MEMORANDUM

To: Docket # EPA-HQ-OAR-2011-0512

From: Mark de Figueiredo, EPA/CCD

Date: November 10, 2014

Subject: Greenhouse Gas Reporting Rule: Technical Support for 2014 Revisions 

and Confidentiality Determinations for Petroleum and Natural Gas Systems; 

Final Rule 

The EPA is finalizing revisions and other clarifications to 40 CFR part 98, subpart W 

(hereinafter referred to as “subpart W”). This memorandum provides background information on

certain revisions relating to the following emission sources or specific provisions1

:

1. Well venting for liquids unloading

2. Gas well venting during completions and workovers with hydraulic fracturing

3. Blowdown vent stacks

4. Dump valves not closing properly at onshore production storage tanks

5. Associated gas venting and flaring from produced hydrocarbons

6. Reciprocating and centrifugal compressor venting

7. Best available monitoring methods (BAMM)

1. Well Venting for Liquids Unloading

The EPA is revising the calculation and reporting requirements for well venting from 

liquids unloading to allow for annualizing venting data for facilities that calculate emissions 

using a recording flow meter (Calculation Method 1). This amendment addresses reporter 

concerns and simplifies reporting. 

Some reporters expressed difficulty in collecting well venting data using a recording flow 

meter for the exact period of January 1 to December 31, because they contended that it would 

require them to be physically present at each recording flow meter on December 31. These 

reporters described that the activity data gathered for liquids unloading associated with well 

venting events are often recorded locally at the well site. They asserted that the data are not 

transmitted to a centralized location and must be collected by a technician visiting each well site. 

As a result, they asserted that it is logistically difficult for some reporters with multiple wells in 

this configuration to collect data from all wells on exactly December 31st or January 1st. They 

suggested that it would be more practical for these reporters to collect the data over a period of 

several weeks, depending on the number of wells and the distance between wells. 

1 For background information related to other revisions, please refer to documents contained in Docket No. EPAHQ-OAR-2011-0512.

1

 
The EPA considered two options to address the issue of allowing reporters to use time 

periods other than exactly January 1 to December 31 (e.g., a period that may cover 300 to 400 

days, instead of exactly 365). These options include: (1) allow the use of an average estimated 

time that venting occurs in a year, using engineering estimates based on best available data; or 

(2) allow reporters to compute an annualized estimate based on data that are collected over at 

least 300 days of the reporting period. The first option increases information collection flexibility 

and requires minimal revisions to the current regulatory language. However, the option would 

potentially compromise data quality due to use of inconsistent methods among reporters to

perform the engineering estimates. The second option increases information collection flexibility 

while still requiring the collection of venting data, avoiding both the need to use engineering 

estimates and to establish criteria for “best available data.” Additionally, the second option 

allows the same procedure to be used across all reporters, resulting in a consistent emissions 

calculation method. 

The EPA is revising Calculation Method 1 (40 CFR 98.233(f)(1)) such that reporters may 

use an annualized value to determine the cumulative amount of time of venting (“Tp” in Equation 

W-7A and W-7B) if data are not available for the specific time period January 1 to December 31. 

The EPA is specifying that if an annualized value is used, the monitoring period must begin 

before February 1 and must not end before December 1 of the reporting year, and that a 

minimum of 300 consecutive days must be used by reporters to determine the annualized vent 

time. In the final rule, the date of the end of one monitoring period must be the start of the next 

monitoring period for the next reporting year, all days must be monitored, and all venting must 

be accounted for. If a reporter uses a monitoring period other than a full calendar year for any 

well, they must report the percentage of wells for which a monitoring period other than a full 

calendar year is used. Although the collected data may or may not represent the exact reporting 

year, if each monitoring period begins immediately following the last, then all venting events are

captured in one of two consecutive reporting years. For example, if a reporter chooses to collect 

data for the period from January 1, 2015 to December 1, 2015 for the 2015 reporting year, then 

the data collection for the 2016 reporting year will start on December 2, 2015 as opposed to 

January 1, 2016.

The EPA is also revising Calculation Method 1 at 40 CFR 98.233(f)(1) to separate the 

calculation and reporting of emissions from wells that have plunger lifts and wells that do not 

have plunger lifts. The calculation and reporting of emissions from these sources separately 

allows the EPA and the public to better analyze the reported emissions and activity data.

Calculation Method 2 at 40 CFR 98.233(f)(2) is also revised to clarify that this method is used 

for wells without plunger lifts. 

Finally, the EPA is amending the definition of the term “SPp” in Equation W-8 (40 CFR 

98.233(f)(2)) to clarify that if casing pressure is not available for each well, reporters may 

determine the casing pressure using a ratio of the casing pressure to tubing pressure from a well 

in the same sub-basin where the casing pressure is known. This amendment would improve the 

consistency of the calculation method used to determine casing pressure across reporters.

2. Gas Well Venting During Completions and Workovers with Hydraulic 

Fracturing

The EPA is amending 40 CFR 98.238 to add definitions for “reduced emissions 

completion” and “reduced emissions workover.” Currently, reduced emissions completions and 

2
reduced emission workovers are mentioned in the relevant calculation method as equipment that 

separates natural gas from the backflow and sends this natural gas to a flow-line. However, the

rule currently has no defined terms for reduced emissions completions and reduced emissions 

workovers. Since the time that subpart W was promulgated, the EPA promulgated new source 

performance standards for the oil and natural gas sector under 40 CFR part 60, subpart OOOO, 

that requires the use of a reduced emissions completion (following fracturing or re-fracturing) in 

specified circumstances. 

The EPA is revising the proposed definition for “reduced emissions completion” and 

“reduced emissions workover” in subpart W to indicate that short periods of flaring may occur.

In the initial flowback periods, there is too little gas for gas/liquid separators to function resulting 

in the separator being by-passed and the liquid is sent to a catch tank that is open to the 

atmosphere, which results in de minimis “venting” of any gases that are also collected with the 

liquid. In some situations flaring is also conducted with reduced emissions well completions and 

workovers. Specifically, the EPA is amending 40 CFR 98.238 to define a “reduced emissions 

completion” and “reduced emissions workover” as follows:

Reduced emissions completion means a well completion following hydraulic 

fracturing where gas flowback emissions from the gas outlet of the separator that 

are otherwise vented are captured, cleaned, and routed to the flow line or 

collection system, re-injected into the well or another well, used as an on-site fuel 

source, or used for other useful purpose that a purchased fuel or raw material 

would serve, with de minimis direct venting to the atmosphere. Short periods of 

flaring during a reduced emissions completion may occur.

Reduced emissions workover means a well workover with hydraulic fracturing 

(i.e., refracturing) where gas flowback emissions from the gas outlet of the 

separator that are otherwise vented are captured, cleaned, and routed to the flow 

line or collection system, re-injected into the well or another well, used as an onsite fuel source, or used for other useful purpose that a purchased fuel or raw 

material would serve, with de minimis direct venting to the atmosphere. Short 

periods of flaring during a reduced emissions workover may occur.

