1 MEMORANDUM

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

FROM: Alexis McKittrick and Ma rk de Figueiredo, EPA/CCD

DATE: September 25, 2015

SUBJECT: Greenhouse Gas Reporting Rule: Techni cal Support for Final 2015 Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems

The U.S. Environmental Protection Agency (E PA) is finalizing revisions to 40 CFR part 98, subpart W (hereafter referred to as “subpa rt W”). This memora ndum provides background information on certain revisions relating to the following emission s ources or specific provisions: 1

1. Oil Well Completions and Workove rs with Hydraulic Fracturing

2. Onshore Petroleum and Natural Ga s Gathering and Boosting Segment

3. Onshore Natural Gas Transmission Pipeline Segment

4. Well Identification Numbers

1 OIL WELL COMPLETIONS AND WORKOVERS WITH HYDRAULIC FRACTURING

The EPA is amending subpart W to include provisions for the reporting of greenhouse gas (GHG) emissions from oil well completions a nd workovers with hydraulic fracturing in the Onshore Petroleum and Natural Gas Production segm ent. Consistent with the requirements for gas well completions and workovers with hydrau lic fracturing, the provisions include the reporting of activity data on 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 updating calculation methods accordingly under 40 CFR 98.233(g) to reflect applicability to both gas well and oil well completions and wor kovers with hydraulic fracturing.

Calculation Method

The EPA is requiring Calculation Method 1, pr eviously specified in subpart W for gas wells, for calculating inputs to Equations W-12A and W-12B for oil wells, which relies on direct

1 For background information related to other aspects of the final rule, please refer to documents contained in Docket ID No. EPA-HQ-OAR-2014-0831.2 measurement of gas flow rate during flowback. In subpart W, Calculation Method 2 uses the measured gas pressure differential across a well c hoke to estimate gas flow rate, but the EPA is not providing the use of Calcul ation Method 2 for oil wells. Calc ulation Method 2 is based on the choke flow equation in Perry’s Chemical Engineering Handbook

, 2 which is intended for use with compressible flows, particularly gases. In pr actice, this includes gase s, supercritical fluids, and multiphase flows containing mostly gases. Based on the information available, the EPA concluded that this methodology may not be appr opriate for estimating emissions from oil well completions because of the differences in ope rational conditions between oil and gas production. The EPA was unable to identify a methodology, other than direct measurement, appropriate for calculating gas flow rate during flowback for oil well completions or workovers with hydraulic fracturing. The EPA sought comment on alternativ e methodologies in the proposed rule and none were identified by commenters.

The goal of the flowback process for oil we ll completions and workovers with hydraulic fracturing is to flow back th e fracture fluids and reservoir gas at high volume and velocity necessary to lift excess proppant and fluids to the surface so that the reservoir fluids (oil and gas) can begin to flow. For oil wells, as the fracture fluids are deplet ed, the flowback contains an increasing volume of crude oil from the formatio n. The duration of the flowback period is largely determined by reservoir characteristics such as the number of zones, depth, reservoir pressure, and composition of the reservoir fluids. Operators are able to measure flowback gas when there is sufficient gas flow and a suffi cient reduction in sand returns to route the flow to a separator. The point at which a separator can function ma rks the beginning of the separation flowback stage.

Calculation Method 1 requires two parameters, FRM s (Equation W-12A) and FRM i (Equation W-12B), which are, re spectively, the ratio of averag e gas flowback to 30-day gas production rate and the ratio of initial gas flow back to 30-day gas production rate. For oil wells where the gas production rate is not metered, the EPA is adding a new Equation W-12C that allows reporters to use the aver age gas to oil ratio (GOR) during the first 30 days of production to estimate the average 30-day gas production flow rate following a completion or workover.

Minimum GOR Threshold for Reporting

The EPA recognizes that oil wells with low GOR values may not have sufficient gas to operate a separator. In some cases, the separato rs are operated by using pumps to move the fluid out of the vessels or by adding make-up gas to th e system to ensure the necessary gas pressure. The EPA evaluated whether a specific GOR value c ould be added to subpart W to clarify the oil

2 Perry’s Chemical Engineering Handbook . Seventh Edition. Ed. R.H. Perry and D.W. Green. Chapter 6: Fluid and Particle Dynamics, Fluid Dynamics: Compressible Flow, p. 6-22.3 wells for which owners and operators are expected to report emissions and solicited comments in the proposed rule on this issue.

Energy Information Administration (EIA) data show that the proportion of “oil only” wells drilled from 2007-2012 was less th an 20 percent of all new wells. 3 Even in wells that produce primarily liquids at surface temperature a nd pressure conditions, th ere is often a volatile gaseous component. This associated gas is usua lly considered wet due to the high content of natural gas liquids (volatile components) included with the gaseous methane (CH 4 ). The ratio of
CH 4 to volatile components increases as the GOR increases. One study that characterized the associated gas of conventional crudes stated th at for a crude oil with a GOR of 1,000 standard cubic feet (scf) per barrel, the associated gas may be comprised of 46 mole percent CH 4 . For a crude oil with a GOR of 5,000 scf per barrel, the associated gas may be comprised of up to 78 mole percent CH 4

. 4 As the GOR increases, the API gravity of the crude tends to increase.

The EPA agrees that includi ng a minimum GOR threshold w ill help minimize reporting burden while still capturing most of the emissions from this source. The primary consideration when determining the level for a threshold is vo latility; the threshold must be low enough that the oil produced is considered non-vo latile. Non-volatile “black oils” ( i.e. , oil likely to not have gases or light hydrocarbons associated with it) ar e generally defined as ha ving GOR values in the range of 200 to 900 standard cubic f eet per stock tank barrel (scf/STB). 5 Oil wells with a GOR less than 300 scf/STB are at th e lower end of this range, and completions and workovers with hydraulic fracturing of these wells will not likely have enough gas associated that can be separated and routed to a flow meter. Given th at the EPA is finalizing the proposed requirement that the oil well flow meter be located downstr eam of the separator, the separator must be operating for the owner or operator to be able to measure the flow rate and estimate emissions from completions and workovers of oil wells with hydraulic fracturing. Therefore, the final monitoring and reporting requireme nts do not apply to completions and workovers of oil wells with hydraulic fracturing that have a GOR of less than 300 scf/STB. 6

3 J. Lieskovsky and S. Gorgen. “Drilling often results in both oil and natural gas production.” Today in Energy , U.S. Energy Information Administration, October 29, 2013. http://www.eia.gov/todayinenergy/detail.cfm?id=13571

. Accessed June 9, 2015. In this an alysis, all hydrocarbon production in the liquid state at the wellhead was considered oil.

4 Laine, Pekka. “Gas Management Solutions in Oil Production: Compression In The Field.” In Pipeline & Gas Journal , September 2010, Vol. 237, No. 9.

5 M.P. Walsh. “Oil Reservoir Pr imary Drive Mechanisms.” In Petroleum Engineering Handbook, Volume V: Reservoir Engineering and Petrophysics , E.D. Holstein (Ed.), L.W. Lake (Ed. In Chief), pp. V-895-980. Society of Petroleum Engineers, 2007.

6 A stock tank barrel is the volume of treated oil as stored in a stock tank (a storage tank specifically for treated oil). A stock tank barrel is the same quantity as a barrel at atmospheric temperature and pressure ( i.e. , surface conditions rather than reservoir conditions).4 Estimation of Emissions base d on Published Literature

Data from published literature were reviewed to estimate emissions that may be reported to the Greenhouse Gas Reporting Program (GHGRP) from oil well completions or workovers with hydraulic fracturing be ginning in reporting year 2016. 7 One source estimated approximately 15,600 oil well completions with hydraulic fracturing in 2012. 8 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 meeti ng the threshold for re porting under subpart W on the effective date of the rule will be similar to the activity level in 2012. The number of gas and oil wells has increased over the last few years and is anticipated to continue to increase in the future because of the continued and expandi ng use of horizontal drilling combined with hydraulic fracturing. Therefore, this estimate may be an underre presentation and the actual number of oil well completions or workovers with hydraulic fracturi ng may in fact be larger than 15,600.

In published literature, estimates of average potential CH 4 emissions from oil well completions with hydraulic fracturing ( i.e. , emissions in the absence of controls) range from 7.7 tons of CH 4 per completion 9 to 32 tons of CH 4 per completion. 10 Multiplying these values by the activity levels described above ( i.e. , 15,600 completions and workovers , assuming all wells will be located at facili ties reporting to the GHGRP) gives a potential emissions range of 120,000
tons CH 4 per year to 499,000 tons CH 4 per year (109,000 to 453,000 metric tons (MT) CH 4 per year).

7 Subpart W did not previously cover emissions from oil well completions and workovers with hydraulic fracturing, except for associated flaring emissions that may have been reported under th e miscellaneous flare stacks category. The data available on oil well completions and workovers with hydraulic fracturing are summarized in the document, Oil and Natural Gas Sector: Standards for Crude Oil and Natural Gas; Background Technical Support Document for the Proposed New Source Performance Standards (40 CFR Part 60, subpart OOOOa ). August, 2015. See Docket ID No. EPA-HQ-OAR-2010-0505. Some stakeholders have opined that some subpart W reporters have reported gas well completions and workovers data from oil formation sub-basins to the EPA through the Electronic Greenhouse Gas Reporting Tool (e-GGRT). However, the EP A notes that subpart W did not previously specify an emissions calculation or estimation method for oil well completions and workovers with hydraulic fracturing. Therefore, the EPA did not assess these data as part of our technical analysis for this new emission source.

8 U.S. EPA. Oil and Natural Gas Sector: Standards for Crude Oil and Natural Gas Facilities; Background Technical Support Document for the Proposed New Source Performance Standards (40 CFR Part 60, subpart OOOOa ). August 2015. See Docket ID No. EPA-HQ-OAR-2010-0505. Oil wells were defined as those with a GOR greater than or equal to 300 scf per barrel but less than 100,000 scf per barrel

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

10 O’Sullivan, Francis and Sergey Paltsev, “Shale gas production: potential versus actual greenhouse gas emissions,” Environmental Research Letters , United Kingdom. November 26, 2012. Docket Item No. EPA-HQ-OAR-2014- 0831-0025.5 2 ONSHORE PETROLEUM AND NA TURAL GAS GATHERING AND BOOSTING SEGMENT

Overview of Gathering and Boosting Systems

A gathering and boosting system is a singl e network of pipelines, compressors and process equipment, including equipment to perform natural gas compression, dehydration, and acid gas removal, that has one or more conn ection points to gas and oil production and a downstream endpoint. Gathering pipelines are used to transport petroleum and natural gas from the downstream exit points of onshore production facilities ( e.g. , wells) to one of the downstream endpoints, typically a gas proces sing plant, transmission pipelin e, local distribution company (LDC) pipeline, or other gathering and boos ting system. Compressors located along the gathering and boosting system are used to contro l or “boost” the pressu re of the gas in the pipeline and keep the gas moving downstream. Acid gas removal units and dehydrators may be located on the gathering and boosting system to treat the collected na tural gas to remove contaminants and prevent corrosion.

