Frequently Asked Questions SEFA
Subpart W: Petroleum and Natural Gas Production Environ™^ protection
Agency
Offshore Petroleum and Natural Gas Production
Please clarify whether the final rule amending 40 CFR Part 98 applies to both onshore and
offshore.
On November 8, 2010, EPA signed 40 CFR part 98, subpart W; a rule that finalizes reporting
requirements for the petroleum and natural gas industry. This final rule covers both offshore and onshore
petroleum and natural gas production facilities. Please review section 98.230 for the definition of the
source category for each segment of the petroleum and natural gas industry covered by subpart.
Information and resources regarding the applicability and requirements of subpart W are available
at: http://www.epa.gOv/climatechange/emissions/subpart/w.html
According to § 98.238, offshore means seaward of the terrestrial borders of the United States,
including waters subject to the ebb and flow of the tide, as well as adjacent bays, lakes or other
normally standing waters, and extending to the outer boundaries of the jurisdiction and control of
the United States under the Outer Continental Shelf Lands Act.
What is terrestrial border?
In south Louisiana most sites are located within the State boundaries in lakes, bays, and bayous
(not in Federal waters). These waters are subject to the ebb and flow of the tide. In some cases these
sites are 150 miles north of the Gulf of Mexico. The sites are over water on platforms built on
pilings. Are these sites considered offshore or onshore sites?
The definition for offshore in § 98.238 includes "lakes or other normally standing waters", therefore, sites
located in lakes, bays, etc are considered offshore.
Is it correct to conclude that emissions from stationary sources of fuel combustion are to be
quantified and reported in accordance with the methodologies specified in 40 CFR Part 98 Subpart
C and not as described in BOEMRE's GOADS instructions?
EPA confirms that stationary sources of fuel combustion, except flares, must be reported using
methodologies specified in 40 CFR Part 98 Subpart C; flare emissions have to be reported under subpart
W, consistent with BOEMRE (30 CFR 250.302 through 304).
Onshore Petroleum and Natural Gas Production
I currently have a client that has traditional oil and gas wells with various equipment including
tanks, well heads, engines, compressors, dehydrators, separators etc. These wells are spread out
over multiple counties. Do the regulations state how we should consider this situation in regards to
determining whether I meet or exceed the GHG reporting threshold? Should we count each
individual well site as a facility or count all the wells as basically one facility?
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The facility definition for onshore petroleum and natural gas production is provided in section 98.238 of
subpart W. Facility with respect to onshore petroleum and natural gas production for purposes of this
subpart and for subpart A means all petroleum or natural gas equipment on a well pad or associated with a
well pad and CO2 EOR operations that are under common ownership or common control including
leased, rented, or contracted activities by an onshore petroleum and natural gas production owner or
operator and that are located in a single hydrocarbon basin as defined in § 98.238. Where a person or
entity owns or operates more than one well in a basin, then all onshore petroleum and natural gas
production equipment associated with all wells that the person or entity owns or operates in the basin
would be considered one facility. Per this definition, all onshore production sources listed in 98.232(c) in
the same basin are considered one facility.
In the "Leak Detection and leaker emission factor" subsection, I see that this section is not
applicable to production. "You must—conduct leak detection of equipment leaks from all sources
listed in Section 98.232 (d7), (e7), (f5), (g3), (h4), and (il). Therefore, I wanted to clarify that leak
detection is not applicable for wellheads, separators at well site, storage tanks and other equipment
defined by "production equipment".
Onshore production reporters do not need to perform leak detection under §98.233(q) for equipment
leaks. For an onshore petroleum and natural gas production facility, equipment leaks are calculated with
the methodology in §98.233 (r), using population count and population emissions factors.
With respect to the onshore petroleum and natural gas production segment and the natural gas
distribution segment, reporting of combustion emissions under subpart W is redundant for those
facilities also subject to subpart C. Yet the necessary information seems different between
Subpart W's subsection and Subpart C. The question is which subpart takes precedence in our
monitoring methodology?
For both the onshore production and natural gas distribution industry segments, all combustion emissions
monitoring and reporting requirements are incorporated into Subpart W. Hence, data reporting for the
onshore production and natural gas distribution segments' combustion emissions starting 2011 are
reported under Subpart W. Please note that for year 2010 onshore production and natural gas distribution
reporters have to comply with requirements of Subpart C for combustion emissions and, accordingly
report combustion related emissions under subpart C in 2010.
Please provide additional definition for determining the limits of a "basin". The rule defines a basin
as "all wells in a particular county". We have multiple isolated fields in the same county/parish,
and some fields that are in multiple counties/parishes. Do we group all oil and gas wells in a
geologically defined field, as the "basin", for applicability purposes?
The definition of both a basin and a facility, as applicable to onshore petroleum and natural gas
production, is provided in 98.238.
Facility with respect to onshore petroleum and natural gas production for purposes of this subpart
and for subpart A means all petroleum or natural gas equipment on a well pad or associated with a well
pad and CO2 EOR operations that are under common ownership or common control including leased,
rented, or contracted activities by an onshore petroleum and natural gas production owner or operator and
that are located in a single hydrocarbon basin as defined in § 98.238. Where a person or entity owns or
operates more than one well in a basin, then all onshore petroleum and natural gas production equipment
associated with all wells that the person or entity owns or operates in the basin would be considered one
facility.