The EPA is also amending the definition of “well completions” in 40 CFR 98.6 to delete 

the phrase “or re-fracture” because this phrase applies to an already producing well and is 

considered a well workover, not a well completion, for the purposes of Part 98. This amendment 

is intended to avoid potential confusion concerning whether a re-fracture is a completion or 

workover in the context of subpart W. This change will also better align the existing definition of 

“well completions” with the new definition of a “reduced emissions completion” by clarifying 

that a reduced emission completion applies to only new fractures and that applicable re-fractures 

are covered under the new definition of “reduced emissions workover.” The definition of “well 

workover” in 40 CFR 98.6 already refers to re-fractures, so no clarifying change is needed for 

that definition.

The EPA is also revising the reporting requirements for completions and workovers to 

differentiate between completions and workovers with different well type combinations in each 

sub-basin category. A well type combination is a unique combination of the following factors: 

vertical or horizontal (i.e., directional drilling), with flaring or without flaring, and reduced 

emissions completion/workover or not reduced emissions completion/workover. Specifically, for 

3
gas well completions and workovers with hydraulic fracturing, the EPA is requiring separate 

counts and separate reporting of emissions for the different well type combinations. These 

revisions improve data quality for emissions from gas wells with hydraulic fracturing. Reporters 

will be required to separate and report their calculated emissions from completions and 

workovers without hydraulic fracturing by whether the emissions are related to completions or 

workovers, which they did not have to do under the current version of the rule. The EPA is also 

revising Equation W-10A to clarify and increase the accuracy of emissions calculations for gas 

well completions and workovers with hydraulic fracturing. In the final subpart W rule, the 

measurement or calculation for determining the ratio of flowback during well completions and 

workovers to 30-day production rate in Equation W-10A (40 CFR 98.233(g)) begins 

immediately upon initiating flowback of a well. Some reporters have asserted that the flowback 

characteristics of a well following hydraulic fracturing do not enable measurement or calculation 

to begin immediately upon initiating flowback due to a lack of sufficient gas being present, and 

the calculation needs to be revised to account for this fact. Therefore, the EPA is modifying the 

calculation to require the measurement of flow rate only when sufficient gas is present to enable 

flow rate measurement. In addition, some reporters have asserted that the accuracy of emissions 

calculations could be affected by the combined use of sales gas volume and approximations on 

flow rates for non-measured wells. To resolve this apparent issue, the time variable “Tp” in 

Equation W-10A and W-10B is being modified. Time that the gas is routed to production is no 

longer included, so it isno longer necessary to subtract the volume of gas being sent to sales. 

The EPA is also revising the calculation section at 40 CFR 98.233(g) and (h) to support 

the separate calculation of emissions from completions and workovers that are vented, flared, or 

recovered to a flow-line (i.e., reduced emissions completions or reduced emissions workovers). 

Reporters currently calculate emissions from all completion and workover activities, but the 

equations do not facilitate the classification of the activity needed for separate reporting. The 

EPA is revising Equation W-13 in 40 CFR 98.233(h) to separate the calculation of emissions 

from workovers from the calculation of emissions from completions, which will now be two

different equations. The EPA is also clarifying that reporters must calculate the annual 

volumetric natural gas emissions from each gas well venting during workovers without hydraulic 

fracturing using Equation W-13A and from each gas well venting from completions without 

hydraulic fracturing using new Equation W-13B. The methodology also requires the addition of 

parameter “Es,p” for Equation W-13B to specify the annual volumetric natural gas emissions in 

standard cubic feet from well completions. We are also revising 40 CFR 98.233(g)(1) to clarify 

the number of measurements or calculations that must be taken to estimate the average ratio of 

flowback rate (FRM).

The EPA is also revising parameter “PRs,p” in Equations W-10A and W-10B and 

Equations W-12A and W-12B to clarify that the first 30 day average production flow rate is the 

average taken after completions of newly drilled gas wells or workovers.

3. Blowdown Vent Stacks

During implementation of the subpart W rule, some reporters requested that the EPA 

allow the use of a factor to adjust for compressibility when calculating emissions from 

blowdown vents. The calculation method for blowdown vents included in the existing subpart W 

rule assumes natural gas is an ideal gas with a compressibility factor of 1, and does not include 

4
an adjustment for compressibility in the calculation. In the existing subpart W rule, natural gas 

emissions are estimated at ideal conditions using the ideal gas law in the following equation. 

n = PV/RT

where: n = molar amount of the gas

P = pressure of the gas

R = ideal gas constant

T = temperature of the gas

A compressibility factor is added to the ideal gas law equation to account for 

intermolecular forces as a result of temperatures and pressures not at ideal conditions. Adding 

the compressibility factor (Z) changes the equation to be the following:

n = PV/ZRT

The inverse of the compressibility factor (1/Z) is the difference between the moles of the 

gas calculated using the ideal gas law and the moles of gas calculated (for the actual temperature, 

pressure, and volume) using the ideal gas law including compressibility. The value of 1/Z can be 

used to estimate the relative uncertainty in emissions calculations using the compressibility 

factor.

The compressibility of methane at standard conditions is close to 1. However, the 

compressibility of methane at low temperatures and high pressures can vary. For example, 

natural gas transmission compression stations typically operate at pressures ranging from 500 to 

1,000 pounds per square inch gauge (psig) (35 to 69 atmospheres absolute pressure).

2 Table 3-1 

shows the compressibility factor (Z) for methane from Perry’s Chemical Engineering, 7th 

edition, and the inverse compressibility factor (1/Z) over various operating temperatures and 

pressures. 

Table 3-1. Compressibility factors (Z) for methane (from Perry’s Chemical Engineering, 

7th edition) and inverse compressibility factors (1/Z)

Pressure

(bars)

Pressure

(psia)

Temperature

250°K (-10°F) 300°K (80°F)

Z 1/Z Z 1/Z

1 14.7 1.00 1.00 1.00 1.00

5 73 0.98 1.02 0.99 1.01

10 145 0.97 1.03 0.98 1.02

20 290 0.94 1.07 0.97 1.03

40 580 0.87 1.15 0.93 1.07

60 870 0.80 1.25 0.90 1.11

80 1160 0.74 1.35 0.88 1.14

2 See page 6-32, American Petroleum Institute (August 2009), Compendium of Greenhouse Gas Emission 

Methodologies for the Oil and Natural Gas Industry. 

5

 
In the proposed rule, EPA considered two options to address the compressibility factor, 

including: (1) include the compressibility term “Z” into Equations W-14A and W-14B with the 

requirement that “Z” can be assumed to be “1” if the temperature is above -10 degrees 

Fahrenheit and pressure is below 5 atmospheres (or if the compressibility factor at the actual 

temperature and pressure is 0.98 or greater) or (2) allow the compressibility to be used at the 

reporter’s discretion. The EPA proposed the first option in consideration of the anticipated 

improvement in the accuracy of the calculated emissions when employing the site-specific 

compressibility adjustment.

