1

MEMORANDUM

TO: Docket ID No. EPA-HQ-OAR-2014-0831

FROM: Alexis McKittrick and Mark de Figueiredo, EPA/CCD

DATE : November 13, 2014

SUBJECT : Greenhouse Gas Reporting Rule: Technical Support for 2015 Revisions and

Confidentiality Determinations for Petroleum and Na tural Gas Systems; Proposed Rule

The U.S. Environmental Protection Agency (EPA) is p roposing revisions to 40 CFR part 98, subpart W (hereafter referred to as “subpart W” ). This memorandum provides background information on proposed revisions relating to the f ollowing emission sources or specific provisions 1 :

1. Oil Well Completions and Workovers with Hydraulic F racturing

2. Onshore Petroleum and Natural Gas Gathering and Boo sting Segment

3. Natural Gas Transmission Lines Between Compressor S tations

4. Well Identification Numbers

1 OIL WELL COMPLETIONS AND WORKOVERS WITH HYDRAULIC
FRACTURING

The EPA is proposing to amend subpart W to include provisions for the reporting of greenhouse gas (GHG) emissions from oil well comple tions and workovers with hydraulic fracturing in the Onshore Petroleum and Natural Gas Production segment. Consistent with the requirements for gas well completions and workovers with hydraulic fracturing, the proposed provisions include the reporting of activity data o n the number of oil well completions and workovers with hydraulic fracturing and on the use of flaring and reduced emission completions. The EPA is also proposing to update calculation met hods accordingly under 40 CFR 98.233(g) to reflect applicability to both gas well and oil w ell completions and workovers with hydraulic fracturing.

1 For background information related to other aspect s of the proposed rule, please refer to documents c ontained in Docket ID No. EPA-HQ-OAR-2014-0831.2

Calculation Method

The EPA is proposing to require Calculation Method 1, currently specified in subpart W for gas wells, for calculating inputs to Equations W-12A and W-12B for oil wells, which relies on direct measurement of gas flow rate during flowb ack. In subpart W, Calculation Method 2 uses the measured gas pressure differential across a well choke to estimate gas flow rate, but the EPA is not proposing to allow the use of Calculatio n Method 2 for oil wells. Calculation Method 2 is based on the choke flow equation in Perry’s Chemical Engineering Handbook 2 , which is intended for use with compressible flows, particula rly gases. In practice, this includes gases, supercritical fluids, and multiphase flows containi ng mostly gases. Based on the information available, the EPA concluded that this methodology may not be appropriate for estimating emissions from oil well completions because of the differences in operational conditions between oil and gas production. The EPA was unable to ident ify a methodology other than direct measurement, appropriate for calculating gas flow r ate during flowback for oil well completions or workovers with hydraulic fracturing.

The goal of the flowback process for oil well compl etions and workovers with hydraulic fracturing is to remove all the fracturing fluids f rom the formation so that the reservoir fluids (oil and gas) can begin to flow. The duration of the flo wback period is largely determined by reservoir characteristics. Operators are able to me asure flowback gas when there is sufficient gas
flow and a sufficient reduction in sand returns to route the flow to a separator.

Calculation Method 1 requires two parameters, FRM s (Equation W-12A) and FRM i (Equation W-12B), which are, respectively, the rati o of average gas flowback to 30-day gas production rate and the ratio of initial gas flowba ck to 30-day gas production rate. For oil wells where the gas production rate is not metered, the E PA is proposing a new Equation W-12C that allows reporters to use the average GOR during the first 30 days of production to estimate the average 30-day gas production flow rate following a completion or workover.

Estimation of Emissions based on Published Literatu re

Data from published literature were reviewed to estimate emissions that may be rep orted to the GHGRP from oil well completions or workovers with hydraulic fracturing if these proposed revisions are finalized 3 . One source estimated approximately 6,200 oil well

2 Perry’s Chemical Engineering Handbook . Seventh Edition. Ed. R.H. Perry and D.W. Green. C hapter 6: Fluid and Particle Dynamics, Fluid Dynamics: Compressible Flo w, p. 6-22.

3 Subpart W does not currently cover emissions from oil well completions and workovers with hydraulic f racturing, except for associated flaring emissions that may be reported under the miscellaneous flare stacks cate gory. The limited data available on oil well completions and workovers with hydraulic fracturing are summarized in the document, Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions and Associated Gas during Ongoing Production . Some stakeholders have opined that some subpart W reporters have reported gas well completions and workovers data from oil formation s ub-basins to the EPA through the Electronic Greenho use Gas3

completions with hydraulic fracturing in 2011 4 . For purposes of the analysis in this memorandum, the EPA assumed the number of oil well completions and workovers with hydraulic fracturing located at facilities meeting the threshold for reporting under subpart W when the rule is proposed to take effect would be s imilar to the activity level in 2011. It is anticipated that the number of gas and oil wells ha s increased and will continue to increase substantially in the future because of the continue d and expanding use of horizontal drilling combined with hydraulic fracturing. Therefore, this estimate may be an underrepresentation and the actual number of oil well completions or workov ers with hydraulic fracturing may in fact be larger than 6,200. The Inventory of U.S. Greenhouse Gas Emissions and Sink s: 1990-2012 published in 2014 (hereafter referred to as the “20 14 U.S. GHG Inventory”) does not currently distinguish between oil wells with and without hydr aulic fracturing, but estimates that over 15,000 oil wells (both wells with and without hydra ulic fracturing) were completed in 2012 5

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In published literature, estimates of potential met hane emissions from oil well completions with hydraulic fracturing (i.e., emissi ons in the absence of controls) range from 7.7 tons of methane (CH 4 ) per completion 6 to 32 tons of CH 4 per completion 7 . Multiplying these values by the activity levels described above (i.e. , 6,200 completions and workovers) gives a potential emissions range of 47,700 tons CH 4 per year to 198,400 tons CH 4 per year (43,300 to 180,000 metric tons (MT) CH 4 per year).

Reporting Tool (e-GGRT). However, the EPA notes tha t subpart W does not currently specify an emissions calculation or estimation method for oil well compl etions and workovers with hydraulic fracturing. The refore, the EPA did not assess these data as part of our techni cal analysis for this proposed new emission source.

4 Memorandum from Eastern Research Group, Inc. (ERG) to EC/R Incorporated. Hydraulically Fractured Oil Well Completions. October 24, 2013.
5 U.S. Environmental Protection Agency. Inventory of U.S. Greenhouse Gas Emissions and Sink s: 1990-2012 . EPA 430-R-14-003. April 15, 2014.

6 Ibid

. 7 O’Sullivan, Francis and Sergey Paltsev, “Shale gas production: potential versus actual greenhouse gas emissions”, Environmental Research Letters, United Kingdom. Nov ember 26, 2012.4

2 ONSHORE PETROLEUM AND NATURAL GAS GATHERING AND
BOOSTING SEGMENT

Overview of Gathering and Boosting Systems

A gathering and boosting system is a single network of pipelines, compressors and process equipment, including equipment to perform n atural gas compression, dehydration, and acid gas removal, that has one or more connection p oints to gas and oil production and a downstream endpoint. Gathering pipelines are used t o transport petroleum and natural gas from the downstream exit points of onshore production fa cilities (e.g., wells) to one of the downstream endpoints, typically a gas processing plant, transm ission pipeline, local distribution company (LDC) pipeline, or other gathering and boosting sys tem. Compressors located along the gathering and boosting system are used to control o r “boost” the pressure of the gas in the pipeline and keep the gas moving downstream. Acid g as removal units and dehydrators may be located on the gathering and boosting system to tre at the collected natural gas to remove contaminants and prevent corrosion.

Specifically, the emissions sources that may be pre sent in a gathering and boosting system include:

• Pneumatic devices

• Acid gas removal units

• Dehydrators

• Blowdown vent stacks (including those on gathering pipelines)

• Storage vessels and separators

• Flares

• Compressors

• Equipment leaks from system components (e.g., valve s, connectors, pressure relief valves)

• Gathering pipelines (emissions from pipeline leaks)

• Combustion sources (e.g., engines, boilers, heaters )

Subpart W currently does not specifically cover emi ssions from gathering and boosting systems. Some sources, such as boosting compressor stations, with combustion emissions that exceed the reporting threshold of 25,000 metric ton s carbon dioxide equivalent (MT CO 2 e) report those emissions to the Greenhouse Gas Report ing Program (GHGRP) under 40 CFR part5

98, subpart C (Stationary Combustion) (hereafter re ferred to as “subpart C”) 8 . Subpart W does cover emissions from sources such as compressors an d dehydrators in other industry segments currently defined in subpart W, such as the Onshore Natural Gas Processing segment or Onshore Petroleum and Natural Gas Production (which include s sources located on a single well pad or associated with a single well pad).

Estimates of Nationwide GHG Emissions for Gathering and Boosting Systems

Two sources of GHG emissions data for gathering and boosting systems were used to
estimate nationwide emissions. This section describ es those sources of data and the methods
used to estimate emissions.