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Basin means geologic provinces as defined by the American Association of Petroleum Geologists
(AAPG) Geologic Note: AAPG-CSD Geologic Provinces Code Map: AAPG Bulletin, Prepared by
Richard F. Meyer, Laure G. Wallace, and Fred J. Wagner, Jr., Volume 75, Number 10 (October 1991)
(incorporated by reference, see § 98.7) and the Alaska Geological Province Boundary Map, Compiled by
the American Association of Petroleum Geologists Committee on Statistics of Drilling in Cooperation
with the USGS, 1978 (incorporated by reference, see § 98.7).
Therefore, all oil and gas wells in a basin as defined by Subpart W have to be grouped together for
applicability purposes.
Are the blowdown emissions from a compressor, separator, or other field equipment included in
the Onshore petroleum and natural gas production sector?
Blowdown emissions from field equipment in the onshore petroleum and natural gas production segment
are not included for reporting under the onshore petroleum and natural gas production industry segment;
see section 98.23 l(a) and 98.232(c).
In Southern California, the South Coast Air Quality Management District (SCAQMD) requires
that fugitive VOC emissions from component leaks at oil and gas production facilities (both
onshore and offshore) be calculated and reported according to one of the methodologies in the
attached document. In order to avoid using different calculation methodologies for fugitive
emissions from component leaks for local vs. federal reporting requirements, it seems appropriate
to use the VOC (or TOC) emissions determined in accordance with the attached SCAQMD
guidance document combined with quarterly representative gas analyses for CH4 and CO2 to
determine fugitive CH4 and CO2 emissions from component leaks to be reported under Subpart
W. Would the use of the above procedure for calculation of fugitive CH4 and CO2 emissions from
component leaks at oil and gas production facilities require prior EPA approval (e.g., under
BAMM).
You must follow the methodological requirements in the rule and cannot use alternative methods.
Emission sources outlined in 40 CFR 98.234(f)(2), and 98.234(f)(3) include provisions for which
reporters may choose to use best available monitoring methods (BAMM) from January to June 2011
without petitioning EPA. All other BAMM requests must be submitted to EPA according to the
provisions outlined in the rule. However, please note that when using BAMM you must follow the
calculation equations in the rule, you may just use alternative methods to obtain the inputs to the
equations. For Frequently Asked Questions on BAMM for subpart W, please refer to
httrj://www.epa.gov/climatechange/emissions/downloadsll/documents/Subpart-W-BAMM-factsheet.pdf
Are the emissions factors listed in Table W-1A for both leaking components and non-leaking
components? How do you calculate emissions from leaking components if onshore petroleum and
natural gas source are not required to monitor components?
Equipment leak emissions in onshore production are to be estimated using methods provided in
98.233(r)(2). Hence, no leak detection of emissions is required for onshore production. Table W-1A
provides population emission factors, which represent the emissions on an average from the entire
population of components - both leaking and non-leaking; please see section 6(d) of the Technical
Support Document for further details on the concept of population emission factors.
98.233(j) - Onshore production storage tanks. The regulation stipulates that calculation
methodologies for onshore production storage tanks depends on whether the separator has a
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throughput greater than or equal to 10 barrels per day. Our clients expect that this would be based
on actual annual average since this is an annual report of actual emissions. Please confirm.
The 10 barrels per day of oil throughput referenced in 98.233(j) is based on annual average daily
throughput.
For an onshore petroleum and natural gas production site, I am confused on which calculation to
use for centrifugal compressor venting 98.233(o). Should the facility use 98.233(o)(l)-(7), and
therefore use equations W-22, W-23, W-24 and W-25? The calculations are contradictory and
redundant. But maybe the facility should only calculate emissions for wet seal oil degassing vents
(as suggested in the checklist). Therefore should the facility only use 98.233(o)(7), and therefore use
only equation W-25?
Onshore petroleum and natural gas production facilities should refer to §98.233(o)(7) to calculate
emissions from centrifugal compressor venting.
Onshore Natural Gas Processing
Section 98.230(a)(3)(ii) states that "All processing facilities that do not fractionate with throughput
of 25 MMscfd per day or greater." are included in the source category. Please specify the basis for
the 25 MMscf per day throughput - is this based on annual average daily flow or max design
capacity?
The gas processing plant throughput threshold in 98.230(a)(3)(ii) is based on annual average throughput.
Regarding terms "fractionate" and "fractionation" in 98.230(a)(3): Please define; does this refer to
separation of NGLs from methane, or the separation of NGLs into chemical species or commercial
products?
It is EPA's intention for the purpose of Subpart W to follow general industry parlance whereby
"fractionate" and "fractionation" refers to the separation of NGLs into individual chemical species or
commercial products.
Section 98.230(a)(3) states that the onshore natural gas processing industry segment includes (i) all
processing facilities that fractionate and (ii) all processing facilities that do not fractionate with
throughput of 25 MMSCF per day or greater. Does this mean that onshore natural gas processing
facilities that do not fractionate and which have a throughput of less than 25 MMSCF per day
are not subject to GHG reporting requirements?
As per the definition provided in 98.230 (a)(3), onshore natural gas processing includes "all processing
facilities that do not fractionate with throughput of 25 MMscf per day or greater." Therefore natural gas
processing facilities that do not fractionate and have a throughput less than 25 MMscf per day are not
subject to the requirements of Subpart W. You may still be subject to other subparts of the rule (e.g.,
subpart C, General Stationary Combustion) therefore you should determine if you are applicable under
any other subparts in 98.2(a).
