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Oil and Natural Gas Sector: Standards of
Performance for Crude Oil and Natural
Gas Production, Transmission, and
Distribution.
Background Technical Support Document for Proposed Standards
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EPA-453/R-11-002
July 2011
Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas
Production, Transmission, and Distribution.
By:
EC/R, Incorporated
501 Eastowne Dr, Suite 250
Chapel Hill, North Carolina 27514
Prepared for:
Bruce Moore, Project Officer
Office of Air Quality Planning and Standards
Sector Policies and Programs Division
Contract No. EP-D-07-061
Work Order No. 4-06
U.S. Environmental Protection Agency
Office of Air and Radiation
Office of Air Quality Planning and Standards
Research, Triangle Park, North Carolina
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DISCLAIMER
This report has been reviewed by EPA's Office of Air Quality Planning and Standards and has been
approved for publication. Mention of trade names or commercial products is not intended to constitute
endorsement or recommendation for use.
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FOREWORD
This background technical support document (TSD) provides information relevant to the proposal of
New Source Performance Standards (NSPS) for limiting VOC emissions from the Oil and Natural Gas
Sector. The proposed standards were developed according to section 11 l(b)(l)(B) under the Clean Air
Act, which requires EPA to review and revise, is appropriate, NSPS standards. The NSPS review allows
EPA to identify processes in the oil and natural sector that are not regulated under the existing NSPS but
may be appropriate to regulate under NSPS based on new information. This would include processes
that emit the current regulated pollutants, VOC and SO2, as well as any additional pollutants that are
identified. This document is the result of that review process. Chapter 1 provides introduction on NSPS
regulatory authority. Chapter 2 presents an overview of the oil and natural gas sector. Chapter 3
discusses the entire NSPS review process undertaken for this review. Finally, Chapters 4-8 provide
information on previously unregulated emissions sources. Each chapter describes the emission source,
the estimated emissions (on average) from these sources, potential control options identified to reduce
these emissions and the cost of each control option identified. In addition, secondary impacts are
estimated and the rationale for the proposed NSPS for each emission source is provided.
in
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TABLE OF CONTENTS
l.ONEW SOURCE PERFORMANCE BACKGROUND 1-1
1.1 Statutory Authority 1-1
1.2 History of Oil and Gas Source Category 1-2
1.3 NSPS Review Process 1-2
2.0SECTOR DESCRIPTION 2-1
3.0NEW SOURCE PERFORMANCE REVIEW PROCESS 3-1
3. lEvaluation of BSER for Existing NSPS 3-1
3.1.1 BSER for VOC Emissions from Equipment Leaks at Natural Gas Processing Plants 3-1
3.1.2 BSER for SO2 Emissions from Sweetening Units at Natural Gas Processing Plants 3-3
3.2 Additional Pollutants 3-5
3.3 Additional Processes 3-6
4.0 WELL COMPLETIONS AND RECOMPLETIONS 4-1
4.1Process Description 4-1
4.1.1 Oil and Gas Well Completions 4-1
4.1.2 Oil and Gas Well Recompletions 4-2
4.2.Emission Data and Emissions Factors 4-3
4.2.1 Summary of Major Studies and Emission Factors 4-3