The first data source is the 2014 U.S. GHG Inventor y 9 , which includes CH 4 and CO 2 emission factors and estimates of GHG emissions for some of the emission sources in gathering and boosting systems. In particular, the U.S. GHG I nventory includes fugitive and vented emission estimates for gathering reciprocating comp ressors and for gathering pipelines. In the U.S. GHG Inventory, gathering and boosting systems are included as part of the natural gas systems production segment. While some sources are considered to be specifically within gathering in the U.S. GHG Inventory (reciprocating compressors and pipelines in the production segment), vented and fugitive GHG emissions from eq uipment sources that are common to both well production sites and gathering systems, such a s dehydrators, storage vessels and separators, and pneumatic devices, are not characterized in the U.S. GHG Inventory into further subsegments.

Applying a global warming potential of CH 4 of 25, the estimated emissions for gathering and boosting compressors and pipeline leaks in the 2014 U.S. GHG Inventory are approximately 10 million metric tons (MMT) CO 2 e. This amount is likely lower than the total emiss ions from all emission sources in gathering and boosting, due to the 2014 U.S. GHG Inventory methodology which accounts for fossil fuel combusti on elsewhere and includes other gathering and boosting emissions sources in the overall produ ction segment number.

An analysis conducted by the Interstate Natural Gas Association of America (INGAA) using data from the 2007 U.S. GHG Inventory estimat ed the “split” of GHG emissions from combustion versus fugitive and vented GHG emissions (i.e., process emissions) for natural gas systems 10 . The INGAA analysis, which was used as a rough est imate to assist in approximating combustion emissions from gathering and boosting sy stems, compared total combustion

8 In 2013, 439 facilities with one or more of the NA ICS codes for a petroleum or natural gas facility r eported to the GHGRP under subpart C but not subpart W. The EPA ex pects that some of these facilities would be part o f the proposed Onshore Petroleum and Natural Gas Gatherin g and Boosting segment.

9 U.S. Environmental Protection Agency. Inventory of U.S. Greenhouse Gas Emissions and Sink s: 1990-2012 . EPA 430-R-14-003. April 15, 2014.

10 INGAA. “Emissions from the Natural Gas Industry.” Available at http://www.ingaa.org/cms/6435.aspx

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emissions and process emissions for natural gas pro duction, natural gas processing and transportation and storage. The INGAA analysis foun d that of the 76.6 MMT CO 2 e emissions reported for natural gas production in the 2007 U.S . GHG Inventory, 41.4 MMT CO 2 e were combustion emissions (54 percent) and 35.2 MMT CO 2 e (46 percent) were “release of methane” (fugitive emissions and venting) 11 . Further, combustion emissions represented about 2 5% of the 2013 subpart W CO 2 e emissions totals for the Onshore Petroleum and Na tural Gas Production segment and approximately 65% of the Onshore Natura l Gas Processing segment emissions totals. The EPA anticipates that the proposed Onsho re Petroleum and Natural Gas Gathering and Boosting segment is expected to fall between these two segments in terms of percentage of total
emissions related to combustion.

Assuming that the ratio of process emissions and co mbustion emissions is consistent with the INGAA analysis between years and industry segme nts, then process emissions are approximately 46 percent of the total emissions ass ociated with gathering and boosting. Conservatively assuming that the approximate value of 10 MMT CO 2 e is a low-bound estimate of total process emissions from the gathering and b oosting segment, this would bring the total emissions from both process and combustion emission s in gathering and boosting to approximately 22 MMT CO 2 e. This is a low-bound estimate because the amount does not include the additional process equipment mentioned above.

The second data source is ICF International’s repo rt from March 2014, titled Economic Analysis of Methane Emission Reduction Opportunitie s in the U.S. Onshore Oil and Natural Gas
Industries 12 , which developed a 2011 emissions baseline for the gathering and boosting segment. The emissions baseline developed for this analysis used the 2013 U.S. GHG Inventory 13 as a starting point and supplemented the activity factor s (equipment counts) and emissions factors data with data from several sources including GHGRP from reporting year 2012 and recent direct measurement studies of gathering and boostin g sources 14

.
The ICF study includes the following equipment in its gathering and boosting analysis:

• Reciprocating compressors;

• Centrifugal compressors;

• Compressor exhaust;

11 Ibid.

12 ICF International. Economic Analysis of Methane Emission Reduction Opp ortunities in the U.S. Onshore Oil and Natural Gas Industries. March 2014. Available at http://www.edf.org/sites/default/files/methane_cost _curve_report.pdf

. 13 U.S. Environmental Protection Agency. Inventory of U.S. Greenhouse Gas Emissions and Sink s: 1990– 2011

. EPA 430-R-13-001. April 12, 2013.

14 For example, Allen, David, et. al., Measurements of Methane Emissions at Natural Gas Pr oduction Sites in the United States . Published in Proceedings of the National Academy of Sciences of the United States of America, 110(44): 17768–17773, October 29, 2013.7 • Gathering and boosting stations;

• Pneumatic devices;

• Pipeline leaks;

• Dehydrators;

• Kimray pumps; and

• Condensate tanks.

This study estimated emissions from Gathering and B oosting to be 0.8 MMT of CH 4 or 20 MMT CO 2 e. These estimates include process emissions but do not include combustion emissions. Using the INGAA analysis 15 referenced above to assume that process emissions of 30
MMT CO 2 e are approximately 46 percent of the total emissio ns associated with gathering and boosting, this would bring the total emissions from both process and combustion emissions in gathering and boosting to approximately 43.5 MMT CO 2 e.

Based on the approaches discussed above, the estima ted total emissions from the gathering and boosting segment of the petroleum and natural gas industry may range between 22
MMT CO 2 e and 43.5 MMT CO 2 e, including both process and combustion emissions. For comparison, Table 2.1 shows the total emissions fro m both process and combustion emissions reported by facilities in other petroleum and natur al gas industry segments.

Table 2.1. Petroleum and Natural Gas Systems Sector — 2013 Reported GHG Emissions by Industry Segment (Reported to the GHGRP as of August 18, 2014)

Industry Segment 2013 Reported Emissions (MMT CO 2 e)
Onshore Petroleum and Natural Gas Production 95

Offshore Petroleum and Natural Gas Production 6 Onshore Natural Gas Processing 59 Onshore Natural Gas Transmission Compression 23 Underground Natural Gas Storage 1 Liquefied Natural Gas (LNG) Import and Export Equip ment < 1 LNG Storage < 1
Natural Gas Distribution 15

15 INGAA. “Emissions from the Natural Gas Industry.” Available at http://www.ingaa.org/cms/6435.aspx

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Definitions

Gathering and Boosting System

The term “gathering system” (including gathering pi peline system, gas gathering system and oil gathering system) is commonly used in the p etroleum and natural gas industry, including by the American Gas Association, the EIA, and indiv idual mid-stream companies, though the exact definition of this term is not always consist ent between groups. The compressors used to “boost” the pressure of the petroleum or natural ga s are generally referred to in the industry as compressor stations or boosting stations. Since the re is some ambiguity in the definition of these sources by different groups, the EPA determined tha t a definition of “gathering and boosting system” would be the best way to clarify what is in cluded in the Onshore Petroleum and Natural Gas Gathering and Boosting segment.

Two main sources were used to develop the definitio n of “gathering and boosting system.” The first is the definition of “gathering system” provided by Schlumberger in their Oilfield Glossary 16 :

The [pipeline] network and process facilities that transport and control the flow of oil or gas from the wells to a main storage facility, processing plant or shipping point. A gathering system includes pumps, headers, separators, emulsion treaters, tanks, regulators, compressors, dehydrators, valves and associated equipment. There are two types of gather ing systems, radial and trunk line. The radial type brings all the (pipelin es) to a central header, while the trunk-line type uses several remote headers to collect fluid. The latter is mainly used in large fields. The gathering system i s also called the collecting system or gathering facility.

The second is the definition of “gathering line” in 49 CFR 192.3 and the description of how to determine if a gathering line is a “regulate d onshore gathering line” under 49 CFR 192.8. A “gathering line” is defined as “a pipeline that t ransports gas from a current production facility to a transmission line or main” (49 CFR 192.3). The regulations in 49 CFR 192.8 incorporate by
reference the American Petroleum Institute Recommen ded Practice 80, Guidelines for the Definition of Onshore Gas Gathering Lines (API RP 80), 17 which defines a “gathering line” as:

16 Schlumberger Limited. The Oilfield Glossary . Available at http://www.glossary.oilfield.slb.com/ . Last accessed September 30, 2014.

17 API Recommended Practice 80, “Guidelines for the D efinition of Onshore Gas Gathering Lines.” 1st edit ion, April 2000.9 ... any pipeline or part of a connected series of pip elines used to (1) transport gas from the furthermost downstream point in a prod uction operation to the furthermost downstream of the following endpoints...:

(A) the inlet of the furthermost downstream natural gas processing plant, other than a natural gas processing plant located on a tr ansmission line,

(B) the outlet of the furthermost downstream gather ing line gas treatment facility,

(C) the furthermost downstream point where gas prod uced in the same production field or separate production fields is c ommingled,

(D) the outlet of the furthermost downstream compre ssor station used to lower gathering line operating pressure to facilitate del iveries into the pipeline from production operations or to increase gathering line pressure for delivery to another pipeline...; or

(2) transport gas from a point other than in a prod uction operation exclusively to points in or adjacent to one or more production operations or gathering facility sites for use as fuel, gas lift, or gas in jection gas within those operations...”