Under onshore natural gas processing where would you report vent emissions? We have a
membrane plant (sweet gas so not acid gas removal) where we remove CO2 and vent should this be
reported under flare as unlit?
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If a membrane unit is used to remove CO2 from natural gas, then emissions must be calculated and
reported as specified in 98.233 (d). Please see EPA-HQ-OAR-2009-0923-1298-18 in the RTC for further
details on the definitions of sweet and sour gas.
In 98.230(a)(3)(ii), is 25 mmscf/day the design capacity for a processing plant or the actual
capacity?
The gas processing plant throughput threshold in 98.230(a)(3)(ii) is based on annual average throughput.
If there is a natural gas processing plant located at the same location as an underground storage
facility and they share compression, how should we report - as two separate facilities with estimated
compression dedicated to each or as one combined facility. If we are one combined facility, should
we follow the reporting requirements for a gas processing plant, an underground storage facility or
both.
If the natural gas processing plant and the underground storage operations are part of the same facility, as
defined in 98.6 you would report as one facility and submit one annual GHG report for these operations.
EPA has provided guidance on how reporters should report for co-located industry segments and dual
purpose equipment, please see the comment response number EPA-HQ-OAR-2009-0923-1024-14. EPA
is considering issuing further guidance on this issue.
Onshore Natural Gas Transmission Compression
Under section 98.233, for transmission storage tanks, the rule states to monitor the tank emissions
for 5 minutes then use a meter to quantify the emissions. Under 98.234#1, the rule says any
emissions detected by the camera is considered a leak. Is there a difference here? How do we treat
in intermittent emission from the storage tank? Can we use an alternative method to quantify the
emissions? Or are we limited to the means listed?
The purpose of this detection and measurement is to determine and quantify any continuous gas emissions
from condensate storage tanks. The most common source of vapor emissions from a transmission
compressor station condensate tank would be liquid transfer from compressor scrubber dump valves.
These sources operating properly would be intermittent transfer of liquids from high pressure vessels to
an atmospheric storage tank, with a short term flashing of dissolved gas, which is assumed to be less than
5 minutes in duration. Malfunction of scrubber dump valves can result in high pressure vapor leaking
through the valve, into the condensate tank, and out the tank roof vent, which would vent indefinitely.
This continuous release of vapor is detected as a continuous blow of gas from the condensate tank roof
vent using a leak imaging camera or by using an acoustic through-valve leak detection instrument. The
tank needs to be monitored to determine whether the "tank vapors are continuous for 5 minutes"; see
section 98.233(k)(2). So if a leak is detected per requirements of 98.234(a)(l) and is continuous per the
requirements of 98.233(k)(2) then the reporter has to measure the emissions per requirements in
98.233(k)(2)(i)-(iii). The reporter has the choice of using an acoustic leak detection device to detect and
measure leaks per requirements in 98.234(a)(5).
If onshore natural gas transmission has different emission factors for compressor and non
compressor components, why don't natural gas storage facilities have the same? Some storage
facilities can compress up to 3000psi. There is no provision for the different component categories
for compressor or non compressor components!
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EPA has reviewed your question but EPA does not have the data that supports the differentiation of
underground storage. Should peer-reviewed data come available, at a time deemed appropriate by EPA,
EPA would consider evaluating information on different emission factors for compressor and non
compressor components for the underground natural gas storage industry segment under subpart W. You
must follow the requirements in the rule.
Underground Natural Gas Storage
How do we report emissions from separate facilities that inject or withdraw gas from the same
underground storage reservoir? These facilities may also fall under other industry segments (e.g.
Transmission Compression or under Subpart C for general combustion sources).
Underground storage and compression and transmission compression are two separate industry segments.
A "facility", as defined in 40 CFR 98.6, must determine if it contains any of the industry segments listed
in subpart W and compare its emissions from all applicable industry segments against the 25,000
mtCO2e threshold defined in 40 CFR 98.2(a)(2) to determine applicability. For a response to the
question related to multipurpose facilities and dual purpose equipment, please see the response to EPA-
HQOAR-2009-0923-1021-14. If multiple owners or operators use the same underground storage
operation, one designated representative must be appointed for reporting purposes.
Could EPA clarify that the natural gas stored in high pressure steel bottles at peak-shaving stations
should NOT be considered an underground natural gas storage facility under Subpart W?
High pressure steel bottles that store natural gas at peak-shaving stations without any subsurface storage
per section 98.230(a)(5) would not be considered underground natural gas storage under Subpart W.
However, if the high pressure steel bottles are located at underground storage per section 98.230(a)(5)
then the equipment leak sources listed in 98.232(f)(5) would be subject to reporting.
Are dehydration units that are used to dehydrate natural gas extracted from underground storage
included within the definition of underground natural gas storage facility? If so, would those
dehydration units be considered part of the same underground storage facility if they are located on
a different site that is not contiguous with the compression facilities or wellheads?
Per 98.230(a)(5), natural gas underground storage processes and operations, including dehydration, are
part of the definition of the underground storage segment. Therefore, if you have these processes at your
facility, as defined in 40 CFR 98.6, you would be required to report on emissions from these dehydration
units.
Liquefied Natural Gas Storage and Import and Export Equipment
For LNG facility equipment that is in Gas Service, is only the equipment listed in Table W-5
(Vapor Recovery Compressor) required to be reported if it is found to be leaking as defined in the
rule.
