MEMORANDUM

To: Docket # EPA

- HQ

- OAR

- 2011

- 0512

From: Mark d e Figueiredo, EPA/CCD

Date: November 10 , 201 4

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 (here in after referred to as “subpart W”) . This memorandum provides background information on certain revisions relating to the following emission sources or specific provisions 1 :

1. Well venting for liquids unloading

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

3. Blowd own v ent s tacks

4. D ump v alves not closing properly at o nshore p roduction s torage t anks

5. Associated gas venting and flaring from produced h ydrocarbons

6. Reciprocating and centrifugal compressor venting

7. Best available monitoring methods (BAMM)



### 1. Well Venting for Li quids Unloading

The EPA is revis ing 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 address es reporter

concern s 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 contend ed that it would require them to be physically present at ea ch recording flow meter on December 31. These

r eporters described that the activity data gathered for liquid s unloading associated with well venting events are often recorded locally at the well site. The y 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 a ssert ed that it is logistically difficult for some reporters with multiple wells in this configuration to collect data from all wells on exactly December 31 st or January 1 st

. They
suggest ed 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. EPA

HQ

- OAR

- 2011

- 0512.

1The EPA considered two o ptions to address the issue of allow ing 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) a llow the use of an average estimated
tim e that venting occurs in a year, using engineering estimates based on best available data ; or (2) a llow 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 req u iring 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
allow s the same procedure to be used across all reporters, resulting in a consistent emissions
calculation method

.
The EPA is revis ing 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 (“T p ” 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
monitori ng period for the next reporting year, all days must be monitored

, and a ll venting must be accounted for. I f 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 p eriod 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 beg ins immediately following the last, then all venting events are captured in one of two consecutive re porting 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, 201 5 as opposed to January 1, 201 6

.
The EPA is also revising C alculation M ethod 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 rep orting of emissions from these sources separately
allow s the EPA and the public to better analyze the reported emissions and activity data.
C alculation M ethod 2 at 40 CFR 98.233(f)(2) is also revised to clarify that this method is used for wells without pl unger lifts.

Finally, t he EPA is amend ing the definition of the term “SP p ” 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 pre ssure to tubing pressure from a well
in the same sub

- basin where the casing pressure is known. This amendment w ould improve the consistency of the calculation method used to determine casing pressure across reporters.



### 2. Gas Well Venting During Completions an d Workovers with Hydraulic Fracturing

The EPA is amend ing 40 CFR 98.238 to add definitions for “reduced emissions completion” and “reduced emissions workover

. ” Currently, reduced emissions completions and

2reduced 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. S ince the t ime that subpart W was promulgated, the EPA promulgated new source performance standards for the oil and natural gas sector under 40 CFR p art 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.

I n the initial flowback periods

, there is too lit tle 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. I n s ome 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 comple tion 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 an other 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 sys tem, 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 workover may occur.

The EPA is also amend ing 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 completi on, for the purposes of P art 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 completio ns” 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 emission s workover .” The defini tion 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 workov ers 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
emission s completion/workover or not reduced emission s completion/workover. S pecifically, for

3gas well completions and workovers with hydraulic fracturing, the EPA is requir ing separate counts and separate reporting of emissions for the different well type combinat ions. 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 emiss ions are related to completions or workovers, which they d id 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 initi ating 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 p resent, and the calculation needs to be revised to account for this fact. Therefore, the EPA is modify ing the calculation to require the measurement of flow rate only when sufficient gas is present to enable flow rate measurement. In addition, some reporte rs 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 “T p ” in Equation W

- 10A and W

- 1 0B is being modified. Time that the gas is routed to production is no longer included, so it is no 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

t he 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 w orkover 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 clarify ing that reporters must calculate the annual volumetric natural gas emissions from each gas well venting during workovers without hydraulic fracturing using Equat ion 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 “E s,p ” for Equation W

- 13B to specify the annual volumetric natural gas emissions in

sta ndard cubic feet from well completions. We are also revis ing 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 “PR s,p ” in E quations W

- 10A and W

- 10B and Equation s W

- 12 A 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

4an 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 equat ion.

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 co mpressibility
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 operat e 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 compressibili ty factor (1/Z) over various operating temperature s 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

.

5In the proposed rule, EPA considered two options to address the compressibility factor, including: (1) i nclude the compressibility term “ Z ” into Equations W

- 14 A and W

- 14 B with the requirement that “ Z ” can be assumed to be “1” if the temperature is above

- 10 degrees
Fahren heit 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 compress ibility 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 w hen considering the high pressures used for transmission lines, the uncertainty in the emission estimates due to the
use of a default factor of 1 w ould only be about 10 percent. The commenters generally s upported the use of an optional site

- specific compressibility factor.