Following proposal, the EPA received several comments opposing the use of mandatory 

site-specific compressibility factors. The commenters stated that mandatory use of 

compressibility factors places a significant burden on industry and would result in 

inconsistencies with prior year reports without producing a substantive benefit in terms of 

increased data and emissions accuracy. One commenter noted that, even when considering the 

high pressures used for transmission lines, the uncertainty in the emission estimates due to the 

use of a default factor of 1 would only be about 10 percent. The commenters generally supported 

the use of an optional site-specific compressibility factor.

Although the accuracy of the emission calculation is improved if a compressibility factor 

is included, we understand that there are other factors, such as variations in gas composition and 

uncertainty of vent volumes, which may also affect emissions calculations. Therefore, we 

determined that it is appropriate to finalize the inclusion of the compressibility factor in the 

equations, but to allow the optional use of site-specific compressibility factors. This approach 

allows for improved accuracy for facilities that have processes in place to determine site-specific 

compressibility factors, while not increasing the burden to facilities that do not. We encourage 

reporters to use a site-specific compressibility factor, especially for systems that operate at low 

temperatures and/or high pressures, but we are not setting mandatory requirements for which 

reporters must use a site-specific compressibility factor. Thus, in the final rule, we are providing 

reporters with the option of using a default value of 1 or a site-specific compressibility factor. 

We are also finalizing harmonizing changes to Equations W-33 and W-34 in 40 CFR 98.233(t) to 

provide reporters with the option to use a default value of 1 or a site-specific compressibility 

term (“Za”) for conversion of volumetric emissions at actual conditions to standard conditions. 

The EPA is revising the reporting requirements for blowdown vents in the rule related to 

“unique physical volumes,” but is retaining the requirement to calculate and keep records for 

blowdown vent stack emissions from each unique volume. We are revising the current reporting 

requirements in 40 CFR 98.236(c)(7) to simplify the reporting structure to report blowdown 

emissions aggregated by seven categories. We are revising and clarifying the proposed 

categories to apply broadly across different applicable industry segments. In the final rule, the 

seven categories are: 

• Facility piping (i.e., piping within the facility boundary other than physical volumes 

associated with distribution pipelines)

• Pipeline venting (i.e., physical volumes associated with distribution pipelines vented 

within the facility boundary)

• Compressors

• Scrubbers/Strainers

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• Pig launchers and receivers

• Emergency shutdowns (this category includes emergency shutdown blowdown emissions 

regardless of equipment type)

• All other equipment with a physical volume greater than or equal to 50 cubic feet.

For situations where a blowdown event resulted in emissions from multiple equipment 

types (other than an emergency shutdown) and the emissions cannot be apportioned to the 

different equipment types, we are also allowing reporters to categorize the blowdown event as 

the equipment type that represents the largest portion of the emissions for the blowdown. 

Although facilities are no longer required to report blowdown vent stack emissions by each 

unique physical volume, facilities will still calculate blowdown vent stack emissions from each 

unique physical volume and categorize the emissions by equipment or event type.

These equipment or event categories cover all blowdown venting from equipment or 

event types associated with the three (3) source categories (i.e., onshore natural gas processing, 

onshore natural gas transmission compression, and liquefied natural gas (LNG) import and 

export equipment). This revision will reduce the reporting burden and provide the EPA with 

sufficient detail to determine the source of emissions.

The EPA is not changing the “unique volume” calculation methods, because an accurate 

estimate of emissions can be obtained only by either estimating the actual volume of equipment 

vented, or by directly measuring the emissions. Reporters must still determine annual venting 

emissions for each unique volume.

It is possible that some facilities are currently using (or would prefer to use) a flow meter 

on some of their blowdown vents. If a flow meter is used, Equation W-14A or W-14B will not be 

necessary for calculating the annual volumetric amount of natural gas vented. Therefore, the 

EPA is providing an optional calculation method for blowdown emissions where a flow meter is 

in place to measure the emissions directly. This option would allow reporters to use an existing 

flow meter, or to install a flow meter in locations where emissions are a routine occurrence rather 

than calculating individual volumes. The accuracy of flow meter measurements is equal to or 

greater than the current unique volume method. We are including associated reporting 

requirements in 40 CFR 98.236. We are also adding additional clarifying edits for both the 

blowdown calculation and reporting sections of the rule. If a flow meter is in place to measure 

emissions, the emissions are reported on a facility basis as specified in 40 CFR 98.236(i)(2) and 

would not be assigned and reported by the seven equipment or event type categories.

4. Dump Valves Not Closing Properly at Onshore Production Storage Tanks

Currently, subpart W reporters must calculate annual emissions from onshore production 

storage tanks, including emissions during periods when the liquid dump valve on gas-liquid 

separators does not close properly (40 CFR 98.233(j)(8)). 

Some reporters asserted that the current requirements for calculating emissions from 

separator dump valves that are not closing properly requires a high effort to monitor and 

document that separator dump valves are closing properly. They also asserted that the current 

equations require them to keep unnecessarily large amounts of records to document periods 

when the valves are closing properly, as well as not closing properly.

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According to these reporters, onshore production companies typically have equipment 

maintenance and monitoring programs in place to maintain the integrity of their equipment and 

to minimize losses of natural gas from various types of equipment leaks, including dump valves 

that are not closing properly on gas liquid separators on onshore production storage tanks. 

Large companies may be responsible for several thousand dump valves and some may 

use remote monitoring to determine whether or not the dump valves are operating properly, 

while other companies may rely on technicians visiting a well site to test the equipment and

ensure it is working properly. Companies that use remote monitoring can determine if a dump 

valve is not closing properly, as indicated by a drop in pressure, a low level in a gas/liquid 

separator, a decrease in gas production rates, or a sudden increase in the level of a storage tank.

Reporters asserted that field technicians usually undertake corrective actions within 24 hours of 

when companies detect abnormal operations at remotely monitored wells.

Other companies may rely on field technicians alone to ensure that equipment such as 

dump valves are operating correctly. Field technicians will take corrective actions when they 

detect faulty equipment. Reporters asserted that the frequency with which a technician visits a 

well will depend on the company’s standard operating procedures, but it will range from once 

every few days to no more than once every two weeks.

In the case of either remote monitoring or field monitoring of equipment, some reporters 

further asserted that they should not need to record information documenting the occurrences of 

dump valves that are closing properly and should, instead, record only those times when the 

dump valves are not closing properly. They asserted that because dump valves operate properly

the vast majority of the time and because many companies are responsible for large numbers of 

dump valves that are monitored continuously or visited frequently, documenting that they are 

operating properly entails making and keeping large amounts of records that can become 

burdensome.