To fully address gathering and boosting within subp art W, the EPA needed to consider individual compressor stations / boosting stations that perform compression and processing for the gathering line systems. API RP 80 notes that “g as treatment often occurs in conjunction with gas processing or compression and in such cases is considered to be part of those operations.” In some cases, however, gas treatment operations invol ve significant stand-alone facilities (e.g., a sulfur recovery or large dehydration facility).

Given this information, the EPA is proposing to def ine a “gathering and boosting system” as “a single network of pipelines, compressors and process equipment, including equipment to perform natural gas compression, dehydration, and a cid gas removal, that has one or more connection points to gas and oil production and a d ownstream endpoint, typically a gas processing plant, transmission pipeline, LDC pipeli ne, or other gathering and boosting system.”

Owner/Operator

Petroleum and natural gas gathering and boosting an d natural gas processing are operations often considered to be in the “midstream ” sector of the petroleum and natural gas industry. While some midstream operations are owned by companies that also have upstream and10

downstream operations, many of the gathering and bo osting systems are constructed, owned and operated by midstream specialists. In addition, the re are midstream contractors who operate gathering systems that are owned by another firm 18

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One of the issues identified by commenters with the EPA’s original proposal to include gathering and boosting operations in the 2010 rule was that the EPA did not adequately address the multiple ownership scenarios for gathering and boosting systems. Several ownership and operating scenarios for gathering pipeline systems were identified through preliminary research and review of publically available information for some gathering pipeline systems and midstream sector companies. Some examples are provi ded in the following list, which is intended for illustration, not as a comprehensive c haracterization of the midstream sector.

• The gathering and boosting system is owned by a ver tically integrated oil and gas company. The company owns the production wells, the gathering and boosting system, and the gas processing plant. The gathering and boosting system may be operated by a contractor; some equipment may be lea sed.

• The gathering and boosting system is owned by an oi l and gas exploration and production company. The company may own the product ion wells, but does not own downstream gas processing. The gathering system may be operated by a contractor and some equipment may be leased.

• The gathering and boosting system is owned and oper ated by a single company specializing in the oil and gas mid-stream sector, which may include gathering and boosting and gas processing.

• The gathering and boosting system is owned and oper ated in partnership by multiple entities. Such entities could include midstream com panies, limited partnerships, investors, and midstream subsidiaries of oil and ga s production companies. Shared or split management may be evident. Under a shared man agement arrangement, the gathering and boosting system may be managed by com mittee of stakeholder representatives. Operation of the gathering and boo sting system may be designated to one of the owners or contracted. Under a split mana gement arrangement, one of the owners may provide administrative management, one m ay provide operating management, and one may provide general management.

Under any of the scenarios above, all or portions o f the operation of the gathering system may be contracted. However, the contractor typicall y is not considered the party responsible for the gathering system. That responsibility lies with the owners. In addition, a gathering and boosting system owner or partial owner may have ful l or partial ownership of multiple gathering

18 See 2014 Midstream Directory published by Hart Energy, www.hartenergy.com . See also, Midstream Business, published by Hart Energy and MidstreamBusiness.com11

and boosting systems within a basin and/or full or partial ownership of gathering and boosting systems in other basins.

As part of the reporting process under the GHGRP, r eporters must select a designated representative (DR) who is responsible for certifyi ng, signing, and submitting all submissions to the EPA. While the DR may need to acquire necessary reporting information from a third party, the Part 98 certification provisions in 40 CFR 98.4 (e)(1) simply require the DR to make “appropriate inquiry” and certify to the best of hi s or her knowledge when reporting; ultimate responsibility rests and must necessarily rest on h im or her. The DR may provide in contracts, leases, or other agreements with third parties that true, accurate, and correct reporting information must be provided to the DR in a timely fashion. If the third party fails to provide timely, true, accurate, or correct information to t he DR, then the DR has recourse contractually, or otherwise, on the third party 19

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Another consideration when determining the definiti on of owner or operator is the responsibility for reporting emissions. For example , it may be necessary to consider scenarios such as who would have reporting responsibility if two companies own a 50 percent stake in a gathering and boosting system, (each individual com pany or the joint venture), and whether the reporting responsibility would change if one of the individual companies also owns another nearby gathering and boosting system.

The EPA has previously promulgated language in 40 C FR 98.4 to address emissions reporting responsibility for facilities with multip le owners/operators through a designated representative. Under this provision, gathering and boosting facilities with multiple owners would identify and authorize a designated represent ative who would be responsible (on behalf of the multiple owners) for identifying and reporting emissions for the gathering pipelines and all gathering and boosting equipment, regardless of whe ther the associated equipment is leased, rented, or owned and regardless of whether the gath ering and boosting facility is operated by a contractor, one of the owners, or an owner committe e.

Given all the ownership possibilities and the need to understand who is responsible for appointing the designated representative, it is imp ortant to include a clear definition of owner or operator for the Onshore Petroleum and Natural Gas Gathering and Boosting segment that is inclusive of the multiple possible ownership scenar ios. The definition proposed in this action is:

Gathering and boosting system owner or operator mea ns any person that holds a contract in which they agree to transport petrole um or natural gas from one or more onshore petroleum and natural gas productio n wells to a natural gas processing facility, another gathering and boosting system, a natural gas

19 75 FR 7447412 transmission pipeline, or a distribution pipeline, or any person responsible for custody of the gas transported.

In the Clean Air Act, “person” is defined as “an in dividual, corporation, partnership, association, State, municipality, political subdivi sion of a State, and any agency, department, or instrumentality of the United States and any office r, agent, or employee thereof” (42 U.S.C. 7602). Therefore, use of the term “person” i n this definition should include all possible ownership scenarios. In addition, the final clause of the definition that refers to the “person responsible for custody of the gas transported” is primarily intended to cover the larger vertically integrated companies that transfer petroleum or nat ural gas from the production wells to points further downstream within the same company (i.e., w ithout a contract).

Facility

In determining the best definition for a facility w ithin the Onshore Petroleum and Natural Gas Gathering and Boosting segment, there were a fe w important considerations. First, the EPA decided not to propose any changes to the facility definitions or segment descriptions for the
Onshore Petroleum and Natural Gas Production and On shore Natural Gas Processing segments to provide consistency for reporters in those segme nts. Different portions of gathering and boosting systems were considered part of the Onshor e Petroleum and Natural Gas Production and Onshore Natural Gas Processing segments in the original subpart W proposal (75 FR 18608, April 12, 2010), and many of the public commenters provided comments disagreeing with the inclusion of gathering and boosting operations in t hose segments, mostly because it created complex reporting situations 20 . Therefore, the EPA determined that the definition of gathering and boosting facility and the description of the On shore Petroleum and Natural Gas Gathering and Boosting segment should include natural gas and petroleum operations that exist between the
current Onshore Petroleum and Natural Gas Productio n and Onshore Gas Processing segments. This approach ensures that the current data gap in subpart W related to gathering and boosting systems may be addressed while minimizing confusion with other existing segments.

As a result, the EPA decided to define the Onshore Petroleum and Natural Gas Gathering and Boosting segment as the gathering pipelines and other equipment used to collect petroleum and/or natural gas from onshore production gas or o il wells and used to compress, dehydrate, sweeten, or transport the gas to a natural gas proc essing facility, a natural gas transmission pipeline, or a natural gas distribution pipeline. G athering and boosting equipment would include, but would not be limited to, gathering pipelines, s eparators, compressors, acid gas removal units, dehydrators, pneumatic devices/pumps, storage vesse ls, engines, boilers, heaters, and flares. The

20 U.S. Environmental Protection Agency. Mandatory Greenhouse Gas Reporting Rule Subpart W – Petroleum and Natural Gas: EPA's Response to Public Comments , November 2010. Docket Item No. EPA-HQ-OAR-2009-09 23- 3608.13

segment description also specifies that the Onshore Petroleum and Natural Gas Gathering and Boosting segment does not include equipment and pip elines that are reported under any other industry segment defined in subpart W. The intent w ith this definition is that if the upstream boundary of a gathering and boosting system is the Onshore Petroleum and Natural Gas Production segment, then the gathering and boosting system would include equipment that may functionally be close to onshore production operati ons but not located on a single well pad or be associated with multiple well pads. For example, if multiple wells are located in close proximity, the output may be routed to a single “production ba ttery” for efficiency of further processing 21

, and those batteries would be considered part of the gathering and boosting system.

Second, there are multiple options for defining a g athering and boosting facility, each imposing a different potential burden to reporters. The ideal definition of a gathering and boosting facility would balance addressing the data gap for the Onshore Petroleum and Natural Gas Gathering and Boosting segment within subpart W while minimizing the burden to potential
reporters.

The EPA decided to apply a 25,000 MT CO 2 e reporting threshold to facilities in the Onshore Petroleum and Natural Gas Gathering and Boo sting segment. All other subpart W industry segments have a reporting threshold of 25, 000 MT CO 2 e, and the EPA did not have any data for gathering and boosting systems to suggest that the reporting threshold should be higher or lower for a gathering and boosting facility than other subpart W industry segments.

