The primary costs associated with converting natural gas-driven pumps to electric pumps are the initial capital expenditures, installation and ongoing operation and maintenance. Based on the Natural Gas STAR document, "PRO Fact Sheet: Convert Natural Gas-Driven Chemical Pumps" the cost of an electric pump to replace a diaphragm pump is $4,647 and to replace a piston pump is $1,819 in 2012 dollars depending on the horsepower of the unit. The annual operating costs for an electric pump are estimated to be $293. Based on these costs annualized over the life expectancy of the pump at a 7 percent discount rate, the annualized costs for an electric pump to replace a diaphragm pump are $954, and $506 to replace a piston pump. In addition, the use of electric pumps will have savings realized from the natural gas not released. We estimate that each diaphragm pump replaced will save 197 Mcf per year of natural gas from being emitted and each piston pump will have a natural gas savings of 22 Mcf per year. The value of the natural gas saved based on $4.00 per Mcf would be $786 per year per diaphragm pump and $72 per year per piston pump.
<IP_ADDRESS>	Instrument Air System
Description
      Instrument air systems require a compressor, power source, dehydrator, and volume tank. The same pneumatic pumps can be used for natural gas and compressed air, without altering any of the parts of the pneumatic pump, but instrument air eliminates the emissions of natural gas. All facilities that have access to an adequate and reliable source of electricity can install an instrument air system. The following, taken from the Natural Gas STAR document, "PRO Fact Sheet: Convert Gas Pneumatic Controls to Instrument Air," describes the major components of an instrument air system:
     (1) Compressors used for instrument air delivery are available in various types and sizes, from rotary screw (centrifugal) compressors to positive displacement (reciprocating piston) types. The size of the compressor depends on the size of the facility, the number of control devices operated by the system, and the typical emission rates of these devices. The compressor is usually driven by an electric motor that turns on and off, depending on the pressure in the volume tank. For reliability, a full spare compressor is normally installed.
     (2) A critical component of the instrument air control system is the power source required to operate the compressor. Because high-pressure natural gas is abundant and readily available, natural gas-driven pneumatic systems can run uninterrupted on a 24-hour, 7-day per week schedule. The reliability of an instrument air system, however, depends on the reliability of the compressor and electric power supply. Most large natural gas plants have either an existing electric power supply or have their own power generation system. For smaller facilities and remote locations, however, a reliable source of electric power can be difficult to assure. In some instances, solar-powered battery-operated air compressors can be feasible for remote locations, which would both reduce VOC emissions and energy consumption. Small natural gas-powered fuel cells are also being developed.
     (3) Dehydrators, or air dryers, are an integral part of the instrument air compressor system. Water vapor present in atmospheric air condenses when the air is pressurized and cooled, and can cause a number of problems to these systems, including corrosion of the instrument parts and blockage of instrument air piping and controller orifices.
     (4) The volume tank holds enough air to allow the pneumatic control system to have an uninterrupted supply of high pressure air without having to run the air compressor continuously. The volume tank allows a large withdrawal of compressed air for a short time, such as for a motor starter, pneumatic pump, or pneumatic tools, without affecting the process control functions.
Control Effectiveness
      Instrument air eliminates all emissions from natural gas-driven pneumatic pumps, but can only be utilized in locations with sufficient and reliable electrical power. Furthermore, instrument air systems are more economical and therefore more common at facilities with a high concentration of pneumatic devices and where an operator can ensure the system is properly functioning. Because all emissions can be avoided by converting natural gas-driven chemical pumps to instrument air, methane emissions can be reduced by an estimated 3.46 tpy per diaphragm pump and 0.38 tpy per piston pump. Based on the gas composition for natural gas in the production segment, we estimate that replacement of a pneumatic pump converted to instrument air will reduce VOC emissions by 0.96 tpy per diaphragm pump and 0.11 tpy for a piston pump.
Cost Impacts
      As stated previously, instrument air conversions require a compressor with a capacity based on the number of control loops at the location. The compressor size is equivalent to the volume of gas used by the control loops after adjusting for gas losses during drying, plus any utility air necessary at the facility. This volume can either be calculated via a meter or utilizing a rule of thumb of one cubic foot per minute (cfm) of instrument air per control loop.
      The costs associated with instrument air systems are primarily capital costs for the compressor(s), air dryer and the volume tank, but also include operational costs for electricity to drive the compressor motor. Other components of the instrument air system including piping, control instruments and valve actuators would already be in place for a gas system. We assume that existing processing plants have an instrument air system in place, including backup systems, and that the cost of increasing air load on the system would be confined to the incremental cost associated with upgrading or replacing the compressor and connecting the pumps to the system. The size of the compressor required would depend on the additional air load required for the instrument air system to handle the pneumatic pumps. Table 7-3 summarizes cost estimates to replace various size compressors in an existing instrument air system.

 Table 7-3. Cost of Compressor Replacement for Existing Instrument Air System
                                 Type of Pump
                                  Size Option
                          Total Capital Costs ($2012)
                                  Annualized
                                     Cost
                             Total O&M ($2012)

                        Annualized with Operating Costs

Diaphragm
                                     Small
                                    $5,999
                                     $854
                                    $9,197
                                    $10,051
Diaphragm
                                    Medium
                                    $29,989
                                    $4,270
                                    $28,002
                                    $32,271
Diaphragm
                                     Large
                                    $52,779
                                    $7,515
                                    $64,880
                                    $72,394
Piston
                                     Small
                                    $5,999
                                     $854
                                    $9,197
                                    $10,051
Piston
                                    Medium
                                    $29,989
                                    $4,270
                                    $28,002
                                    $32,271
Piston
                                     Large
                                    $52,779
                                    $7,515
                                    $64,880
                                    $72,394
<IP_ADDRESS>	Route Emissions to an Existing or New Combustion Device
Description
      Combustion devices can generally reduce 95 percent of the emissions routed to it. Combustion requires a reliable ignition source where the average gas consumption per pilot burner is 70 scf per hour. Typical combustion devices used in the oil and natural gas industry to control VOC emissions are discussed in greater detail in section <IP_ADDRESS> of chapter 4 of this document. It is assumed that most processing plants and large dehydration facilities have at least one existing combustion device on-site.
 Table 7-3. Cost of Compressor Replacement for Existing Instrument Air System
                                 Type of Pump
                                  Size Option
                          Total Capital Costs ($2012)
                                  Annualized
                                     Cost
                             Total O&M ($2012)

                        Annualized with Operating Costs

Diaphragm
                                     Small
                                    $5,999
                                     $854
                                    $9,197
                                    $10,051
Diaphragm
                                    Medium
                                    $29,989
                                    $4,270
                                    $28,002
                                    $32,271
Diaphragm
                                     Large
                                    $52,779
                                    $7,515
                                    $64,880
                                    $72,394
Piston
                                     Small
                                    $5,999
                                     $854
                                    $9,197
                                    $10,051
Piston
                                    Medium
                                    $29,989
                                    $4,270
                                    $28,002
                                    $32,271
Piston
                                     Large
                                    $52,779
                                    $7,515
                                    $64,880
                                    $72,394

Control Effectiveness
      Routing emissions from a natural gas-driven pump to an existing combustion device, or a newly installed combustion device does not reduce the volume of natural gas discharged from the pump, but rather combusts the gas. Based on the gas composition for natural gas in the production segment, we estimated that routing emissions to a combustion device would reduce VOC emissions by an estimated 0.91 tpy per diaphragm pump and 0.1 tpy for a piston pump.
Cost Impacts
      Routing natural gas to an existing combustion device or installing a new combustion device have associated capital costs and operating costs. Based on costs for a combustion device provided in the 2011 NSPS TSD, the capital costs for installing a new combustion device to control emissions are estimated to cost $32,301 in 2008 dollars. Escalating these costs to 2012 dollars, the estimated capital costs for installing a new combustion device are $34,250 and the annual operating costs are $17,001. Based on the life expectancy for a combustion device, we estimate the annualized costs of installing a new combustion device to be approximately $21,877, and the annualized costs of routing emissions to an existing combustion device to be $285, using a 7 percent discount rate. Because the natural gas captured is combusted there is no gas savings associated with the use of a combustion device to reduce VOC emissions. Table 7-4 presents the estimated VOC cost of control for emission reductions from routing natural gas-driven pump emissions to an existing combustion device, and Table 7-5 presents the cost of control for routing natural gas-driven pump emissions to a new combustion device.
Table 7-4. VOC Cost of Control for Routing Natural Gas-Driven Pump Emissions to an Existing Combustion Device
                                  Pump Type/
                                    Segment
                            VOC Emission Reductions
                                  (tpy/pump)
                               Annualized Costs
                                    ($2012)
                        VOC Cost of Control ($2012/ton)
Diaphragm Pumps
Production
                                     0.91
                                     $285
                                     $312
Processing
                                     0.91
                                     $285
                                     $312
Piston Pumps
Production
                                     0.10
                                     $285
                                    $2,840
Processing
                                     0.10
                                     $285
                                    $2,840

Table 7-5. VOC Cost of Control for Routing Natural Gas-Driven Pump Emissions to a New Combustion Device
                              Pump Type/ Segment
                                 VOC Emission
                                  Reductions
                                  (tpy/pump)
                               Annualized Costs
                                    ($2012)
                        VOC Cost of Control ($2012/ton)
                                Diaphragm Pumps
Production
                                     0.91
                                    $21,877
                                    $23,944
Processing
                                     0.91
                                    $21,877
                                    $23,944
                                 Piston Pumps
Production
                                     0.10
                                    $21,877
                                   $218,017
Processing
                                     0.10
                                    $21,877
                                   $218,017