4.2.2 Representative Completion and Recompletion Emissions 4-6
4.3 Nationwide Emissions from New Sources 4-8
4.3.1 Overview of Approach 4-8
4.3.2 Number of Completions and Recompletions 4-8
4.3.3 Level of Controlled Sources in Absence of Federal Regulation 4-10
4.3.4 Emission Estimates 4-12
4.4 Control Techniques 4-12
4.4.1 Potential Control Techniques 4-12
4.4.2 Reduced Emission Completions and Recompletions 4-14
4.4.2.1 Description 4-14
4.4.2.2 Effectiveness 4-15
4.4.2.3 Cost Impacts 4-15
4.4.2.4 Secondary Impacts 4-18
4.4.3Completion Combustion Devices 4-18
4.4.3.1 Description 4-18
4.4.3.2 Effectiveness 4-19
4.4.3.3 Cost Impacts 4-19
4.4.3.4Secondary Impacts 4-20
4.5 Regulatory Options 4-22
4.5.1 Evaluation of Regulatory Options 4-24
4.5.2 Nationwide Impacts of Regulatory Options 4-27
4.5.2.1 Primary Environmental Impacts of Regulatory Options 4-27
4.5.2.2 Cost Impacts 4-28
4.5.2.3 Secondary Impacts 4-30
4.6 References 4-32
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5.0 PNEUMATIC CONTROLLERS 5-1
5.1 Process Description 5-1
5.2. Emission Data and Emissions Factors 5-3
5.2.1 Summary of Major Studies and Emission Factors 5-3
5.2.2 Representative Controller Emissions 5-3
5.3 Nationwide Emissions from New Sources 5-5
5.3.1 Overview of Approach 5-5
5.3.2 Population of Devices Installed Annually 5-5
5.3.3 Emission Estimates 5-9
5.4 Control Techniques 5-9
5.4.1 Potential Control Techniques 5-9
5.4.2 Low Bleed Controllers 5-12
5.4.2.1 Emission Reduction Potential 5-12
5.4.2.2 Effectiveness 5-12
5.4.2.3 Cost Impacts 5-14
5.4.2 A Secondary Impacts 5-16
5.4.3 Instrument Air Systems 5-16
5.4.3.1 Description 5-16
5.4.3.2 Effectiveness 5-18
5.4.3.3 Cost Impacts 5-19
5.4.3.4 Secondary Impacts 5-22
5.5 Regulatory Option 5-22
5.5.1 Evaluation of Regulatory Options 5-22
5.5.2 Nationwide Impacts of Regulatory Options 5-24
5.6 References 5-26
6.0 COMPRESSORS 6-1
6.1 Process Description 6-1
6.1.1 Reciprocating Compressors 6-1
6.1.2 Centrifugal Compressors 6-2
6.2. Emission Data and Emissions Factors 6-2
6.2.1 Summary of Major Studies and Emission Factors 6-2
6.2.2 Representative Reciprocating and Centrifugal Compressor Emissions 6-2
6.3 Nationwide Emissions from New Sources 6-6
6.3.1 Overview of Approach 6-6
6.3.2 Activity Data for Reciprocating Compressors 6-6
6.3.2.1 Wellhead Reciprocating Compressors 6-6
6.3.2.2 Gathering and Boosting Reciprocating Compressors 6-8
6.3.2.3 Processing Reciprocating Compressors 6-8
6.3.2.4 Transmission and Storage Reciprocating Compressors 6-9
6.3.3 Level of Controlled Sources in Absence of Federal Regulation 6-9
6.3.4 Emission Estimates 6-9
6.4 Control Techniques 6-11
6.4.1 Potential Control Techniques 6-11
6.4.2 Reciprocating Compressor Rod Packing Replacement 6-12
6.4.2.1 Description 6-12
6.4.2.2 Effectiveness 6-12
6.4.2.3 Cost Impacts 6-16
6.4.2.4 Secondary Impacts 6-18
6.4.3 Centrifugal Compressor Dry Seals 6-18
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6.4.3.1 Description 6-18
6.4.3.2 Effectiveness 6-19
6.4.3.3 Cost Impacts 6-19
6.4.3.4 Secondary Impacts 6-21
6.4.4 Centrifugal Compressor Wet Seals with a Flare 6-21
6.4.4.1 Description 6-21
6.4.4.2 Effectiveness 6-23
6.4.4.3 Cost Impacts 6-23
6.4.4.4 Secondary Impacts 6-23
6.5 Regulatory Options 6-23
6.5.1 Evaluation of Regulatory Options 6-27
6.5.2 Nationwide Impacts of Regulatory Options 6-28
6.6 References 6-31
7.0 STORAGE VESSELS 7-1