The remainder of this section describes three poten tial approaches that the EPA considered when developing the proposed definition for a gathering and boosting facility. Table 2.2 includes a summary of the potential appro aches and the EPA’s analysis of their potential advantages and disadvantages. Note that, while all three of these options are mentioned in the preamble to the proposed amendments, Option 2 is the proposed option.

Option 1 – Site-Based Facility

In Option 1, the EPA considered applying the GHGRP definition of a facility as a single site to gathering and boosting systems (i.e., the d efinition of “facility” found in 40 CFR 98.6), which is “any physical property, plant, building, s tructure, source, or stationary equipment located on one or more contiguous or adjacent prope rties in actual physical contact or separated solely by a public roadway or other public right-of -way and under common ownership or common control, that emits or may emit any GHG. Ope rators of military installations may

21 See the Global Methane Initiative website for diag rams showing the location of these production/gas b atteries ( https://www.globalmethane.org/m2mtool/gas.html ). Note that these batteries may be used for single wells as well as for situations with multiple wells in close prox imity, but if a production battery is on or associa ted with a single well pad, then it is by definition part of the Onsh ore Petroleum and Natural Gas Production facility a nd segment.14

classify such installations as more than a single f acility based on distinct and independent functional groupings within contiguous military pro perties.”

The advantage of this approach is that it uses the definition for facility that is already used in the GHGRP. It would also provide granular, site-specific data for each compressor/boosting station. On the other hand, the EPA would likely still have to provide guidance related to the inclusion of gathering pipe lines within a facility, and it is likely that companies would have multiple facilities within eac h basin. In addition, this definition may not address the current data gap, because of the geogra phic dispersion of these operations. Although one possible way to address this issue would be to make this an “all in” segment (i.e. all facilities would be required to report regardless of their ann ual emissions), an “all in” approach has not been applied to any of the segments within subpart W to date.

Option 2 – Basin-Based Facility

In Option 2, the EPA considered defining the facili ty as all the gathering and boosting systems owned by a gathering and boosting owner or operator in a single hydrocarbon basin.
This definition would be similar to the current def inition of “facility with respect to onshore petroleum and natural gas production for purposes o f reporting under this subpart and for the corresponding subpart A requirements” for the Onsho re Petroleum and Natural Gas Production segment. Since this option would use a definition o f facility similar to the definition for the Onshore Petroleum and Natural Gas Production segmen t, it would likely not cause unnecessary confusion among reporters. This definition recogniz es the fact that gathering and boosting facilities are more dispersed than processing facil ities and are geographically similar to the Onshore Petroleum and Natural Gas Production segmen t in size and number of sources. This definition is also expected to require fewer report s for a given owner or operator than the definition in Option 1, because owners and operator s would be able to report all of their operators within a basin as one facility (instead o f many).15

Option 3 – Basin-Based Facility for Boosting Statio ns and Nationally-Based Facility for Gathering Pipelines

In Option 3, the EPA considered using a basin-based definition of facility as in Option 2 for the portion of the gathering and boosting syste m that is consolidated (i.e., the boosting or compressor station), and setting a separate facilit y definition for gathering pipelines. The gathering pipeline facility would be all gathering pipelines owned by a gathering and boosting owner or operator in the United States.

Under this option, the definition of a boosting sta tion facility would recognize the fact that gathering and boosting facilities are more dis persed than processing facilities and are geographically similar to the Onshore Petroleum and Natural Gas Production segment in size and number of sources, as in Option 2. In addition, the pipeline facility boundaries would be easy to understand, and the EPA would not need to define ho w much of the gathering pipeline should be included in the facility definition as would be nee ded in Option 1. However, dividing gathering and boosting systems into two different types of fa cilities may increase reporter burden, particularly for owners and operators with both typ es of facilities.16Table 2.2. Options for Facility Definition in the Onshore Petroleum and Natural Gas Gathering and Boosting SegmentFacilityDefinitionOptionApproach/ConsiderationsBurden to ReportersCoverage of Emissions1. SiteBasedFacilityDefinition of facility consistent withdefinition in 40 CFR 98.6, which is usedby subparts in the GHGRP that do nothave geographically dispersed sources.Would need to determine the facilityboundaries for gathering lines (i.e. whatlength of pipeline upstream ordownstream from the main site would beconsidered part of the facility).25,000 MT CO2e reporting threshold: Eachindividual site would have to be evaluated todetermine if it would exceed the reporting threshold.Reporting burden is expected to be relatively lowbecause it is expected that only the largest siteswould exceed the reporting threshold, but if anowner/operator has many sites, each would have tobe reported separately.No reporting threshold: There would be no burdenrelated to applicability because all facilities wouldbe required to report regardless of emissions.However, if a company owns a large number offacilities, total reporting burden would be relativelyhigh because a separate report would be required foreach facility. This option would likely placereporting burden on small entities as well.25,000 MT CO2e reporting threshold: Emissionscoverage expected to be limited, as only largestfacilities would exceed the reporting threshold.Note that emissions from facilities that exceedthe threshold based on combustion sources arealready reporting under subpart C.Option provides potential ability to collect moregeographically specific data, but limited overallcoverage may offset that advantage.No reporting threshold: Emissions coveragewould be comprehensive.2. BasinBasedFacilityDefinition of facility is all the gatheringand boosting systems owned by agathering and boosting owner or operatorin a single hydrocarbon basin. Basinbased facility consistent with OnshorePetroleum and Natural Gas Productionsegment. Recognizes the fact that thesesites are more dispersed than processingfacilities, and geographically similar tothe production sector in size and numberof sources.Fewer facilities than in Option 1, if the thresholdoption is used, so the burden to evaluate whether afacility exceeds the reporting threshold would belower than Option 1. Reporting burden would likelybe higher than Option 1, if the threshold option isused, because more emission sources would bereported. If no reporting threshold is used forOption 1, then Option 1 would likely have morefacilities and higher reporting burden than Option2.Higher than Option 1 if the threshold option isused; most facilities would be larger and includemore emission sources, increasing the number ofemission sources reported. Lower than Option 1if no threshold is used.Option provides potential ability to collectgeographically specific data.17FacilityDefinitionOptionApproach/ConsiderationsBurden to ReportersCoverage of Emissions3. BasinBasedFacility forBoostingStationsandNationallyBasedFacility forGatheringPipelinesTwo definitions of facility; Definition offacility consistent with definition inOption 2 for the boosting or compressorstations and national-level facility forgathering pipelines. Having two differentdefinitions of facility could be confusing.Each collection of boosting stations in a basin wouldhave to be evaluated to determine if it would exceedthe reporting threshold of 25,000 MT CO2e, andowners/operators would have to aggregate andevaluate all gathering pipelines at the national level,which would be slightly more burdensome thanOption 2. Overall reporting burden would be similarto or slightly less than Option 2, depending on thenumber of boosting station facilities that wouldexceed the reporting threshold without the gatheringpipelines and the number of national gatheringpipeline facilities that would have to report. Burdenfor an individual owner or operator would increasefrom Option 2, as separate reports would be requiredfor boosting station facilities and national gatheringpipeline facilities.May be similar to Option 2 but likely slightlylower. Separation of gathering pipelines fromcompressor stations would mean each facilityconsists of fewer emission sources, particularlyfor gathering pipelines, decreasing the number ofemission sources reported.Option provides potential ability to collectgeographically specific data for boostingstations. Gathering pipeline emissions would bereported at the national level rather than on ageographic basis.18

Options 1 and 3 would provide limited data on the p roposed Onshore Petroleum and Natural Gas Gathering and Boosting segment (with th e exception of the Option 1 case where no reporting threshold is used) as a whole due to decr eased coverage compared to other options and would likely be more burdensome overall to reporter s, because a larger number of “facility” reports would be required for each owner or operato r. Therefore, the EPA concluded that these options would not achieve the goals of having a tho rough data set and transparent, complete information for this sector while minimizing burden to reporters.

Option 2 was selected as the best option for the de finition of facility for the gathering and boosting segment because it provides the best balan ce of minimizing burden to reporters and coverage of emissions from sources in the segment. Therefore, the proposed rule includes the following definition:

Facility with respect to petroleum and natural gas gathering and boosting for purposes of reporting under this subpart and for th e corresponding subpart A requirements means all gathering pipelines and othe r equipment located along those pipelines that are under common ownership or common control by a gathering and boosting system owner or operator and that are located in a single hydrocarbon basin as defined in this section . Where a person owns or operates more than one gathering and boosting syste m in a basin (for example, separate gathering lines that are not connected), t hen all gathering and boosting equipment that the person owns or operates in the basin would be considered one facility. Any gathering and boosting equipment that is associated with a single gathering and boosting sys tem, including leased, rented, or contracted activities, is considered to be under common control of the owner or operator of the gathering and boosting system that contains the pipeline. The facility does not include equipment a nd pipelines that are part of any other industry segment defined in this subpart.