Vapor recovery compressors use a population emission factor, hence there is no leak detection required.
Reporters have to count the number of vapor recovery compressors and use the population emission
factor.
LNG facilities will not be surveying the valves, connectors, and other components that are in Gas Service
under 98.233(q). At an LNG facility, a compressor that recovers vapor, but is designed so that it does not
have reportable emissions of methane-containing gas, such as a flooded screw compressor, or one with
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seals purged with pressurized nitrogen, will not be reported, in accordance with the rule and the EPA's
response in Response to Public Comments, EPA-HQ-OAR-2009-0923-1026-7, p. 46.
Do I have to calculate emissions from operational LNG storage tank venting at LNG storage
facilities or LNG import or export terminals? Also, the equipment listed to be surveyed for leaks
does not include pressure relief valves, an emissions source listed for other facility types in
98.233(q). Am I required to report these emissions?
Section 98.233(q)(6) and (7) clearly states that emissions factors for "...valves, pump seals, connectors,
and other." shall be used from the tables in the rule. A pressure relief valve is a valve and the relief vent
stack would be in the "other" category, so both are included the leak detection survey and required to be
reported.
I am confused as to how offshore LNG would apply. The two offshore terminals in New England
and one offshore in R-6 are basically buoys out in the ocean where a ship connects, regasifies the
LNG onboard and injects natural gas under pressure into the pipeline. The ships are hooked up to
the buoys for about a week to 10 days at a time. Once they offload their cargo, they return to their
home ports and are replaced at the buoy by another vessel. These vessels - for purposes of air and
water permits - have been determined by EPA to be stationary sources while they are connected
and offloading, but treated as vessels while under way. How are we to treat GHG reporting
applicability here? There are other types of offshore terminals that have all their equipment on a
fixed or floating processing station. Those ships would be treated like ships coming to a traditional
land based terminal where they offload for half a day and leave. We also have one of those
terminals in our region with three others proposed.
The LNG import and export terminal source category includes offshore equipment that receives imported
LNG via ocean transport, stores LNG, re-gasifies LNG, and delivers re-gasified natural gas to a natural
gas transmission or distribution system. The floating vessels described above, not the ships, are
considered LNG import terminal facilities. Applicability would be determined by determining the
estimated emissions and comparing against the threshold in 40 CFR 98.2(a)(2).
Natural Gas Distribution
Multiple Leak Surveys - Section 98.233(q)(l) regarding leak detection and leaker emission factors
(bottom of p. 218 of pre-publication notice) provides: "You must select to conduct either one leak
detection survey in a calendar year or multiple complete leak detection surveys in a calendar year.
The number of leak detection surveys selected must be conducted during the calendar year."
The preamble indicates that you must do one leak detection survey per year, and you may do
multiple leak surveys. The wording in the rule above indicates that you must select either one or
multiple surveys. This sounds as though we are required to indicate in advance how many leak
detection surveys will be conducted in the year which is onerous and doesn't make sense. We
believe you meant that we must conduct at least one leak detection survey in a calendar year, and if
we find a component that has a "leak" (e.g. as understood under Method 21) then at our option we
may fix the leak - e.g. by tightening a fitting ~ and then conduct another leak survey to confirm
that the component is not leaking.
For natural gas distribution, a facility, which is the collection of all distribution pipelines, metering
stations, and regulating stations that are operated by an LDC, is required to do at least one facility wide
leak detection survey per calendar year and has the option to conduct additional facility wide leak
detection surveys; if the facility selects this option, the additional facility wide survey(s) must be
completed during the same calendar year in order to take credit for fixing one or more leaks. If the
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facility chooses to fix one or more leaks and conduct another survey to determine that the component is
not leaking, it must conduct a facility wide leak detection survey in order to take credit for fixing the
leak(s). As leaks are random in nature and while some leaks are fixed others are likely to occur.
Therefore, a comprehensive survey is the only statistically relevant manner by which to establish facility-
wide leak emissions rates and take credit for leaks repaired. Please see the response to comment EPA-
HQ-OAR-2009-0923-1014-9 for further details.
It is very important to note that the requirement to conduct additional facility-wide leak detection surveys
should a company wish to take credit for fixing a leak does not preclude in any way a company from
repairing a leak. If a company chooses to conduct only one facility-wide leak detection survey in a
calendar year but finds a leak during the survey, the company can and is encouraged to fix the leak. The
leak detected though, as noted above, must be reported as a leaker for the entire calendar year should the
company choose not to conduct a second survey.
Sunset Non-Leaking City Gates: What happens if an LDC goes out to a custody transfer city gate
station year after year and finds that it has no leaking components? Could EPA provide a sunset
provision so that annual leak surveys would no longer be required?
Equipment/ component leaks are random in nature and minimal leaks in one year do not guarantee similar
leak levels in the future. There are no sunsetting provisions for individual emissions sources, only
facilities. EPA has provided provisions that allow facilities to stop reporting under certain conditions and
with prior notification to EPA. Please see 40 CFR 98.2(h)(i)(l) - (i)(3). EPA addressed sunset
provisions in general in the proposal to the 2009 Mandatory Reporting of Greenhouse Gases Rule (74 FR
16478).