7.1 Process Description 7-2
7.2. Emission Data 7-2
7.2.1 Summary of Major Studies and Emission Factors 7-2
7.2.2 Representative Storage Vessel Emissions 7-2
7.2.2.1 Model Condensate Tank Batteries 7-2
7.2.2.2 Model Crude Oil Tank Batteries 7-4
7.2.2.3 VOC Emissions from Model Condensate and Crude Oil Storage Vessels 7-4
7.3 Nationwide Emissions from New Sources 7-10
7.3.1 Overview of Approach 7-10
7.3.2 Number of New Storage Vessels Expected to be Constructed or Reconstructed 7-10
7.3.3 Level of Controlled Sources in Absence of Federal Regulation 7-10
7.3.4 Nationwide Emission Estimates for New or Modified Storage Vessels 7-12
7.4 Control Techniques 7-12
7.4.1 Potential Control Techniques 7-12
7.4.2 Vapor Recovery Units 7-12
7.4.2.1 Description 7-12
7.4.2.2 Effectiveness 7-13
7.4.2.3 Cost Impacts 7-13
7.4.2.4 Secondary Impacts 7-13
7.4.3 Combustors 7-15
7.4.3.1 Description and Effectiveness 7-15
7.4.3.2 Cost Impacts 7-15
7.4.3.3 Secondary Impacts 7-15
7.5 Regulatory Options 7-18
7.5.1 Evaluation of Regulatory Options 7-18
7.5.2 Nationwide Impacts of Regulatory Options 7-22
7.5.3 Primary Environmental Impacts of Regulatory Options Impacts 7-22
7.5.4 Cost Impacts 7-24
7.6 References 7-26
8.0 EQUIPMENT LEAKS 8-1
8.1 Process Description 8-1
8.2. Emission Data and Emissions Factors 8-1
8.2.1 Summary of Major Studies and Emission Factors 8-1
8.2.2 Model Plant 8-2
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8.2.2.1 Oil and Natural Gas Production 8-2
8.2.2.2 Oil and Natural Gas Processing 8-9
8.2.2.3 Natural Gas Transmission 8-9
8.3 Nationwide Emissions from New Sources 8-9
8.3.1 Overview of Approach 8-9
8.3.2 Activity Data 8-13
8.3.2.1 Well Pads 8-13
8.3.2.2 Gathering and Boosting 8-13
8.3.2.3 Processing Facilties 8-16
8.3.2.4 Transmission and Storage Facilties 8-16
8.3.4 Emission Estimates 8-16
8.4 Control Techniques 8-18
8.4.1 Potential Control Techniques 8-18
8.4.2 Subpart VVa LDAR Program 8-21
8.4.2.1 Description 8-21
8.4.2.2 Effectiveness 8-21
8.4.2.3 Cost Impacts 8-23
8.4.2.4 Secondary Impacts 8-26
8.4.3 LDAR with Optical Gas Imaging 8-31
8.4.3.1 Description 8-31
8.4.3.2 Effectiveness 8-31
8.4.3.3 Cost Impacts 8-31
8.4.3.4 Secondary Impacts 8-34
8.4.4 Modified Alternative Work Practice with Optical Gas Imaging 8-34
8.4.4.1 Description 8-34
8.4.4.2 Effectiveness 8-34
8.4.4.3 Cost Impacts 8-35
8.4.4.4 Secondary Impacts 8-35
8.5 Regulatory Options 8-37
8.5.1 Evaluation of Regulatory Options for Equipment Leaks 8-37
8.5.1.1 Well Pads 8-37
8.5.1.2 Gathering and Boosting 8-38
8.5.1.3 Processing Facilties 8-39
8.5.1.4 Transmission and Storage Facilties 8-39
8.5.2 Nationwide Impacts of Regulatory Options 8-40
8.6 References 8-42
APPENDIX A
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1.0 NEW SOURCE PERFORMANCE STANDARD BACKGROUND
Standards of performance for new stationary sources are established under section 111 of the Clean Air
Act (42 U.S.C. 7411), as amended in 1977. Section 111 directs the Administrator to establish standards
of performance for any category of new stationary sources of air pollution which "... causes or
contributes significantly to air pollution which may reasonably be anticipated to endanger public health
or welfare." This technical support document (TSD) supports the proposed standards, which would
control volatile organic compounds (VOC) and sulfur dioxide (862) emissions from the oil and natural
gas sector.