Specifically, the emissions sources that ma y be present 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. , valves, connectors, pressure relief valves)

 Gathering pipelines (emissions from pipeline leaks)

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

Subpart W did not previously cover emissi ons from gathering and boosting systems. Some sources, such as boosting compressor stati ons, with combustion emissions that exceed the reporting threshold of 25,000 MT carbon dioxide equivalent (CO 2 e) report those emissions to the GHGRP under 40 CFR part 98, subpart C (Stationary Combustion) (hereafter referred to as6 “subpart C”). 11 Subpart W did cover emissions from sources such as compressors and dehydrators in other industry se gments already defined in subpart W, such as the Onshore Natural Gas Processing segment or Onshore Petroleum and Natural Gas Production (which includes sources located on a single well pad or associated with a single well pad).

As drilling of multiple horizontal wells from a single well pad has become a common industry practice, the complex in frastructure to produce, trans port, and process hydrocarbons is no longer a simple linear train. 12 This often makes the distincti on between a production facility end point and the beginning of a gathering and boosting system difficult to assess. The Onshore Petroleum and Natural Gas Gathering and Boosti ng segment is intended to include upstream components that are not already included in th e Onshore Petroleum and Natural Gas Production segment and may have fugitive emissions, including multiphase flow gathering pipelines as well as gas gathering pipelines.

Multiphase Gathering Pipelines

The inclusion of both “petroleum ” and “natural gas” in the segment name is intended to reflect the complex nature of ups tream operations where wells can produce oil, natural gas, or a mixture of both and to signify the inclusi on of GHG emissions from gathering and boosting systems moving high volatility liqui ds in this new segment. According to the EIA, more than 50 percent of new wells produced both oil and natural gas in 2011 and 2012. 13 When wells go into production, either single phase or multiphase flow gathering pipelines transport the fluid to separation and processing facilities.

It cannot be assumed that pipelines that ca rry “primarily liquids” will not have fugitive gas emissions. As noted in Section 1 of this document, even in wells that produce primarily liquids at surface temperature and pressure c onditions, there is often a volatile gaseous component. For example, in the Bakken shale an d similar tight oil reservoirs, the presence of associated gas is a necessary condition for high-volume production. 14 A recent study of Bakken crude oils measured the flammable gas content of oil as high as 12 percent. 15 A report prepared

11 In 2013, 439 facilities with one or more of the North American Industry Classificati on System (NAICS) codes for a petroleum or natural gas facility reported to the GHGRP under subpart C but not subpart W. The EPA expects that some of these facilities will be part of the Onshore Petr oleum and Natural Gas Gathering and Boosting segment.

12 Conder, Michael W. and Kevin A. Lawlor. “Produc tion Characteristics Of Liqu ids-Rich Resource Plays Challenge Facility Design,” American Oil & Gas Reporter , May 2014.
13 J. Lieskovsky and S. Gorgen. “Drilling often results in both oil and natural gas production.” Today in Energy

, U.S. Energy Information Administration, October 29, 2013. http://www.eia.gov/todayine nergy/detail.cfm?id=13571

. Accessed June 9, 2015.

14 U.S. Department of Energy Quadrennial Energy Review Task Force Secretariat an d Energy Policy and Systems Analysis Staff. “QER Public Stakeholder Meeting: Infrastructure Constraints in the Bakken,” Memorandum to Members of the Public, August 8, 2014.

15 Dangerous Goods Transport Consulting, Inc. A Survey of Bakken Crude Oil Characteristics Assembled for the U.S. Department of Transportation . Submitted by American Fuel & Petroc hemical Manufacturers, May 14, 2014.7 for the North Dakota Petroleum Council noted that volatile components of the oil could accumulate in atmospheric storage tanks. 16

The potential for leakage from a multiphase gathering pipeline can be determined by a number of factors, including vapor pressure, GOR, the flow regime, line pressure, and the volatility of the crude oil. The EPA considered several options to clarify the intent to exclude gathering pipelines containing e ssentially only oil. Some multipha se gathering pipelines carrying fluid through the gathering and boosting system will carry heavier crude with a very limited potential for fugitive emissions leaks. To distingu ish from more volatile oil, some measure of the gaseous component of the oil can be used. The following are options considered to estimate the volatility of the oil and the likelihood of fugitive emissions:

 Vapor pressure. Vapor pressure represents the liqui d’s tendency to evaporate into its gaseous phase with rising temperature. 17 Crude with higher volatility would produce high levels of gas during pipeline transportation.

 API gravity. Use API gravity as a proxy to identify those light crudes likely to contain enough gas to create potential fugitive emissions.

 GOR. The higher the GOR, the more likely that the pipeline will have the potential for fugitive emissions, because the gaseous content will be higher for higher GOR values.

Vapor pressure is used to determine the volat ility of crude oil. Typically, the Reid vapor pressure (RVP) test is used to measure vapor pr essure of petroleum. As outlined in ASTM D 323 – 99a, calculation of the RVP requires special ized equipment and c ontrolled conditions. 18 Conducting this test on a gathering and boosti ng system or, alterna tively, collecting the necessary samples and sending them to a laboratory for testing would likel y result in the highest burden to reporters of the three options considered.

API gravity has the unit of de gree, where a low value in degrees is heavy and high value is light. This makes API gravity the inverse of density, usually measured by specific gravity. Lighter crudes may contain more gaseous compon ents that can create emissions. However, API gravity is not a direct measure of volatility or gas content and may not yield a consistent threshold for the purpose of GHG reporting.

16 Auers, John R., Ryan M. Couture, and Dennis L. Sutton. The North Dakota Petroleum Council Study on Bakken Crude Properties , report prepared for the North Dakota Petroleum Council, August 4, 2014.

17 Pharris, T.C. and R.L. Kolpa. Overview of the Design, Construction, and Operation of Interstate Liquid Petroleum Pipelines , Argonne National Laboratory, ANL/EVS/TM/08-1, November 2007.

18 ASTM International. Standard Test Method for Vapor Pressure of Petroleum Products (Reid Method) . ASTM D 323 – 99a. Approved April 10, 1999; published June 1999.8 The GOR is the measure of gaseous component s of crude oil to the liquid components. The higher the GOR, the higher the volatility a nd thus the potential fo r emissions. Operators regularly calculate GOR in the fiel d as part of assessing the likely sales volume of gas and/or oil. Therefore, completing a GOR measurement is not anticipated to be an additional burden to reporters. For these reasons, GOR was determined to be the best mechanism for assessing the volatility of the gaseous phase in a multiphase gathering pipeline.

As with oil well completions , the selection of a GOR threshold should consider minimizing reporting burden while still capturing most of the emissions from this source. A primary consideration when setting a threshold is volatility; the threshold must be low enough that the oil produced is considered non-volatile. Non-volat ile “black oils” (i.e., oil likely to not have gases or light hydrocarbons associated with it) are generally defined as having GOR values in the range of 200 to 900 scf/STB. 19 Because the considerations for gathering pipelines are similar to those for oil well completions a nd workovers with hydraulic fracturing, the EPA evaluated applying the same GOR threshold of 300 scf/STB to multiphase gathering pipelines. Oil transported in gathering pipeline segments with a GOR less than 300 scf/STB are at the lower end of the range for “black oils,” and oil transported in these pipelines will not likely have significant amounts of associated gas. Therefore, the EPA selected a GOR of 300 scf/STB as the threshold between multiphase gathering pipelines and oil pipelines, and oil pipelines (those with a GOR less than 300 scf/STB) are not considered part of the Onshore Petroleum and Natural Gas Gathering and Boosting segment.

Estimates of Nationwide GHG Emission s for Gathering and Boosting Systems

Several sources of GHG emissions data for ga thering and boosting systems were used to estimate nationwide emissions. This section desc ribes those sources of data and the methods used to estimate emissions.

The first data source for estimating ga thering and boosting emissions is the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012 published in 2014 (hereafter referred to as the “2014 U.S. GHG Inventory”), 20 which includes CH 4 and carbon dioxide (CO 2 ) emission factors and estimates of GHG emissions for some of the emission sour ces in gathering and boosting systems. In particular, the U.S. GHG I nventory includes fugitive and vented emission estimates for reciprocating compressors in th e natural gas production segment and for gas gathering pipelines. In the U.S. GHG Inventory, gathering and boosting systems are included as part of the natural gas systems production segm ent. Vented and fugitive GHG emissions from

19 M.P. Walsh. “Oil Reservoir Pr imary Drive Mechanisms.” In Petroleum Engineering Handbook, Volume V: Reservoir Engineering and Petrophysics , E.D. Holstein (Ed.), L.W. Lake (Ed. In Chief), pp. V-895-980. Society of Petroleum Engineers, 2007.

20 U.S. Environmental Protection Agency. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012 . EPA 430-R-14-003. April 15, 2014. Docket Item No. EPA-HQ-OAR-2014-0831-0008.9 equipment sources that are common to both well pr oduction sites and gathering systems, such as dehydrators, storage vessels and se parators, and pneumatic devices, are not assigned in the U.S. GHG Inventory to further sub-segments.

Applying a global warming potential for CH 4 of 25, the estimated em issions 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 emissions from all emission sources in gathering and boos ting, due to the 2014 U.S. GHG Inventory methodology, which accounts for fossil fuel combus tion elsewhere and includes other gathering and boosting emissions sources in the overall production segment number.

To estimate the combustion emissions associ ated with gathering and boosting, the EPA reviewed an analysis conducte d by the Interstate Natural Gas Association of America (INGAA). INGAA used data from the 2007 U.S. GHG I nventory and estimated the “split” of GHG emissions from combustion versus fugitive and vented GHG emissions ( i.e. , process emissions) for natural gas systems. 21 The INGAA analysis compared total combustion emissions and process emissions for natural gas production, natural gas processing and transportation and storage. The INGAA analysis found that of the 83.0 MMT CO 2 e emissions reported for natural gas production in the 2007 U.S. GHG Inventory, 47.8 MMT CO 2 e were combustion and flaring emissions (58 percent) and 35.2 MMT CO 2 e (42 percent) were “release of methane” (fugitive emissions and venting). 22,23

Assuming that the ratio of process emissions and combustion emissions is consistent with the INGAA analysis between years and industr y segments, then process emissions are approximately 42 percent of the total emissi ons associated with gathering and boosting. Conservatively assuming that the approximate value of 10 MMT CO 2 e from the 2014 U.S. GHG Inventory is a low-bound estimate of total process emissions from the gathering and boosting segment, this brings the total emissions fr om both process and combustion emissions in gathering and boosting to approximately 24 MMT CO 2 e. This is a low-bound estimate because the amount does not include the additiona l process equipment mentioned above.

Another data source is ICF Internat ional’s report from March 2014, titled Economic Analysis of Methane Emission Re duction Opportunities in the U.S. Onshore Oil and Natural Gas

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

. 22 Ibid.

23 Using data gathered through the GHGRP for subpart W in RY2013, combustion emissions represented about 25 percent of the 2013 subpart W CO 2 e emissions totals for the Onshore Petroleum and Natural Gas Production segment and approximately 65 percent of the Onshore Natural Gas Processing segment emissions totals. The EPA anticipates that the Onshore Petroleum and Natural Gas Gath ering and Boosting segment is expected to fall between these two segments in terms of percentage of total emissions related to combustion, which is consistent with the 58 percent estimate calculated using the INGAA analysis.10 Industries

, 24 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 25 as a starting point and supplemented th e activity factors (equipment counts) and emissions factors data with data from several sources incl uding GHGRP from reporting year 2012 and recent direct measurement studies of gathering and boosting sources. 26

The ICF study includes the following equipmen t in its gathering and boosting analysis:

 Reciprocating compressors;

 Centrifugal compressors;

 Compressor exhaust;

 Gathering and boosting stations;

 Pneumatic devices;

 Pipeline leaks;

 Dehydrators;

 Kimray pumps; and

 Condensate tanks.