Population Counts: It appears that there may be inconsistencies in some factors used in the
equations that Distribution facilities are directed to use on page 220 for population count emissions
(EQ W-31) and the calculated facility emission factor (EQ W-32) on page 224. "Counts" as used in
EQ W-31 is the total number of a type of source or component type. Does this mean that all
components should be counted?
"Count" as used in EQ W-32 is total number of meter runs, which will likely be a much lower
number than the number of a given component type in a meter run. EF as calculated here is
supposed to be a facility emission factor. This should work if there is only one meter run at a
facility (above grade M&R city gate).
EFs for EQ W-31 is defined on page 221 as the EF determined in EQ W-32.
We would appreciate clarification regarding how the population counts will work in the different
formulas.
For natural gas distribution, for below grade meters and regulators; mains; and services, these sources
shall use the appropriate default population emission factors listed in Table W-7 of subpart W.
The term "Counts" required in Eq. W-31 is a generic term, signifying the total number (activity) of the
type of emission source under consideration, at the facility. For natural gas distribution non-custody
transfer city gate stations, the term "Counts" refers to the total number of meter runs, since that is the
activity on which the emission factor for this sector is based on (see Table W-7 of subpart W).
The emission factor as defined in Eq. W-32 is intended for the sources of above grade meters and
regulators at city gate stations not a custody transfer, since these sources use the total volumetric GHG
emissions at standard conditions for all related equipment leak sources. First, the reporter is required to
estimate emissions "for all equipment leaks sources calculated in paragraph (q)(8) of section 98.233.
Then Es,i as defined in Eq W-32 is the emissions from ALL sources at above ground custody transfer
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stations. This when divided by the total number of meter runs for these custody transfer stations as in
Equation W-32 results in an emissions factor per meter that includes all the sources.
The emission factor for non-custody transfer city gate station comes ONLY from W-32. For all other
emissions source the reporter must use emissions factors in the tables as appropriately defined for EFs for
Equation W-31.
I found what I think is an error in the equations for estimating fugitive emissions from non-custody
transfer gate stations; equations W-31 and W-32.
Equation W-31 is as follows: Es,i = Counts * EFs *GHGi *Ts
EFs is the emission factor in scf/hr and Ts is the number of hours of operation during the calendar
year.
For non custody transfer gate stations EFs is calculated using Equation 32 which is EF = Sum
(Es,i/Count) (Eq. W-32)
Where Es,i is the annual estimated emissions from custody transfer gate station and count is the
number of meter runs.
I think EPA's intent was to assume fugitive emissions from non-custody transfer gate stations was
the same as fugitive emissions from custody transfer gate stations, which isn't a bad assumption,
but equation W-32 produces an emission factor, EFs, that is the average annual fugitive emissions
per meter run at custody transfer gate stations rather than an hourly emission factor required by
Equation W-31. As a result, the estimated emissions from non-custody transfer gate stations are
8,760 times greater than estimated emissions from custody transfer gate stations.
Equation W-32 should be EF = Sum (Es,i/(Count*Ts)) so that the calculated emission factor is an
hourly emission factor rather than an annual emission factor.
EPA has acknowledged the error and is considering options to address this issue.
For a distribution company that has underground service lines that are made of an unknown
material, is it appropriate to assume the most conservative worst-case population emission factor
(unprotected steel at 0.19 scf/hr/number of services) for each of these service lines if available data,
excluding a costly excavation of the service line, does not document the material type for the
particular service line?
Where no information is available on the type of service pipeline material, the reporter may make the best
judgment based on available information and use appropriate emissions factors. It is not appropriate to
assume the worst-case population emission factor. The reporter should document this determination in
the monitoring plan under 40 CFR 98.3(g).
Subpart W provides population factors in Table W-7 for cast iron mains, but not for cast iron
services. If a distribution company owns cast iron services, is it appropriate to develop a cast-iron
specific service lines emission factor by taking the company's average service line length (in miles)
and multiplying this by the emission factor for cast iron distribution mains?
There is no emission factor for cast iron services in Table W-7, therefore you are not required to calculate
emissions from cast iron services.
Other: Acid Gas Removal Units
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98.236(c)(3) requires the "total throughput off the acid gas removal unit" to be reported. Please
confirm that the throughput is the volume of gas exiting the AGR unit (outlet gas), not the volume
of gas vented to atmosphere.
Yes, the term "throughput" refers to the volume of gas flowing out of the AGR unit.
This question relates to Subpart W, Acid Gas Removal Vents, using Calculation Methodology 3.
Are we allowed to assume that volume fraction of CO2 content in natural gas out of the AGR unit
(Vo) is zero? This will result in a conservative estimate of AGR vent emissions.
No. §98.233(d)(8) does not instruct reporters to assume volume fraction of zero for VO. Reporter must
use the methodologies prescribed in §98.233(d)(8) to determine the CO2 composition of the natural gas
exiting the AGR unit (VO).
Other: Blowdown Vent Stacks
Clarify whether 98.233(i) Blowdown vent stacks is applicable to pipeline blowdowns (if occurring at
a Subpart W "facility" such as a well pad). The term 'equipment' makes this unclear whether it
only applies to compressors and tanks and their associated piping, or if it actually applies to
pipeline blowdowns as well.
The blowdown vent stacks source is not listed under 98.232(c) and therefore does not have to be
monitored for onshore petroleum and natural gas production.