<IP_ADDRESS>	Route Emissions to a Vapor Recovery Unit (VRU)
Description
      Vapor recover units capture low pressure vapor streams, increase the pressure by means of a compressor, and then route the vapor stream to a process or other useful purpose. These systems typically include a backup compressor system to allow for shutdowns and repairs. Vapor recovery units are more economical for facilities with multiple natural gas emission sources that can be routed to the VRU. Some of these other emission sources can include tanks, dehydrators, and compressors and as a result, VRUs are more common at natural gas processing plants. Vapor recovery units are discussed in greater detail in section <IP_ADDRESS> of chapter 4 of this document.
Control Effectiveness
      Use of a vapor recovery technology has the potential to reduce the emissions from natural gas-driven pumps by 100 percent if all vapor is recovered. However, the effectiveness of the natural gas capture system (typically less than 100 percent) and downtime of the VRU for repairs and maintenance would reduce the overall emission reductions and therefore, we estimate that routing emissions from a natural gas-driven pump to an existing or newly installed VRU can reduce the natural gas emitted by approximately 95 percent, while at the same time, capturing the natural gas for beneficial use. We estimate that methane emission reductions for routing gas to a VRU to be 3.29 tpy for a diaphragm pump and 0.36 tpy for a piston pump. Based on the gas composition for natural gas in the production segment, we estimate that routing emissions to a VRU will reduce VOC emissions by 0.91 tpy per diaphragm pump and 0.1 tpy for a piston pump.
Cost Impacts
      Based on costs for a VRU provided in the 2011 NSPS TSD for pneumatic pumps, the capital costs and installation costs for a VRU was estimated to be $98,186 in 2008 dollars.  We estimate the capital costs of installing a VRU to be $104,111 and the annual operation and maintenance cost to be $9,932 in 2012 dollars. The total annualized costs of a new VRU are estimated to be $24,755 based on a 7 percent discount rate.
      If a VRU is already on-site, then the additional costs for routing emissions from a pump are small, as the majority of costs are piping. We estimated the cost of routing emissions to an existing VRU to be $2,000 in 2012 dollars. The annualized costs of routing natural gas emissions to an existing VRU are estimated to be $285 based on a 7 percent discount rate. In addition, there is potential for beneficial use of natural gas recovered through the VRU. We estimated the annual natural gas recovered to be 187 Mcf per year per diaphragm pump and 21 Mcf per year per piston pump. The resulting natural gas savings is estimated to be $749 per diaphragm pump and $84 per piston pump, per year based on a value of $4.00 per Mcf of natural gas recovered. Table 7-6 presents the estimated VOC cost of control for routing natural gas-driven pump emissions to an existing VRU, and Table 7-7 presents the estimated VOC cost of control for routing gas-driven pump emissions to a new VRU.
Table 7-6. VOC Cost of Control for Routing Natural Gas-Driven Pump Emissions to an Existing VRU
                                  Pump Type/
                                    Segment
                            VOC Emission Reductions
                                  (tpy/pump)
                               Annualized Costs
                                    ($2012)
                        VOC Cost of Control ($2012/ton)

                                Without savings
                                 With savings
                                Diaphragm Pumps
                                  Production
                                     0.91
                                     $285
                                     $312
                                    ($507)
                                  Processing
                                     0.91
                                     $285
                                     $312
                                    ($507)
                                 Piston Pumps
                                  Production
                                     0.10
                                     $285
                                    $2,840
                                    $2,007
                                  Processing
                                     0.10
                                     $285
                                    $2,840
                                    $2,007

Table 7-7. VOC Cost of Control for Routing Natural Gas-Driven Pump Emissions to a New VRU
                                  Pump Type/
                                    Segment
                            VOC Emission Reductions
                                  (tpy/pump)
                               Annualized Costs
                                    ($2012)
                        VOC Cost of Control ($2012/ton)

                                Without savings
                                 With savings
Diaphragm Pumps
                                  Production
                                     0.91
                                    $24,755
                                    $27,094
                                    $26,274
                                  Processing
                                     0.91
                                    $24,755
                                    $27,094
                                    $26,274
Piston Pumps
                                  Production
                                     0.10
                                    $24,755
                                   $246,697
                                   $245,860
                                  Processing
                                     0.10
                                    $24,755
                                   $246,697
                                   $245,860

7.3.2	Existing Federal, State and Local Regulations
<IP_ADDRESS>	Federal Regulations that Specifically Require Control of VOC Emissions
      The EPA has proposed federal requirements for natural gas-driven pneumatic pumps under 40 CFR part 60, subpart OOOOa (subpart OOOOa). Under the proposed subpart OOOOa, each natural gas-driven chemical/methanol and diaphragm pump located at a natural gas processing plant must have zero natural gas emissions, and each natural gas-driven chemical/methanol and diaphragm pump located outside of a natural gas processing plant must reduce VOC emissions by 95 percent or greater when there is a control device already in place at the facility, or when a control device is installed at an existing facility.
<IP_ADDRESS>	State and Local Regulations that Specifically Require Control of VOC Emissions
      States may have permitting restrictions on VOC emissions that may apply to an emissions source as a result of an operating, NSR NA, or PSD permit (e.g., on a case-by-case basis) based on air quality maintenance or improvement goals of an area. Permits specify what construction is allowed, what emission limits must be met, and often how the source may be operated. To assure that sources follow the permit requirements, permits also contain monitoring, recordkeeping, and reporting requirements. Permits specify what construction is allowed, what emission limits must be met, and often how the source must be operated. To assure that sources follow the permit requirements, permits also contain monitoring, recordkeeping, and reporting requirements.
      At least one state (Wyoming) requires emissions associated with the discharge streams from all natural gas-operated pneumatic pumps be controlled by at least 98 percent or routed into a closed loop system (e.g., sales line, collection line, fuel supply line). Several states also have registration rules for controlling fugitive VOC emissions (which may include fugitive emissions from pneumatic pumps).
7.4	Recommended RACT Level of Control
      Based on our evaluation of available data obtained in the development of the 2015 NSPS proposal and peer review comments received on the EPA's white paper "Oil and Natural Gas Sector Pneumatic Devices," and considering that Wyoming already requires emissions associated with the discharge streams from all natural gas-operated pneumatic pumps to be controlled by at least 98 percent or routed into a closed loop system (e.g., sales line, collection line, fuel supply line), we recommend that VOC emissions from individual natural gas-driven piston and diaphragm pumps located from the wellhead to the point of custody transfer to the natural gas transmission and storage segment and at a natural gas processing plant be controlled by RACT.
      Our recommended RACT for existing individual gas-driven piston and diaphragm pumps located from the wellhead to the point of custody transfer to the transmission and storage segment, using natural gas emissions as a surrogate for VOC emissions, is to reduce natural gas emissions by 95 percent by routing emissions to a control device where there is an existing control device available on-site. If there is an existing VRU available on-site, then we recommend RACT to be reducing natural gas emissions by 95 percent by using the VRU to route emissions to a process. If a control device is subsequently installed at the facility where the pump is located, then the owner or operator would have to route the natural gas emission stream from the pump to the newly installed control device. Our rationale for selecting 95 percent control when there is an existing control device is that, as presented in Table 7-4 in section <IP_ADDRESS> of this chapter, the VOC cost of control when an existing combustion device is available on-site was estimated to be $312/ton for diaphragm pumps and $2,850/ton for piston pumps. As presented in Table 7-6 in section <IP_ADDRESS> of this chapter, the VOC cost of control when an existing VRU is available on-site was estimated to be a cost savings for diaphragm pumps and $2,007/ton for piston pumps. We consider these costs to be reasonable. Requiring control where there is not an existing control device on-site was not considered to be reasonable available technology, and the costs per ton of VOC reduced are estimated at greater than $20,000 per ton of VOC reduced for diaphragm pumps and over $200,000 per ton of VOC reduced for piston pumps.
      Our recommended RACT for existing individual chemical/methanol and diaphragm pump located at natural gas processing plants is that they have zero natural gas emissions (unless there are functional needs, including but not limited to response time, safety and positive actuation, requiring an emission rate greater than zero). Our rationale for selecting a natural gas emission rate of zero (with functional and safety exceptions) for our recommended RACT is based on the ability of most natural gas processing plants to install and utilize an instrument air system. As discussed in section <IP_ADDRESS> of this chapter, by using an instrument air system, compressed air may be substituted for natural gas in pneumatic systems without altering any of the parts of the pneumatic system. Therefore, the use of instrument air eliminates natural gas and VOC emissions from each gas-driven pneumatic pump and supports a natural gas emission rate of zero.
      In summary, we recommend the following RACT for pneumatic pumps in the oil and natural gas industry:
      (1)       Each Natural Gas-Driven Chemical/Methanol and Diaphragm Pump Located at a Natural Gas Processing Plant: Each pump must have zero natural gas emissions.
      (2)       Each Natural Gas-Driven Chemical/Methanol and Diaphragm Pump Located From the Wellhead to the Natural Gas Processing Plant: If there is a control device located on-site of the location of the pump, using natural gas as a surrogate for VOC, each pump must reduce natural gas emissions by 95 percent by routing to the control device or to a process. If there is no existing control device at the location of the pneumatic pump, submit a certification that there is no device. If a control device is subsequently added to the site where the pump is located, then the natural gas emissions from the pump must be routed to the newly installed control device.
      Although sources have a choice on how they meet the RACT level of control, the technologies that will likely be used to meet the RACT level of control for each natural gas-driven pneumatic pump located from the wellhead to the natural gas processing plant are either routing the natural gas emissions to an on-site existing combustion device (or a subsequently installed combustion device) or routing the natural gas emissions to a process using an on-site existing VRU (or a subsequently installed VRU).
	Similarly, the technology that will likely be used to meet the RACT level of control for each natural gas-driven chemical/methanol and diaphragm pump located at a natural gas processing plant is the use of an existing instrument air system assumed to already exist on-site at natural gas processing plants.
7.5	Factors to Consider in Developing Pneumatic Pump Compliance Procedures
7.5.1	Oil and Natural Gas Production Segment Recommendations
	We recommend that regulatory agencies require each pneumatic pump be tagged with the date that the pneumatic pump is required to comply with the rule (as established by the regulating agency) that allows traceability. We also suggest that regulatory agencies require owners and operators of pneumatic pumps to maintain records that document the location and manufacturer's specifications of each pneumatic pump that are tied to the identification information of each pump. We also recommend that regulatory agencies require owner or operators to document deviations in cases where a pneumatic pump was not operated in compliance with RACT. Lastly, we suggest that regulatory agencies require owners and operators to submit annual reports that include the records of deviations that occurred during the reporting period.
      The appendix to this document presents example model rule language that incorporates compliance elements recommended in this section that states may choose to use in whole or in part when implementing RACT.
7.5.2	Natural Gas Processing Segment Recommendations
      We suggest that regulatory agencies require each pneumatic pump be tagged with the date that the pneumatic pump is required to comply with the rule (as established by the regulating agency) that allows traceability. We also recommend that regulatory agencies require owners and operators of pneumatic pumps to maintain records that document the location and manufacturer's specifications of each pneumatic controller that are tied to the identification information of each pump. The owner or operator should also be required to document deviations in cases where a pneumatic pump was not operated in compliance with RACT. Lastly, we recommend that regulatory agencies require owners and operators to submit annual reports that include the records of deviations that occurred during the reporting period.
      The appendix to this document presents example model rule language that incorporates compliance elements recommended in this section that states may choose to use in whole or in part when implementing RACT.