Emission Sources

Subpart W already contains monitoring and calculati on methods for emission sources that
would be included in the Onshore Petroleum and Natu ral Gas Gathering and Boosting segment, with the exception of gathering pipelines, in eithe r the Onshore Petroleum and Natural Gas Production segment or the Onshore Natural Gas Proce ssing segment. After reviewing the emission source types and the calculation methods a lready included in subpart W, the EPA determined that because most processing of the gas and oil extracted from wells will be processed downstream of the gathering and boosting facility, the equipment/activities in the Onshore Petroleum and Natural Gas Production segmen t will be designed to handle gas and oil19

of composition similar to the gas and oil in the On shore Petroleum and Natural Gas Gathering and Boosting segment, so the same methods are appli cable.

This section discusses emission sources for which t he EPA considered calculation
methods other than those in the Onshore Petroleum a nd Natural Gas Production segment, or
conducted additional research to confirm that the O nshore Petroleum and Natural Gas Production segment method was the best method.

Blowdown Vent Stacks

Emissions from blowdown vent stacks are addressed i n subpart W for several segments, but for the most part, the blowdown vent stacks in these segments are located at consolidated facility sites. Therefore, the EPA evaluated the ap plicability of the method for blowdowns of emissions from gathering pipelines.

Blowdown vent stacks are located at various points along a gathering pipeline at some distance in between the connection points for the v arious production fields and the compression boosting stations. A blowdown vent stack is one com ponent of an isolation-blowdown assembly
that would include isolation or “block” valves that would be closed to shut-off flow to a segment of pipeline and a blowdown valve that would be open ed to evacuate gas from the isolated segment of pipeline. All blowdown valve assemblies will have a vent stack, which is simply a pipe through which the blowdown gas is released to the atmosphere or is routed to a combustion device (flare) or other equipment to capture the ga s. The length and diameter of isolated pipeline section and the pressure of the gas in the pipeline will determine the volume of gas that will be emitted during a gathering line blowdown. If the pi peline blowdown is for scheduled maintenance and repair, pipeline operators generall y prepare by reducing the volume of gas in the pipeline segment prior to isolation and blowdow n, or by temporarily routing the gas flow around the isolated pipeline segment. Although the distance between blowdown vent stacks may be greater for gathering pipelines than for blowdow n vent stacks at more consolidated facility sites, the general isolation-blowdown configuration is similar to those other facilities, so the emissions calculation method in subpart W would be appropriate for the Onshore Petroleum and Natural Gas Gathering and Boosting segment.

Compressors and Equipment Leaks

Compressors are used in gathering and boosting syst ems to keep pipelines at a high enough pressure so natural gas will continue flowin g through the pipelines. The two primary types of compressors in use in gathering and boosti ng systems are reciprocating compressors and centrifugal compressors. Reciprocating compressors used in gathering and boosting systems typically have two to six cylinders, which can be c onfigured to operate in parallel or in series20

(“stages”). Most gathering and boosting compressors are configured in two or three stages. Compressors used in gathering and boosting may rang e in size from 1,000 horsepower (hp) to 4,500 hp. Gathering and boosting compressors may be located out in the open or housed in compressor stations. The compressors operate for lo ng periods of time; 8,400 hours of operating time per year is typical 22

.
Centrifugal compressors are best suited to handle l arge volumes of gas at high pressure and stable flow rates that require a moderate press ure boost. Some gathering and boosting systems, particularly the newer, large gathering sy stems handling shale gas production, use centrifugal compressors.

Compressor drivers in gathering and boosting system s include gas engines, electric motors, propane and diesel engines. Spark ignition natural gas engines are the most common, but if gas richness exceeds 1,200 Btu per cubic foot, p roduced gas is less suitable for use as a fuel

gas 23 . Gathering and boosting system design is driven by well head pressure, gas composition, production volumes, and well spacing. The configura tion and operating design of a gathering and boosting system may change over the lifetime of pro ducing field, and a balance must be struck between pipeline size and compression cost.

For compressors and equipment leaks, subpart W cont ains one method in the Onshore Petroleum and Natural Gas Production segment and a different method for the same emission source in the Onshore Natural Gas Processing segmen t. The EPA is proposing that gathering and boosting reporters use the same method as in the On shore Petroleum and Natural Gas Production segment, which relies on the reporter counting the number of compressors or components (e.g., population counts) and then applying emission facto rs per compressor or component for that population. Alternatively, for equipment leaks, the reporter may count the number of pieces of major equipment, assume the default component count s in Table W-1B, and then apply emission factors per component. This proposed population cou nt approach is appropriate for the Onshore Petroleum and Natural Gas Gathering and Boosting se gment because, as in the Onshore Petroleum and Natural Gas Production segment, the e quipment is often geographically dispersed and may be visited only intermittently. Under the p roposed approach, a reporter would need to establish an inventory of the components or equipme nt subject to the population counts, apply the emission factors, and then update the inventory each year to account for new or retired components or equipment.

22 For more information, see “Compressors are heart o f Natural Gas Production” by Norm Shade in Gas & Oil Magazine on-line publication, August 6, 2014, http://www.gasandoilmag.com/gas%20&%20oil/2013/07/0 2/compressors-are-heart-of-natural-gas-production and “Gathering and Processing Design Options for Un conventional Gas” by K.A. Lawlor and M. Conder in Hart Energy Midstream Business , Vol. 3, No. 4, April 2013.

23 Lawlor and Conder, op. cit

.21

Gathering Pipelines

The only other segment in subpart W that currently includes pipelines is the Natural Gas Distribution segment. Currently, subpart W requires that emission leaks from distribution mains be estimated using an emission factor approach. To assess whether an emission factor approach would be appropriate for gathering pipelines, the E PA compared the characteristics of three types of pipeline, including gathering pipelines, distrib ution mains (used in the Natural Gas Distribution segment), and natural gas transmission pipelines. The pipeline characteristics include typical material, pipe size, maximum operat ing pressure, and burial depth.

The results are summarized in Table 2.3.22

Table 2.3. Comparison of Types of Petroleum and Nat ural Gas Systems Pipelines

Characteristic Type of Pipeline

Gathering Pipelines 24 Distribution Mains 25 Transmission

Pipelines 26

Material Varies, but usually polyethylene for low pressure

pipelines; coated steel for high pressure pipelines Flexible plastic and corrugated steel are rapidly replacing rigid steel pipe High strength

steel

Size 2–36 inches (”) in diameter. The common size range of

gathering pipeline for conventional gas plays and o lder gathering systems is 2–12”. For unconventional gas developments, the gathering lines are generally muc h larger, ranging from 12–36”, and have much higher maximum allowable operating pressures than historic al

norms 27

. 2–24” diameter 20–42” diameter (transmission laterals 6–16”)

Maximum Operating Pressure During operation, pressure in a gathering system wi ll

fluctuate depending on whether the gas is moving to or from a compression point. The gathering system is m ost likely to approach the maximum allowable operating pressure when it is departing the downstream outlet of a compressor. After it leaves the compressor, pressur e decreases uniformly along the gathering system to t he next compression point or the gathering system endpoint 28 . Operating pressure can range from less than 100 pounds per square inch (psi) to more than 700 p si. Less than 150 psi. Regulators step the pressure down for distribution mains from city gates to the service lines. Distribution mains and service lines typically operate at less than 20 percent of design pressure; 60 psi is typical for distribution and 3 psi – 0.25 psi is typical for services. 200 – 1,500

psi; 700 psi is typical

Burial Depth Some low pressure, smaller diameter gathering lines are

not buried. Some are buried to very shallow depths of approximately 4– 6”. Large gathering pipelines are typically buried to depths of up to 36”. Each main must be installed with at least 24” of

cover 29

. Minimum

depth is 30” from top of pipe

24 Sources: Corken Inc., “What is a gas gathering sys tem” www.corken.com/gas_gathering ; Bullin, K.A. and Chipps, J., Bryan Research and Engineering, 2005, Optimization of natural gas gathering systems and g as plants

, presented at the 84th GPA Annual Convention, San An tonio, TX, March 13-16, 2005, www.bre.com/portals/0/technicalarticles/GPA05.Chipp s.Jason.pdf

. 25 Bruno, M. and Moe, J., Xcel Energy Accelerated Main Renewal Program , Natural Gas STAR Annual Implementation Workshop, April 11, 2012; and Natura l Gas Supply Association.
26 American Gas Association, www.aga.org/KC/AboutNaturalGas ; Natural Gas Supply Association, www.Naturalgas.org

. 27 Burdeaux, D. Briefing Paper: Onshore Gas Gathering, Advisory Committee Action – Information . March 24, 2011. Available at http://www.phmsa.dot.gov/pv_obj_cache/pv_obj_id_8D4 A289CD397250DA8D8ED1115A1CEA03E8A0000/filen ame/Tab%207b%20-%20Briefing%20-%20TPSSC%20Gas%20Gat hering%20Lines%20-%20Dewitt.pdf

. 28 Williams Company, www.williamsinthenortheast.com/projects/landowner-f aq

. 29 49 CFR 192.327.23

The 2014 U.S. GHG Inventory lists more than 1.24 mi llion miles of distribution mains. Emission factors for distribution mains vary depend ing upon the pipe material. In terms of pipeline composition, distribution mains constructe d from plastic or from protected steel are comparable to gathering pipelines, but the emission factors are significantly lower for
distribution mains. The emission factors for these two types of distribution pipelines are 0.35 standard cubic feet (scf)/hour/mile (protected stee l) and 1.13 scf/hour/mile (plastic) 30,31

.
The 2014 U.S. GHG Inventory lists 445,135 miles of gathering pipelines 32,33 . The emission factor for gathering pipeline leaks in the 2014 U.S. GHG Inventory varies slightly by National Energy Modeling System (NEMS) region, from 19.1 thousand cubic feet (Mcf)/mileyear (2.18 scf/hour/mile) to 22.6 Mcf/mile-year (2. 58 scf/hour/mile). For transmission pipelines, the 2014 U.S. GHG Inventory emission factor is 1.55 standard cubic feet per day (scfd) per mile or approximately 0.57 Mcf/mile-year (0.065 scf/hour /mile). These emission factors are derived from the 1996 GRI/EPA study. No other published emi ssion factors for pipeline leaks were identified for gathering pipelines.