The calculation methodology for blowdown vent stacks indicates that natural gas volumetric
emissions at standard conditions (calculated using Eq. W-14) are to be converted to GHG mass
emissions using the methodology in 98.233(v). Unless the blowdown stream was a pure CH4 or CO2
stream, natural gas volumetric emissions cannot be converted directly to GHG mass emissions.
Before volumetric natural gas emissions can be converted to GHG mass emissions, the volumetric
natural gas emissions must first be converted to GHG volumetric emissions. Please confirm that
emissions for blowdown vent stacks should be calculated using the following approach: volumetric
natural gas emissions at standard conditions [98.233(i), Eq. W-14], convert to GHG volumetric
emissions (CH4 and CO2) at standard conditions [98.233(u), Eq. W-35], convert to GHG mass
emissions at standard conditions [98.233(v), Eq. W-36].
EPA acknowledges the error and is considering ways to address this.
Other: Compressors
With regards to the (Component Count Methodology 1) are tubing systems, one half inch in
diameter included in the totals shown on Tables W-1B and W-1C. If a component count exist for a
facility, and the component totals are significantly higher than using the average component counts
listed in Tables W-1B and W-1C, which count should be used?
Tubing systems equal to less than one half inch diameter are exempt from the requirements of section
98.233(r). If a component count exists for a facility, then that actual count may be used as required in
section 98.233(r)(2)(ii).
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In regard to emissions calculations for reciprocating compressor venting, specifically for
production, using Equation W-29, why and how would I use Section 98.233 (u) to estimate
volumetric GHGi emissions from volumetric natural gas emissions as outlined in the above section
using Equation W-35? It appears as though Equation W-29 already calculates volumetric GHGi
emissions and one should proceed to calculation of mass emissions with Equation W-36 from
Section 98.233 (v).
Regarding calculating emissions from reciprocating compressor venting, it is EPA's intent that 40 CFR
98.233(p) should only reference paragraph 98.233(v) for determining mass emissions. EPA is currently
considering options to address this.
I was seeking clarification on Subpart W, Section 98.233, Subsection (o), regarding calculation of
emissions for Centrifugal compressor venting. From the regulation I am unclear as to the
procedures for using Equations W-22 and W-23, specifically, are both calculations used
independent of each other? If so, under what circumstances is one employed over the other?
The text in paragraphs 98.233(o)(4) and 98.233(o)(5) are not alternate methods. Per 98.234(o)
compressors must be measured in all three modes over a 3 year period and therefore section 98.233(o)(4)
is the calculation method for compressor modes measured during a specific reporting year and section
98.233(o)(5) is the calculation method for compressor modes not measured during the specific reporting
year.
98.233(p)(10) for reciprocating compressors refers to applying the calculation methods found in
paragraph (u) yet all equations in paragraph (p) calculate component volumes rather than total
volumes. The similar section 98.233(o) for centrifugal compressors does not reference paragraph
(u). It appears that the reference to paragraph (u) is in error in section (p)(10), please verify.
Paragraph (u) is incorrectly referenced in §98.233(p)(10). We are considering options to address this.
Other: Dehydrators
98.233(e) - Dehydrator vents. The regulation requires producers and processors to identify which
dehydrators have a throughput less than 0.4 MMscf/day. Our clients expect that this would be
based on actual annual average since this is an annual report of actual emissions.
The daily throughput of 0.4 MMscf per day for dehydrators referenced in 98.233(e) is based on annual
average daily throughput.
Other: Flaring
For Equation W-21 - Flare Emissions: Do you use "5" for Ri (# of carbon atoms) for hydrocarbons
with more than 5 carbons?
For hydrocarbon constituents with 5 or more carbon atoms, Rj is 5 as defined in equation W-21.
We noticed in Subpart W of the MRR on page 74498 (n) Flare Stack Emissions that the calculation
methods do not offer use of a CEMS as a valid method of quantifying emissions for flare stacks.
The Dehydration vent stack source category and the AGR unit vent stack source category both
allow use of a CEMS to quantify emissions. Was it possibly an oversight to not allow use of a CEMS
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as a quantification method on flares? Most facilities are more likely to have a CEMS on the flare
than the Dehy/AGR units, and given the extremely large variance in possible products going to the
flare, the CEMS would likely be much more accurate than any calculation.
You must follow the calculation and monitoring requirements in the rule. You are correct that 98.233(n)
does not currently allow the use of CEMS as a method for quantifying emissions for flare stacks.
Please confirm that flare stack emissions are included in determining applicability for Subpart W.
That is, are flare emissions included in the 98.2(a)(3)(iii) combined emissions from all stationary
fuel combustion sources when determining applicability for Subpart W per Section 98.231(a)?
To determine facility applicability, you must determine if you meet the requirements of paragraphs
98.2(a)(l), (a)(2) or (a)(3). Based on the information provided we assume you meet the definition of the
source category for subpart W and are only subject to reporting for subparts C and W.
Based on the assumptions above, for the 2010 reporting year, you are only required to report emissions
from stationary combustion. When determining applicability under 98.2(a)(3)(iii) you do not need to
include emissions from flares because flares are not included specifically under subpart C.
For the 2011 reporting year, you must include flare stack emissions in the applicability determination, as
flares are included under subpart W.