This study estimated emissions from ga thering and boosting to be 0.8 MMT of CH 4 or 20 MMT CO 2 e. These estimates include process em issions but do not include combustion emissions. Using the INGAA analysis 27 referenced above to assume that process emissions of
20 MMT CO 2 e are approximately 42 percent of the total emissions associated with gathering and boosting, this brings the total emissions from both process and combustion emissions in gathering and boosting to approximately 47 MMT CO 2 e.

A recent study published in Environmental Science and Technology estimated national emissions of methane from gathering and boosting to be 47 MMT CO 2 e. The study used measured emissions data from a sample of gather ing plants, a Monte Carlo approach to estimate

24 ICF International. Economic Analysis of Methane Emission Reduc tion Opportunities in the U.S. Onshore Oil and Natural Gas Industries. March 2014. Available at http://www.edf.org/sites/default/file s/methane_cost_curve_report.pdf . Docket Item No. EPA-HQ-OAR-2014-0831- 0028.
25 U.S. Environmental Protection Agency. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990– 2011

. EPA 430-R-13-001. April 12, 2013. Docket Item No. EPA-HQ-OAR-2014-0831-0026.
26 For example, Allen, David, et. al., Measurements of Methane Emissions at Natural Gas Production 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.

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

.11 emissions from gathering plants, and the GHG inventory estimate for pipeline emissions. 28 Using the INGAA analysis 29 referenced above to assume that process emissions of 47 MMT CO 2 e are approximately 42 percent of the total emissions associated with gathering and boosting, this brings the total emissions from both process a nd combustion emissions in gathering and boosting to approximately 111 MMT CO 2 e

Based on the approaches discussed above, the estimated total emissions from the gathering and boosting segment of the petroleu m and natural gas industry may range between
24 MMT CO 2 e and 111 MMT CO 2 e, including both process and combustion emissions. For comparison, Table 2.1 shows the total emissions from both process and combustion emissions reported by facilities in other petroleu m and natural gas industry segments.

Table 2.1. Petroleum and Natural Gas System s 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 Equipment < 1 LNG Storage < 1
Natural Gas Distribution 15

Definitions

Gathering and Boosting System

The term “gathering system” (including gather ing pipeline system, gas gathering system and oil gathering system) is commonly used in the petroleum and natural gas industry, including by the American Gas Association, the EIA, and individual mid-stream companies, though the exact definition of this term is not always c onsistent between groups. The compressors used to “boost” the pressure of the natural gas are gene rally referred to in the industry as compressor stations or boosting stations. Si nce there is some ambiguity in the definition of these sources by different groups, the EPA determined that a de finition of “gathering and boosting system” is the

28 Marchese et al., Methane Emissions from United States Natural Gas Gathering and Processing , Published in Environmental Science and Technology, 2015, 49, 10718-10727, available at http://pubs.acs.org/doi/pdf/10.1021/acs.est.5b02275

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

.12 best way to clarify what is included in the Onshore Petroleum and Natural Gas Gathering and Boosting segment.

Two main sources were used to develop the definition of “gathering and boosting system.” The first is the definition of “gathe ring system” provided by Schlumberger in their Oilfield Glossary: 30

The [pipeline] network and process faci lities 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 t ypes of gathering systems, radial and trunk line. The radial type brings all th e (pipelines) to a central header, while the trunk-line type uses several remote h eaders to collect flui d. The latter is mainly used in large fields. The gather ing system is also called the collecting system or gathering facility.

The second is the definition of “gathering li ne” in 49 CFR 192.3 and the description of how to determine if a gathering line is a “r egulated onshore gathering line” under 49 CFR 192.8. A “gathering line” is defined as “a pipeline that transports gas fr om 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 Recommended Practice 80, Guidelines for the Definition of Onshore Gas Gathering Lines (API RP 80), 31 which defines a “gathering line” as:

... any pipeline or part of a connected se ries of pipelines used to (1) transport gas from the furthermost downstream poi nt in a production operation to the furthermost downstream of the following endpoints...:

(A) the inlet of the furthermost downstr eam natural gas processing plant, other than a natural gas processing plan t located on a transmission line,

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

(C) the furthermost downstream point where gas produced in the same production field or separate produ ction fields is commingled,

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

31 API Recommended Practice 80, “Guidelines for the Definition of Onshore Gas Gathering Lines.” 1st edition, April 2000.13 (D) the outlet of the furthermost downstr eam compressor station used to lower gathering line operating pressure to facil itate deliveries into the pipeline from production operations or to increase gath ering line pressure for delivery to another pipeline...; or

(2) transport gas from a point other th an in a production operation exclusively to points in or adjacent to one or more production operations or gathering facility sites for use as fuel, gas lif t, or gas injection gas within those operations...”

To fully address gathering and boosting within subpart W, the EPA needed to consider individual compressor stations / boosting stations th at perform compression and processing for the gathering line systems. API RP 80 notes that “gas treatment of ten 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 i nvolve significant sta nd-alone facilities ( e.g. , a sulfur recovery or larg e dehydration facility).

Given this information, the EPA is defini ng a “gathering and boosting system” as “a single network of pipelines, compressors and process equipment, including equipment to perform natural gas compression, dehydration, and acid gas removal, that has one or more connection points to gas and oil production and a downstrea m endpoint, typically a gas processing plant, transmission pi peline, LDC pipeline, or other gathering and boosting system.”

Owner/Operator

Petroleum and natural gas gathering a nd boosting and natural gas processing are operations often considered to be in the “midst ream” sector of the petroleum and natural gas industry. While some midstream operations are ow ned by companies that also have upstream and downstream operations, many of the gathering an d boosting systems are constructed, owned and operated by midstream specialists. In addition, there are midstream contractors who operate gathering systems that ar e owned by another firm. 32

One of the issues identified by commenters on the EPA’s original proposal to include gathering and boosting operations in the 2010 ru le (75 FR 18608, April 12, 2010) was that the EPA did not adequately address the multiple ow nership scenarios for gathering and boosting systems. Several ownership and operating scen arios for gathering pipeline systems were identified through preliminary rese arch and review of publically available information for some gathering pipeline systems and midstream sector co mpanies. Some examples are provided in the

32 See 2014 Midstream Directory published by Hart Energy, www.hartenergy.com . See also, Midstream Business, published by Hart Energy and MidstreamBusiness.com14 following list, which is intended for illustration, not as a comprehensive characteriza tion of the midstream sector.

 The gathering and boosting system is owned by a vertically inte grated oil and gas company. The company owns the producti on 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 leased.

 The gathering and boosting system is ow ned by an oil and gas exploration and production company. The company may own th e production wells, but does not own downstream gas processing. The gathering sy stem may be operated by a contractor and some equipment may be leased.

 The gathering and boosting system is owned and operated 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 owne d and operated in partnership by multiple entities. Such entities could include mids tream companies, limited partnerships, investors, and midstream subs idiaries of oil and gas production companies. Shared or split management may be evident. Under a shared management arrangement, the gathering and boosting system may be managed by committee of stakeholder representatives. Operation of the gatheri ng and boosting system may be designated to one of the owners or contracted. Under a split management arrangement, one of the owners may provide administrative management, one may provide operating management, and one may provide general management.

Under any of the scenarios above, all or porti ons of the operation of the gathering system may be contracted. However, the contractor typically is not cons idered the party responsible for the gathering system. That res ponsibility lies with the owne rs. In addition, a gathering and boosting system owner or partial owner may have full or partial ownership of multiple gathering 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, reporters must select a designated representative (DR) who is re sponsible for certifying, signing, and submitting all submissions to the EPA. While the DR may need to acquire ne cessary reporting information from a third party, the Part 98 certification provi sions in 40 CFR 98.4(e)(1) simp ly require the DR to make “appropriate inquiry” and certify to the best of his or her knowledge when reporting; ultimate responsibility rests and must necessarily rest on him or her. The DR may provide in contracts, leases, or other agreements with third part ies that true, accurate, and correct reporting information must be provided to the DR in a tim ely fashion. If the third party fails to provide15 timely, true, accurate, or correct information to th e DR, then the DR has recourse contractually, or otherwise, on the third party. 33

Another consideration when determining th e definition of owner or operator is the responsibility for reporting emissions. For example, it may be necessary to consider scenarios such as who has reporting respons ibility if two companies own a 50 percent stake in a gathering and boosting system, (each individual company or the joint venture), and whether the reporting responsibility changes if one of the individual companies also owns another nearby gathering and boosting system.

The EPA has previously promulgated langua ge in 40 CFR 98.4 to address emissions reporting responsibility for facil ities with multiple owners/operators through a DR. Under this provision, gathering and boosting facilities with multiple owners will identify and authorize a DR who will be responsible (on behalf of the multiple owners) for identifying and reporting emissions for the gathering pipelines and all ga thering and boosting equipment, regardless of whether the associated equipment is leased, re nted, or owned and rega rdless of whether the gathering and boosting facility is operated by a contractor, one of the owners, or an owner committee.

Given all the ownership possibi lities and the need to unders tand who is responsible for appointing the DR, it is important to include a clear definition of owner or operator for the Onshore Petroleum and Natural Gas Gathering a nd Boosting segment that is inclusive of the multiple possible ownership scenarios. The final definition is:

Gathering and boosting syst em owner or operator means any person that holds a contract in which they agree to transport petroleum or natural gas from one or more onshore petroleum and natu ral gas production we lls to a natural gas processing facility, a nother gathering and boosting system, a natural gas transmission pipeline, or a distribution pipeline, or any person responsible for custody of the petroleum or natural gas transported.

In the Clean Air Act, “person” is defined as “an individual, co rporation, partnership, association, State, municipality, political subdivision of a State, and any agency, department, or instrumentality of the United States and any officer, agent, or employee thereof” (42 U.S.C. 7602). Therefore, use of the term “person” in 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 cove r the larger vertically

33 75 FR 7447416 integrated companies that transf er petroleum or natural gas from the production wells to points further downstream within the same company ( i.e. , without a contract).

Facility

In determining the best definition for a facility within the Onshore Petroleum and Natural Gas Gathering and Boosting segment, there were a few important considerations. First, the EPA decided not to make any changes to the facility definitions or segment descriptions for the Onshore Petroleum and Natural Gas Production a nd Onshore Natural Gas Processing segments to provide consistency for reporters in those segments. Different portions of gathering and boosting systems were considered part of the Onshore 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 those segments, mostly because it created complex reporting situations. 34 Therefore, the EPA determined that the definition of gathering and boosting facility and the desc ription of the Onshore Petroleum and Natural Gas Gathering and Boosting segment should include natural gas a nd petroleum operations th at exist between the Onshore Petroleum and Natural Gas Production 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 confus ion with other segments already defined in subpart W.