After considering existing calculation methodologie s, the EPA determined that an emission factor approach would still be the most ap propriate for gathering pipelines. However, considering the variability in the gathering pipeli nes and gathering system configurations, the EPA determined that specific emission factors for g athering pipelines should be added to subpart

W.

Options for these emission factors include:

• Using CH 4 emission factors for gathering lines in the 2014 U .S. GHG Inventory, which range by NEMS region but average around 20 Mc f/mile-year (2.28 scf/hour/mile).

• Using CH 4 emission factors for distribution pipelines in the 2014 U.S. GHG Inventory made of protected steel (0.35 scf/hour/mi le) or plastic (1.13 scf/hour/mile). These can be adjusted to account for the generally higher pressure of gathering lines relative to distribution lines.

• Developing a new set of emission factors based on a function of pipeline material (e.g., protected steel, plastic composite), pipe di ameter, and throughput pressure to account for the variation in the different characte ristics of gathering pipelines.

30 U.S. Environmental Protection Agency. Inventory of U.S. Greenhouse Gas Emissions and Sink s: 1990-2012 . EPA 430-R-14-003. April 15, 2014.

31 Table W-7 of Subpart W of Part 98.

32 This is the sum of the mileage reported by NEMS Re gion in the 2014 U.S. GHG Inventory, Table A-125: 2 012 Data and Calculated CH 4 Potential Emissions (Mg) for the Natural Gas Produ ction Stage, by NEMS Region.

33 ICF (1996), Estimation of Activity Factors for the Natural Gas Exploration and Production Industry in the U.S.24 • Allowing reporters to use their own site-specific e mission factors, subject to EPA approval as another way to account for the variatio n in the different characteristics of gathering pipelines.

The EPA reviewed the documentation in the original 1996 GRI/EPA report for the gathering line emission factors in the 2014 U.S. GH G Inventory and found that the gathering line
emission factors are based on measured data obtaine d from distribution mains. Measured leak data for distribution mains from 10 participating d istribution companies were adapted to gathering lines (and to transmission pipelines, as well) to account for differences between typical distribution mains and typical gathering lines in t erms of pipe diameter, operating pressure, burial depth and oxidation of CH 4 in soil, and pipe material (mostly coated steel or plastic for gathering lines). From this review, the EPA conclud ed that the CH 4 emission factors for gathering lines that are already in the 2014 U.S. G HG Inventory are the best available, meaning that they are based on actual leak measurements tha t have been explicitly adapted to the unique characteristics of gathering pipelines.

The EPA determined that gathering and boosting syst em owners and operators should develop CO 2 emission estimates for gathering pipelines in addi tion to CH 4 . The next step was to determine whether to develop a specific CO 2 emission factor or a “whole gas” emission factor (total hydrocarbon emission factor, similar to the emission factors for equipment leaks in Table W-1A of subpart W) for gathering pipelines. Use of whole gas emission factors would require reporters to determine CH 4 and CO 2 emissions based on CH 4 and CO 2 content of the gas in the pipeline, which is slightly more burdensome than na tionwide (or Eastern U.S. and Western U.S.)
CH 4 and CO 2 emission factors. However, use of whole gas emissi on factors would also provide the advantage of more accurate emissions reporting because they would allow for differences in the type of production field as well as the amount of processing the company chooses to conduct near the production well instead of at the gas proc essing facility.

To develop these options for proposed emission fact ors for gathering pipelines, the EPA used data for the average CH 4 content of the gas in the Onshore Petroleum and Na tural Gas Production segment, available in the 2014 U.S. GHG Inventory (Annex 3, Table 131). The data for the average CH 4 content of natural gas in the Onshore Petroleum an d Natural Gas Production segment in the 2014 U.S. GHG Inventory are provided by NEMS region; these data are shown in Table 2.4. The data for the average CH 4 content of natural gas in the Onshore Petroleum an d Natural Gas Production segment in the 2014 U.S. GHG Inventory are provided by NEMS region;
these data are shown in Table 2.4.25

Table 2.4. Emission Factors for Leaks from Gatherin g Pipelines by NEMS Region

NEMS Region CH 4 Emission Factor

(scf CH 4 /hour/mile) a Production Sector CH 4 in Natural

Gas (General Sources) for 2012 b Whole Gas Emission Factor (scf /hour/mile) c

Northeast 2.39 85.2 % 2.81

Mid-Continent 2.32 82.6 % 2.81 Rocky Mountain 2.18 77.5 % 2.81

Southwest 2.26 80.5 % 2.81

West Coast 2.58 91.9 % 2.81

Gulf Coast 2.48 88.2 % 2.81

a 2014 U.S. GHG Inventory, Annex 3, Table A-125.

b 2014 U.S. GHG Inventory, Annex 3, Table A-131.

c Derived from 2014 U.S. GHG Inventory data shown in first two columns of this table.

Using these data, the EPA determined a “whole gas” or total hydrocarbon emission factor of 2.81 scf/hour/mile for gathering pipelines. This emission factor allows gathering pipeline owners/operators flexibility to account for variati on in CO 2 content at the points where natural gas enters the gathering pipeline system, as well a s at acid gas removal points. The burden to reporters to calculate CH 4 and CO 2 content will be minimal because they will already be conducting these calculations to estimate emissions from components such as valves and

connectors.26

3 NATURAL GAS TRANSMISSION LINES BETWEEN COMPRESSOR
STATIONS

Background

Natural gas transmission compressor stations are cu rrently covered in subpart W as part of the Natural Gas Transmission Compression segment , and the natural gas transmission pipelines between those compressor stations are not . The 2014 U.S. GHG Inventory estimated that the total transmission pipelines in 2012 were 303,126 miles and that there were 1,799 compression stations 34 . Emissions from blowdowns of transmission pipeline s between compressor stations represent a gap in the data col lected by the GHGRP.

The main source of emissions for natural gas transm ission pipelines is venting through a blowdown vent stack (other emissions sources are co nsidered to be part of the compressor stations and are, therefore, already covered under subpart W, as noted above). Transmission pipeline blowdowns occur when a segment of pipeline is isolated from the rest of the line and the natural gas inside is purged through a blowdown ven t stack. These blowdowns are needed to safely inspect and maintain the pipelines. Using th e information in the 2014 U.S. GHG Inventory, net emissions from pipeline venting are estimated to be 2.12 MMT CO 2 e per year in 2012, or 7.0 MT CO 2 e/mile-year (applying the global warming potential of CH 4 is 25). Using the
emissions information in the Compendium of Greenhouse Gas Emissions Methodologie s for the Oil and Natural Gas Industry published by API in August 2009 (hereafter referre d to as the “API Compendium”) and the pipeline mileage from the 2014 U.S. GHG Inventory, emissions from gas transmission pipeline venting and blowdowns are est imated to be 40.95 thousand standard cubic feet (Mscf) CH 4 /mile-year, or 0.7855 MT CH 4 /mile-year 35 , which is equivalent to 6.0 MMT
CO 2 e per year in 2012, or 19.6 MT CO 2 e/mile-year (applying the global warming potential of
CH 4 is 25).

Definition of Owner/Operator

Similar to gathering and boosting systems, transmis sion pipelines can have complex ownership scenarios. For example, master limited pa rtnerships (MLPs) are a unique structure of ownership which is common in midstream sector corpo rations and in transmission companies.

34 U.S. Environmental Protection Agency. Inventory of U.S. Greenhouse Gas Emissions and Sink s: 1990– 2012

. EPA 430-R-14-003. April 15, 2014. Annex 3, Table A- 129: 2012 Data and CH 4 Emissions (Mg) for the Natural Gas Transmission Stage.
35 American Petroleum Institute (API). Compendium of Greenhouse Gas Emissions Methodologie s for the Oil and Natural Gas Industry . Prepared by T.M. Shires, C.J. Loughran, S. Jones, E. Hopkins, URS Corporation, for API. August 2009. Table 5-26. Table B-21 of this documen t shows that the emission factor is based on a comb ination of data used in the 1996 GRI/EPA study and additional data from seven Canadian facilities.27

The EPA evaluated the subpart A definitions of “own er” and “operator” and determined that they could not be easily applied to natural ga s transmission pipelines. Therefore, the EPA concluded that a definition of owner or operator sp ecific to natural gas transmission pipelines was necessary. The PHMSA already includes a specifi c definition of “operator” that entities are to use for the purpose of submitting reports:

• For interstate pipelines, the operator is the holde r of the Certificate of Public Convenience and Necessity issued under 15 U.S.C. 71 7f by the Federal Energy Regulatory Commission (FERC). This is the certifica te issued by FERC that allows the pipeline company to engage in the transportatio n and/or sale for resale of natural gas in interstate commerce or to acquire and operat e facilities needed to accomplish this. They are issued by FERC after FERC has approv ed the construction of a pipeline, and they allow the holder to build and op erate the pipeline.