Subpart W 98.233(m), covering Associated Gas Venting and Flaring, assumes continuous gas
venting or flaring throughout the year, which is typically the case for "stranded" gas from oil wells
where gathering infrastructure is not available to route gas to sales. Equation W-18 uses total
annual oil production with the appropriate GOR to capture total gas emissions for the reporting
year. In a situation where associated gas is only flared when an equipment disruption occurs, like a
compressor going down for a short period of time, it is our interpretation that this quantity of
flared gas does not fall within 98.232(m) since it is not continuous throughout the year, and
therefore Equation W-18 would grossly overestimate emissions from the flaring event. Instead, our
interpretation is that this flaring event should be reported under 98.232(n) [EPA note: should be
98.233(n)) that covers Flare Stack Emissions to allow for a more accurate reflection of the emissions
from the flaring event.
The interpretation on equipment disruption is correct; it has to be reported under 98.233(n) and not
98.233(m). Section 98.233(m) only covers natural gas that is not recovered from the production operation.
Other: Pneumatic Devices
Equation W-l, legend entry for GHGi includes reference to facilities listed in 98.230(a)(3) through
(a)(8). However, reporting for this source (pneumatic device venting) is required only for
onshore production (which is specifically mentioned earlier in this legend item), and NG
transmission compression and underground NG storage, which are 98.230(a)(4) and (a)(5)
respectively. I recommend changing this reference in the legend to reference only (a)(4) and (a)(5),
to avoid confusion.
For the source of pneumatic device venting, section §98.233(a)(l) and (a)(2) outlines the segments to be
considered for emissions reporting from this source, in the definition of the term 'count'. Further, the
definition of the term 'EF' highlights the sectors that are relevant for this source. The reference of
sections §98.233(a)(3) through §98.233(a)(8) is a generic reference to the term 'GHGi.'
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General Emissions Detection and Measurement
What types of equipment meet the requirements of Method 21? We understand that "Gas
Rangers" qualify. What other brands of hand held gas wand devices qualify? Could you provide a
list? Or could we rely on the vendor to certify compliance of the device? Method 21 provides specs
in Section 6 - e.g., instrument scale readable to 2.5% of leak definition (or 250 ppm in this rule
which is 2.5% of 10,000 ppm). Could EPA allow an option that does not require such fine
resolution (e.g., if you can detect 10,000 ppm - the threshold for having a defined "leak" - it should
not matter whether the device scale is readable to 250 ppm). Method 21 performance
specifications may inadvertently exclude some devices that can accurately measure the leak
threshold of 10,000 ppm. Does the rule provide an avenue to use those devices?
Method 21 describes industry practices reviewed and established by EPA as a standard for the
measurement of volatile organic compound leaks. The methodology has been mutually accepted by EPA
and industry and used in practice for many years, and EPA references it in the interest of reducing burden
on the user and assuring consistency of measurements. As such, EPA also relies on the quality assurance
standards built into Section 6.3 of the existing methodology, which specify that the "scale of the
instrument meter shall be readable to ±2.5 percent of the specified leak definition concentration;" in the
case of Subpart W this translates to 2.5% of 10,000 ppm, or 250 ppm. Rather than recommending one
particular type of brand of equipment, defining the methodology and instrumentation accuracy allows the
user to select from a range of equipment options to best suit their individual situation.
Subpart W allows for facilities to use alternatives to the Method 21 approach and such provisions are
outlined in the rule. For example, facilities are also given the option of using other methods such as an
optical gas imaging device in the Alternative Work Practice to Method 21, or acoustic leak detection
methods to monitor sources. For additional information, please see the response to comment EPA-HQ-
OAR-2009-0923-1039-18.
Documentation for Leak Surveys of Components: What documentation is required for leak
surveys? Must all connectors, block valves, control valves, pressure relief valves, office meters,
regulators, and open ended lines be documented regardless if they are leaking or not. Currently, we
check all connectors, valves, etc. but only document the actual leaks. If documentation will be
needed on all components surveyed, then that would place an additional burden of recordkeeping
and additional manpower will be needed to meet the requirements.
For emissions source types indicted in 98.232(i)(l), the rule requires facilities to report the "total count of
leaks found in each complete survey listed by date of survey and each type of leak source". Therefore,
only leakers are to be reported, not the entire population of equipment/ components. Please refer to
section 98.236(b) (15)(i). There are no recordkeeping requirements for emissions sources determined not
to be leaking.
Option for Direct Measurement & Facility-Specific Emission Factors: Can a facility choose
between (a) the provided emission factors or (b) conducting a statistical analysis and calculating a
site-specific emission factor and applying it "across the board" to that facility and to other facilities
with like equipment?
EPA requires that the reporters use emissions factors provided in the rule, except where a facility-specific
emission factor is specifically required (e.g., above grade M&R at city gate stations). EPA does not allow
for statistical analysis based emissions on a reporter by reporter basis as this cannot be verified easily and
can result in non-standard reporting across the reporting facilities.
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Please explain whether detecting leaks through soap bubble testing is acceptable for natural gas
distribution systems and compressor stations?
Reporters may use soap bubble testing methods as specified in Method 21 (please see 98.234(a)(2)).
Can you tell me if the Hi Flow Sampler qualifies as a meter? It quantifies like any type of flow
meter.
Section 98.234 (a) states that any of the methods including flow meters, calibrated bags, or high volume
samplers may be used for quantifying equipment leaks and through-valve leakage. While EPA does not
endorse a specific equipment manufacturer, high volume samplers (including the Hi Flow Sampler) can
be used as a method for leak quantification as well as long as it conforms to requirements in 98.234(d).