Equation W-16 in the current rule also does not calculate separate emissions for those 

periods when the dump valves are not closing properly. Instead, the current equation calculates 

total annual emissions from each storage tank, and combines emissions during normal dump 

valve operation with emissions when dump valves are not closing properly. Under the current 

equation, the data do not distinguish emissions that occur when dump valves are not closing 

properly from the total emissions from the separator on the storage tank. Therefore, the EPA is 

finalizing changes to simplify Equation W-16 to calculate emissions for only periods when the 

dump valve is not closing properly. The EPA is clarifying that the revised equation calculates 

only the additional emissions that result when the dump valve is not closing properly. 

Because the revised Equation W-16 calculates only the additional emissions from dump 

valves not closing properly, it was necessary to adjust the correction factors (CFn) in order to 

simplify the equation. The EPA is decreasing the correction factors for crude oil production and 

gas condensate production by “1” to reflect emissions originating only from the dump valve not 

closing properly. We also added reporting requirements to separately report these emissions.

We generally received only supportive comments for the proposed revisions. However, in 

reviewing the calculation order, it may be unclear whether or not the emissions calculated in the 

revised Equation W-16 can be adjusted for recovery or if these emissions must be included in the 

flow estimates to the flare (if a flare is used to control emissions from the production storage 

tank). With respect to adjusting for recovery, we revised the definition of the term “En” in 

8
Equation W-16 to read: “Storage tank emissions as determined in paragraphs (j)(1), (j)(2) and, if 

applicable, (j)(4) of this section in standard cubic feet per year.” By expressly including 

reference to paragraph (j)(4), we are allowing reporters to use the emissions adjusted for 

recovery in Equation W-15. For reporters that use vent the production storage tank emissions to a 

flare, we note that 40 CFR 98.233(j)(5)(i) requires reporters to “use your separator flash gas 

volume and gas composition as determined in this section”. We intend that the additional natural 

gas emissions determined for dump valves not closing properly would be added to the emissions 

determined for Calculation Methods 1 and 2 to determine the total volumetric flow to the flare.

5. Associated Gas Venting and Flaring from Produced Hydrocarbons

Subpart W reporters must calculate annual emissions from associated natural gas venting 

and flaring (40 CFR 98.233(m)). 

Some reporters requested that a term be added to Equation W-18 to account for situations 

where a portion of the natural gas is going to the sales line and a portion of the natural gas is 

flared. These reporters described situations in which new well production could exceed the 

capacity of the sales line until the downstream operator makes adjustments, or where temporary 

equipment problems limit the sales line capacity. In these situations, some of the natural gas 

production from a well may be flared while some of the production goes to sales. In this case, 

these reporters assert that the associated gas emissions calculation method, found in Equation W18, would overestimate the associated gas emissions, because the equation estimates emissions 

based on the gas to oil ratio (GOR) and volume of oil produced during the flaring period. The 

GOR is based on total gas from the well, which means all the gas would be reported as flared, 

despite some of the gas going to the sales line.

Three options to address these reporters’ concerns were: (1) allow the use of an 

“adjusted” gas to oil ratio, where reporters would use engineering estimates to revise the gas to 

oil ratio to account for average amount of gas sent to sales; (2) require reporters to meter the 

amount of associated gas vented or flared; or (3) add a definition of “Associated gas venting or 

flaring” to clarify what is covered by this term and add terms to Equation W-18 to exclude gas 

sent to sales and emissions that are calculated and reported elsewhere under subpart W.

Allowing reporters to use engineering estimates in the first option to revise the gas to oil 

ratio to account for average amount of gas sent to sales could provide flexibility, but would result 

in inconsistent data collection among reporters and could potentially compromise data quality. 

The second option to require reporters to meter the amount of associated gas vented or flared 

would result in greater data quality but could potentially increase burden on reporters. 

The EPA proposed the third option of adding a definition of “Associated gas venting or 

flaring” and adding terms to Equation W-18 to subtract the volume of associated gas sent to sales 

and the volume of gas reported elsewhere under subpart W from the annual volumetric natural 

gas emissions from associated gas venting. We received comments that the volume of gas 

reported elsewhere under subpart W would be burdensome to account for and, given differences 

in the calculation methods, may result in negative emission estimates. We originally considered 

that the gas-to-oil ratio (GOR) determined for Equation W-18 would double count gas that may 

be subsequently released from production storage tanks. However, upon further evaluation, we 

determined that the potential for double-counting emissions using Equation W-18 with emissions 

reported elsewhere was minimal, particularly given the proposed definition of “associated gas 

9
venting or flaring.” For example, we determined that the emissions as calculated using Equation 

W-18 are not expected to include or double-count emissions from onshore production storage 

tanks receiving oil from a separator at the wellhead. If onshore production storage tanks receive 

oil directly from the wellhead, these emissions are accounted for in the provisions for onshore 

production storage vessels, and these emissions would not constitute “associated gas venting or 

flaring” as defined in the rule. Therefore, we are not including the proposed “EREp,q” term in the 

final Equation W-18. These final changes minimize the risk of over-estimating emissions, clarify

the emissions to be reported, and are not expected to significantly increase the reporting burden.

6. Reciprocating and Centrifugal Compressor Venting

According to the current Subpart W requirements at 40 CFR 98.233(o) and (p), reporters 

must perform annual emissions measurements of compressor vents in the mode in which the 

compressor is found (referred to as “as found” measurements). There is an additional 

requirement in 40 CFR 98.233(o)(1)(i)(C) and (p)(1)(i)(D) that requires measurement in notoperating-depressurized-mode (NOD mode) “at least once in any three consecutive calendar 

years.” Some reporters suggested that this provision could require an unscheduled shutdown of 

the compressor for the sole purpose of making an NOD mode measurement. Some reporters also

contended that it is not practical to require a measurement from each individual compressor for 

groups of compressors that are routed to a common vent manifold (or flare header), because this 

required the entire group of compressors that are connected to the common manifold (or flare 

header) to be shutdown, blown down, and purged in order to safely install meters (or ports for 

temporary meters) and enable individual measurements. The reporters stated that it is extremely 

rare that entire groups of compressors are shutdown at the same time. In the November 2010 

response to public comments on the subpart W final rule (Docket ID No. EPA-HQ-OAR-2009-

0923), the EPA noted that commenters requested that the EPA allow direct measurements of 

common manifolded vent lines on compressors. At least one commenter stated that if continuous 

measurement of manifolded vent lines and aggregate annual emissions reporting were allowed as 

an option for measuring compressors, they would be able to safely collect and report to the EPA 

continuously measured data. 