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 oil wells and used to compress, dehydrate, sweeten, or transport the petrol eum and/or natural gas to a na tural gas processing facility, a natural gas transmission pipeline , or a natural gas distribution pipeline. Gathering and boosting equipment includes, but is not limited to, gather ing pipelines, separators, compressors, acid gas removal units, dehydrators, pneumatic devices/pump s, storage vessels, engi nes, boilers, heaters, and flares. The segment description also specif ies that the Onshore Petroleum and Natural Gas Gathering and Boosting segment does not include equipment and pipelines that are reported under any other industry segment defined in subpart W. The intent with 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 includes equipment that may functionally be close to onshor e production operations but not lo cated on a single well pad or be associated with multiple well pads. For example, if multiple wells are located in close proximity,

34 U.S. Environmental Protection Agency. Mandatory Greenhouse Gas Reporting Rule Subpart W – Petroleum and Natural Gas: EPA’s Respon se to Public Comments , November 2010. Docket Item No. EPA-HQ-OAR-2009-0923- 3608.17 the output may be routed to a single “producti on battery” for efficiency of further processing, 35 and those batteries are considered part of the gathering and boosting system.

Second, there are multiple options for defini ng a gathering and boosting facility, each imposing a different potential burden to reporte rs. The ideal definition of a gathering and boosting facility balances 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 Boosting segment. All other subpart W industry segments have a re porting threshold of 25,000 MT CO 2 e, and the EPA did not have any data for gathering and boosting systems to sugge st that the reporting th reshold should be higher or lower for a gathering and boosting facility than other subpart W industry segments.

The remainder of this section describes three potential approaches that the EPA considered when developing the definition fo r a gathering and boosti ng facility. Table 2.2 includes a summary of the potential approaches and the EPA’s analysis of their potential advantages and disadvantages. Note that, while all three of thes e options are mentioned in the preamble to the proposed amendments, Option 2 is th e basis of the proposed and final definition.

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 definition of “facil ity” found in 40 CFR 98.6), which is “any physical property, plant, building, structure, 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 a nd under common ownership or common control, that emits or may emit any G HG. Operators of military installations may classify such installations as more than a si ngle facility based on di stinct and independent functional groupings within contiguous military properties.”

The advantage of this approach is that it uses the definition for faci lity that is already used in the GHGRP. It would also provide granular, site-specific data for each compressor/boosting station. On the other hand, th e EPA would likely still have to provide guidance related to the inclusion of gathering pipelines within a facility, and it is likely that companies would have multiple facilities within each basin. In addition, this definition may not

35 See the Global Methane Initiative website for diagrams showing the location of these production/gas batteries ( 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 proximity, but if a production battery is on or associated with a single well pad, then it is by definition part of the Onshore Petroleum and Natural Gas Production facility and segment.18 address the current data gap, because of the geographic dispersion of these operations. Although one possible way to address this issue woul d be to make this an “all in” segment ( i.e. all facilities would be required to report regardless of thei r annual emissions), an “all in” approach has not been applied to any of the segm ents within subpart W to date.

Option 2 – Basin-Based Facility

In Option 2, the EPA considered defining th e facility as all the gathering and boosting systems owned by a gathering and boosting owne r or operator in a si ngle hydrocarbon basin. This definition would be similar to the subpart W definition of “facility with respect to onshore petroleum and natural gas production for purposes of reporting under this subpart and for the corresponding subpart A requirements” for the Onshore Petroleum and Natural Gas Production segment. Since this option would use a definition of facility similar to the definition for the Onshore Petroleum and Natural Gas Production se gment, it would likely not cause unnecessary confusion among reporters. This definition reco gnizes the fact that gathering and boosting facilities are more dispersed th an processing facilities and ar e geographically similar to the Onshore Petroleum and Natural Gas Production se gment in size and number of sources. This definition is also expected to require fewer reports for a give n owner or operator than the definition in Option 1, because owners and operato rs would be able to report all of their operators within a basin as one facility (instead of many).

Option 3 – Basin-Based Facility for Boosting Stations 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 boos ting system that is consolidated ( i.e. , the boosting or compressor station), and setting a separate faci lity definition for gath ering pipelines. The gathering pipeline facility would be all gath ering pipelines owned by a gathering and boosting owner or operator in the United States.

Under this option, the definition of a boosting station facility woul d recognize the fact that gathering and boosting facili ties are more dispersed than processing facilities and are geographically similar to the On shore Petroleum and Natural Gas Production segment in size and number of sources, as in Option 2. In addition, the pipeline faci lity boundaries would be easy to understand, and the EPA would not need to define how much of the gather ing pipeline should be included in the facility definiti on as would be needed in Option 1. However, dividing gathering and boosting systems into two different types of facilities may incr ease reporter burden, particularly for owners and operators with both types of facilities.19Table 2.2. Options for Facility Definition in the OnshorePetroleum 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 reportingthreshold. Reporting burden is expected to berelatively low because it isexpected that only thelargest sites would exceedthe reporting threshold,but if an owner/operator has many sites, eachwould have to be 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 separatereport would be requiredfor each facility. This option would likely placereporting burden on small entities as well.25,000 MT CO2e reporting threshold:Emissions coverage expected to be limited, asonly largest facilities would exceed thereporting threshold. Note that emissions fromfacilities that exceed the threshold based oncombustion sources are already reportingunder subpart C.Option provides potential ability to collectmore geographically specific data, but limitedoverall coverage 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 wouldlikely be higher than Option 1, if the thresholdoption is used, because more emission sourceswould be reported. If no reporting threshold is usedfor Option 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 andinclude more emission sources, increasing thenumber of emission sources reported. Lowerthan Option 1 if no threshold is used.Option provides potential ability to collectgeographically specific data.20FacilityDefinitionOptionApproach/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 basinwould have to be evaluated to determine if it wouldexceed the reporting threshold of 25,000 MT CO2e,and owners/operators would have to aggregate andevaluate all gathering pipelines at the nationallevel, which would be slightly more burdensomethan Option 2. Overall reporting burden would besimilar to or slightly less than Option 2, dependingon the number of boosting station facilities thatwould exceed the reporting threshold without thegathering pipelines and the number of nationalgathering pipeline facilities that would have toreport. Burden for an individual owner or operatorwould increase from Option 2, as separate reportswould be required for boosting station facilities andnational gathering pipeline facilities.May be similar to Option 2 but likely slightlylower. Separation of gathering pipelines fromcompressor stations would mean each facilityconsists of fewer emission sources,particularly for gathering pipelines, decreasingthe number of emission sources reported.Option provides potential ability to collectgeographically specific data for boostingstations. Gathering pipeline emissions wouldbe reported at the national level rather than ona geographic basis.21 Options 1 and 3 would provide limited data on the Onshore Petroleum and Natural Gas Gathering and Boosting segment (with the exception of the Op tion 1 case where no reporting threshold is used) as a whole due to decreased coverage compared to other options and would likely be more burdensome overall to reporters, because a larger number of “facility” reports would be required for each owner or operator. Therefor e, the EPA concluded that these options would not achieve the goals of having a thorough da ta set and transparent, complete information for this sector while minimizing burden to reporters.

Option 2 was selected as the best option for th e definition of facility for the gathering and boosting segment because it provides the best balance of minimizing burden to reporters and coverage of emissions from sources in the se gment. Therefore, the final rule includes the following definition:

Facility with respect to petroleu m and natural gas gathering and boosting for purposes of reporting under this sub part and for the corresponding subpart A requirements means all gathering pipelines and other 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 th is section. Where a person owns or operates more than one gathering and boos ting system in a basin (for example, separate gathering lines that are not connected), then all gathering and boosting equipment that the person owns or operates in the basin would be considered one facility. Any gather ing and boosting equipment that is associated with a single gathering and boosting system, including leased, rented, or contracted activities, is co nsidered to be under common control of the owner or operator of the gathering and boosting sy stem that contains the pipeline. The facility does not include equipment and pipelines that are part of any other industry segment defined in this subpart.

If a gathering and boosting system spans multiple basins, the owner or operator reporter should submit one report per basin ( i.e. , per “facility with respect to petroleum and natural gas gathering and boosting for purposes of reporti ng under this subpart a nd for the corresponding subpart A requirements” as it is defined in subpart W at 40 CFR 98.238) if the portion of the gathering and boosting system in th at basin exceeds the 25,000 MT CO 2 e per year reporting threshold (as defined at 40 CF R 98.2). In other words, the reporter would determine the emissions from the portion of gathering and boosti ng system associated with each basin. If the total emissions in each ba sin exceed the 25,000 MT CO 2 e per year reporting threshold, then the reporter would submit two reports. If the total emissions in one basin exceed the 25,000 MT
CO 2 e threshold, but the emissions in the other basin are below th e threshold, then the reporter22 would submit one report for the ba sin that exceeds the threshol d. For reference, the EPA is including a map of the U.S. geologic basi ns in Docket ID N o. EPA-HQ-OAR-2014-0831. 36

Emission Sources

Subpart W already contains monitoring and cal culation methods for emission sources that are included in the Onshore Petroleum and Natu ral Gas Gathering and Boosting segment, with the exception of gathering pipeli nes, in either the Onshore Pe troleum and Natural Gas Production segment or the Onshore Natural Gas Processing segment. After reviewing the emission source types and the calculation methods already included in subpa rt W, the EPA determined that because most processing of the gas and oil extrac ted from wells will be processed downstream of the gathering and boosting facility, the equipm ent/activities in the Onshore Petroleum and Natural Gas Production segment will be designed to handle gas and oil of composition similar to the gas and oil in the Onshore Petroleum and Na tural Gas Gathering and Boosting segment, so the same methods are applicable.

This section discusses emission sources fo r which the EPA considered calculation methods other than those in the Onshore Petr oleum and Natural Gas Production segment, or conducted additional research to confirm that the Onshore Petroleum and Natural Gas Production segment method was the best method.

Blowdown Vent Stacks

Subpart W requires reporting of emissions from “blowdown vent stacks,” defined in subpart A of Part 98 as “natural gas and/or CO 2 released due to main tenance and/or blowdown operations including compressor blowdown and em ergency shut-down (ESD) system testing,” for several segments. For the most part, the blow down vent stacks in these segments are located at consolidated facility sites, and for the bl owdown vent stacks in the Onshore Petroleum and Natural Gas Gathering and Boosting segment that are similar to those other industry segments, the calculation methodologies in subpart W ar e appropriate. The EPA then evaluated the applicability of the same subpart W calculation methodolog ies for blowdown vent stacks on gathering pipelines in the Onshore Petroleum an d Natural Gas Gathering and Boosting segment. Both of these types of blowdown vent stac ks were included in the proposed rule.

Blowdown vent stacks are located at various points along a gathering pipeline at some distance in between the connection points for th e various production fiel ds and the compression boosting stations. A blowdown vent stack is one component of an isolation-blowdown assembly that includes isolation or “block” valves that w ould be closed to shut-off flow to a segment of

36 R.F. Meyer, L.G. Wallace, and F.J. Wagner, Jr., Editors. Contiguous United States AAPG-CSD Geologic Provinces Code Map. Revised edition: 1991

.23 pipeline and a blowdown valve that would be ope ned 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 th e atmosphere or is routed to a combustion device (flare) or othe r equipment to capture the gas. The leng th 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 pipeline blowdown is for scheduled maintenance and repair, pipeline operators gene rally prepare by reducing the volume of gas in the pipeline segment prior to isolation and bl owdown, or by temporarily routing the gas flow around the isolated pipeline segment. Although the distance between blowdown vent stacks may be greater for gathering pipeline s than for blowdown vent stacks at more consolidated facility sites, the general isolation-blow down configuration is similar to those other facilities, so the emissions calculation method in subpart W is a ppropriate for the Onshore Petroleum and Natural Gas Gathering and Boosting segment.