Under Subpart W, Section 98.233 (q) addressing leak detection and leaker emission factors:
Provided the streams with gas content greater than 10 percent methane plus carbon dioxide by
weight are monitored, can monitoring data from a state permit required fugitive emissions
monitoring program already in place, which has a lower leak detection rate of 500 ppm, be used to
estimate fugitive greenhouse gas emissions?
You must follow the methods outlined in the rule. The reporter has to determine whether the
concentration limits required by the state permit fall within or outside the 10 percent by weight methane
plus carbon dioxide limit imposed by Subpart W. Concentration of GHGs in a leak cannot be always
correlated with the weight percent of the GHGs in the stream that is leaking. This is because
concentrations of GHGs in the leak are dependent on external factors that cause dispersion of the
emissions. Hence EPA cannot provide concrete guidance on using State specified limits that are not
directly comparable to Subpart W requirements.
Applicability Tool
Screening Tools - Especially for LNG Peak Shaving Facilities and Underground Storage: When
and how will EPA develop its Screening Tools to help companies determine whether certain
facilities do not need to report?
The screening tools are available on the website and are created to assist in the determination of which
facilities are required to report under subpart W. Please see
.
Any way we can get unlocked Subpart W screening spreadsheets (see attached) from the
applicability tool?
No. EPA's intention in posting Subpart W calculation utilities is to provide facilities with a simple tool
for estimating emissions when determining applicability. Additionally, the tools include a guidance and
source tab to document how emission estimates were calculated. The utilities are only a guide to help
facilities determine their Subpart W applicability. If you suspect a facility may exceed the annual 25,000
metric ton CO2e threshold, you should refer to the calculation methodologies in 98.233 to determine
emissions.
The applicability tool for Onshore Petroleum and Natural Gas has an operating factor for
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associated gas venting from produced hydrocarbons. How does this operating factor correlate with
the barrels of crude oil produced?
EPA has provided guidance on the operating factor in the Notes section, where it states, "*This is defined
as the fraction of time the process unit is operating in a calendar year. For example, a 90% operating
factor would be entered as 0.9 because the unit is in operation for 90% of the year."
For a 2011 report with the "Liquefied Natural Gas Storage" option selected; how does the
"calculation utility" excel spreadsheet account for "Population Count & Emission Factors" when
providing the user with a final CO2e number?
For the "Liquefied Natural Gas Storage" calculation utility, the spreadsheet multiplies Population Counts,
Emission Factors, and conversion factors to output methane emissions in tonnes CO2e for each source.
Final CO?e emissions = (Population Count) x (Emission Factors) x (Volume conversion)
Monitoring Plan
Subparts C and W: If a facility that operates stationary combustion equipment becomes subject the
GHGRP due to Subpart W related emissions, does a GHG monitoring plan have to be put in place
by January 1 or April 1,2011 for the basic procedures that will be used to collect data necessary for
Subpart C combustion emissions?
For Subpart W, monitoring plans as outlined in 40 CFR98.237 are to be completed by April 1, 2011.
This monitoring plan would include an explanation of the processes and methods used to collect the
necessary data for all GHG calculations, including those in both subpart C and subpart W.
General
Is there a PowerPoint presentation available on the reporting rule signed by Administrator Jackson
on November 8, 2010 for the petroleum and natural gas facilities? We would like to share the
presentation with our state technical advisory committee.
A PowerPoint briefing on Subpart W, Petroleum and Natural Gas Systems, as well as other supporting
materials are available on the Subpart W page of the Greenhouse Gas Reporting Program website at
http://www.epa.gOv/climatechange/emissions/subpart/w.html.
Subpart W states that external combustion sources with rated heat capacity equal to or less than 5
MMbtu/hr do not need to report combustion emissions. Do the emission from these sources need to
be included in the 25,000 metric ton threshold determination?
The emissions from external combustion equipment equal to or below the threshold do not have to be
included in the determination of reporting threshold for the facility. Please see response to comment
EPA-HQ-OAR-2009-0923-1060-27.
My question concerns the calculation of standard temperature and pressure. The rule stipulates
what standard temperature and pressure are, but how, for an annual average, is actual
temperature and pressure defined. Is it conditions at the time data were collected? Is it the average
temperature and pressure for a given location based on annual averages? Is it something else? Flow
sensors are going to read actual CFM not SCFM.
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Actual temperature and pressure as defined for 98.233 is the "average atmospheric conditions or typical
operating conditions." Therefore, the average temperature and pressure at a given location based on
annual averages can be used for actual temperature and actual pressure.
Should self-propelled workover equipment and truck loading/unloading be included for reporting
GHG emissions under Subpart W?
If the power take-off for operating the truck mounted workover rig is the truck wheel drive engine (i.e. a
transmission option to transfer the truck wheel drive shaft to powering the rig generator or wench or other
rig equipment) then yes, this workover rig arrangement is "self propelled." However, if the truck has a
separate engine not connected to the drive wheels that powers the workover rig equipment, then it is a
"non-self propelled equipment."
This information is provided solely for informational purposes. It does not provide legal
advice, have legally binding effect, or expressly or implicitly create, expand, or limit any legal
rights, obligations, responsibilities, expectations, or benefits in regard to any person. These
FAQs are intended to assist reporting facilities/owners in understanding key provisions of 40
CFRpart98.
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