To address the issue of measuring compressors every 3 years in the NOD mode, we 

considered: (1) eliminating the requirement altogether; (2) allowing measurement in the NOD 

mode to be taken at the next scheduled depressurized compressor shutdown; and (3) allowing

measurement in the NOD mode to be taken every 5 years (instead of once every 3 years). The 

option to remove the requirement altogether eliminates the need to do a measurement in the 

NOD mode, but it may limit the number of compressors for which NOD mode measurements are 

made. The option to allow measurement in the NOD mode to be taken at the next scheduled 

compressor shutdown ensures that the data are collected as soon as practical if no “as found” 

measurement was made in the NOD mode in the previous 3 years, provides consistent data 

collection among reporters, and prevents the potential need to shut down a compressor at an 

unscheduled interval for the sole purpose of measuring that compressor in NOD mode. The 

option to allow measurement in NOD mode to be taken every 5 years would eliminate the need

to shut down a compressor prior to every 5 years for the sole purpose of measuring in notoperating-depressurized-mode. However, this option does not provide flexibility for reporters 

who do not have a scheduled shut down of their compressor(s) within a 5-year period.

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Table 6-1 summarizes the fraction of methane emissions from compressors attributable to 

the NOD mode emissions for the 2011, 2012, and 2013 reporting years. Because emissions from 

the NOD mode can contribute significantly to the emissions from a compressor, the EPA is not 

eliminating the requirement to ensure a measurement is made in the NOD mode at this time. The 

EPA notes that certain data, which inform an analysis of NOD mode emissions, are inputs to 

emissions equations that have not yet been reported to the EPA because they are deferred for 

reporting until 2015. The deferred reporting elements include the total time that a compressor is 

in a particular mode and the mode-specific reporter emission factor. Because option 2 eliminates 

the need for an unscheduled shutdown while otherwise maintaining the 3 year measurement 

interval currently in subpart W, the EPA is finalizing revisions that would require measurement

in the NOD mode at least once in any 3 consecutive calendar years, provided the measurement 

can be taken during a scheduled shutdown. If there is no scheduled shutdown within 3 

consecutive calendar years, then the NOD mode measurement must be made at the next

scheduled depressurized compressor shutdown. We received comments that the term “scheduled 

shutdown” was ambiguous and could be interpreted to be anytime the compressor is taken offTable 6-1. Reported NOD Mode Compressor Emissions

(Reported as of August 18, 2014)

Industry Segment /

Reporting Year

Centrifugal Compressors Reciprocating Compressors

Total Methane

Emissions from 

Compressors

(mt CO2e)

Percent of 

Compressor 

Emissions from 

NOD Mode

Total Methane

Emissions from 

Compressors

(mt CO2e)

Percent of 

Compressor 

Emissions from 

NOD Mode

Onshore natural gas processing

2011 744,701 6.8% 1,112,812 5.0%

2012 726,946 10.3% 1,214,995 7.3%

2013 476,335 11.8% 1,471,562 4.7%

Onshore transmission compression

2011 299,903 49.6% 2,149,009 17.4%

2012 523,345 65.7% 1,870,101 19.4%

2013 568,572 79.7% 1,989,781 31.1%

Underground natural gas storage

2011 31,856 86.3% 222,389 35.9%

2012 141,071 83.6% 190,019 33.5%

2013 29,415 39.7% 264,584 48.1%

LNG import and export equipment

2011 40,930 34.9% 11,944 38.8%

2012 44,086 59.0% 8,902 63.6%

2013 38,780 96.7% 18,964 38.3%

LNG storage

2011 — — 1,386 0%

2012 — — 108 0%

2013 — — 619 0.02%

11
line for any reason or time period. In the final rule we are clarifying that a scheduled shutdown 

means a shutdown that requires a compressor to be taken off-line for planned or scheduled 

maintenance and that a scheduled shutdown does not include instances when a compressor is 

taken offline due to a decrease in demand but must remain available.

To address the issue of having to measure individual compressors that are manifolded, we 

first considered manifolded systems that are directed to the atmosphere separately from 

manifolded systems that are routed to a flare. Options considered for atmospheric manifolded 

compressor vents included requiring reporters to take either one, two, or three measurements per 

year on the common vent stack that is associated with the manifolded group of compressor 

sources (before emissions are comingled with other non-compressor emission sources). The 

options to require annual measurements from a single point in the manifold would likely reduce 

overall burden on reporters. The EPA proposed the option to perform measurements of 

manifolded groups of compressors three times a year and sought comment on alternative 

frequencies.

The EPA received comments regarding installation of sampling ports and the burden of 

taking measurements. While the provisions for measuring a manifolded group of compressors 

rather than the individual compressors were intended to decrease burden, the EPA recognizes 

that the proposed requirements related to sampling frequency may have unintentionally increased 

burden. Therefore in the final rule the EPA is providing that reporters may take one measurement 

per year for each manifolded group of compressors, which is the same monitoring frequency as 

for individual compressors. 

While the EPA would prefer to have the manifolded compressor measurements to include 

only compressor sources, we recognize that other sources may be tied in with the manifolded 

compressor sources. We proposed allowing measurements of the combined emissions from 

manifolded groups of compressors (rather than each individual compressor source) to reduce 

burden to the reporter and to address operational and safety concerns that arose during the 

implementation of Subpart W for these types of systems. We determined that reasonably

accurate compressor measurements could usually be made at the final stack (after comingling of 

other sources), if measurement prior to comingling of non-compressor emissions was not 

practical. Based on the public comments received, we recognize that installing sampling ports at 

locations in manifolded systems where emissions are not comingled with non-compressor 

sources is not possible for certain installations. Therefore, we are not finalizing this provision as 

proposed. Instead, we are revising the requirement from the proposed rule so that the final rule 

reads as follows “Measure at a single point in the manifold downstream of all compressor inputs 

and, if practical, prior to comingling with other non-compressor emission sources”. Information 

related to the operating conditions of each compressor in the manifolded group of compressors at 

the time of the measurement are required to be reported. We are also adding a reporting element 

for compressor measurements of manifolded systems to indicate whether the measurement 

location is prior to comingling with other non-compressor emission sources.

For compressor sources routed to a flare, it is likely that other emission sources would be 

routed to the same flare header system. Determination of the total flow to the flare is already 

required under the provisions for flare emissions in 40 CFR 98.233(n). Thus, rather than 

measurement of individual compressor sources or measurement of manifolded compressor 

sources prior to comingling that are routed to a flare, the EPA simplified the requirements to 

12
allow flared emissions from compressors to include multiple compressors and other noncompressor emissions. Currently, for most emission sources (including compressors), subpart W 

requires that flare emissions be calculated separately for each source type, backed out of the total 

flare emissions, and reported with each source type separately. For other emission sources that 

do not have a requirement to report as a specific source type emission, the remaining flare

emissions are reported in the flare source type. To address the issue of having to measure 

manifolded compressor sources prior to comingling with non-compressor sources when these 

sources are routed to an operational flare, the EPA is allowing facilities to determine the overall 

emissions from the flare without the need to calculate and report compressor flare emissions

separately. This addresses reporters’ safety concerns, provides reporters flexibility, and reduces

burden by not requiring reporters to sample compressors individually or to sample manifolded 

compressor sources prior to comingling with non-compressor sources in order to calculate the

portion of the total gas combusted in the flare that is attributable to compressor sources. 