• For intrastate pipelines, the operator is the opera tor identified on the pipeline’s Statement of Operating Conditions that is prepared for compliance under section 311 of the Natural Gas Policy Act (NGPA). Section 311 o f the NGPA allows an interstate pipeline company to sell or transport gas on behalf of any intrastate pipeline or local distribution company without prior FERC approval.

This definition is straightforward and already unde rstood by the industry through PHMSA reporting and through the requirements of FER C. It also avoids the need to address each possible ownership scenario to identify the owner. Therefore, the EPA determined that this definition would be the most appropriate definition for natural gas transmission pipeline facilities in subpart W.

Definition of Facility

In defining the facility, the EPA considered severa l options, including:

• the segment of transmission pipeline between two co mpressor stations, or between a compressor station and a distribution system

• total mileage of natural gas transmission pipelines owned and operated by an entity within a state

• total mileage of natural gas transmission pipelines owned and operated by an entity within a basin

• total U.S. mileage of natural gas transmission pipe lines owned and operated by an entity28

For each option, the EPA considered the amount of b urden to the owner or operator compared to the amount of data that could be collec ted. Table 3.1 summarizes the analysis that was performed.

Table 3.1. Options for Definition of Natural Gas Tr ansmission Pipeline Facility

Facility Definition Option Approach/Considerations Burden to Reporters Coverage of Emissions Segment of transmission pipeline between two compressor stations, or between
a compressor station and a distribution system Owners/operators would

determine the number of miles of a transmission pipeline segment. Dividing the total miles of pipeline (303,126 miles) by the number of compressor stations estimated by the 2014 U.S. GHG Inventory (1,799 stations), the estimated average distance between compressor stations is 168 miles. Each pipeline segment would have to be evaluated to determine if it would exceed the reporting threshold of 25,000 MT CO 2 e, which could be burdensome. Reporting burden is expected to be relatively low because it is unlikely that any individual pipeline segment would exceed the reporting threshold, but if an owner/operator has several such pipeline segments, each would have to be reported separately. Extremely limited, as it is unlikely that many individual pipeline segments would exceed the reporting threshold of 25,000 MT CO 2 e.

Total mileage of natural gas transmission pipelines owned and operated by an entity within a state Owners/operators would

determine the number of miles of transmission pipeline in a

state. Data reported to EIA and PHMSA are by state. Fewer facilities would have to be evaluated and compared to the reporting threshold of 25,000 MT CO 2 e than segment-based facility. Reporting burden would be higher than segment-based facility because more facilities expected to exceed the threshold, and because the owner/operator would have to track data elements within each state separately. Higher coveragethan segmentbased option, as more facilities would be expected to report emissions.

Total mileage of natural gas transmission pipelines owned and operated by an entity within a basin Owners/operators would

determine the number of miles of transmission pipeline in a basin. Slightly higher than a state-based facility, as some states contain multiple basins. Additional burden may be incurred due to reporting data by basin rather than by state, which is already required by EIA and PHMSA. Likely slightlyless than a statebased facility, since facility.

Total U.S. mileage of natural gas transmission pipelines owned and operated by an entity Owners/operators would

determine the total number of miles of transmission pipeline in the United States. This option would require the least evaluation and comparison to the reporting threshold of 25,000 MT CO 2 e, as there would be a maximum of one facility per owner/operator. More facilities would likely exceed the reporting threshold than any other option, but reporting burden for each owner/operator would be minimized as much as possible by the requirement to file only one report. The highest of any other option considered.29

In considering these options, the EPA took into acc ount the fact that many major pipeline systems are essentially linear systems to move gas from one part of the U.S. to another. The EPA also took into account the fact that many entities own and operate pipeline segments that may not be directly interconnected, but are connected with pipelines owned and operated by other entities as part of the national network of natural gas tran smission pipelines.

After comparing the options, the EPA concluded that requiring reporters to file separate reports for each portion of the system in any one s egment, state, or basin would impose higher evaluation and reporting burden on owners and opera tors without providing the EPA with
additional useful emissions information and activit y data. Defining the facility on the national level limits the burden on reporters to correlate t he pipeline ownership transfer points with specific geographical segments. Instead, the report ers can track the required information for their various pipelines, regardless of location, and subm it data associated with all of them in one
report.

The reporting threshold for facilities in this segm ent would be 25,000 MT CO 2 e/year, the same as all other facilities in industry segments o f subpart W. This means that a facility required to report blowdown emissions under subpart W is est imated to need a minimum of between 1,273 and 1,640 miles of pipeline (based on the API Compendium and the 2014 U.S. GHG Inventory data, respectively).

Data Reported to the PHMSA

Data for incidents from transmission pipelines that exceed a defined threshold and are unintentional (with targeted exceptions) must be re ported to the Pipeline and Hazardous Materials Safety Administration (PHMSA), per 49 CFR part 191. Specifically, PHMSA collects data on transmission pipeline incidents 36 . As defined in 49 CFR 191.3, an incident includes any of the following events:

• An event that involves a release of gas from a pipe line and that results in one or more of the following consequences:

o A death, or personal injury necessitating in-patien t hospitalization;

o Estimated property damage of $50,000 or more;

o Unintentional estimated gas loss of 3 million cubic feet or more.

• An event that results in an emergency shutdown of a n LNG facility (unless the emergency shutdown system is activated for reasons other than an actual emergency).

• Any other event that is significant in the judgment of the operator.

36 See the link for “Incident/Accident Data from Gas Distribution, Gas Gathering, Gas Transmission, and Hazardous Liquids and LNG Operators Accident and Incident Dat a” at http://www.phmsa.dot.gov/pipeline/library/data-stat s

.30

For each incident, the owner or operator must compl ete and submit a report within 30 days of the incident, per 49 CFR 191.15. Reports typically include: (1) location/ facility/ operator information; (2) estimated volume of gas a nd/or liquid released; (3) cause of the incident/ release; (4) information on any injuries, fatalities, or property damage; and (5) details on any resulting shutdowns, explosions, evacuations 37

.
Natural gas transmission pipeline blowdowns for rep airs and maintenance are not required to be reported to PHMSA, unless the blowdo wn otherwise fits the definition of a transmission pipeline “incident” or a “safety-relat ed condition” under 49 CFR 191.

Data Reported to the Department of Energy (DOE)

Many of the data elements proposed to be reported u nder 40 CFR 98.236(aa)(11) are also reported to the DOE and two of its associated agenc ies, EIA and FERC.

Most of the data elements are reported to EIA throu gh Forms EIA-176 38 and EIA-191 39 by each company that meets the description of a req uired reporter, for each state in which that company is conducting one of the listed activities. The data from these forms are made available
on the EIA Web site 40 and in EIA publications such as Natural Gas Monthly 41 . The specific reporting elements are discussed below.

• The quantity of natural gas received at all custody transfer stations in the calendar year: The instructions for Form EIA-176 indicate th at reporters must provide “the name of the company, the adjacent State or Country from which the gas was received, and the volume of gas received at the State line or U.S. border” and “the volume of other receipts within the report State if the gas w as delivered to a point on your company’s system and not previously reported.”

• The quantity of natural gas withdrawn from in-syste m storage in the calendar year: The instructions for Form EIA-191 indicate that rep orters “must provide net withdrawals from storage reservoirs,” and the data are available in Table 8 of the Natural Gas Monthly

.

37 Instructions (rev 12-2012) for Form PHMSA F 7100.2 (rev 12-2012) Incident Report – Natural and Other Gas Transmission and Gathering Pipeline Systems. Decemb er 2012. Available at http://phmsa.dot.gov/pipeline/library/forms

. 38 EIA Form EIA-176: Annual Report of Natural and Sup plemental Gas Supply and Disposition. OMB No. 1905- 0175, Version 2012.01. Available at http://www.eia.gov/survey/#eia-176

. 39 EIA Form EIA-191: Monthly Underground Gas Storage Report. OMB No. 1905-0175, Version 2012.01. Available at: http://www.eia.gov/survey/#eia-191

. 40 EIA Natural Gas Annual Respondent Query System. La st release: April 2014. Available at http://www.eia.gov/cfapps/ngqs/ngqs.cfm?f_report=RP 1

. 41 U.S. Department of Energy, U.S. Energy Information Administration, Office of Oil, Gas, and Coal Suppl y Statistics. Natural Gas Monthly . Released monthly; most recent version available a t http://www.eia.gov/naturalgas/monthly/

.31 • The quantity of natural gas added to in-system stor age in the calendar year: The instructions for Form EIA-176 indicate that reporte rs must provide the “total volumes of natural and supplemental gas stored in company-o perated facilities,” and the instructions for Form EIA-191 indicate that reporte rs “must provide net injections into storage reservoirs.” The data are available in Table 8 of the Natural Gas Monthly

.