8.0 	EQUIPMENT LEAKS FROM NATURAL GAS PROCESSING PLANTS
      This chapter presents the causes for equipment leaks from natural gas processing plants, and provides emission estimates for "model" facilities in the processing segment of the oil and natural gas industry. Methods that are designed to reduce equipment leak emissions are presented, along with our recommended RACT and the associated VOC emission reductions and cost impacts for equipment component leaks from natural gas processing plants.
8.1	Applicability
	For purposes of this guideline, the emissions and emission controls discussed herein would apply to the group of all equipment (except compressors) within a process unit located at a natural gas processing plant in VOC service or in wet gas service. For a piece of equipment to be considered not in VOC service, it must be determined that the VOC content can be reasonably expected never to exceed 10.0 percent by weight at or greater than 300 hours per year. For a piece of equipment to be considered in wet gas service, the piece of equipment must contain or contact the field gas before the extraction step at a natural gas processing plant.  Equipment is defined as each pump, pressure relief device, open-ended valve or line, valve, and flange or other connector that is in VOC service or in wet gas service
8.2	Process Description and Emission Sources
8.2.1	Process Description
      Natural gas processing involves the removal of natural gas liquids from field gas, fractionation of mixed natural gas liquids to natural gas products, or both. The types of process equipment used to separate the liquids are separators, glycol dehydrators, and amine treaters. In addition, centrifugal and/or reciprocating compressors are used to pressurize and move the natural gas from the processing facility to the transmission stations.
      There are several potential sources of equipment leak emissions at natural gas processing plants. Equipment such as pumps, pressure relief devices, valves, flanges, and other connectors are potential sources that can leak due to seal failure. Other sources, such as open-ended lines and valves may leak for reasons other than faulty seals. In addition, corrosion of welded connections, flanges, and valves may also be a cause of equipment leak emissions. The following sub-sections describe potential equipment leak sources and the magnitude of the VOC emissions from natural gas processing plants.
      Due to the large number of valves, pumps, and other equipment within natural gas processing plants, VOC emissions from leaking equipment can be significant (chapter 2.2 of the 1983 CTG presents a description of these equipment components and is not repeated here).
8.2.2	Equipment Leak Emission Data and Emission Factors
<IP_ADDRESS> Summary of Major Studies and Emission Factors
      The 2012 NSPS STSD evaluated emissions data from equipment leaks collected from chemical manufacturing and petroleum production to assist in the development of control strategies for reducing VOC emissions from these sources.[,][,] Table 8-1 presents a list of the studies consulted along with an indication of the type of information contained in the study. In addition to these sources, we evaluated the peer reviewer and public comments received on the EPA's white paper, "Oil and Natural Gas Sector Leaks."
Table 8-1. Major Studies Reviewed for Consideration of Emissions and Activity Data
                                  Report Name
                                  Affiliation
                                Year of Report
                                   Activity
                                    Factors
                                Emissions Data
                                Control Options
Protocol for Equipment Leak Emission Estimates[a]
                                      EPA
                                     1995
                                     None
                                       X
                                       X
Methane Emissions from the Natural Gas Industry: Equipment Leaks[b]
                                    EPA/GRI
                                     1996
                                  Nationwide
                                       X
                                       X
Greenhouse Gas Reporting Program[c]
                                      EPA
                                     2014
                                  Nationwide
                                       X
                                       X
Inventory of Greenhouse Gas Emissions and Sinks: 1990-2012[d]
                                      EPA
                                     2014
                                  Nationwide
                                       X

Methane Emissions from the Natural Gas Industry[e,f,g,h]
                                    EPA/GRI
                                     1996
                                  Nationwide
                                       X
                                       X
Methane Emissions from the U.S. Petroleum Industry[i]
                                      EPA
                                     1996
                                  Nationwide
                                       X

Methane Emissions from the US Petroleum Industry[j]
                                      EPA
                                     1999
                                  Nationwide
                                       X

Oil and Gas Emission Inventories for Western States[k]
                       Western Regional Air Partnership
                                     2005
                                   Regional
                                       X
                                       X
Recommendations for Improvements to the Central States Regional Air Partnership's Oil and Gas Emission Inventories[l]
                    Central States Regional Air Partnership
                                     2008
                                   Regional
                                       X
                                       X
Oil and Gas Producing Industry in Your State[m]
                 Independent Petroleum Association of America
                                     2009
                                  Nationwide

Emissions from Natural Gas Production in the Barnett Shale and Opportunities for Cost-effective Improvements[n]
                          Environmental Defense Fund
                                     2009
                                   Regional
                                       X
                                       X
Emissions from oil and Natural Gas Production Facilities[o]
                  Texas Commission for Environmental Quality
                                     2007
                                   Regional
                                       X
                                       X
Petroleum and Natural Gas Statistical Data[p]
                    U.S. Energy Information Administration
                                   2007-2009
                                  Nationwide

Preferred and Alternative Methods for Estimating Air Emissions from Oil and Gas Field Production and Processing Operations[q]
                                      EPA
                                     1999

                                       X
                                       X
  a. U.S. Environmental Protection Agency, Protocol for Equipment Leak Emission Estimates. Office of Air Quality Planning and Standards. Research Triangle Park, NC. November 1995. EPA-453/R-95-017. Available at http://www.epa.gov/ttn/chief/efdocs/equiplks.pdf.
 [b.] Gas Research Institute (GRI)/U.S. Environmental Protection Agency. Research and Development, Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks. June 1996 (EPA-600/R-96-080h).
[c.] U.S. Environmental Protection Agency. . Research and Development, Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks. June 1996 (EPA-600/R-96-080h).
 Greenhouse Gas Reporting Program. (Annual Reporting; Current Data Available for 2011-2013). 2014.
 [d.] U.S. Environmental Protection Agency (EPA). Inventory of Greenhouse Gas Emissions and Sinks: 1990-2012. Climate Change Division, Washington, DC.
 [e.] U.S. Environmental Protection Agency/GRI. Methane Emissions from the Natural Gas Industry, Vol. 2: Technical Report. EPA-600/R-96-080b.June 1996.
 [f.] U.S. Environmental Protection Agency/GRI. Methane Emissions from the Natural Gas Industry, Vol. 3: General Methodology. EPA-600/R-96-080c.June 1996.
 [g.] U.S. Environmental Protection Agency/GRI. Methane Emissions from the Natural Gas Industry, Vol. 5: Activity Factors. EPA-600/R-96-080e.June 1996.
 [h.] U.S. Environmental Protection Agency/GRI. Methane Emissions from the Natural Gas Industry, Vol. 6: Vented and Combustion Source Summary Emissions. EPA-600/R-96-080f. June 1996.
 [i.] U.S. Environmental Protection Agency/GRI. Methane Emissions from the U.S. Petroleum Industry, Draft Report. June 14, 1996.
 [j.] ICF Consulting. Estimates of Methane Emissions from the U.S. Oil Industry. Prepared for the U.S. Environmental Protection Agency. 1999.
 [k.] ENVIRON International Corporation. Oil and Gas Emission Inventories for the Western States. Prepared for Western Governors' Association. December 27, 2005.
 [l.] ENVIRON International Corporation. Recommendations for Improvements to the Central States Regional Air Partnership's Oil and Gas Emission Inventories Prepared for Central States Regional Air Partnership. November 2008.
 [m.] Independent Petroleum Association of America. Oil and Gas Producing Industry in Your State.
 [n.] Armendariz, Al. Emissions from Natural Gas Production in the Barnett Shale Area and Opportunities for Cost-Effective Improvements. Prepared for Environmental Defense Fund. January 2009.
 [o.] Eastern Research Group, Inc. Emissions from Oil and Gas Production Facilities. Prepared for the Texas Commission on Environmental Quality. August 31, 2007.
 [p.] U.S. Energy Information Administration. Annual U.S. Natural Gas Wellhead Price. Energy Information Administration. Natural Gas Navigator. Retrieved online on 12 Dec 2010 at http://www.eia.doe.gov/dnav/ng/hist/n9190us3a.htm.
 [q] Eastern Research Group, Inc. Preferred and Alternative Methods for Estimating Air Emissions from Oil and Gas Field Production and Processing Operation. Prepared for the U.S. Environmental Protection Agency. September 1999.
<IP_ADDRESS> Natural Gas Processing Model Plant
      Natural gas processing plants can consist of a variety of combinations of process equipment and components. In order to conduct analyses to be used in evaluating potential options to reduce emissions from leaking equipment, the 2011 NSPS TSD and the 2012 NSPS STSD used a model plant approach.
      Information related to equipment counts were obtained from a natural gas industry report. This document provided average equipment counts for gas production and gas processing segments. These average counts were used to develop a model plant. These equipment counts are consistent with those contained in the EPA's analysis to estimate methane emissions conducted in support of the GHGRP. The natural gas processing model plant is discussed in the following section. A summary of the model plant production equipment counts for a gas processing facility is provided in Table 8-2.

      Table 8-2. Equipment Counts for Natural Gas Processing Model Plant
                                   Equipment
                                Equipment Count
                          (non-compressor equipment)
Valves
                                     1,392
Connectors
                                     4,392
Open-Ended Lines (OEL)
                                      134
Pressure Relief Valve (PRV)
                                      29
                 Data Source: EPA/GRI, Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks, Table 4-13, June 1996. (EPA-600/R-96-080h)
<IP_ADDRESS>	Natural Gas Processing Model Plant Emissions
Overview of Approach
      The EPA gathered equipment leak data and cost information for the development of the proposed Uniform Standards for Equipment Leaks rule. These Uniform Standards data were used to estimate baseline emissions for a natural gas processing model plant for the 2012 NSPS STSD and provide the baseline and controlled emission options for processing plants presented in this guideline.[,]
      The baseline emissions were defined as being equivalent to a 40 CFR part 60, subpart VV (subpart VV) leak detection and repair (LDAR) program, which represents the same set of requirements that apply to natural gas processing plants under 40 CFR part 60, subpart KKK (subpart KKK). The 2012 NSPS requires the implementation of 40 CFR part 60, subpart VVa (subpart VVa) and currently applies to natural gas processing plants constructed or modified after August 23, 2011. It is assumed that natural gas processing plants constructed or modified on or before August 23, 2011 currently still comply with subpart KKK, which is similar to the control level of subpart VV. We evaluated requiring a similar subpart VVa level of control to these plants as was required under the 2012 NSPS. We used leak frequency data (refers to the estimated percentage of equipment that will be found leaking at a given leak definition) to calculate emission estimates, in addition to several other sources of information (including the Protocol for Equipment Leak Emissions Estimates and industry data). Table 8-3 provides a summary of the equipment leak frequency data used for the natural gas processing model plant. Emission factors are the estimated leak rates for an equipment type at a given leak definition and are normally given in kg/hr/piece of equipment. Table 8-4 provides a summary of the VOC equipment leak emission factors representing the subpart VVa level of control was used for the natural gas processing model plant.
Table 8-3. Summary of Equipment Leak Frequency for Natural Gas
                                LDAR Program[a]
                                    Valves
                                   (percent)
                                  Connectors
                                   (percent)
 Baseline
                                   1.18/1.18
                                      NA
 Valves
                                   5.95/1.91
                                      NA
 Connectors
                                      NA
                                   1.70/0.81
            NA = Not Applicable; no equipment leak frequency percent data were available.
            Data Source: Memorandum from Cindy Hancy, RTI International to Jodi Howard, EPA/OAQPS, Analysis of Emission Reduction Techniques for Equipment Leaks, December 21, 2011, Table 5.
            [a.] The leak frequencies provided in the tables are presented as initial leak frequency and subsequent leak frequency under the subpart VVa level of control.