The EPA does recognize that blowdown vent st acks not located at c onsolidated facility sites are not always manned. As noted in the pr evious paragraph, pipeline owners and operators know when maintenance activities are going to occur, and they know the parameters needed to calculate emissions. However, emergency blow downs may occur without personnel on-site or nearby, making it difficult to determine emissions from a blowdown event. Therefore, for emergency blowdowns, reporters may use engineer ing estimates based on the most recently available information to determine the temper ature and pressure used in Equation W-14A.

Compressors and Equipment Leaks

Compressors are used in gathering and boos ting systems to maintain pipelines at a sufficient pressure so natural gas will continue flowing. The two types of compressors in use in gathering and boosting systems are reciprocat ing compressors and centrifugal compressors. Reciprocating compressors used in gathering and boosting systems typically have two to six cylinders, which can be configured to operate in parallel or in se ries (“stages”). Most gathering and boosting compressors are config ured in two or three stages. Compressors used in gathering and boosting may range in size from 1,000 horse power (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 long periods of time; 8,400 hour s of operating time per year is typical. 37

37 For more information, see “Compressors are heart of Natural Gas Production” by Norm Shade in Gas & Oil Magazine on-line publication, August 6, 2014, http://www.gasandoilmag.com/gas%20&%20oil/2013/07/02/ compressors-are-heart-of-natural-gas-production (Docket Item No. EPA-HQ-OAR-2014-0831-0041) and “Gathering and Processing Design Options for Unconventional Gas” by K.A. Lawlor and M. Conder in Hart Energy Midstream Business , Vol. 3, No. 4, April 2013.24 Centrifugal compressors are best suited to ha ndle large volumes of gas at high pressure and stable flow rates that re quire a moderate pressure boos t. Some gathering and boosting systems, particularly the newer, large gath ering systems handling shale gas production, use centrifugal compressors.

Compressor drivers in gathering and boosting systems include gas engines, electric motors, propane and diesel engines. Spark ign ition natural gas engines are the most common, but if gas richness exceeds 1,200 British thermal units (Btu) per cubic foot, produced gas is less suitable for use as a fuel gas. 38 Gathering and boosting system design is driven by well head pressure, gas composition, production volumes , and well spacing. The configuration and operating design of a gathering and boosting syst em may change over the lifetime of a producing field, and a balance must be struck be tween pipeline size and compression cost.

For compressors and equipment leaks, subpa rt W contains one method in the Onshore Petroleum and Natural Gas Production segment a nd a different method for the same emission source in the Onshore Natural Gas Processing segment. The EPA is requiring gathering and boosting reporters to use the same method as in the Onshore Petroleum and Natural Gas Production segment, which relies on the report er counting the number of compressors or components ( e.g. , population counts) and then applying emission factors 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 counts in Table W-1B, and then apply emission factors per component. The popul ation count approach is appropriate for the Onshore Petroleum and Natural Gas Gathering a nd Boosting segment because, as in the Onshore Petroleum and Natural Gas Production segment, th e equipment is often geographically dispersed and may be visited only intermittently. Under this approach, a reporter needs to establish an inventory of the components or equipment subj ect to the population c ounts, apply the emission factors, and then update the inventory each year to account for new or retired components or equipment.

Gathering Pipelines

Prior to the addition of the Onshore Petrol eum and Natural Gas Gathering and Boosting segment, the only other segment in subpart W th at included emissions fr om pipelines was the Natural Gas Distribution segment. For that industry segment, s ubpart W requires that emission leaks from distribution mains be estimated using an emission factor approach. To assess whether a similar emission factor approach would be appropriate for gathering pipelines, the EPA compared the characteristics of three types of pi peline, including gatherin g pipelines, distribution mains (used in the Natural Gas Distribution se gment), and natural gas transmission pipelines.

38 Lawlor and Conder, op. cit

.25 The pipeline characteristics incl ude typical material, pipe size , maximum operating pressure, and burial depth.

The results are summarized in Table 2.3.26 Table 2.3. Comparison of Types of Petroleum and Natural Gas Systems Pipeline

Characteristic Type of Pipeline

Gathering Pipelines 39 Distribution Mains 40 Transmission Pipelines 41 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 older gathering systems is 2–12”. For unconventional gas developments, the gathering lines are generally much larger, ranging from 12–36”, and have much higher maximum allowable operating pressures than historical norms. 42 2–24” diameter 20–42” diameter (transmission laterals 6–16”)

Maximum Operating Pressure During operation, pressure in a gathering system will fluctuate depending on whether the gas is moving to or from a compression point. The gathering system is most likely to approach the maximum allowable operating pressure when it is departing the downstream outlet of a comp ressor. After it leaves the compressor, pressure decr eases uniformly along the gathering system to the next compression point or the gathering system endpoint. 43 Operating pressure can range from less than 100 pounds per square inch (psi) to more than 700 psi. 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. 44 Minimum depth is 30” from top of pipe

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

, presented at the 84th GPA Annual Convention, San Antonio, TX, March 13-16, 2005, www.bre.com/portals/0 /technicalarticles/GPA05.Chipps.Jason.pdf, Docket Item No. EPA-HQ-OAR-2014-0831- 0020.
40 Bruno, M. and Moe, J., Xcel Energy Accelerated Main Renewal Program , Natural Gas STAR Annual Implementation Workshop, April 11, 2012; and Natural Ga s Supply Association. Docket Item No. EPA-HQ-OAR2014-0831-0045.

41 American Gas Association, www.aga.org/KC/AboutNaturalGas ; Natural Gas Supply Association, www.Naturalgas.org

. 42 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_8 D4A289CD397250DA8D8ED1115A1CEA03E8A0000/filen ame/Tab%207b%20-%20Briefing%20-%20TPSSC%20G as%20Gathering%20Lines%20-%20Dewitt.pdf

. 43 Williams Company, www.williamsinthenortheast.co m/projects/landowner-faq . Docket Item No. EPA-HQ-OAR2014-0831-0036.27 The 2014 U.S. GHG Inventory lists more than 1.24 million miles of distribution mains. Emission factors for distribution mains vary depending upon the pipe material. In terms of pipeline composition, distribution mains constructed from plastic or from protected steel are comparable to gathering pipelines, but the emission factors are significantly lower for distribution mains than the average factor for ga thering pipelines. The emission factors for these two types of distribution pipeli nes are 0.35 standard cubic feet per hour per mile (scf/hour/mile) (protected steel) and 1.1 3 scf/hour/mile (plastic). 45,46

The 2014 U.S. GHG Inventory lists 445,135 miles of gathering pipelines. 47,48 The emission factor for gathering pi peline leaks in the 2014 U.S. GHG Inventory varies slightly by National Energy Modeling System (NEMS) region, from 19.1 thousand cubic feet (Mcf)/mile/year (2.18 scf/hour/mile) to 22.6 Mcf/mile/year (2.58 scf/hour/mile). For transmission pipelines, the 2014 U.S. GHG Inventor y emission factor is 1.55 standard cubic feet per day per mile (scfd/mile) or approximately 0.57 Mcf/mile/year (0.065 scf/hour/mile). These emission factors are derived from the 1996 Gas Research Institute (GRI)/EPA foundational study (hereafter referred to as “the 1996 GRI/EPA study”). 49 No other published emission factors for pipeline leaks were identif ied for gathering pipelines.

After considering existing calculation methodologies, the EPA determined that an emission factor approach would st ill be the most appropriate for gathering pipelines. However, considering the variability in the gathering pipe lines and gathering syst em configurations, the EPA determined that specific emission factor s for gathering pipelines should be added to subpart W.

Options for these emission factors include:

 Using CH 4 emission factors for gathering li nes in the 2014 U.S. GHG Inventory, which range by NEMS region but average around 20 Mcf/mile/year (2.28 scf/hour/mile).

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

44 49 CFR 192.327.
45 2014 U.S. GHG Inventory.
46 Table W-7 of Subpart W of Part 98.

47 This is the sum of the mileage reported by NEMS Region in the 2014 U.S. GHG Inventory, Table A-125: 2012 Data and Calculated CH 4 Potential Emissions (Mg) for the Natural Gas Production Stage, by NEMS Region.
48 ICF (1996), Estimation of Activity Factors for the Natural Gas Exploration and Production Industry in the U.S.
49 M. Harrison, T. Shires, J. Wessels, and R. Cowgill, eds. Methane Emissions from the Natural Gas Industry

. Prepared by Radian International LLC for National Risk Management Research Laboratory, Air Pollution Prevention and Control Division, Research Triangle Park, NC. EPA-600/R-96-080a.28  Developing a new set of emission factors ba sed on a function of pipeline material ( e.g. , protected steel, plastic composite), pi pe diameter, and throughput pressure to account for the variation in the different characteristics of gathering pipelines.

 Allowing reporters to use th eir own site-specific emissi on factors, subject to EPA approval, as another way to account for the va riation in the different characteristics of gathering pipelines.

 Using the information from the original 1996 GRI/EPA study to develop emission factors by pipeline material on a nationwide basis.

The proposed emission factor for gatheri ng and boosting pipelines was based on an average emission factor for ga thering and boosting pipelines fr om the 2014 U.S. GHG Inventory (the first option in the list above). Although the emission factors for gathering and boosting pipelines in the 2014 U.S. GHG Inventory were initially base d on the 1996 GRI/EPA emission factors for gathering pipeline material type, differe nt activity factors have been applied to derive average gathering pipeline emission factors for six different U.S. onshor e production regions. In response to comments received on the proposed emission factors, which recommended using characteristics of currently opera ting gathering pipelines rather than distribution pipelines or older data on gathering pipelines, the EPA re-e valuated the development of the emission factors for gathering pipelines.

The EPA reviewed the documentation in th e 1996 GRI/EPA study for the gathering line emission factors in the 2014 U.S. GHG Invent ory and found that the gathering line emission factors are based on measured data obtained from distribution mains. Measured leak data for distribution mains from 10 participating distribu tion 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 terms of pi pe diameter, operating pressure, burial depth and oxidation of CH 4 in soil, and pipe material (mostly coated steel or plastic for gathering lines).

The 1996 GRI/EPA study presents emission f actors for gathering pipelines based on pipeline material. 50 As shown in Table 2.4, the 1996 GRI/EPA study emission factors are presented in units of st andard cubic feet of CH 4 per leak per year (scf CH 4 /leak/yr) by pipe material, except for the cast iron pipe emission factor, which is presented in units of scf
CH 4 /mile/year. The activity factor s presented in 1996 GRI/EPA st udy are “number of leaks per year” and the “miles of gathering pipeline” for each pipe material type. If the average leaks per year are known and miles of gathering pipeline are known for each pipe material type, emission factors in units of scf/mile can be derived from the 1996 GRI/EPA study for each category of

50 M. Harrison, H.J. Williamson, and L.M. Campbell. Methane Emissions from the Na tural Gas Industry, Volume 3: General Methodology . Prepared by Radian International LLC for National Risk Management Research Laboratory,Air Pollution Prevention and Control Division, Research Triangle Park, NC. EPA-600/R-96-080c. Pages A-17 – A21.29 pipe material. These emission factors are derived in Table 2.4; Column D shows CH 4 emission factors in units of scf/mile/year, Column E s hows emission factors in units of scfd/mile and Column F shows emission factor s in units of scf/hour/mile.