In the development of the proposed rule, the EPA considered requiring that compressors 

must be measured at least once in any three consecutive calendar years when the compressor is 

in the operating-mode. We are not finalizing this provision in the final rule. Emissions data 

reported for 2011 through 2013 were reviewed and we determined that most compressor 

emissions are already measured in the operating-mode. Because the majority of the data 

currently collected for compressors is already collected in the operating-mode, we have 

determined that operating-mode is the most likely “as found” compressor mode that will be 

measured. Therefore, the requirement to conduct a measurement in the operating-mode once 

every three years is not necessary to ensure these emissions are quantified.

We are including provisions that allow flexibility for facilities when determining whether 

compressor sources require measurement. Facilities may use the optical gas imaging instrument 

methods at 40 CFR 98.234(a) for compressor vent screening. Specifically, we are expanding the 

use of the methods in 40 CFR 98.234(a) to allow for pre-screening for emissions from 

compressor isolation valves, blowdown valves, or rod packing released through a vent, to 

identify whether a measurement is needed. If any emissions are detected using an optical gas 

imaging instrument, then reporters are required to use one of the methods currently specified in 

subpart W (i.e., acoustic leak detection device, calibrated bagging or high volume sampler, or 

temporary meter such as a vane anemometer) to quantify the emissions. If no emissions are 

detected with an optical gas imaging instrument, the reporter may use zero as the measured 

emissions from that source and would not be required to follow-up with a measurement to 

quantify emissions. The use of an optical gas imaging instrument is allowed for the screening of 

transmission tank vents, and these vents are similar to compressor vents. This method provides 

flexibility for reporters and does not affect the quality of the data reported. For instance, the use 

of an optical gas imaging instrument will enable certain reporters to screen vents that are unsafe 

or inaccessible and that were previously difficult to measure. Under the requirements of the final 

rule, reporters would only be required to conduct measurements from these compressor sources 

if emissions are identified. Reporters would then use the existing measurement methods under 

98.234(a)(5), (c) and (d) to quantify emissions.

The EPA received multiple comments requesting that we develop emission factors for 

compressor sources based on the currently reported data. The EPA agrees that facilities have 

collected data under part 98 related to centrifugal and reciprocating compressors that can be used 

to inform an emission factor. However, the data which are inputs to emissions equations have not 

13
yet been reported to the EPA because they are deferred for reporting until 2015. The deferred 

reporting elements include the reporter-specific emission factors that are used to calculate 

emissions and the total time that a compressor is in a particular mode. The reporter-specific 

emission factors provide information on how measured data is applied to a reporter’s other 

compressors that were not measured in a particular mode, and these factors are applied to all 

compressors for the total time each compressor is operated in each mode. Therefore the deferred 

data provide important information that could help inform the development of emission factors 

for each mode of operation. The EPA intends to analyze this deferred information after it is 

received in 2015. The EPA also notes that the prevalence of BAMM in the reported data can 

affect cross-facility comparisons for developing emission factors, but the effect of BAMM 

cannot be fully analyzed until the inputs data are reported. 

The EPA reviewed verified data for reporting years 2011, 2012, and 2013 to assess its 

use in developing a compressor emissions factor for Subpart W reporting. Table 6-2 and 

Table 6-3 provide a summary of the reported process emissions data for reciprocating and 

centrifugal compressors, respectively. The EPA notes that reciprocating and centrifugal 

compressor emissions combined account for over half of the process emissions for the onshore

natural gas transmission compression, LNG import and export, and underground natural gas 

storage facility emissions. The two industry segments that have the highest compressor process 

emissions are onshore natural gas transmission compression and onshore natural gas processing; 

these two segments account for over 80 percent of total compressor emissions (i.e., reciprocating 

and centrifugal compressors combined). 

Next, the EPA reviewed the variance within each industry sector by reviewing reported 

emissions from individual compressors and compressor sources. Subpart W requires reporting of 

emission separately by compressor source (operating mode blowdown valve leakage; operating 

mode wet seal degassing vent, and NOD mode unit isolation valve leakage for centrifugal 

compressors and operating mode blowdown valve leakage; standby pressurized mode blowdown 

vent leakage, operating mode rod packing emissions, and NOD mode unit isolation valve 

leakage for reciprocating compressors). As noted previously, the reporting of certain data 

elements that are important to this analysis, such as the reporter emission factor and the time the 

compressor is in a given mode, have been deferred for reporting until 2015. Without these data, 

it is uncertain whether the cause of a given compressor source contributing significantly to the 

emissions is caused by a high emissions rate from that source, high operating time in that mode, 

or a combination of both. That is, given the limited data currently reported for compressors, one 

cannot determine a direct compressor emissions factor by compressor source, so only overall 

compressor emissions can be developed without the deferred data. 

14
Table 6-2. Reported Reciprocating Compressor Process Emissions

(Reported as of August 18, 2014)

Industry Segment 

/ Reporting Year

Total Number 

of 

Reciprocating 

Compressors

Number of 

Reciprocating 

Compressors 

that used 

BAMM

Reported 

CO2 Emissions 

(MT CO2e)

Reported 

CH4 Emissions 

(MT CO2e)

Total Reported 

Reciprocating 

Compressor 

Process 

Emissions 

(MT CO2e)

Onshore natural gas processing

2011 2,048 1,431 58,660 1,112,812 1,171,697

2012 2,201 1,017 108,116 1,214,995 1,323,346

2013 2,518 881 97,089 1,471,562 1,568,710

Onshore transmission compression

2011 1,916 1,152 3,904 2,149,009 2,152,913

2012 2,000 782 3,269 1,870,101 1,873,370

2013 2,111 814 29,999 1,989,781 2,019,796

Underground natural gas storage

2011 276 147 382 222,389 222,771

2012 309 64 290 190,019 190,398

2013 318 66 306 264,584 264,891

LNG import and export equipment

2011 21 7 12 11,944 12,411

2012 23 7 11 8,902 9,357

2013 26 11 9 18,964 18,975

LNG storage

2011 4 2 1 1,386 1,386

2012 4 0 8 108 116

2013 11 0 71 619 691

15
Table 6-3. Reported Centrifugal Compressor Process Emissions

(Reported as of August 18, 2014)

Industry Segment / 

Reporting Year

Total 

Number of 

Centrifugal 

Compressors

Number of 

Centrifugal 

Compressors 

that used 

BAMM

Number of 

Centrifugal 

Compressors 

with Wet 

Seals

Reported 

CO2

Emissions 

(MT 

CO2e)

Reported CH4

Emissions (MT 

CO2e)

Total Reported 

Centrifugal 

Compressor 

Process Emissions

(MT CO2e)