Table 8-4. Summary of VOC Equipment Leak Emission Factors for the Natural Gas Processing Model Plant
                                   Component
                           Uncontrolled (kg/comp-hr)
                           Baseline (kg/comp-hr)[a]
                                  Subpart VVa
                                 Control Level
                                (kg/comp-hr)[b]
Valves
                                   3.71E-04
                                   2.24E-04
                                   8.85E-05
Connectors
                                   1.04E-04
                                   1.04E-04
                                   3.95E-05
OEL
                                   2.30E-03
                                   7.34E-05
                                      NA
PRV
                                   1.60E-01
                                   9.80E-02
                                      NA
     NA = Not Applicable
     Data Source: Memorandum from Cindy Hancy, RTI International to Jodi Howard, EPA/OAQPS, Analysis of Emission Reduction Techniques for Equipment Leaks, December 21, 2011, Table 7.
     a. The baseline option is assumed to be equivalent to a subpart VV LDAR program.
     b. Assumed to be equivalent to a subpart VVa LDAR program.
8.3	Available Controls and Regulatory Approaches
8.3.1	Available VOC Emission Control Options
      The EPA has determined that leaking equipment, such as valves, pumps and connectors, are a significant source of VOC emissions from natural gas processing plants. The following subsections describe the techniques used to reduce emissions from these sources.
.1..1 Leak Detection and Repair Program
      The most commonly employed control technique for equipment leaks is the implementation of a LDAR program. Emission reductions from implementing a LDAR program can potentially reduce product losses, increase safety for workers and operators, decrease exposure of hazardous chemicals to the surrounding community, and reduce emissions fees. The elements of an effective LDAR program include:
   (1) Identifying Equipment;
   (2) Leak Definition;
   (3) Monitoring Equipment;
   (4) Repairing Equipment; and
   (5) Recordkeeping.
      The primary sources of equipment leak emissions from natural gas processing plants are valves and connectors, because these are the most prevalent equipment and can number in the thousands (see Table 8-2). The major cause of emissions from valves and connectors is a seal or gasket failure due to normal wear or improper maintenance. A leak is detected whenever the measured concentration exceeds the threshold standard (i.e., leak definition) for the applicable regulation. Leak definitions vary by regulation, equipment type, service (e.g., light liquid, heavy liquid, gas/vapor), and monitoring interval. Most NSPS regulations have a leak definition of 10,000 ppm, while many National Emission Standards for Hazardous Air Pollutants (NESHAP) regulations use a 500-ppm or 1,000-ppm leak definition. In addition, some regulations define a leak based on visual inspections and observations (such as fluids dripping, spraying, misting or clouding from or around equipment), sound (such as hissing), and smell.
      For many NSPS and NESHAP regulations with leak detection provisions, the primary method for monitoring to detect leaking components is EPA Reference Method 21 (40 CFR part 60, appendix A-7). Method 21 is a procedure used to detect VOC leaks from equipment using a toxic vapor analyzer (TVA) or organic vapor analyzer (OVA).
      A second method for monitoring to detect leaking components is optical gas imaging (OGI) using an infrared camera. The infrared camera may be passive or active. The passive infrared cameras scan an area to produce images of equipment leaks from a number of sources. Active infrared cameras point or aim an infrared beam at a potential source to indicate the presence of equipment leaks. The optical imaging camera can be very efficient in monitoring multiple pieces of equipment in a short amount of time. However, the optical imaging camera cannot quantify the amount or concentration of the equipment leak.
      Acoustic leak detectors measure the decibel readings of high frequency vibrations from the noise of leaking fluids from equipment leaks using a stethoscope-type device. The decibel reading, along with the type of fluid, density, system pressure, and component type can be correlated into leak rate by using algorithms developed by the instrument manufacturer. The acoustic detector does not decrease the monitoring time because components are measured separately, like the OVA or TVA monitoring. The accuracy of the measurements using the acoustic detector can also be questioned due to the number of variables used to determine the equipment leak emissions.
      In addition, other monitoring tools such as soap solution and electronic screening devices can be used to monitor process components. Other factors that can improve the efficiency of a LDAR program include training programs for equipment monitoring personnel and tracking systems that address the cost efficiency of alternative equipment (e.g., competing brands of valves in a specific application).
Subpart VVa LDAR Program
      One LDAR option to control VOC emissions from natural gas processing plant equipment leaks is the implementation of the subpart VVa LDAR program. This program is similar to the  subpart VV monitoring program (whose requirements are cross-referenced in subpart KKK), but finds more leaks due to the lower leak definition, increased monitoring frequency and the addition of connectors to the components being monitored, thereby achieving better emission reductions.
Description
      The subpart VVa LDAR program requires the monitoring of pumps, compressors, pressure relief devices, sampling connection systems, open-ended lines, valves and connectors. These components are monitored with an OVA or TVA to determine if a component is leaking and measure the concentration of the organics if the component is leaking. Connectors, valves, and pressure relief devices have a leak definition of 500 ppmv. Valves are monitored monthly, connectors are monitored annually, and open-ended lines and pressure relief valves have no monitoring requirements, but are required to operate without any detectable emissions. Compressors are not included in this leak detection and repair option and are regulated separately.
Control Effectiveness
      The control effectiveness of an LDAR program is based on the frequency of monitoring, leak definition, frequency of leaks, percentage of leaks that are repaired, and the percentage of reoccurring leaks. The control effectiveness of a leak program can vary from 45 to 96 percent and is dependent on the frequency of monitoring and the leak definition. Descriptions of the frequency of monitoring and leak definition are described further below.
      Monitoring Frequency. The monitoring frequency is the number of times each piece of equipment is checked for leaks over a given period of time. With more frequent monitoring, leaks are found and repaired sooner thus providing higher control effectiveness.
      Leak Definition. The leak definition describes the local VOC concentration at the surface of an equipment source where indications of VOC emissions are present. The leak definition is an instrument meter reading, in parts per million based on a reference compound. Decreasing the leak definition generally increases the number of leaks found during a monitoring period, which generally increases the number of leaks that are repaired.
      The 2012 NSPS STSD calculated incremental emission reductions from the baseline requirements (assuming that an LDAR program equivalent to the subpart VV/subpart KKK LDAR program is currently implemented at natural gas processing plants), and the leak frequency and emission factors from a supporting document for the Equipment Leak Uniform Standards were used to calculate the emission reductions and costs. The natural gas processing plant component counts (see Table 8-2) were obtained from a EPA/GRI document. The incremental VOC emission reductions for implementing a subpart VVa leak detection and repair program (as determined in the 2012 NSPS STSD) for the natural gas processing model plant was calculated to be 13 percent.
Cost Impacts
      Table 8-5 presents a summary of the incremental capital and annual costs and the cost of control (estimated in the 2012 NSPS STSD) from baseline (subpart VV) to implementing subpart VVa for the gas processing model plant. The costs obtained from the 2012 NSPS STSD have been converted to 2012 dollars from 2008 dollars using the Federal Reserve Economic Data GDP Price Deflater (Change in GDP: Implicit Price Deflator from 2008 to 2012 (5.69 percent)).
Table 8-5. Summary of the Gas Processing Model Plant VOC Cost of Control
for the Subpart VVa Option
                        Annual VOC Emission Reductions
                                     (tpy)
                             Capital Costs ($2012)
                                 Annual Costs
                                 ($2012/year)
                              VOC Cost of Control
                                  ($2012/ton)

                                Without savings
                                     With
                                  savings[a]
                                     4.56
                                    $8,499
                                    $12,959
                                    $2,844
                                    $2,010
a With savings calculated assuming the natural gas (82.9% methane) from the methane reduction has a value of $4/Mscf. The VOC/methane ratio was assumed to be 0.278.
      Table 8-6 provides a summary of the capital and annual costs and the cost of control on a component basis for the natural gas processing model plant.

Table 8-6. Summary of the Gas Processing Component VOC Cost of Control
for the Subpart VVa Option
                                   Component
                        Annual VOC Emission Reductions
                                     (tpy)
                             Capital Costs ($2012)
                                 Annual Costs
                                 ($2012/year)
                              VOC Cost of Control
                                  ($2012/ton)

                                Without Savings
                                With Savings[a]
Valves
                                     1.82
                                    $5,231
                                    $9,280
                                    $5,095
                                    $4,261
Connectors
                                     2.74
                                    $8,374
                                    $4,405
                                    $1,610
                                     $776
[a] With savings calculated assuming the natural gas (82.9 percent methane) from the methane reduction has a value of $4/Mscf. The VOC/methane ratio was assumed to be 0.278.

<IP_ADDRESS> Leak Detection and Repair Program with Optical Gas Imaging
      Another option to control VOC emissions is the implementation of a program that uses OGI to detect equipment leaks. This option is currently available as an alternative work practice (40 CFR part 60, subpart A) for monitoring emissions from equipment leaks in subpart VVa. The alternative work practice requires monthly monitoring of all equipment using OGI and an annual monitoring of all equipment using a Method 21 monitoring device. Method 21 monitoring allows the facility to determine the concentration of a leak and to then use emission factors found in the EPA's emissions leak protocol to quantify emissions from equipment leaks, since the OGI system can only provide the presence of the equipment leaks. A more detailed description of, and the cost of implementing LDAR with OGI program for the natural gas processing model plant is presented in the following paragraphs.
Description
      The alternative work practice for equipment leaks in §60.18 of 40 CFR part 60, subpart A allows the use of an OGI system to monitor equipment leaks. This LDAR program requires monthly monitoring and repair of components using OGI and annual monitoring of equipment using a Method 21 instrument. This requirement does not have a leak definition because OGI can only measure the presence of a leak and not the concentration. Compressors are not included in this LDAR option and are discussed in chapter 5 of this document.