Although the accuracy of the emission calculation is improved if a compressibility factor
is included , w e understand that there are other factors, such as variations in gas composition a nd uncertainty of vent volumes, which may also a ffect 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 compressi bility 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

- speci fic 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, i n th e final rule, we are pr oviding 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 ( “Z a ” ) 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
emis sions 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 bou ndary 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

6• Pig l aunchers and r eceivers

• Emergency shutdowns (this category includes emergency shutdown blowdown emissions regardless of equipment type)

• A ll other equipment with a physical volume greater than or equal to 50 cubic feet

.

For situations where a blowdown event resulted in emissions f rom 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 port ion 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 cat egorize 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 transm ission compression, and liquefied natural gas ( LNG ) import and export equipment). T his 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. R eporters must still determine annual venting
emiss ions 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 v olumetric 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 emission s are reported on a facility basis a s 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, s ubpart 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 fr om 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

.

7According 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 equipm ent 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 in crease in the level of a storage tank. Reporters asserted that f ield technicians usually undertake correct ive actions within 24 hours of when companies detect abnormal operations at remotely monitored wells.

Other companies may rely on field technicians al one 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 t he frequency with which a technician visits a well will depend on the compa ny’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 reco rd 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
burden some.
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 emissio ns 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 separat or 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 calculate s only the additional emissions from dump
valves not closing properly , it was necessary to adjust the correction factors (CF n ) in order to simpl ify the equation. The EPA is decreas ing 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 recov ery 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 “E n ” in

8Equation 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 adju sted 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 “u se your separator flash gas volume and gas composition as determined in this secti on ”. 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 f rom Produced H ydrocarbons

Subpart W reporters must calculate annual emissions from associated natural gas venting and flaring ( 40 CFR 98.233(m)).

Some r eporters request ed that a term be added to E quation 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 r eporters described situations in which new well production could exceed the capacity of the sales line until the downstream operator makes adjustment s, 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 a ssert that the associated g as emissions calculation m ethod , found in Equation W

18

, 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.

T hree options t o address the se reporters’ concerns were : (1) a llow 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) r equire reporters to meter the amount of associated gas vented or flare d ; 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 r esult
in inconsistent data collection among reporters and could p otentially 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 c ould potentially increase burden on reporters

.
The EPA proposed the third option of adding a definition of “Associated gas venting or flaring” and add ing terms to Equa tion 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 co unt 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

9venting 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 ve nting or flaring” as defined in the rule

. Therefore, we are not including the proposed “ ERE p,q ” term in the final Equation W

- 18. Th ese final changes m inimize the risk of over

- estimating emissions , c larif y 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 98.2 3 3(o) and (p) , reporters must perform annual emissions measurements of compressor vents in the m ode in which the compressor is found (referred to as “as found” measurements). There is an additional requirement in 40 CFR 98.2 3 3(o)(1)(i)( C ) and (p)( 1 )(i) (D) that requires measurement in not

operating

- 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 t hat 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 require d the entire group of compressors that are connected to the common m anifold (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 shut down 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 comp ressors. 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
continuo usly measured data.

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

, we considered : (1) eliminating the requirement altogether; (2) a llow ing measurement in the NOD
mode to be taken at the next scheduled depressurized compressor shutdown ; and ( 3 ) a llow ing
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 compr essors for which NOD mode measurements are made. The option to a llow 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 c onsistent 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 not

operating

- depressurized

- mode. However, this option does not provide flexibility for reporte rs who do not have a scheduled shut down of their compressor(s) within a 5

- year period.

10Table 6

- 1 summarizes the fraction of methane emissions from compressors attributable to
the NOD mode emissions for the 2011

, 2012, and 2013 reporting year s. Because em issions from the NOD mode can contribute significantly to the emissions from a compressor, the EPA is not eliminat ing 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 m ode

- 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 measure ment
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, the n the NOD mode measurement must be made at the next scheduled depressurized compressor shutdown

. We received comments that t he term “ scheduled
shutdown ” was ambiguous and could be interpreted to be anytime the compressor is taken off

Table 6

- 1. Reported NOD Mode Compressor Emission s ( R eported as of Augus t 18, 2014)