Onshore natural gas processing

2011 431 317 271 28,060 744,701 772,869

2012 432 231 275 13,589 726,946 740,796

2013 460 232 278 15,105 476,335 491,562

Onshore transmission compression

2011 630 296 238 409 299,903 300,312

2012 722 292 291 661 523,345 524,006

2013 788 315 319 679 568,572 569,254

Underground natural gas storage

2011 33 30 25 37 31,856 31,893

2012 39 12 23 166 141,071 141,237

2013 34 9 20 36 29,415 29,451

LNG import and export equipment

2011 9 8 5 47 40,930 40,977

2012 10 9 5 51 44,086 44,137

2013 13 12 4 41 38,780 38,821

LNG storage

2011 0 0 0 0 0 0

2012 2 0 2 0 0 0

2013 2 0 2 0 0 0

Due to the limited number of compressors reported in the LNG storage and LNG import 

and export equipment industry segments, we focused our analysis on onshore natural gas 

processing, onshore natural gas transmission compression, and underground natural gas storage 

industry segments. Table 6-4 shows a summary of the reported methane emissions per 

compressor for 2011, 2012, and 2013. There are some consistencies with respect to average 

emissions across reporting years from a given type of compressor within certain industry 

segments. The standard deviation exceeds the average emission factor for each compressor type 

and industry segment combination, which indicates potential variability in the reported 

compressor emissions. It is unclear if the per compressor source emissions factors may be less 

variable since some of the variability in the per compressor emissions factor may be caused by 

differences in the time in a given operating mode. This suggests that further analysis is warranted 

and the EPA looks forward to reviewing the deferred Part 98 data, the data that will be reported 

under these revisions and the data from outside studies in order to determine if appropriate 

emission factors can be developed, and, if so, the EPA may revise the calculation and reporting 

requirements for compressors in a future rulemaking.

16
Table 6-4. Summary of Compressor-Specific Reported Emissions Data

(Reported as of August 18, 2014)

Compressor Type / Industry 

Segment

Reporting 

Year

Number of 

Compressors

Compressor 

Annual 

Methane 

Emissions

(mt CO2e)

Average 

Methane 

Emissions 

per 

Compressor 

(mt CO2e 

/yr)

Standard 

Deviation of

per

Compressor 

Methane 

Emissions 

(mt CO2e /yr)

Dry Seal Centrifugal Compressors

Onshore natural gas processing 2011 160 53,770 336 918

2012 157 47,610 303 768

2013 182 61,756 339 985

Onshore natural gas transmission 

compression

2011 392 71,326 182 851

2012 431 186,254 432 1,536

2013 469 210,063 448 1,543

Underground natural gas storage 2011 8 11,306 1,413 3,918

2012 16 114,284 7,143 27,580

2013 14 3,307 236 274

Wet Seal Centrifugal Compressors

Onshore natural gas processing 2011 271 690,930 2,550 3,697

2012 275 679,337 2,470 5,693

2013 278 414,579 1,491 3,524

Onshore natural gas transmission 

compression

2011 238 228,577 960 2,004

2012 291 337,091 1,158 4,817

2013 319 358,509 1,124 5,712

Underground natural gas storage 2011 25 20,550 822 1,984

2012 23 26,787 1,165 2,284

2013 20 26,108 1,305 1,981

Reciprocating Compressors

Onshore natural gas processing 2011 2,048 1,112,812 543 1,408

2012 2,201 1,214,995 552 1,284

2013 2,518 1,471,562 584 2,661

Onshore natural gas transmission 

compression

2011 1,916 2,149,009 1,122 3,461

2012 2,000 1,870,101 935 1,999

2013 2,111 1,989,781 943 2,249

Underground natural gas storage 2011 276 222,389 806 1,993

2012 309 190,019 615 972

2013 318 264,584 832 1,991

17
7. Best Available Monitoring Methods (BAMM)

In order to provide facilities with time to adjust to the requirements of the rule, subpart W 

has provisions allowing the optional use of BAMM for unique or unusual circumstances. Where 

a facility uses BAMM, it is required to follow emission calculations specified by the EPA, but is 

allowed to use alternative methods for determining inputs to calculate emissions. Inputs are the 

values used by facilities to calculate equation outputs. Examples of BAMM include: Monitoring 

methods used by the facility that do not meet the specifications of subpart W or the use of

supplier data, engineering calculations, and other company records when measurement methods 

are specified. Facilities are required to receive approval from the EPA prior to using BAMM and 

these facilities are required to specify in their GHG annual reports when BAMM is used for an 

emission source. 

The EPA has previously noted that the Agency intended to “approve the use of BAMM

beyond 2011 only in cases that are unique or unusual” (76 FR 59538). Furthermore, the EPA 

limited the approvals of BAMM to one reporting year in keeping with the intent to allow use of 

BAMM as a transitional provision until facilities come into compliance with the final rule. While 

the EPA occasionally uses BAMM for targeted, short-term monitoring flexibilities (e.g., 

provision for reporters who became subject to Part 98 from the recent GWP changes to subpart A 

to have automatic BAMM for the first three months of reporting), no industry-specific subpart 

within Part 98 continues to use the BAMM flexibility except subpart W.

The EPA is finalizing several revisions to the subpart W calculation methods and 

reporting requirements to resolve the need for BAMM flexibility. In the development of the final 

rule, the EPA reviewed Subpart W BAMM requests and found that the sources with the most 

frequent BAMM requests included centrifugal compressors, reciprocating compressors, 

blowdown vent stacks, and onshore production storage tanks, which are addressed in the final 

rule. The most common concerns raised in BAMM requests associated with technical 

infeasibility included concerns related to having to shut down a facility to install access ports to

conduct compressor measurements. Other concerns related to compressors routed to a flare, 

manifolded lines, and compressor vents that were unsafe or inaccessible to measure. Table 7-1 

summarizes examples of previous BAMM issues and revisions to the final rule, by emission 

source type, which are intended to address these concerns.

The EPA notes that there have been previous BAMM requests in which facilities noted 

technical concerns including instances where certain equation parameters were unknown or 

where equipment modifications or installations were necessary. Such situations should no longer 

arise because, by the 2015 reporting year, facilities will have had four years to implement any 

necessary changes in order to fully comply with subpart W.

18
Table 7-1. Examples of Past BAMM Issues and Final Revisions to Address These Issues

Emission Source 

Type Issue Final Revisions

Centrifugal and 

reciprocating 

compressors

When compressor emissions are 

manifolded together, individual 

compressor vents are not 

accessible or practical to measure.

Allow emission measurement in the manifold after 

emissions are combined or at the manifold vent outlet, 

rather than at each individual compressor. Reporters must 

conduct a single annual as found measurement for 

manifolded compressors routed to a common vent.

Measuring emissions in the notoperating-depressurized-mode at 

least once in a 3-year period may 

require unit to be shutdown just to 

take measurement.

Measurements in the not-operating- depressurized-mode 

should be taken during scheduled depressurized compressor 

shutdowns. If there is no scheduled depressurized shutdown 

within three consecutive calendar years, then the 

measurement must be taken at the next scheduled shutdown

that requires a compressor to be taken off-line for planned 

or scheduled maintenance.