Effectiveness
      No data were found on the control effectiveness of the alternative work practice. For purposes of this analysis, we assumed that this option would provide the same control effectiveness as the subpart VVa monitoring program. Therefore, the control effectiveness values for implementing an alternative work practice were assumed to be 93.6 percent for valves, 95.9 percent for connectors, 100 percent for open-ended lines, and 100 percent for pressure relief devices.
Cost Impacts
      The 2011 NSPS TSD calculated costs using procedures developed for estimating capital and annual costs for applying LDAR to the Petroleum Refinery and Chemical Manufacturing industry. Costs obtained from the 2011 NSPS TSD have been converted to 2012 dollars from 2008 dollars using the Federal Reserve Economic Data GDP Price Deflater (Change in GDP: Implicit Price Deflator from 2008 to 2012 (5.69 percent)). It was assumed that a single OGI device and a single Method 21 monitoring device could be used at multiple locations. To calculate the shared cost of OGI and the Method 21 devices, the time required to monitor a single facility was estimated. It was assumed for gas processing facilities that the full cost of the OGI system and the Method 21 monitoring device would apply to each individual plant. Assuming a 20-day work month, the total number of facilities that could be monitored by a single OGI system and Method 21 device is 80. Therefore, the shared cost of the Method 21 monitoring device was calculated to be $1,209 per site.
      Table 8-7 presents a summary of the capital and annual costs and the VOC cost of control for the natural gas processing model plant using the alternative work practice monitoring. A cost of control analysis on a component basis for the alternative work practice was not performed because the OGI system is intended for facility-wide monitoring.

Table 8-7. Summary of the Natural Gas Processing Model Plant VOC Cost of Control for Optical Gas Imaging and Method 21 Monitoring
                        Annual VOC Emission Reductions
                                     (tpy)
                             Capital Costs ($2012)
                                 Annual Costs
                                 ($2012/year)
                              VOC Cost of Control
                                  ($2012/ton)

                                Without Savings
                                 With Savings
                                     4.56
                                    $97,787
                                    $92,013
                                    $20,192
                                    $19,358
8.3.2	Existing Federal, State and Local Regulations
<IP_ADDRESS>	Federal Regulations that Specifically Require Control of VOC Emissions
      Federal regulations that regulate VOC emissions from equipment leaks at natural gas processing plants include the 2012 NSPS, subpart KKK and the 1983 CTG (established a recommended RACT for VOC for natural gas processing plants at a level of control equivalent to subpart KKK).
<IP_ADDRESS>	State and Local Regulations that Specifically Require Control of VOC Emissions
      States may have permitting restrictions on VOC emissions that may apply to an emissions source as a result of an operating, NSR NA, or PSD permit (e.g., on a case-by-case basis) based on air quality maintenance or improvement goals of an area. Permits specify what construction is allowed, what emission limits must be met, and often how the source must be operated. To assure that sources follow the permit requirements, permits also contain monitoring, recordkeeping, and reporting requirements.
      We assume that all states currently regulate equipment leaks (except compressors) at existing natural gas processing plants at the 1983 CTG and subpart VV level of control.
8.4	Recommended RACT Level of Control for Equipment Leaks from Equipment at Natural Gas Processing Plants
      As discussed in section 8.3.2 of this chapter, existing federal and state and local regulations already require the reduction of VOC emissions using an LDAR program. The 2012 NSPS requires a 40 CFR part 60 subpart VVa LDAR monitoring program for processing plants. The 2012 NSPS reported a cost of control for natural gas processing plants to be $2,844 per ton of VOC removed for the 40 CFR part 60 subpart VVa option, and $20,192 per ton of VOC removed for the Method 21/OGI option. The option for just monitoring just valves or connectors at the 40 CFR part 60 subpart VVa level of control was estimated to be $5,095 and $1,610 per ton of VOC removed, respectively.
      Based on costs and existing LDAR programs that are already employed at natural gas processing plants, we recommend that RACT for natural gas processing plants be the implementation of an LDAR program equivalent to what is required under 40 CFR part 60 subpart VVa for equipment (with the exception of compressors) in VOC service. This RACT recommendation would increase the stringency from the currently implemented LDAR programs at most existing natural gas processing plants (that were built prior to 2012) in VOC service by lowering the leak definitions, increasing the monitoring frequency and including additional components. The subpart VVa leak detection and repair program requires the annual monitoring of connectors using an OVA or TVA (500 ppm leak definition), monthly monitoring of valves (500 ppm leak definition) and requires open-ended lines and pressure relief devices to operate with no detectable emissions (500 ppm leak definition). The estimated annual incremental VOC emission reductions for the recommended RACT for a natural gas processing plant was estimated to be 4.56 tpy (see Table 8-5 of this chapter). The annual VOC emission reductions assume a baseline level of control equivalent to the 40 CFR part 60, subpart VV LDAR program. Table 8-5 presents the gas processing model plant VOC cost of control for the recommended RACT. The costs assume a baseline level of control equivalent to the 40 CFR part 60, subpart VV LDAR program. The recommended RACT VOC cost of control is estimated to be $2,844 per ton of VOC reduced without savings and $2,010 with savings.
      In summary, we recommend the following RACT for equipment leaks at natural gas processing plants:
      RACT for Equipment Leaks at Natural Gas Processing Plants: We recommend the implementation of an LDAR program equivalent to what is required under 40 CFR part 60 subpart VVa for equipment components (with the exception of compressors) in VOC service.
8.5	Factors to Consider in Developing Equipment Leak Compliance Procedures
      Existing natural gas processing plants that would be subject to the recommend RACT are already subject to an LDAR program and the basic elements of the LDAR program for the facility are in place. However, the LDAR program would need to be modified to increase the stringency from the currently implemented LDAR program by lowering the leak definitions, and to require annual monitoring of connectors using an OVA or TVA (500 ppm leak definition), monthly monitoring of valves (500 ppm leak definition) and to require open-ended lines and pressure relief devices to operate with no detectable emissions (500 ppm leak definition). As with the currently implemented LDAR program, to ensure that equipment in VOC service that leak at natural gas processing plants are properly monitored and repaired under the LDAR RACT recommendations, we suggest that regulatory agencies specify monitoring and equipment component repair recordkeeping and reporting requirements to document compliance.
	Monitoring intervals vary according to the applicable regulation, but are typically weekly, monthly, quarterly, and yearly. The monitoring interval depends on the equipment type and periodic leak rate for the equipment. For each piece of equipment that is found to be leaking, the first attempt at repair should be made within a reasonable period of time, such as no later than five calendar days after each leak is detected. First attempts at repair include, but are not limited to, the following best practices, where practicable and appropriate:
     (1)       Tightening of bonnet bolts;
     (2)       Replacement of bonnet bolts;
     (3)       Tightening of packing gland nuts and
     (4)       Injection of lubricant into lubricated packing.
Once the equipment is repaired, it should be monitored over the next several days to ensure the leak has been successfully repaired. Another method that can be used to repair equipment is to replace the leaking equipment with a "leakless" equipment or other technologies.
	When implementing an LDAR program, we recommend that regulatory agencies consider including recordkeeping requirements that require owner/operators of subject facilities to maintain a list of identification numbers for all equipment subject to an equipment leak regulation. A list of equipment that is designated as "unsafe to monitor" should also be maintained with an explanation/review of conditions for the designation. Detailed schematics, equipment design specifications (including dates and descriptions of any changes), and piping and instrumentation diagrams should also be maintained with the results of performance testing and leak detection monitoring.
      The appendix to this document presents example model rule language that incorporates compliance elements recommended in this section that states may choose to use in whole or in part when implementing RACT.

9.0	FUGITIVE EMISSIONS FROM WELL SITES AND COMPRESSOR STATIONS
      Fugitive emissions from components in the oil and natural gas industry are a source of VOC emissions. This chapter discusses the sources of fugitive emissions, and provides VOC emission estimates for well sites and compressor stations in the production segment (located from the wellhead to the point of custody transfer to the natural gas transmission and storage segment or point of custody transfer to an oil pipeline). This chapter also presents a description of programs that are designed to reduce fugitive emissions, along with costs and emission reductions. Finally, this chapter provides a discussion of our recommended RACT and the estimated VOC emission reductions and costs for fugitive emissions from well sites and compressor stations.
9.1	Applicability
      For purposes of this guideline, the emissions and programs to control emissions discussed herein would apply to the collection of fugitive emissions components at a well site with an average production of greater than 15 barrel equivalents per well per day (15 barrel equivalents), and the collection of fugitive emissions components at compressor stations in the production segment. It is our understanding that fugitive emissions at a well site with low production wells are inherently low and that many well sites are owned and operated by small businesses. We are concerned about the burden of the fugitive emissions recommendation on small businesses, in particular where there is little emission reduction to be achieved. For the purposes of this guideline, fugitive emissions recommendations would not apply to well sites that only contain wellheads.
      Fugitive emissions, for the purposes of applicability of this guideline, means those emissions from a stationary source that could not reasonably pass through a stack, chimney, vent, or other functionally equivalent opening. Equipment leak emissions at natural gas processing plants are covered under chapter 8 of this document.
9.2	Fugitive Emissions Description and Data
9.2.1	Fugitive Emissions Description
      There are several potential sources of fugitive emissions throughout the oil and natural gas industry. Fugitive emissions occur when connection points are not fitted properly or when seals and gaskets start to deteriorate. Changes in pressure, temperature or mechanical stresses can also cause fugitive emissions from components. Fugitive emission components are defined as any component that has the potential to emit fugitive emissions at a well site or gathering and boosting station. These components include valves, connectors, pressure relief devices, open-ended lines (OEL), access doors, flanges, closed vent systems, thief hatches or other openings on storage vessels, agitator seals, distance pieces, crankcase vents, blowdown vents, pump seals or diaphragms, compressors, separators, pressure vessels, dehydrators, heaters, instruments, and meters. Devices that vent as part of normal operations, such as natural gas-driven pneumatic controllers or natural gas-driven pumps, are not fugitive emissions components, insofar as the natural gas discharged from the device's vent is not considered a fugitive emission. Emissions originating from other than the vent, such as seals around the bellows of a diaphragm pump, would be considered fugitive emissions.
      In April of 2014, the EPA published a white paper titled "Oil and Natural Gas Sector Leaks" that summarized the EPA current understanding of fugitive emissions at oil and natural gas production, processing and transmission facilities (referred to herein as the "equipment leaks white paper"). The equipment leaks white paper identified 12 studies or publicly available sources that provided fugitive emission estimates from the various segments of the oil and natural gas industry. Many of the fugitive emission measurements were conducted with EPA Method 21 instruments. In addition to EPA Method 21 analyzers, several studies conducted fugitive emission surveys using OGI in conjunction with portable Method 21 analyzers and gas chromatograph equipment to measure individual VOC compounds. These studies provided emission estimates in the form of component or equipment emission factors or emission estimates by facility. Fugitive emission estimates for VOC ranged from 0.4 to 10 tpy for oil and natural gas production sites. Even though there is a wide variation in the VOC emissions estimates, the studies showed that there are viable options for reducing these emissions.
9.2.2.	Emission Data and Emission Factors
<IP_ADDRESS>	Summary of Major Studies and Emission Factors
      The equipment leaks white paper provided a summary of fugitive emission studies at oil and natural gas production and compressor stations in the production segment. When we evaluated the emissions and emission reduction options for equipment leaks, many of these studies in the white paper were consulted. Table 9-1 presents a list of the studies consulted along with an indication of the type of information contained in the study.