Table 2.4. Methane Emission Factors for Gathering Pipelines (1996 GRI/EPA Study)

Column A Column B Column C Column D Column E Column F

Pipe Material Average Emission

Factor, scf/leak/yr Activity Factor: Average Leaks per Year Activity Factor: Miles of Gathering

Pipeline Derived Emission

Factor (scf/mile/year) Derived Emission

Factor (scfd/mile) Derived Emission

Factor (scf/hour/mile)

Protected Steel 17,102 53,657 268,802 3,414 9.35 0.39

Unprotect ed Steel 43,705 114,6555 41,400 121,039 331.61 13.82

Plastic 84,237 6,467 29,862 18,243 49.98 2.08

Cast Iron 201,418 (scf/mile/year) 856 201,418 551.83 22.99

The U.S. GHG Inventory provides potential CH 4 emission factors for gathering pipelines in units of scfd/mile by NEMS region. These are derived emission factors; the underlying average emission factors in units of scf/leak /yr are from the 1996 GRI/EPA study, but different assumptions are made about gathering pipeline activity factors for each NEMS region to derive an emission factor in units of scfd/mile fo r each region. These activity factor assumptions include average leaks per year by pipeline material type and the miles of gathering pipeline in each NEMS region by material type.

To develop a single emission factor per mile of gathering pipeline for subpart W, the miles of gathering pipeline by material type is needed. For example, the original 1996 GRI/EPA study found that 79 percent of ga thering pipelines were protected steel, 12 percent were unprotected steel, 9 percent were plastic, and 0.3 percent of gath ering pipelines were iron. These percentages could be applied to the 1996 GRI/EPA study emission f actors, resulting in a derived factor of 2.23 scf/hour/mile, regardle ss of pipeline type. However, as noted earlier in this section, there is significant variability in gathering pipelin es and gathering system configurations, and the configuration and operating design of a gather ing and boosting system may change over the lifetime of a producing field, so th ese percentages are not expected to have remained the same over the last 20 years. Therefore, rather than calculate a single emissi on factor for gathering pipelines based on a distribution of gathering pi peline materials, the EPA determined that the most appropriate approach is to include gathering pipeline emi ssion factors for four pipeline material types – protected steel, unprotected st eel, plastic, and cast iron – in subpart W.30 The EPA also determined that gathering and boosting system owners and operators should develop CO 2 emission estimates for gathering pipelines in addition to CH 4 , as the CH 4 content of materials transported in gathering pipelines may vary from facility to facility. The next step was to determine wh ether to develop a specific CO 2 emission factor or a “whole gas” emission factor (total hydrocar bon emission factor, similar to th e emission factors for equipment leaks in Table W-1A of subpart W) for gatheri ng 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 nationwide (or Eastern U.S. and Western U.S.) CH 4 and CO 2 emission factors. However, use of whole gas emission factors would also provide the advantage of more accurate em issions 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 in stead of at the gas processing facility.

Table 2.5 summarizes the CH 4 and whole gas emission factors for gathering pipelines by pipeline material type. The CH 4 emission factors were converted to whole gas emission factors using the average CH 4 content of natural gas in the U. S. production sector of 83.3 percent. 51 These whole gas emission factors are incl uded in Table W-1A of the final rule.

Table 2.5. Emission Factors for Gas Gatherin g Pipelines by Pipeline Material Type

Pipeline Material Derived CH 4 Emission Factor (scf/hour/mile) Derived Whole Gas Emission Factor (scf/hour/mile)
Protected Steel 0.39 0.47 Unprotected Steel 13.82 16.59
Plastic 2.08 2.50
Cast Iron 22.99 27.60

These emission factors allow gathering pipeli ne owners/operators flexibility to account for variation in CO 2 content at the points where natural gas enters the gathering pipeline system, as well as at acid gas rem oval points. The burden to reporters to calculate CH 4 and CO 2 content will be minimal because they will already be co nducting these calculations to estimate emissions from components such as valves and connectors.

51 2014 U.S. GHG Inventory, Annex 3, Table A-131, U.S. Production Sector CH 4 Content in Natural Gas by NEMS Region (General Sources) ; value from “Lower 48 States” column.31 3 ONSHORE NATURAL GAS TRANSMISSION PIPELINE SEGMENT

Background

Natural gas transmission compressor stations are 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. 52 Emissions from blowdowns of transmissi on pipelines between compressor stations represent a gap in the data collected by the GHGRP.

The main source of emissions for natural gas transmission pipelines is venting through a blowdown vent stack (other emi ssions sources are considered 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 vent stack. These blowdowns are needed to safely inspect and maintain the pipelines. Using the 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 glob al warming potential for CH 4 of 25). Using the emissions information in the Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Natural Gas Industry published by API in August 2009 (hereafter referred 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 estimated to be 40.95 thousand standard cubic feet (Mscf) CH 4 /mile/year, or 0.7855 MT CH 4 /mile/year, 53 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 for CH 4 of 25).

Definition of Owner/Operator

Similar to gathering and boosting systems, transmission pipelines can have complex ownership scenarios. For example a master limite d partnership (MLP) is a unique structure of ownership that is common in midstream sector corporations and in tr ansmission companies.

The EPA evaluated the subpart A definitions of “owner” and “operator” and determined that they could not be easily applied to natural gas transmissi on pipelines. Therefore, the EPA concluded that a definition of owner or operator specific to natural gas transmission pipelines

52 2014 U.S. GHG Inventory, Annex 3, Table A-129: 2012 Data and CH 4 Emissions (Mg) for the Natural Gas Transmission Stage.
53 American Petroleum Institute (API). Compendium of Greenhouse Gas Emissions Methodologies 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 document shows that the emission factor is based on a combination of data used in the 1996 GRI/EPA study and additional data from seven Canadian facilities.32 was necessary. The Pipeline and Hazardous Mate rials Safety Administ ration (PHMSA) already includes a specific description of “operator” that entities are to use for the purpose of submitting reports:

 For interstate pipelines, the operator is the holder of the Certificate of Public Convenience and Necessity issued under 15 U.S.C. 717f by the Federal Energy Regulatory Commission (FERC). This is the certificate i ssued by FERC that allows the pipeline company to engage in the transportation and/or sale for resale of natural gas in interstate commerce or to acquire and operate facilities needed to accomplish this. They are issued by FERC after FE RC has approved the construction of a pipeline, and they allow the holder to build and operate the pipeline.

 For intrastate pipelines, the operator is the operator identifie d on the pipeline’s Statement of Operating Conditions that is prepared for compliance under section 311 of the Natural Gas Policy Act (NGPA). Sec tion 311 of the NGPA allows an interstate pipeline company to sell or transport gas on behalf of any intrastate pipeline or LDC without prior FERC approval.

This description is straightforward and already understood by the industry through PHMSA reporting and through the requi rements of FERC. It also avoids the need to address each possible ownership scenario to identify the owner. However, upon review of the existing definition of “transmission pipeline” in subpa rt W, the EPA recognized that the PHMSA description of “operator” is not inclusive enough to cover all s ubpart W transmission pipelines.

Specifically, subpart W defines a “transmi ssion pipeline” as a “FERC rate-regulated interstate pipeline, a state rate-regulated Intras tate pipeline, or a pipe line that falls under the ‘Hinshaw Exemption’ as referenced in section 1( c) of the Natural Gas Act.” This definition was proposed in September 2011 “to clearly demarcate transmission pipelines from distribution and gathering pipelines” because transmission pipelin es are clearly designate d as such by FERC for interstate pipelines, individual States for intr astate pipelines, and the Hinshaw exemption under the Natural Gas Act for Hinshaw transmission pipelines.” 54 During the public comment period for the 2011 amendments, one commenter expressed concern that the prop osed definition would cover parts of gathering systems and submitted a dditional language for the definition that would describe what is not covered. In the response, th e EPA noted that “pipelines, such as gathering facilities that are exempt from ra te regulation under the Natural Ga s Act, do not fall in any one of [the] three categories [and] are not covered as transmission pipelines.” 55

54 76 FR 56010; September 9, 2011

55 U.S. EPA. Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments – 2011 Technical Revisions to the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule . December 2011. Docket Item No. EPA-HQ-OAR-2011-0512-0054.33 Therefore, intrastate pipelines were to be considered a transmission pipeline for the purposes of subpart W if they are “state rate-regulate d.” It is clear that some states regulate rates, but it appears that others do not. Thus, the PHMSA definition above would not cover all intrastate pipelines. Even within those states th at do regulate rates, not all intrastate pipelines would be covered because only some intrastate pi pelines are subject to section 311 of the NGPA. Specifically, they are subject to the NGPA only if they transport natura l gas on behalf of an interstate pipeline (or LDC served by an intrastate pipeline), or if they sell natural gas to an interstate pipeline. For those intr astate pipelines that are not s ubject to section 311 of the NGPA, the owner or operator would be the person identified as the owne r or operator on reports to the regulatory body of the state or municipality having jurisdiction to regulate rates and charges for the sale of natural gas to consumers within the State or municipality.

In addition, it appears that pi pelines that fall under the “Hin shaw Exemption” also would not be covered by the PHMSA definition because they are not required to obtain a Certificate of Public Convenience and Necessity, and they are not intrastate pipe lines (or subject to section 311 of the NGPA). However, in order to transport on behalf of interstate pipelines (just like an intrastate pipeline) they must apply for a “blanket certificate” under section 284.224 of CFR title 18. Thus, Hinshaw pipelines would be covered as transmission pi peline facilities under subpart W if the definition of owner or operator indicat es that the owner or operator is the person identified as the owner or operator on bl anket certificates issued under 18 CFR 284.224.

As a result of this research, the final de finition of “Onshore natural gas transmission pipeline owner or operator” has been a dded to 40 CFR 98.238 to read as follows:

Onshore natural gas transmission pipeline owner or operator means, for interstate pipelines, the person identified as the transmission pipeline owner or operator on the Certificate of Public Convenience a nd Necessity issued under 15 U.S.C. 717f, or, for intrastate pipe lines, the person identified as the owner or operator on the transmission pipeline’ s Statement of Operating Conditions under section 311 of the Natural Gas Polic y Act, or for pipelines that fall under the “Hinshaw Exemption” as refere nced in section 1(c) of the Natural Gas Act, 15 U.S.C. 717-717 (w)(1994), the person identified as the owner or operator on blanket certificates issued under 18 CFR 284.224. If an intrastate pipeline is not subject to section 311 of the NGPA, the onshore natural gas transmission pipeline owner or operator is the person identified as the owner or operator on reports to the state regu latory body regulati ng rates and charges for the sale of natura l gas to consumers.34 Definition of Facility

In defining the facility, the EPA c onsidered several options, including:

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

 total mileage of natural gas transmission pi pelines owned and operated by an entity within a state

 total mileage of natural gas transmission pi pelines owned and operated by an entity within a basin

 total U.S. mileage of natural gas transm ission pipelines owned and operated by an entity

For each option, the EPA considered the am ount of burden to the owner or operator compared to the amount of data that could be collected. Table 3.1 summari zes the analysis that was performed.35 Table 3.1. Options for Definition of Natu ral Gas Transmission 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.