Measuring compressor emissions 

routed to flares individually and 

reporting flare compressor 

emissions separately from other

flare emissions is burdensome and

the manifolds to the flare are often 

not accessible or practical to 

measure.

Allow reporters to determine overall flare emissions 

without determining separately the portion of flare 

emissions attributable to compressors. Reporters would still 

report compressor-related activity data, but do not need to 

separately measure the compressor emissions going to the 

flare.

Certain individual or manifolded 

compressor vents are unsafe, not 

accessible, or impractical to 

measure.

Allow reporters to use optical gas imaging for pre-screening 

of emissions from blowdown valves on compressors in 

operating-mode or standby-pressurized-mode and for 

isolation valves on compressors in not-operatingdepressurized-mode. The option to use optical gas imaging

to screen for emissions, in addition to the current allowance 

for use of an acoustic measurement device, provides 

alternative measurement methods for unsafe, inaccessible, 

or impractical to measure valves. The final rule also 

provides the option to measure continuously using a 

permanent meter.

Onshore 

production storage 

tanks 

Quantifying and recording 

information for properly 

functioning dump valves is 

excessively burdensome.

The final rule clarifies that the total time a dump valve is 

not closing properly (i.e., the time variable used in Equation 

W-16) is to be estimated based on maintenance, operations, 

or routine well pad inspections that indicate the period of 

time when the valve was malfunctioning in open or partially 

open position. No records are required for periods when the 

dump valve is functioning properly. Equation W-16 was 

revised to calculate emissions that result from only those 

periods when the dump valve is not closing properly. 

Facilities must calculate and report emissions from dump 

valves only for time periods that dump valves are not 

closing properly. Additionally, the reporting requirements 

were revised (40 CFR 98.236(j)(3)) to clarify that dump 

valve emissions are to be reported separately from other 

emissions from the tanks (e.g., flashing emissions), 

consistent with the revised calculation in Equation W-16. 

19
Table 7-1. Examples of Past BAMM Issues and Final Revisions to Address These Issues 

(continued)

Emission Source 

Type Issue Final Revisions

Blowdown vent 

stacks 

Reporting blowdown vent 

emissions data by unique physical 

volume is not consistent with 

industry practices.

Blowdown emissions may be grouped by equipment type 

for reporting, but emissions must still be calculated for each 

unique physical volume. Alternatively, facilities may use a 

flow meter and report the annual emissions from the 

blowdown vent stack regardless of the equipment type or 

physical volumes associated with blowdown events during 

the year.

Well venting for 

liquids unloading 

It is not feasible to gather vent 

hours or number of unloadings 

from all controllers on one day, i.e. 

January 1 or December 31. 

Rule language was revised to allow facilities to use an 

annualized value and gather data for monitoring periods 

with start/end dates between December 1 and January 31 

that are at least 300 days. 

There is uncertainty regarding 

definition of shut-in pressure in 

Equation W-8. 

Shut-in pressure definition was revised to clarify when it 

should be determined. Definition was also revised to 

describe how to estimate casing pressure for a well if it is 

not known, using data from other wells in the same subbasin. 

Completions and 

workovers

There is uncertainty regarding the 

point in time when a completion or 

workover begins. 

Equations W-10A and W-10B were revised to clarify that 

the time period starts when gas is first detected in the 

flowback.

Parameter “FRMs” in Equation W10A is not well-specific. “FRMs” was modified to be specific to each sub-basin and 

well type combination. 

Given the revisions summarized in Table 7-1, the EPA is removing all existing provisions 

in 40 CFR 98.234(f) for BAMM. The removal of these BAMM requirements will improve data 

quality by requiring consistent reporting for each segment in subpart W. It has been the EPA’s 

intent throughout implementation of subpart W that BAMM be available as a limited, transitional 

program to serve as a bridge to full compliance with the rule for cases where reporters faced 

reasonable impediments to using the monitoring methods in the rule. These amendments are in 

keeping with the EPA’s stated intent to transition to reporting without BAMM.

Although the EPA is removing prior requirements of 40 CFR 98.234(f), we are revising 

40 CFR 98.234(f) to provide for short-term provisional BAMM for reporting year 2015. These

BAMM provisions are intended to address situations in which some facilities may need to obtain 

the necessary equipment to conduct measurements per the revised calculation methods in the 

final rule. These requirements are intended to be targeted, short-term transitional requirements 

for certain reporters for which the revised monitoring and measurement methods in this final rule 

would apply. First, the EPA assessed monitoring methods in the final rule and identified where 

those methods may have changed. Next, we evaluated if these changes were significant enough 

to warrant transitional BAMM provisions. Table 7-2 summarizes the emission sources where 

transitional BAMM provisions are included in the final rule.

The EPA is finalizing requirements to allow the use of BAMM for specified parameters 

(i.e., those for which the need for transitional BAMM is specified in Table 7-2) during the 

January 1, 2015 to March 31, 2015 time period without seeking prior EPA approval. 

Automatically allowing BAMM until March 31, 2015, allows additional time following the 

20
publication of the final rule for reporters to prepare for data collection and install the necessary 

monitoring equipment. The final rule also provides an option for reporters to request an 

extension for the use of BAMM beyond March 31, 2015, but no further than December 31, 2015. 

Reporters who request an extension must submit a request to the Administrator by January 31, 

2015 to receive approval to use BAMM beyond March 31, 2015. 

Table 7-2. Revisions and Rationale for Transitional BAMM

Source Type Final Rule Revision Rationale for Transitional BAMM 

Well Venting for 

Liquids Unloading

Separates measurement and calculation of 

emissions from wells with plunger lifts and 

wells without plunger lifts 

Reporters may have previously measured one 

site to represent all wells of the same tubing 

diameter and pressure (including wells with 

and without plunger lifts). If the facility has 

both wells with plunger lifts and wells 

without plunger lifts in a well tubing 

diameter and pressure group combination, the 

revised rule would require the reporter to 

measure an additional site to separately 

characterize the emissions with and without 

plunger lifts.

Well Venting during 

Completions and 

Workovers with 

Hydraulic Fracturing

Separates calculation of emissions for 

completions and workovers for each subbasin and well-type combination. Revises 

well-type combination to include with or 

without flaring and reduced emission 

completion/workover or not reduced 

emission completion/workover. Separates 

calculation for periods of initial flowback 

rate and average flow rated when sufficient 

quantities of gas are present to enable 

separation.

Reporters may have to consider one or more 

reporting categories in performing 

measurements (i.e., for different well-type

combinations in the sub-basin). They may 

have to measure flowback rate and/or 

pressure for additional wells to obtain data 

for representative wells for each subbasin/well-type combination. 

Centrifugal and 

Reciprocating 

Compressors

Provides alternative measurement options 

for manifolded compressors (single annual 

measurement)

Reporters with manifolded compressors may 

not have instrumentation on the manifolded 

vents.

21