<IP_ADDRESS>	Model Plants
      Facilities in the oil and natural gas industry consist of a variety of combinations of process equipment and components. This is particularly true in the production segment of the industry, where "surface sites" can vary from sites where only a wellhead and associated piping is located to sites where a substantial amount of separation, treatment, and compression occurs. In order to conduct analyses to be used in evaluating potential options to reduce fugitive emissions from well sites and gathering and boosting stations, a model plant approach was used. The following sections discuss the creation of these model plants.
      We obtained information related to equipment counts for natural gas well sites and gathering and boosting stations from the EPA/GRI natural gas industry study. This document also provided average component counts for equipment in the natural gas production segment. The types of components that are associated with this equipment include: valves, connectors, open-ended lines, and pressure relief valves. These average counts were used to develop an average model plants for well sites in the production segment of the industry and for a gathering and boosting station. Equipment counts associated with oil well sites were obtained from an API Workbook. These equipment counts are consistent with those contained in the EPA's analysis to estimate methane emissions conducted in support of the GHGRP. These model plants are discussed in the following sections.

       Table 9-1. Major Studies Reviewed for Emissions and Activity Data
                                  Report Name
                                  Affiliation
                                Year of Report
                                   Activity
                                    Factors
                                Emissions Data
                                Control Options
Protocol for Equipment Leak Emission Estimates[a]
                                      EPA
                                     1995
                                     None
                                       X
                                       X
Methane Emissions from the Natural Gas Industry: Equipment Leaks[b]
                                    EPA/GRI
                                     1996
                                  Nationwide
                                       X
                                       X
Greenhouse Gas Reporting Program[c]
                                      EPA
                                     2013
                                   Facility
                                       X

Inventory of Greenhouse Gas Emissions and Sinks: 1990-2012[d]
                                      EPA
                                     2014
                                   Regional
                                       X

Measurements of Methane Emissions at Natural Gas Production Sites in the United States[e]
                  Multiple Affiliations, Academic and Private
                                     2013
                                  Nationwide
                                       X
                                      X
City of Fort Worth Natural Gas Air Quality Study, Final Report[f]
                              City of Fort Worth
                                     2011
                                Fort Worth, TX
                                       X
                                       X
Measurements of Well Pad Emissions in Greeley, CO[g]
                  ARCADIS/Sage Environmental Consulting/ EPA
                                     2012
                                   Colorado
                                       X
                                       X
Quantifying Cost-Effectiveness of Systematic Leak Detection and Repair Programs Using Infrared Cameras[h]
                                 Carbon Limits
                                     2013
                              Canada and the U.S.
                                      X
                                      X
Mobile Measurement Studies in Colorado, Texas, and Wyoming[i]
                                      EPA
                                 2012 and 2014
                         Colorado, Texas, and Wyoming
                                       X
                                       X
Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil and Natural Gas Industries[j]
                               ICF International
                                     2014
                                  Nationwide
                                       X
                                       X
Identification and Evaluation of Opportunities to Reduce Methane Losses at Four Gas Processing Plants[k]
                         Clearstone Engineering, Ltd.
                                     2002
                            4 gas processing plants
                                       X
                                       X
Cost-Effective Directed Inspection and Maintenance Control Opportunities at Five Gas Processing Plants and Upstream Gathering Compressor Stations and Well Sites[l]
                         Clearstone Engineering, Ltd.
                                     2006
                    5 gas processing plants, 12 well sites
                                       X
                                       X
[a]  U.S. Environmental Protection Agency. Protocol for Equipment Leak Emission Estimates. Office of Air Quality Planning and Standards. Research Triangle Park, NC. November 1995. EPA-453/R-95-017. Available at http://www.epa.gov/ttn/chief/efdocs/equiplks.pdf.
 [b.] Gas Research Institute (GRI)/U.S. Environmental Protection Agency. Research and Development, Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks. June 1996 (EPA-600/R-96-080h).
[c.] U.S. Environmental Protection Agency. [b] U.S. Environmental Protection Agency/GRI. Research and Development, Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks. June 1996 (EPA-600/R-96-080h).
c  U.S. Environmental Protection Agency. Greenhouse Gas Reporting Program. (Annual Reporting; Current Data Available for 2011-2013). 2014.
[d.] U.S. Environmental Protection Agency. Inventory of Greenhouse Gas Emissions and Sinks: 1990-2011. Climate Change Division, Washington, DC. April 2013. Available at http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2013-Chapter-3-Energy.pdf.
[e.]Allen, David, T., et al. Measurements of methane emissions at natural gas production sites in the United States. Proceedings of the National Academy of Sciences (PNAS) 500 Fifth Street, NW NAS 340 Washington, DC 20001 USA. October 29, 2013. 6 pgs. Available at http://www.pnas.org/content/early/2013/09/10/1304880110.full.pdf+html.
[f.] ERG and Sage Environmental Consulting, LP. City of Fort Worth Natural Gas Air Quality Study, Final Report. Prepared for the City of Fort Worth, Texas. July 13, 2011. Available at http://fortworthtexas.gov/gaswells/default.aspx?id=87074.
[g.] Modrak, Mark T., et al. Understanding Direct Emissions Measurement Approaches for Upstream Oil and Gas Production Operations. Air and Waste Management Association 105[th] Annual Conference and Exhibition, June 19-22, 2012 in San Antonio, Texas.
[h]. Carbon Limits. Quantifying cost-effectiveness of systematic Leak Detection and Repair Programs using Infrared cameras. December 24, 2013. Available at http://www.catf.us/resources/publications/files/CATF-Carbon_Limits_Leaks_Interim_Report.pdf.
[i.] Thoma, Eben D., et al. Assessment of Methane and VOC Emissions from Select Upstream Oil and Gas Production Operations Using Remote Measurements, Interim Report on Recent Studies. Proceedings of the 105[th] Annual Conference of the Air and Waste Management Association, June 19-22, 2012 in San Antonio, Texas.
[j.]ICF International. Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil and Natural Gas Industries. ICF International (Prepared for the Environmental Defense Fund). March 2014.
[k.] Clearstone Engineering Ltd. Identification and Evaluation of Opportunities to Reduce Methane Losses at Four Gas Processing Plants. June, 2002.
[l.] Clearstone Engineering Ltd. Cost-Effective Directed Inspection and Maintenance Control Opportunities at Five Gas Processing Plants and Upstream Gathering Compressor Stations and Well Sites. March, 2006.

       consist of a variety of combinations of process equipment and components. This is particularly true in the production segment of the industry, where "surface sites" can vary from sites where only a wellhead and associated piping is located to sites where a substantial amount of separation, treatment, and compression occurs. In order to conduct analyses to be used in evaluating potential options to reduce fugitive emissions from well sites and gathering and boosting stations, a model plant approach was used. The following sections discuss the creation of these model plants.
      We obtained information related to equipment counts for natural gas well sites and gathering and boosting stations from the  This document also provided average component counts for equipment in the natural gas production segment. The types of components that are associated with this equipment include: valves, connectors, open-ended lines, and pressure relief valves. These average counts were used to develop an average model plants for well sites in the production segment of the industry and for a gathering and boosting station. Equipment counts associated with oil well sites were obtained from an API Workbook. These equipment counts are consistent with those contained in the EPA's analysis to estimate methane emissions conducted in support of the GHGRP. These model plants are discussed in the following sections.
Well Sites
      Oil and natural gas production varies from one site to the next. Some production sites may include only a single wellhead that is extracting oil or natural gas from the ground, while other sites may include multiple wellheads attached to a well site. A well site is a site where the production, extraction, recovery, lifting, stabilization, separation and/or treating of petroleum and/or natural gas (including condensate) occurs. These sites include all equipment (including piping and associated components, compressors, generators, separators, storage vessels, and other equipment) associated with these operations. A well site can serve one well on a pad or multiple wells on a pad. Therefore, the number of components with potential for fugitive emissions can vary depending on the number of wells feeding into the production pad and the amount of processing equipment located at the site.
	We used equipment count data from the EPA GHG Inventory to calculate the average counts of production equipment located at a well site. The types of production equipment located at a well site include: gas wellheads, separators, meters/piping, heaters, and dehydrators. The types of components that are associated with this equipment include: valves, connectors, open-ended lines, and pressure relief valves. Component counts for each of the equipment items were calculated using the average component counts for gas production equipment in the Eastern U.S and the Western U.S. for the EPA/GRI document.
      A model plant was developed using the average number of wells associated with a well site using data from the Drillinginfo HPDI database. Baseline fugitive emissions from well sites depend upon the quantity of equipment and components, which in turn is based on this estimate of wells per pad. To estimate the average number of wells co-located on the same site as a new well completion or recompletion, the EPA developed a pair of algorithms that identified new and existing wells within a given distance of a new well completion or recompletion. This distance was assumed to represent the distance that, if other wells were within the distance, the wells would likely be co-located with the well under examination on the same site. The algorithms were written in the open source R programming language.
	The HPDI well and production data used to estimate the average number of well co-located on a well site drew upon the latitude and longitude of new well completions and recompletions as well as the coordinates of all wells producing oil or natural gas in 2012. The first algorithm estimated the distances between each new completion and recompletion and all producing wells, which also includes wells newly completed and producing in 2012 within the same county as the completed well. If the distance between the completed well and producing well was less than the assumed size of a typical well site, we assumed the two wells were co-located. This algorithm progressed county by county across the U.S. where oil and natural gas production occurred in 2012 to identify all co-located wells in the U.S. The number of new well completions and recompletions in 2012 was about 44,000, which includes oil and natural gas wells whether they were hydraulically fractured or not. All wells producing in 2012 numbered about 1.27 million. The second algorithm processed the results of the first such that a well can only appear once on a modelled well site.
      Once these algorithms were complete and produced a results file, we converted the results into a "kml" file that enabled the visual inspection of the results within Google Earth. We did not visually inspect every site in the U.S. linked to a 2012 completion or recompletion as they numbered greater than 20,000. Instead, we examined sites randomly across a range of oil and natural gas production regions. The results of this visual examination indicated the algorithms were functioning as intended.
      We estimated the number of wells per site assuming sites of one, two and three acres, based upon input from petroleum industry data analysts. Table 9-2 shows the high-level results of these analyses.
Table 9-2. Estimated Average Number of Wells per Site of New Well Completion in 2012
                            Assumed Well Site Size
                                    No. of
                                  Well Sites
                                    No. of
                                Wells at Sites
                           Average of Wells Per Site
One Acre
                                    29,213
                                    50,599
                                     1.73
Two Acres
                                    28,938
                                    52,422
                                     1.81
Three Acres
                                    28,710
                                    53,981
                                     1.88

      For assumed well sites of two acres, the analysis identified 28,938 independent well sites that contained 52,422 wells (including both single and multi-well sites). The total number of wells identified as being co-located with new well completions and recompletions exceeds the total number of completions and recompletions because the sites include about 8,500 existing wells producing in 2012.
      However, the high level summary presented in Table 9-3 masks variation by basins and well types. Table 9-3 presents more detail along these dimensions for the assumed two-acre well site.

