geographically dispersed and large in population?

Can largest

emitters be

isolated? N

o

Use Engineering Estimation method on the largest emitters and population

emission factor and source count on res t Yes

Yes

Use continuous or periodic monitoring

What monitoring frequency is necessary? Representative Sample? N o

N o Does an engineering estimate methodology

exist? Use population

emission factor

and source count

to estimate

emissions. Does credible

emission facto r exist? Yes

N o

Use Engineering

Estimation

method YesPage 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 H 2 S concentration 14) Inlet lean amine CO 2 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 H 2 S 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 drilli ng 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 H 2 S 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 wei ght percentage of equipment leaks (averages provided given

CH 4 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 H 2 O content 8) Is the unprocessed gas saturated? 9) Wet gas H 2 O content 10) Wet gas temperature 11) Wet gas pressure 12) Cold separator temperature 13) Cold separator pressure 14) Unprocessed natura l 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 CH 4 and CO 2 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/APage 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 therule 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 H 2 S 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 Engi nes above Same as Natural Gas Engines above .

Pneumatic Pumps 1) Manufacturer 2) Model 1) Count of natural gas driven pneumatic

pumpsPage 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 se parators that dump valve factor is applied.

Cold Vents(Includes Un1) Hours operated 2) Volume vented Included in specific equipment vents, ( such as tanks, dehydrators, compressorPage 17 of 18 combusted Flare Emissions) 3) Vent type 4) Vent gas H 2 S 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 vent s 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 workoverPage 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