Industry Segment /

Reporting Year Centrifugal Compressors Reciprocating Compressors

Total Methane
Emissions from

Compressors

(mt CO 2 e) Percent of Compressor
Emissions from

NOD Mode Total Methane
Emissions from

Compressors

(mt CO 2 e) Percent of Compressor
Emissions from

NOD Mode

Onshore natural gas processing

2011 74 4

, 7 01 6.8% 1,1 12

, 812 5.0%

2012 7 26

, 946 10.3% 1, 214

, 995 7.3%

2013 47 6

, 335 11.8% 1,47 1

, 562 4.7 %

Onshore transmission compression

2011 299

, 903 49.6% 2,1 49 ,00 9 17.4%

2012 52 3

, 345 65.7% 1,870, 101 19.4%

2013 568, 572 79.7% 1,9 89

, 781 31.1 %

Underground natural gas storage

2011 31,8 56 86.3% 222, 389 35.9%

2012 141

, 0 71 83.6% 190,0 19 33.5%

2013 29,4 15 39.7% 2 64

, 584 48.1 %

LNG import and export equipment

2011 40,9 3 0 34.9% 11,9 44 38.8%

2012 44, 086 59.0% 8,90 2 63.6%

2013 38, 78 0 96.7% 1 8

, 964 38.3 %

LNG storage

2011

— — 1,3 86 0%

2012

— — 108 0%

2013

— — 619 0.02 %

11line 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 schedule d 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. O ptions considered for atmospheric manifolded

c ompressor vent s included r equir ing 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 emiss ion sources). The option s to require annual measurement s from a single point in the manifold would likely reduce overall burden on reporters

. T he 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

t aking measurements

. While the provisions for measuring a manifolded group of compressors rather than the individual compr essors 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 t he 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 th an 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. W e determined that reasonabl y accurate compressor measuremen ts 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. B ased on the public comments received , we recognize that installing sampling ports at
locatio ns in manifolded systems where emissions are not comingled with non

- compressor sources i s 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

r elated 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 wh ether 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 tota l flow to the flare is already required under the provisions for flare emissions in 40 CFR 98.233(n) . Thus

, rather than

measure ment of individual compressor s ources or measurement of manifolded compressor sources prior to comingling that are routed to a fl are, the EPA simplified the requirements to

12allow flared emissions from compressors to include multiple compressors and other non

compressor emissions. Currently, f or 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 a n 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 a ddress es 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, t he EPA considered requir ing that compressors must be measured at least once in any three consecutive calendar years when the compressor is
in the operating

- mode. W e are not finalizing this provision in the final ru le. Emissions data reported for 2011 through 201 3 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 op erating

- 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 no t necessary to ensure these emis sions 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 ne eded. If any e missions 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
tempora ry 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 measureme nt 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, reporter s 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 compressor s that can be used to inform an emission factor. However, the data which are inputs to emissions equations have not

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

- specif ic 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 no t 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 fact ors 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, bu t 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 fo r 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 repo rted 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 le akage 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 compresso rs, one cannot determine a direct compressor emissions factor by compressor source, so only overall compressor emissions can be developed without the deferred data.

14Table 6

- 2

. Reported Reciprocating Compressor Process Emission s (R eported as of August 18, 2014)

Industry Segment / Reporting Year Total Number
of Reciprocating Compressors Number of Reciprocating Compressors

that used
BAMM Reported
CO 2 Emissions

(MT CO 2 e) Reported
CH 4 Emissions

(MT CO 2 e) Total Reported Reciprocating

Compressor

Process
Emissio ns (MT CO 2 e)

Onshore natural gas processing

2011 2,0 48 1,4 31 58,6 60 1, 112

, 812 1, 171

, 697

2012 2, 201 1,017 108,1 16 1, 214

, 995 1,3 23

, 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

, 5 84 2 64

, 89 1

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

15Table 6

- 3

. Reported Centrifugal Compressor Process Emission s (R eported 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
CO 2 Emissions (MT
CO 2 e) Reported CH 4 Emissions (MT
CO 2 e) Total Reported Centrifugal Compressor
Process Emissions (MT CO 2 e)

Onshore natural gas processing

2011 431 31 7 271 28, 060 74 4, 70 1 77 2

, 86 9

2012 4 32 231 27 5 13, 589 726,946 740,796

2013 460 232 278 15,10 5 47 6

, 335 491, 562

Onshore transmission compression

2011 630 296 238 409 299,903 300,312

2012 72 2 292 291 661 523,345 524,006

2013 788 315 31 9 67 9 568, 572 56 9

, 254

Underground natural gas storage

2011 33 3 0 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

compre ssor 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

.