Table 9-3. Estimated Average Number of Wells per Two Acre Site of New Well Completion and Recompletion in 2012, by HPDI Basin and Type of Well (Oil or Natural Gas, Hydraulically Fractured or Not)

                             Oil Well Completions
                         Natural Gas Well Completions

HPDI Basin
                                 No. Of Sites
HF
Not HF
All
HF
Not HF
All
Total
Los Angeles
                                      23
                                      N/A
                                     13.07
                                     13.07
                                      N/A
                                      N/A
                                      N/A
                                     13.07
Piceance
                                      111
                                     2.00
                                     1.00
                                     1.75
                                     6.72
                                     11.75
                                     10.14
                                     9.84
Arctic Ocean
                                       2
                                      N/A
                                     5.50
                                     5.50
                                      N/A
                                      N/A
                                      N/A
                                     5.50
Green River
                                      164
                                     2.23
                                     1.57
                                     2.01
                                     4.37
                                     1.13
                                     4.19
                                     3.88
Unidentified
                                      226
                                     1.18
                                     3.57
                                     3.38
                                     1.00
                                     1.77
                                     1.44
                                     3.22
San Joaquin Basin
                                     1,745
                                     1.56
                                     3.46
                                     3.21
                                     2.61
                                     1.42
                                     2.24
                                     3.16
Arkoma Basin
                                      374
                                     4.00
                                     1.33
                                     2.00
                                     3.06
                                     1.00
                                     3.01
                                     3.00
Denver Julesburg
                                      826
                                     2.63
                                     3.10
                                     2.75
                                     1.48
                                     3.14
                                     1.72
                                     2.46
Ft Worth Basin
                                     1,305
                                     2.05
                                     1.86
                                     1.91
                                     3.27
                                     1.10
                                     2.93
                                     2.33
Central Western Overthrust
                                       7
                                     1.50
                                      N/A
                                     1.50
                                     2.60
                                      N/A
                                     2.60
                                     2.29
Ventura Basin
                                       1
                                      N/A
                                     2.00
                                     2.00
                                      N/A
                                      N/A
                                      N/A
                                     2.00
Arctic Slope
                                      42
                                      N/A
                                     2.13
                                     2.13
                                      N/A
                                     1.65
                                     1.65
                                     1.99
Ouachita Folded Belt
                                      181
                                     2.01
                                     1.90
                                     1.99
                                     1.50
                                     1.00
                                     1.43
                                     1.97
Salina Basin
                                      13
                                      N/A
                                     1.92
                                     1.92
                                      N/A
                                      N/A
                                      N/A
                                     1.92
Palo Duro Basin
                                      81
                                     1.42
                                     1.97
                                     1.89
                                     1.00
                                      N/A
                                     1.00
                                     1.86
Uinta
                                      548
                                     1.16
                                     1.33
                                     1.32
                                      N/A
                                     3.33
                                     3.33
                                     1.83
Texas & Louisiana Gulf Coast
                                     3,994
                                     2.03
                                     1.82
                                     1.96
                                     1.37
                                     1.14
                                     1.28
                                     1.79
Central Kansas Uplift
                                      450
                                      N/A
                                     1.78
                                     1.78
                                      N/A
                                     1.53
                                     1.53
                                     1.77
Permian Basin
                                     8,507
                                     1.66
                                     1.76
                                     1.69
                                     1.50
                                     1.57
                                     1.52
                                     1.68
Sedgwick Basin
                                      240
                                      N/A
                                     1.67
                                     1.67
                                     1.67
                                     1.55
                                     1.55
                                     1.62
Las Animas Arch
                                      25
                                     1.00
                                     1.64
                                     1.61
                                      N/A
                                     1.50
                                     1.50
                                     1.60
Nemaha Anticline
                                      38
                                      N/A
                                     1.55
                                     1.55
                                      N/A
                                      N/A
                                      N/A
                                     1.55
Arkla Basin
                                      811
                                     1.09
                                     1.57
                                     1.49
                                     1.47
                                     1.09
                                     1.42
                                     1.46
Chautauqua Platform
                                      461
                                     1.36
                                     1.57
                                     1.49
                                     1.64
                                     1.03
                                     1.35
                                     1.45
Cook Inlet Basin
                                       9
                                      N/A
                                     2.00
                                     2.00
                                      N/A
                                     1.29
                                     1.29
                                     1.44
Appalachian
                                     2,496
                                     1.14
                                     1.05
                                     1.10
                                     2.28
                                     1.10
                                     1.77
                                     1.43
Williston
                                     1,570
                                     1.36
                                     1.00
                                     1.35
                                     1.43
                                     1.00
                                     1.39
                                     1.35
Cherokee Basin
                                      271
                                     1.17
                                     1.29
                                     1.29
                                      N/A
                                     1.69
                                     1.69
                                     1.35
San Juan
                                      158
                                     1.00
                                     1.00
                                     1.00
                                     1.38
                                     1.20
                                     1.37
                                     1.31
East Texas Basin
                                      618
                                     1.25
                                     1.74
                                     1.52
                                     1.22
                                     1.06
                                     1.21
                                     1.31
Forest City Basin
                                      172
                                      N/A
                                     1.28
                                     1.28
                                      N/A
                                      N/A
                                      N/A
                                     1.28
Anadarko Basin
                                     2,663
                                     1.17
                                     1.77
                                     1.37
                                     1.09
                                     1.29
                                     1.13
                                     1.27
South Oklahoma Folded Belt
                                      167
                                     1.17
                                     1.36
                                     1.30
                                     1.11
                                     1.11
                                     1.11
                                     1.24
Chadron Arch
                                      49
                                      N/A
                                     1.22
                                     1.22
                                      N/A
                                      N/A
                                      N/A
                                     1.22
Sacramento Basin
                                      13
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                                     1.15
                                     1.15
                                     1.15
Mississippi & Alabama Gulf Coast
                                      132
                                     1.00
                                     1.18
                                     1.14
                                     1.00
                                     1.00
                                     1.00
                                     1.14
Central Montana Uplift
                                      10
                                     1.13
                                     1.00
                                     1.10
                                      N/A
                                      N/A
                                      N/A
                                     1.10
Big Horn
                                      30
                                     1.10
                                     1.11
                                     1.11
                                     1.00
                                      N/A
                                     1.00
                                     1.10
Powder River
                                      232
                                     1.15
                                     1.03
                                     1.12
                                     1.05
                                     1.00
                                     1.04
                                     1.10
Sweet Grass Arch
                                      17
                                     1.00
                                     1.08
                                     1.05
                                     1.50
                                     1.00
                                     1.33
                                     1.10
Paradox
                                      13
                                     1.00
                                     1.10
                                     1.09
                                     1.00
                                      N/A
                                     1.00
                                     1.08
Black Warrior Basin
                                      57
                                     1.00
                                     1.00
                                     1.00
                                     1.00
                                     1.75
                                     1.07
                                     1.05
Wind River
                                      63
                                     1.00
                                     1.02
                                     1.02
                                     1.00
                                     1.00
                                     1.00
                                     1.02
Wasatch Uplift
                                       1
                                      N/A
                                     1.00
                                     1.00
                                      N/A
                                      N/A
                                      N/A
                                     1.00
North Park
                                       2
                                     1.00
                                     1.00
                                     1.00
                                      N/A
                                      N/A
                                      N/A
                                     1.00
Raton
                                      20
                                      N/A
                                      N/A
                                      N/A
                                     1.00
                                     1.00
                                     1.00
                                     1.00
Grand Total
                                    28,938
                                     1.64
                                     1.99
                                     1.79
                                     1.90
                                     1.76
                                     1.86
                                     1.81

      Table 9-3 provides data that the concentration of wells at production sites varies greatly by basin. However, the analysis indicates that most wells sites have relatively few or no co-located wells, which brings the national average wells per new completion or recompletion site to 1.81 for the two-acre well site. While the analysis shows variation by basin, at the national-level, there is relatively little variation across oil and natural gas well completion sites and whether the new wells were completed or recompleted using hydraulic fracturing. For example, oil well sites averaged 1.79 wells per site while natural gas wells averaged 1.86.
      As a result of this analysis, based upon professional judgment, we decided to use the two-acre well site as the assumed maximum size of a site to estimate the number of wells co-located at sites of new completions and recompletions. Also, to simplify analysis of costs and emissions at well sites, we rounded the 1.81 national average wells per site to 2.
      While we are confident that the assumed two acre well site is a reasonable size to capture most co-located wells in 2012, it is by no means a perfect assumption. First, industry and state regulatory trends indicate that well drilling will likely become increasingly concentrated on sites, potentially leading to an increase in the average number of wells per well site. However, it is not possible at this point to forecast this increasing concentration, especially with the variations by fields described above. Also, it is possible that two acres is too small to accurately estimate the number of co-located wells for large well sites in some fields. As a result, the algorithms might result in an under-estimate of the average number of wells at a site and identify more than one site when in actuality there is only one. Alternatively, the assumed two acres might over-estimate the size of sites in some fields and, as a result, pull in more than one site, overestimating the number of wells on the site. We also noted that the latitude and longitude values on many wells were likely incorrect or exact duplicates of other wells. Despite these caveats, we believe that the well site analysis described here produces a reasonable estimate of national average of number of wells on new well completion and recompletion sites in 2012. Therefore, based on this analysis, the model plant for an oil and natural gas production site was based on a well site with 2 wells.
      For natural gas well sites, the model plant was developed using the average equipment and fugitive emissions components counts for gas production data from the EPA/GRI report. The average equipment count for a gas well was estimated by weighting the average of equipment counts for the Eastern and Western U.S. data sets for gas production equipment. The weighted averages of the data sets were determined to be 1.6 separators, 0.8 meters/piping, 0.8 in-line heaters, and 0.6 dehydrators per well. The total natural gas well site equipment counts were calculated by multiplying the average well equipment values by the average number of wells per well site (2), and rounding the product to the nearest integer. Average component counts for each of the equipment items were calculated using the average component counts for production equipment in the Eastern U.S and the Western U.S. from the EPA/GRI study. The total number of fugitive emissions components was calculated by multiplying the rounded equipment counts by the component count per equipment and rounding to the nearest integer. Table 9-4 presents a summary of the fugitive emissions component counts for natural gas well sites.
For oil well sites, the model plant was developed using equipment counts from an API workbook and component count data from the EPA/GRI study. The average equipment count for an oil well were determined to be 0.7 separators, 0.7 headers, and 0.03 heater/treaters per well. The total oil well site equipment counts were calculated by multiplying the average well equipment values by the average number of oil wells per oil well site (2), and rounding the product to the nearest integer. Average component counts obtained from the API workbook were used to calculate the total number of components by multiplying the rounded equipment counts by the component count per equipment and rounding up to the nearest integer. Table 9-5 presents a summary of the fugitive emissions component counts for oil well sites.