• The quantity of natural gas transferred to third pa rties such as LDCs or other transmission pipelines: The instructions for Form E IA-176 indicate that reporters must provide “the total volumes of... natural and sup plemental gas delivered to
others”

• The quantity of natural gas consumed by the transmi ssion pipeline facility for operational purposes: The instructions for Form EIA -176 indicate that reporters must provide “the volume of gas consumed as fuel in [the ] company’s operations” including space heating, “new pipeline fill, pipeli ne distribution or storage compressor use, and other (specify type) within the report State.” The data are available in Table 2 of the Natural Gas Monthly.

The last data element proposed to be reported under 40 CFR 98.236(aa)(11), the miles of transmission pipeline in the facility, is reported through FERC Form No. 2 42 and is available on the FERC and individual company Web sites.

42 FERC FORM No. 2: Annual Report of Major Natural Ga s Companies and Supplemental Form 3-Q: Quarterly Financial Report. OMB Nos. 1902-0028 and 1902-0205.32

4 WELL IDENTIFICATION NUMBERS

Owners and operators of all onshore and offshore pe troleum or natural gas production wells in the U.S. must apply for a permit from the relevant permitting authority, or the entity that issues permits for drilling of oil and gas wells 43 . Typically, a single drilling permit is issued to an onshore well, which spells out, or incorporates by reference, a range of requirements for the operator. These include requirements for well const ruction, geophysical well logs, and protection of sensitive areas, as well as requirements to noti fy the state or other relevant agency at various points in the development of the well. For example, there may be notification requirements before well tests, before and after hydraulic fract uring, after well completion and before and after a well is plugged and abandoned. In addition, a wel l identification number is issued for the proposed well at the time of the initial permit app lication, which must be granted prior to the start of drilling operations, so that each well can be uniquely identified.

In 1962, the API subcommittee on Well Data Retrieva l Systems was formed to make recommendations for a system that would allow regul ators to track drilling permits, collect royalties, and optimize field conservation. The sub committee’s first recommendations on the API Well Number system were published as Appendix A of API Bulletin D12 (Well Data Glossary) in 1966; this appendix was superseded in 1968 by API Bulletin D12A 44 . API transferred ownership of the well numbering specifi cation to the Professional Petroleum Data Management (PPDM) Association in 2010. PDDM issued an updated specification in May 2013
and then renamed the identifier as the “US Well Num ber” in June 2014 45 . The PDDM is working with state regulatory agencies to implement the 201 3 updates, but adoption is currently at the discretion of the agency. State agencies that elect not to use the US Well Number assign unique well identification numbers to the gas and oil well s in that state for tracking in their regulatory
databases.

43 For wells drilled on private land, state lands and state waters, the permitting authorities are the i ndividual state regulatory agencies, departments, boards, or commis sions tasked with regulating the oil and gas indust ry in that state. Each state has only one entity that issues o il and gas well drilling permits. For wells drilled onshore on federal land, the permitting authority is the Bureau of Lan d Management (BLM). For wells drilled offshore in f ederal water, the permitting authority is the Bureau of Ocean Ene rgy Management (BOEM).

44 American Petroleum Institute. The API Well Number and Standard State And County N umeric Codes Including Offshore Waters . API Bulletin D12A, January 1979. Available at http://wellidentification.org/dl/US_API_Bulliten_19 79.pdf.
45 The Professional Petroleum Data Management Associa tion. The US Well Number Standard: An Identifier for Petroleum Industry Wells in the USA . Version 2013 rev 1, published June 19, 2014. Avai lable at http://dl.ppdm.org/dl/1147

.33

The US Well Number Standard provides instruction for assigning each well a 12- digit unique identifier, with some wells having more than 12 digits if an optional extension is used. The assignment of each digit is explained below:

• State Code (digits 1 and 2): The state code represe nts a state (including off-shore state waters) or other location (e.g., Offshore Federal W aters). A list of state codes is provided in The US Well Number Standard

.

• County Code (digits 3 through 5): The county code r epresents an onshore county, parish (Louisiana), U.S. Geological Survey (USGS) q uadrangle (Alaska), or a pseudo-county for offshore state and federal waters . A list of county codes is provided in The US Well Number Standard

.

• Well Code (digits 6 through 10): The well code is a ssigned to each well as determined by a unique well origin and must be uniq ue within a county code. The well code must be numeric, but according to The US Well Number Standard , there is no sequence or order significance implied by the co de applied.

• Wellbore Code (also referred to as the directional sidetrack code in the API Well Number) (digits 11 and 12): The wellbore code may b e assigned to the original wellbore (typically “00”), directional sidetracks, or deepening. It must be unique within the well code for the well. Some regulating agencies do not assign the wellbore code. The wellbore code must be numeric, b ut according to The US Well Number Standard , there is no sequence or order significance implie d by the code applied.

• Extension (also referred to as the event sequence c ode in the API Well Number) (any digits beyond 12): The extension may be assigned ba sed on regulatory agency requirements and may include alphanumeric or specia l characters. The only requirement for the extension provided in The US Well Number Standard is that it may not be used to identify wellbores (the wellbore code must be used for that purpose). (This is a change from the previous API W ell Number standard.) The standard suggests that the extension may be used to describe events such as completions, plugbacks, and recompletions, and that it should not be used for administrative events such as regulatory filings an d permit numbers.

The US Well Number Standard requires the state code, county code, well code, a nd the wellbore code; the extension is optional and is not further defined by the standard. US Well Numbers are publically available, but the accessibi lity of the data varies from state to state. The
US Well Number Standard specifies that historical API Well Numbers should b e included in the
state’s master list of US Well Numbers without bein g revised unless there are concerns that the number is not or will not be unique. However, previ ous versions of the standard have not always included the wellbore code, so some historical API Well Numbers may be only 10 digits long. For these numbers, The US Well Number Standard specifies that a wellbore code should be34

added but leaves the ultimate decision of whether t o do so up to the regulatory agency with primary jurisdiction over the drilling of oil and g as wells (given that retroactive assignment of wellbore codes may take years to complete).

The US Well Number Standard provides a protocol for assigning unique and perma nent US Well Numbers to each well in the U.S., and nearl y all states follow this protocol. However, there is no national authority that requires or ass igns US Well Numbers. Therefore, as noted above, there are a few states that, historically, h ave not assigned US Well Numbers to wells. The reasons some states may have not adopted the US Wel l Number standard vary: (1) the level of oil and gas exploration and development activity in the state may be low; (2) conversely, the state may have a very large number of old wells and historical well records; (3) regulatory agency staff resources may be limited; or (4) the s tate has a previously established system for identifying wells and maintaining well records that already meets its need. Although some states do not use US Well Numbers, such states do assign a unique number to every well according to their own system, so all wells are uniquely identif ied. In addition, some operators in these states may request or otherwise acquire US Well Numbers (i n addition to the state-assigned identifiers) for ease of use in specialized mapping programs and other analytical software tools 46

.
Well identification numbers have long been used in the oil and gas exploration and production industry as the primary means of integra ting all forms of well data and linking the data to specific wells and boreholes (in the case o f wells with multiple sidetrack or lateral boreholes). For example, basic well information (su ch as location, depth, well status), geophysical well log data, reservoir and rock sampl e data, pressure test and production data are all linked to specific wells and boreholes via a un ique identification number. Unique well identification numbers are used in regulatory filin gs by operators, and in various transactions pertaining to working interest, production and roya lties, well ownership and operating agreements. Unique well identification numbers are more accurate for such purposes than well names, hence the practice of using well identificat ion numbers for data integration is long established and universally accepted in the oil and gas industry. For this reason, the US Well Number, or the predecessor API Well Number, is inte nded to be a straightforward way for operators to link emissions reporting to specific p roduction facilities.

46 For example, the Indiana Division of Oil and Gas ( DOG) assigned API well numbers to newly permitted w ells between 1967 and 1990. In 1994, the need for a uniq ue well identifier was recognized, but it was deter mined that the API well number would not be suitable because there were inconsistencies in the existing API well numb ers and the historical numbers could not be verified. Instead, wells in Indiana are issued a six-digit number know n as the Indiana Geological Survey (IGS) Petroleum Well Iden tification Number (IGS ID). The Petroleum Informati on Corporation (now IHS, Inc.) began issuing API well numbers to Indiana wells in 1994, but they hold the cross referenced list of assigned numbers proprietary, so this list of API well numbers is not used by the p ublic or the permitting authority. (See “API Well Numbers in Ind iana (Draft 1)” by Charles W. Zuppann, Indiana Geol ogical Survey, July 2011, http://igs.indiana.edu/pdms/help/API_Numbers_in_Ind iana.htm .)35

As part of this proposal, the EPA has included well identification reporting requirements to improve the EPA’s ability to verify reported dat a and enhance transparency. Adding well identification numbers to the required reporting fo r oil and gas wells covered by the Onshore Petroleum and Natural Gas Production segment will e nable the EPA and other stakeholders to directly match data for reported wells with other l ocal, state, and federal permitting and other reported information.