In considering these options, the EPA took in to account the fact that many major pipeline systems are essentially linear systems to move gas from one part of the United States to another. The EPA also took into account the fact that many entities own and operate pipeline segments36 that may not be directly interconnected, but ar e connected with pipelines owned and operated by other entities as part of th e national network of natural gas transmission pipelines.

After comparing the options, the EPA concluded that requiring reporters to file separate reports for each portion of the system in any one segment, state, or basin would impose higher evaluation and reporting burden on owners a nd operators without providing the EPA with additional useful emissions information and acti vity data. Defining the facility on the national level limits the burden on reporters to correlate the pipeline ownership transfer points with specific geographical segments. Instead, the reporter s can track the required information for their various pipelines, regardless of location, and submit data associat ed with all of them in one report.

The reporting threshold for faciliti es in this segment is 25,000 MT CO 2 e/year, the same as all other facilities in industr y segments of subpart W. This m eans that a facility required to report blowdown emissions under subpart W is es timated to need a minimum of between 1,273 and 1,640 miles of pipeline (based on the AP I Compendium and the 2014 U.S. GHG Inventory data, respectively).

Data Reported to PHMSA

Data for incidents from transmission pipeli nes that exceed a defined threshold and are unintentional (with targ eted exceptions) must be reporte d to PHMSA, per 49 CFR part 191. Specifically, PHMSA collects data on transmission pipeline incidents. 56 As defined in 49 CFR 191.3, an incident includes a ny of the following events:

 An event that involves a release of gas from a pipeline and that results in one or more of the following consequences:

o A death, or personal injury necessi tating in-patient 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 an 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.

For each incident, the owner or operator must complete 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 and/or liquid releas ed; (3) cause of the

56 See the link for “Incident/Accident Data from Gas Distri bution, Gas Gathering, Gas Transmission, and Hazardous Liquids and LNG Operators Accident and Incident Data” at http://www.phmsa.dot.gov/pipeline/library/data-stats

.37 incident/ release; (4) information on any injuries , fatalities, or property damage; and (5) details on any resulting shutdowns, explosions, evacuations. 57

Natural gas transmission pipeline blowdow ns for repairs and maintenance are not required to be reported to PHMSA, unless the blowdown otherwise fits the definition of a transmission pipeline “incident” or a “safety-related condi tion” under 49 CFR 191.

Data Reported to the U.S. Department of Energy (DOE)

Many of the data elements required to be reported under 40 CFR 98.236 (aa)(11) are also reported to the DOE and two of its associated agencies, EIA and FERC.

Most of the data elements are reported to EIA through Forms EIA-176 58 and EIA-191 59 by each company that meets the description of a required reporter, for each state in which that company is conducting one of the li sted activities. The data from these forms are made available on the EIA Web site 60 and in EIA publications such as Natural Gas Monthly

. 61 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 Fo rm EIA-176 indicate that re porters 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 was delivered to a point on your company’s system and not previously reported.”

 The quantity of natural gas withdrawn from in-system storage in the calendar year: The instructions for Form EIA-191 indi cate that reporters “must provide net withdrawals from storage reservoirs,” and the data are available in Table 8 of the Natural Gas Monthly

.

 The quantity of natural gas added to in-s ystem storage in the calendar year: The instructions for Form EIA-176 indicate that reporters must provide the “total volumes of natural and supplemental gas stored in company-operated facilities,” and the

57 Instructions (rev 12-2012) for Form PHMSA F 7100.2 (rev 12-2012) Incident Report – Natural and Other Gas Transmission and Gathering Pipeline Sy stems. December 2012. Available at http://phmsa.dot.gov/pipeline/library/forms . Docket Item No. EPA-HQ-OAR-2014-0831-0044.
58 EIA Form EIA-176: Annual Report of Natural and Supplemental Gas Supply and Disposition. OMB No. 1905- 0175, Version 2012.01. Available at http://www.eia.gov/survey/#eia-176 . Docket Item No. EPA-HQ-OAR-2014- 0831-0048.
59 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 . Docket Item No. EPA-HQ-OAR-2014-0831-0047.

60 EIA Natural Gas Annual Respondent Query Syst em. Last release: April 2014. Available at http://www.eia.gov/cfapps/ ngqs/ngqs.cfm?f_report=RP1

. 61 U.S. Department of Energy, U.S. Energy Information Administration, Office of Oil, Gas, and Coal Supply Statistics. Natural Gas Monthly . Released monthly; most recent version available at http://www.eia.gov/naturalgas/monthly/

.38 instructions for Form EIA-191 indicate that reporters “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 parties such as LDCs or other transmission pipelines: The instructions for Form EIA-176 indicate that reporters must provide “the total volumes of... na tural and supplemental gas delivered to others.”

 The quantity of natural gas consumed by the transmission pipeline facility for operational purposes: The instructions for Fo rm EIA-176 indicate that reporters must provide “the volume of gas consumed as fuel in [the] company’s operations” including space heating, “new pipeline f ill, pipeline 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 required to be re ported under 40 CFR 98.236(aa)(11), the miles of transmission pipeline for each state in the facility, is reported through FERC Form No. 2 62 and is available on the FERC and indi vidual company Web sites.

Subpart W Reporting

At proposal, there were seven blowdown equipm ent and event type categories applicable to all blowdowns in 40 CFR 98.233(i)(2), includi ng blowdowns within the Onshore Natural Gas Transmission Pipeline segment. The EPA orig inally developed these categories based on compressor station blowdowns. During the public comment period, multiple commenters noted that the blowdown equipment and event type cate gories that were proposed were developed for compressor station blowdowns do not provide mean ingful information for pipeline blowdowns. The EPA agrees that the rule should incl ude blowdown categories specific to pipeline blowdowns in the Onshore Natural Gas Transmission Pipeline segment. Therefore, the final rule at 40 CFR 98.233(i)(2) specifies that the Onshor e Natural Gas Transmission Pipeline segment blowdowns must be grouped into one of the following ei ght categories:

 pipeline integrity work ( e.g. , the preparation work of modifying facilities, ongoing assessments, maintenance or mitigation),

 traditional operations or pipeline maintenance,

 equipment replacement or repair ( e.g. , valves),

 pipe abandonment,

62 FERC FORM No. 2: Annual Report of Major Natural Gas Companies and Supplemental Form 3-Q: Quarterly Financial Report. OMB Nos. 1902-0028 and 1902-0205. Docket Item No. EPA-HQ-OAR-2014-0831-0029.39  new construction or modification of pipe lines including commissioning and change of service,

 operational precaution during activities ( e.g. excavation near pipelines),

 emergency shutdowns including pipeline in cidents as defined by PHMSA, and

 all other pipeline segments with a physical volume greater than or equal to 50 cubic feet.40 4 WELL IDENTIFICATION NUMBERS

Owners and operators of all onshore and o ffshore petroleum or natural gas production wells in the United States must apply for a perm it from the relevant permitting authority, or the entity that issues permits for drilling of oil and gas wells. 63 Typically, a single drilling permit is issued to an onshore well, which sp ells out, or incorporates by refe rence, a range of requirements for the operator. These include requirements fo r well construction, geophysical well logs, and protection of sensitive areas, as well as requirement s to notify 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 af ter hydraulic fracturing, after well completion and before and after a well is plugged and abandoned. In addition, a well iden tification number is issued for the proposed well at the time of the in itial permit application, which must be granted prior to the start of drillin g operations, so that each well can be uniquely identified.

In 1962, the API subcommittee on Well Data Re trieval Systems was formed to make recommendations for a system that would allo w regulators to track drilling permits, collect royalties, and optimize field conservation. Th e subcommittee’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 s uperseded in 1968 by API Bulletin D12A. 64 API transferred ownership of the well numbering spec ification to the Professional Petroleum Data Management (PPDM) Association in 2010. PPDM issued an updated specification in May 2013 and then renamed the identifier as the “US Well Number” in June 2014. 65 The PDDM is working with state regulatory agencies to implement th e 2013 updates, but adoption is currently at the discretion of the agency. State agencies that el ect not to use the US Well Number assign unique well identification numbers to the gas and oil wells in that state for tracking in their regulatory databases.

63 For wells drilled on private land, state lands and state waters, the permitting authorities are the individual state regulatory agencies, departments, boards, or commissions tasked with regulating the oil and gas industry in that state. Each state has only one entity that issues oil and gas well drilling permits. For wells drilled onshore on federal land, the permitting authority is the Bureau of Land Manage ment (BLM). For wells drilled offshore in federal water, the permitting authority is the Bureau of Ocean Energy Management (BOEM).

64 American Petroleum Institute. The API Well Number and Standard State And County Numeric Codes Including Offshore Waters . API Bulletin D12A, January 1979. Avai lable at https://dl.ppdm.org/dl/62.

65 The Professional Petroleum Data Management Association. The US Well Number Standard: An Identifier for Petroleum Industry Wells in the USA . Version 2013 rev 1, published June 19, 2014. Available at http://dl.ppdm.org/dl/1209

.41 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 represents a state (including off-shore state waters) or other location ( e.g. , Offshore Federal Waters). A list of state codes is provided in The US Well Number Standard

.

 County Code (digits 3 thr ough 5): The county code represents an onshore county, parish (Louisiana), U.S. Geological Surv ey (USGS) quadrangl e (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 we ll code is assigned to each well as determined by a unique well origin and mu st be unique 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 code applied.

 Wellbore Code (also referred to as the di rectional sidetrack code in the API Well Number) (digits 11 and 12): The wellbore co de may be assigned to the original wellbore (typically “00”), di rectional sidetracks, or d eepening. 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, but according to The US Well Number Standard , there is no sequence or order significance implied by the code applied.

 Extension (also referred to as the event sequence code in the API Well Number) (any digits beyond 12): The extension may be assigned based on regulatory agency requirements and may include alphanume ric or special 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 pr evious API Well 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 regu latory filings and permit numbers.

The US Well Number Standard requires the state code, county code, well code, and the wellbore code; the extension is optional and is not further defined by the standard. US Well Numbers are publically available, but the accessibili ty of the data varies from state to state. The US Well Number Standard specifies that historical API Well Numbers should be included in the state’s master list of US Well Numbers without being revised unless there are concerns that the number is not or will not be uni que. However, previous versions of the standard have not always included the wellbore code, so some historical API Well Numb ers may be only 10 digits long. For these numbers, The US Well Number Standard specifies that a wellbore code should be42 added but leaves the ultimate decision of whet her to do so up to the regulatory agency with primary jurisdiction over the drilling of oil and ga s 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 permanent US Well Numbers to each well in the United States, and nearly all states follow this protocol. However, there is no national authority that requir es or assigns US Well Nu mbers. Therefore, as noted above, there are a few stat es that, historically, have not assigned US Well Numbers to wells. The reasons some states may have not adop ted the US Well 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 we lls and historical well records; (3) regulatory agency staff resources may be limited; or (4) th e state has a previously established system for identifying wells and maintaining well records that already meets its nee d. Although some states do not use US Well Numbers, such states do assi gn a unique number to every well according to their own system, so all wells ar e uniquely identified. In addition, so me operators in these states may request or otherwise acquire US Well Number s (in addition to the st ate-assigned identifiers) for ease of use in specialized mapping progr ams and other analytical software tools. 66

Well identification numbers have long been used in the oil and gas exploration and production industry as the primary means of inte grating all forms of well data and linking the data to specific wells and boreholes (in the cas e of wells with multiple sidetrack or lateral boreholes). For example, basic well inform ation (such as location, depth, well status), geophysical well log data, reservoi r and rock sample data, pressu re test and production data are all linked to specific wells a nd boreholes via a unique identification number. Unique well identification numbers are used in regulatory f ilings by operators, and in various transactions pertaining to working interest , production and royalties, we ll ownership and operating agreements. Unique well identification numbers are more accurate for such purposes than well names, hence the practice of using well identi fication numbers for data integration is long established and universa lly accepted in the oil and gas industry. For th is reason, the US Well Number, or the predecessor API Well Number, is intended to be a straightforward way for operators to link emissions reporting to specific production facilities.