16Table 6

- 4

. Summary of Compressor

- S pecific Reported Emissions Data (R eported as of August 18, 2014)

Compressor Type / Industry Segment Reporting

Year Number of Compressor s Compressor
Annual

Methane
Emissions (mt CO 2 e) Average

Methane
Emissions

per Compressor

(mt CO 2 e /yr) Standard
Deviation of

per Compressor

Methane
Emissions (mt CO 2 e /yr)

Dry Seal Centrifugal Compressors

Onshore natural gas processing 2011 160 53

, 770 336 918

2012 157 47

, 610 303 768

2013 182 61,75 6 339 985

Onshore natural gas transmission compression 2011 392 71

, 326 1 82 851

2012 431 1 8 6, 2 54 432 1, 536

2013 469 210,063 448 1,543

Underground natural gas storage 2011 8 11

, 306 1, 4 13 3

, 918

2012 16 114

, 284 7

, 143 2 7

, 58 0

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, 47 0 5

, 693

2013 27 8 41 4

, 579 1, 49 1 3,5 24

Onshore natural gas transmission compression 2011 238 228

, 577 960 2

, 004

2012 291 337

, 0 9 1 1,1 58 4, 817

2013 319 358,509 1,124 5,712

Underground natural gas storage 2011 25 20

, 550 822 1, 984

2012 23 2 6

, 787 1,165 2

, 284

2013 20 26,108 1,305 1,981

Reciprocating Compressors

Onshore natural gas processing 2011 2,04 8 1,112

, 812 543 1, 408

2012 2,20 1 1, 214

, 995 552 1, 284

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

Onshore natural gas transmission compression 2011 1,91 6 2

, 149

, 009 1,122 3

, 461

2012 2,000 1, 8 70, 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 19 0

, 0 1 9 61 5 972

2013 318 264,584 832 1,99 1

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 req uired 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 bec a me subject to Part 98 from the recent GWP changes to subpart A
to have automatic BAMM for the first three mo nths 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 fl exibility

. In the development of the final
rule , the EPA review ed Subpart W BAMM request s and found that the sources with the most frequent BAMM requests included centrifugal compressors, reciprocating compressors, blowdown vent stacks, and onshore product ion storage tanks , which are addressed in the final
rule

. T he 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 mea surements. 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 p revious 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 modifica tions 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

.

18Table 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 c ompressor emissions are manifolded together

, individual
compressor vents are not accessible or practical to measure. A llow 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 annu al as found measurement for manifolded compressors routed to a common vent.

Measuring emissions in the not

operating

- 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 shutdow n that requires a compressor to be taken off

- line for planned
or scheduled maintenance.

Measuring c ompressor emissions routed to flares individually and reporting flare compressor
emissions separately from other
flare emissions is burdensome and
the mani folds 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

- rel ated 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

- operating

depressurized

- mode. The option to use optical gas imaging to screen for emissions, in add ition to the current allowance
for use of a n 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 dum p valves are not closing properly

. A dditionally, 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 wit h the revised calculation in Equation W

- 16.

19Table 7

- 1

. Examples of Past BAMM Issues and Final Revisions to Address These Issues (continued)

Emission Source Type Issue Final Revisions

Blowdown vent
stacks R eporting blowdown vent
emissions data by unique physical
volume is not consistent with industry practices. Blowdown emission s may be grouped by equipment type for reporting, but emissions must still be calculated for each unique physical volume. Alternati v e ly

, facilities may use a
flow m eter 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 o f 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 sub

basin.

Completions and

wor kovers 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 “FRM
s ” in Equation W

10A is not well

- specific. “FRM
s ” was modified to be specific to each sub

- basin and well type combination.

Given the revisions summarized in Table 7

- 1, t he EPA is remov ing 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 fu ll compliance with the rule for cases where reporters faced reasonable impediments to using the monitoring methods in the rule . The se amendments are in keeping with the EPA’s stated intent to transition to reporting without BAMM.

Although the EPA is remov ing 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 necess ary 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

20publication of the final rule for reporters to prepare for data c ollection 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 R eporters may have previously measured one site to represent all wells of the same tubing
diameter and pressure ( including w ells 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 s eparately
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 sub

basin 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 quantit ies of gas are present to enable separation. R eporters may have to consider one or more reporting categor ies in performing measurements (i.e., for different well

- type
combination s in the sub

- basin). They may have to measure flowback rate and/or pressure fo r additional wells to obtain data
for representative wells for each sub

basin/well

- type combination

.

Centrifugal and Reciprocating Compressors Provides alternative measurement options for manifolded compressors (single annual measurement) R eporters with manifolded compressors may
not have instrumentation on the manifolded

vents

.

21