      Baseline emissions for the natural gas well site model plant were calculated using the equipment and fugitive emissions component counts and the representative gas service emission factors.

Table 9-4. Average Component Count for Natural Gas Well Site Model Plant
                                   Equipment
                         Model Plant Equipment Counts
                   Average Component Count per Equipment[a]
                    Average Component Count per Model Plant

                                    Valves
                                  Connectors
                                     OELs
                                     PRVs
                                    Valves
                                  Connectors
                                     OELs
                                     PRVs
Gas Wellheads
                                       2
                                       9
                                      37
                                       1
                                       0
                                      19
                                      74
                                       1
                                       0
Separators
                                       2
                                      22
                                      68
                                       4
                                       1
                                      43
                                      137
                                       7
                                       2
Meters/Piping
                                       1
                                      13
                                      48
                                       0
                                       0
                                      13
                                      48
                                       0
                                       0
In-Line Heaters
                                       1
                                      14
                                      65
                                       2
                                       1
                                      14
                                      65
                                       2
                                       1
Dehydrators
                                       1
                                      24
                                      90
                                       2
                                       2
                                      24
                                      90
                                       2
                                       2
                                                                          Total
                                      113
                                      414
                                      12
                                       5
                                                               Rounded up Total
                                      114
                                      414
                                      14
                                       6
[a] Data Source: EPA/GRI, CH4 Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks, Table 4-4 and 4-7, June 1996. (EPA-600/R-96-080h)

Table 9-5. Average Component Count for Oil Well Site Model Plant
                                   Equipment
                         Model Plant Equipment Counts
                   Average Component Count per Equipment[a]
                    Average Component Count per Model Plant

                                    Valves
                                  Connectors
                                     OELs
                                     PRVs
                                    Valves
                                  Connectors
                                     OELs
                                     PRVs
Oil Wellheads
                                       2
                                       5
                                      18
                                       0
                                       0
                                      10
                                      36
                                       0
                                       0
Separators
                                       1
                                       6
                                      22
                                       0
                                       0
                                       6
                                      22
                                       0
                                       0
Headers
                                       1
                                       5
                                      14
                                       0
                                       0
                                       5
                                      14
                                       0
                                       0
Heater/Treaters
                                       1
                                       8
                                      32
                                       0
                                       0
                                       8
                                      32
                                       0
                                       0
                                                                          Total
                                      29
                                      104
                                       0
                                       0
                                                               Rounded up Total
                                      29
                                      104
                                       1
                                       1
[a] Data Source: EPA/GRI, CH4 Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks, Table 4-4 and 4-7, June 1996. (EPA-600/R-96-08
      Baseline emissions for the natural gas well site model plant were calculated using the equipment and fugitive emissions component counts and the representative gas service emission factors. Emissions were estimated using the EPA Protocol which provided total organic compound (TOC) emission factors for production sources (well sites, gathering and boosting). Annual emissions were calculated assuming 8,760 hours of operation each year. Table 9-6 presents the emission factors for the natural gas and oil production segments.
Emissions of VOC were calculated using weight ratios for VOC as described in the

2000 Gas Composition Memorandum developed for the 2012 NSPS. A summary of the equipment counts, and average TOC emission factors and VOC emissions for natural gas and oil well sites are provided in Tables 9-7 and 9-8, respectively. Using these data, the average fugitive emissions from a gas well model plant was determined to be 1.26 tpy of VOC and the average fugitive emissions from an oil well model plant was determined to be 0.302 tpy of VOC. The VOC emission estimates were used to evaluate the potential emission reductions and cost of control of a fugitive emissions reduction program.

Table 9-6. Oil and Natural Gas Production Operations Average TOC Emission Factors
                                Component Type
                               Component Service
                            TOC Emission Factor[a]
                                (kg/hr/source)
Valves
                                      Gas
                                    4.5E-03
Connectors
                                      Gas
                                    2.0E-04
OEL
                                      Gas
                                    2.0E-03
PRV
                                      Gas
                                    8.8E-03
                 [a] Data Source: EPA, Protocol for Equipment Leak Emission Estimates, Table 2-4, November 1995. (EPA-453/R-95-017)

Table 9-7. Estimated Fugitive VOC Emissions for Natural Gas Production Model Plant
                  Natural Gas Well Site Model Plant Component
                        Model Plant Component Count[a]
                      Uncontrolled TOC Emission Factor[b]
                                 (kg/hr/comp)
                          Uncontrolled VOC Emissions
                                   (tpy)[c]
 Valves
                                      114
                                    0.0045
                                     0.957
 Connectors
                                      414
                                    0.0002
                                     0.154
 OELs
                                      14
                                     0.002
                                     0.052
 PRVs
                                       6
                                    0.0088
                                     0.098
                                                                          Total
                                     1.26
     [a] Component count values for model plant are based on a 2 wellhead pad and are rounded to the nearest integer.
     [b] TOC emission factors obtained from Table 2-4 for the EPA Equipment Leaks Protocol for components in gas service.
     [c] VOC emissions calculated using 0.193 weight ratio for VOC/TOC obtained from the 2011 Gas Composition Memorandum.

Table 9-8. Estimated Fugitive VOC Emissions for Oil Well Site Model Plant
                  Natural Gas Well Site Model Plant Component
                        Model Plant Component Count[a]
                      Uncontrolled TOC Emission Factor[b]
                                 (kg/hr/comp)
                          Uncontrolled VOC Emissions
                                   (tpy)[c]
 Valves
                                      29
                                    0.0045
                                     0.243
 Connectors
                                      104
                                    0.0002
                                     0.039
 OELs
                                       1
                                     0.002
                                     0.004
 PRVs
                                       1
                                    0.0088
                                     0.016
                                                                          Total
                                     0.302
    [a] Component count values for model plant are based on a 2 wellhead pad and are rounded to the nearest integer.
    [b] TOC emission factors obtained from Table 2-4 for the EPA Equipment Leaks Protocol for components in gas service.
    [c] VOC emissions calculated using 0.193 weight ratio for VOC/TOC obtained from the 2011 Gas Composition Memorandum.

       Annual emissions were calculated assuming 8,760 hours of operation each year. Table 9-6 presents the emission factors for the natural gas and oil production segments.
      Emissions of VOC were calculated using weight ratios for VOC as described in the
Gathering and Boosting Stations
      Gathering and boosting stations are sites that collect natural gas from well sites and direct them to the natural gas processing plants. These stations have similar equipment to well sites; however they are not directly connected to the wellheads. The gathering and boosting station model plant was developed using the average equipment and fugitive emissions component counts for production from the EPA/GRI study. The average equipment counts for a gathering and boosting station were estimated by weighting the average of equipment counts for the Eastern and Western U.S. data sets for production equipment. The weighted averages of the data sets were determined to be 11 separators, 7 meters/piping, 5 gathering compressors, 7 in-line heaters, and 5 dehydrators. Fugitive emissions component counts for each of the production equipment items were calculated using the average component counts for production equipment in the Eastern U.S and the Western U.S. from the EPA/GRI study. The components for gathering compressors were included in the model plant total counts, but the compressor seals were excluded. Compressors seals are addressed in chapter 8 of this document. Table 9-9 presents a summary of the fugitive emissions component counts for gathering and boosting stations.
      Baseline emissions were calculated using the component counts and the TOC emission factors for oil and natural gas production (See Table 9-6). Table 9-10 summarizes the baseline emissions for gathering and boosting stations. The average fugitive emissions from a gathering and boosting station were determined to be 9.8 tpy of VOC. The VOC emission estimate was used to evaluate the potential emission reductions and cost of control of a fugitive emissions reduction program.

Table 9-9. Average Component Count for the Oil and Natural Gas Production Gathering and Boosting Station Model Plant
                                   Equipment
                        Model Plant Equipment Counts
                   Average Component Count per Equipment[a]
                    Average Component Count per Model Plant

                                    Valves
                                  Connectors
                               Open-Ended Lines
                            Pressure Relief Valves
                                    Valves
                                  Connectors
                               Open-Ended Lines
                            Pressure Relief Valves
Separators
                                      11
                                      22
                                      68
                                       4
                                       1
                                      242
                                      748
                                      44
                                      11
Meters/Piping
                                       7
                                      13
                                      48
                                       0
                                       0
                                      91
                                      336
                                       0
                                       0
Gathering Compressors
                                       5
                                      71
                                      175
                                       3
                                       4
                                      355
                                      875
                                      15
                                      20
In-Line Heaters
                                       7
                                      14
                                      65
                                       2
                                       1
                                      98
                                      455
                                      14
                                       7
Dehydrators
                                       5
                                      24
                                      90
                                       2
                                       2
                                      120
                                      450
                                      10
                                      10
                                                                        Total
                                      906
                                     2,864
                                      83
                                      48
a Data Source: EPA/GRI, Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks, Table 4-4 and 4-7, June 1996. (EPA-600/R-96-080h)

Table 9-10. Estimated Fugitive TOC and VOC Emissions for the Oil and Natural Gas Production Gathering and Boosting Station Model Plant
                                   Component
                        Model Plant Component Count[a]
                         Component TOC Emission Factor
                             (kg/hr/ component)[b]
                          VOC Emissions (tons/yr)[c]
Valve
                                      906
                                    0.0045
                                      7.6
Connectors
                                     2,864
                                    0.0002
                                      1.1
OEL
                                      83
                                     0.002
                                      0.3
PRV
                                      48
                                    0.0088
                                      0.8
                                                                          Total
                                      9.8
       [a] Component counts from Table 9-7. Component count values for model plant are based on 2 wellhead sites
        and are rounded to the nearest integer.
       b TOC emission factors obtained from Table 2-4 for the EPA Equipment Leaks Protocol for components in gas service.
       [c] VOC emissions calculated using 0.193 weight ratio for VOC/TOC obtained from the 2011 Gas Composition memorandum.
9.3	Available Controls and Regulatory Approaches
9.3.1	Available VOC Emission Control Options