66 For example, the Indiana Division of Oil and Gas ( DOG) assigned API well numbers to newly permitted wells between 1967 and 1990. In 1994, the need for a unique well identifier was recognized, but it was determined that the API well number would not be suitable because there were inconsistencies in the existing API well numbers and the historical numbers could not be verified. Instead, wells in Indiana are issued a six- digit number known as the Indiana Geological Survey (IGS) Petroleum Well Identification Number (IGS ID). The Petroleum Information Corporation (now IHS, Inc.) began issuing API well number s 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 public or the permitting authority. (See “API Well Numbers in Indiana (Draft 1)” by Charles W. Zuppann, Indiana Geological Survey, July 2011, http://igs.indiana.edu/pdms/help/API_Numbers_in_Indiana.htm . Docket Item No. EPA-HQOAR-2014-0831-0024.)43 The final revisions to subpart W include we ll identification reporting requirements for individual oil and gas wells covered by the Onshore Petroleum and Natural Gas Production segment and equipment or operations associated with those individual wells. In addition, the EPA is finalizing the requirements in 40 CFR 98. 236(aa)(1)(ii)(D) th rough (H) to include a list of the well identification numbers by sub-basin for the producing wells at th e end of the calendar year and lists of the well iden tification numbers for the wells acquired, divested, completed, and permanently taken out of production during the ca lendar year. These requirements will improve the EPA’s ability to verify reported data and en hance transparency and will enable the EPA and other stakeholders to directly ma tch data for reported wells with other local, state, and federal permitting and other reported information.

The EPA also considered including well identification reporting requirements for equipment other than wells. As part of this consideration, the EPA reviewed the well and emission-source equipment reporting practices us ed by a number of producing states to assess the current status of reporting of well iden tification numbers associated with each emission source. Seven states were surveyed to see how th e issue of linking well identification numbers to the various emission-source equipment is handled at the state level. Although most of the states assign unique identifiers to each emission source , the EPA found that only two of the seven states have a tracking system that links indivi dual emission sources to specific wells and well identification numbers, and these two states a pproach the linking of we ll identification numbers to equipment differently. See Appendix A of this document for details of the state analysis.

The EPA’s review of state requirements show s that there may be multiple scenarios in which a reporter does not know which well or we lls are associated with a particular emission source. Therefore, the EPA is not requiring fa cilities in this rulemaking to report well identification numbers for every emission source in a facility in the Onshore Petroleum and Natural Gas Production segment. Instead, the EPA is requiring the reporting of well identification numbers for the Onshore Petroleu m and Natural Gas Production segment only for information related specifically to wells.Appendix A

Use of Well Identification Numbers in State ProgramsA-1 APPENDIX A

Use of Well Identification Numbers in State Programs

The EPA reviewed the well and emission-sour ce equipment reporting practices used by a number of producing states to assess the current status of re porting of well identification numbers associated with each emission source. Seve n states were surveyed to see how the issue of linking well identification numbers to the vari ous emission-source equipment is handled at the state level.

All seven state exploration and production re gulatory agencies requi re that individual wells be given a unique identifier as current practice. Without an id entifier, each state’s ability to permit wells, track production and levy severance would be impossibl e. Most of these regulatory programs are based on well-level data identifie d by a unique number. Each state requires a drilling and operations permit for well sites th at includes a descrip tion of the well and a schematic of the site. Because the primary purpose of these drilling permits is to manage oil and gas production, there is limited information on emissions-source equipment provided therein. Additionally, many of these states report air emissions through di fferent bureaus, departments and, in a few cases, differe nt regulatory entities.

In the seven-state sample, two states specifi cally created a tracki ng system that linked individual emission-source equipment to well id entification numbers for at least one emissions reporting program. The other states surveyed either did not atte mpt to link individual emissionsource equipment to well identification numbers or did not assign any iden tification numbers to emission-source equipment that would allow a li nk with well identification numbers to be established.

States Not Tracking Equipment by Well Identification Number

In North Dakota, the Department of Health regulates air emissions while the North Dakota Industrial Commission regul ates sites and production. The De partment of Health requires well identification numbers (NDIC Permit Number) on the Registration for Oil/Gas Production Facility SFN 14334 form if the permit includes a well but assigns no iden tification number to specific equipment. For multiple well pads, the SFN 14334 form also requires listing other existing wells at the site by NDIC Permit Number. For equipment with emissions, there is no identification system or assignment to a particular well. Location data for a piece of equipment is done only at the township and section level. Emissions by equipment category are aggregated and then entered into the workbook provided. i

The Pennsylvania Department of Environmenta l Protection regulates all aspects of oil and gas development. The Bureau of Air Quality regulates air emissions and the Bureau of OilA-2 and Gas Management regulates sites and produc tion. For the Bureau of Air Quality GP-05 Permit Application Form 2700-PM-BAQ0205 for Na tural Gas Compression Facilities and/or Processing Facilities, the facility is not tied to a particular well identification number, though there are identification numbers for the speci fic pieces of equipment (such as internal combustion engines, turbines, dehydrators, fractiona tors, tanks, and pumps). Permit site diagrams do require the location of nearby equipment a nd facilities including “well(s), compressor stations(s), processing plant(s), natural gas wastewater storage and treatment facilities, interconnect/metering stations and transmission stations etc. within a five (5) miles radius, which are under common control.” ii However, there is no specific requirement to add identification numbers to the plot.

Ohio regulates oil and gas operations through the Department of Na tural Resources and air emissions through the Ohio Environmental Pr otection Agency. The Ohio EPA has developed General Permit 12 for air emissions reporting from oil and gas operations. There is one form for facilities with large flares and another for facilitie s with small flares. This facility permit process includes an emissions activity ca tegory (EAC) form along with the application for Permit to Install (PTI) and Permit to Inst all/Operate (PTIO). Though the EA C form is industry-specific, the actual permit application is not specific to the oil a nd gas industry. It follows the facility and equipment identification approach. Therefore, emission-source equipment is given a unique identification but is not linked to a particular well identification number anywhere on the form. iii

In California, emissions reporting for wells a nd related facilities is managed by each air quality district rather than by the California Environmental Protection Agency - Air Resources Board while production and other well site regula tion is managed by the Division of Oil, Gas, and Geothermal Resources. iv As an example, the South Coast Air Quality Management District (AQMD) Rule 222 Registration Form assigns an AQMD facility identification for permitting and a facility can have up to four wells associated in a well produ ction group. Equipment is assigned a number that relates to the facil ity rather than the individual well. v Other air quality districts have different procedures.

Air emission regulation in Oklahoma is mana ged by the Department of Environmental Quality (DEQ) while site and production are regulated by the Oklahoma Corporation Commission. The DEQ requires a Minor Source General Permit fo r Oil & Gas Facilities (GPOGF) form from operators in the state. The form does assign identifications for emission-source equipment but does not require a sp ecific well identification number. vi

States Tracking Equipment by Well Identification Number

Some states have created an approach that links unique emission-source equipment to well identification numbers for at least one regulato ry program. However, ea ch follows a slightlyA-3 different approach. For Wyoming, the approach is to link each piece of emission-source equipment to the nearest well identification number. Texas created a facility identification numbering system that includes we lls and emission-source equipment.

For Wyoming, Wyoming Department of Envi ronmental Quality m onitors air quality while the Wyoming Oil and Gas Conservation Commission regulates sites and production. As regulated by Wyoming DEQ, the State of Wy oming Production Site Emissions Inventory requires that emissions from production facilities be identified by API number for its Triennial Minor Source Emissions program:

Facilities with associated American Petroleum Institute (API) number ( i.e. production sites, water injection wells, ta nk batteries, etc.) should be reported using one of three excel “Production E quipment Inventory” forms available below. These forms are identical in natu re except that they allow the user to report more or less facilities.

The spreadsheets require the well name a nd API number for each particular piece of emission-source equipment. This data is required to help crosscheck the inventory data with information collected by the Wyoming Oil and Gas Conservation Commission. vii

For Texas, the regulation of sites an d production is handled by the Texas viii Railroad Commission while the Texas Commission of E nvironmental Quality (TCEQ) manages air emissions. Under Title 30 Texas Ad ministrative Code (TAC), Chap ter 116, Subchapter B, TCEQ “requires facilities that may em it air contaminants to obtain aut horization prior to construction” including reporting emissions by site/location when point source reporting is required. If emissions are estimated to be above a certain level, the site/location is assigned a Regulated Entity Reference Number (RN), and the individual facility, be it a flare, vapor recovery unit or component, is assigned an individu al Facility Id entification Number (FIN ). TCEQ uses a tiered approach to permitting and, unless a facility is designated as De Minimis, the information is submitted to the agency. This system allows very detailed analysis of emissions data by location, equipment type, field, and, in certain cases, producing formation. ixA-4 i North Dakota Department of Health. Oil & Gas Upstream programs. Accessed May 15, 2015, at http://www.ndhealth.gov/aq/oilgaswell.aspx

. ii Pennsylvania Department of Environmental Protection. General Permits: GP-05, Natural Gas Compression and/or Processing Facilities. Accessed May 15, 2015, at http://www.elibrary.dep.state.pa.us/dsweb/View/Collection-9747

. iii Ohio Environmental Protection Agency, General Perm its – Oil and Gas Well-Site Production Operations. Accessed May 15, 2015, at http://epa.ohio.gov/dapc/genpermit/oilandgaswellsiteproduction.aspx

. iv California Environmental Protection Agency - Air Resources Board, Oil and Natural Gas Production, Processing, and Storage. Accessed May 15, 2015, at http://www.arb.ca.gov/cc/oil-gas/oil-gas.htm

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v South Coast AQMD. Rule 222 Filing Program. Accessed May 15, 2015, at http://www.aqmd.gov/home/permits/equipment -registration/rule-2 22-filing-program

. vi Oklahoma Department of Environmental Quality. Genera l Permits & Permits by Rule for Oil and Gas Facilities. Accessed May 15, 2015, at http://www.deq.state.ok.us/aqdnew/permitting/genperm.htm

. vii Wyoming Department of En vironmental Quality. Triennial Minor Sour ce Emissions. Accessed May 15, 2015, at http://deq.wyoming.gov/aqd/emission-inventories/ resources/triennial-minor-source-emissions/

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ix Texas Commission on Environmental Quality. Oil and Gas Facilities: Air Compliance Information. Accessed May 15, 2015, at https://www.tceq.texas.gov/assistance /industry/oil-and-gas/oilgas_air.html

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