1.1 Statutory Authority
Section 111 of the Clean Air Act (CAA) requires the Environmental Protection Agency Administrator to
list categories of stationary sources, if such sources cause or contribute significantly to air pollution
which may reasonably be anticipated to endanger public health or welfare. The EPA must then issue
performance standards for such source categories. A performance standard reflects the degree of
emission limitation achievable through the application of the "best system of emission reduction"
(BSER) which the EPA determines has been adequately demonstrated. The EPA may consider certain
costs and nonair quality health and environmental impact and energy requirements when establishing
performance standards. Whereas CAA section 112 standards are issued for existing and new stationary
sources, standards of performance are issued for new and modified stationary sources. These standards
are referred to as new source performance standards (NSPS). The EPA has the authority to define the
source categories, determine the pollutants for which standards should be developed, identify the
facilities within each source category to be covered and set the emission level of the standards.
CAA section 11 l(b)(l)(B) requires the EPA to "at least every 8 years review and, if appropriate, revise"
performance standards unless the "Administrator determines that such review is not appropriate in light
of readily available information on the efficacy" of the standard. When conducting a review of an
existing performance standard, the EPA has discretion to revise that standard to add emission limits for
pollutants or emission sources not currently regulated for that source category.
In setting or revising a performance standard, CAA section 11 l(a)(l) provides that performance
standards are to "reflect the degree of emission limitation achievable through the application of the best
system of emission reduction which (taking into account the cost of achieving such reduction and any
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non-air quality health and environmental impact and energy requirements) the Administrator determines
has been adequately demonstrated." This level of control is referred to as the best system of emission
reduction (BSER). In determining BSER, a technology review is conducted that identifies what emission
reduction systems exist and how much the identified systems reduce air pollution in practice. For each
control system identified, the costs and secondary air benefits (or disbenefits) resulting from energy
requirements and non-air quality impacts such as solid waste generation are also evaluated. This analysis
determines BSER. The resultant standard is usually a numerical emissions limit, expressed as a
performance level (i.e., a rate-based standard or percent control), that reflects the BSER. Although such
standards are based on the BSER, the EPA may not prescribe a particular technology that must be used
to comply with a performance standard, except in instances where the Administrator determines it is not
feasible to prescribe or enforce a standard of performance. Typically, sources remain free to elect
whatever control measures that they choose to meet the emission limits. Upon promulgation, a NSPS
becomes a national standard to which all new, modified or reconstructed sources must comply.
1.2 History of Oil and Natural Gas Source Category
In 1979, the EPA listed crude oil and natural gas production on its priority list of source categories for
promulgation of NSPS (44 FR 49222, August 21, 1979). On June 24, 1985 (50 FR 26122), the EPA
promulgated a NSPS for the source category that addressed volatile organic compound (VOC) emissions
from leaking components at onshore natural gas processing plants (40 CFR part 60, subpart KKK). On
October 1, 1985 (50 FR 40158), a second NSPS was promulgated for the source category that regulates
sulfur dioxide (SO2) emissions from natural gas processing plants (40 CFR part 60, subpart LLL). Other
than natural gas processing plants, EPA has not previously set NSPS for a variety of oil and natural gas
operations. These NSPS are relatively narrow in scope as they address emissions only at natural gas
processing plants. Specifically, subpart KKK addresses VOC emissions from leaking equipment at
onshore natural gas processing plants, and subpart LLL addresses SO2 emissions from natural gas
processing plants.
1.3 NSPS Review Process Overview
CAA section 11 l(b)(l)(B) requires EPA to review and revise, if appropriate, NSPS standards. First, the
existing NSPS were evaluated to determine whether it reflects BSER for the emission affected sources.
This review was conducted by examining control technologies currently in use and assessing whether
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these technologies represent advances in emission reduction techniques compared to the technologies
upon which the existing NSPS are based. For each new control technology identified, the potential
emission reductions, costs, secondary air benefits (or disbenefits) resulting from energy requirements
and non-air quality impacts such as solid waste generation are evaluated. The second step is evaluating
whether there are additional pollutants emitted by facilities in the oil and natural gas sector that
contribute significantly to air pollution and may reasonably be anticipated to endanger public health or
welfare. The final review step is to identify additional processes in the oil and natural gas sector that are
not covered under the existing NSPS but may be appropriate to develop NSPS based on new
information. This would include processes that emit the current regulated pollutants, VOC and SC>2, as
well as any additional pollutants that are identified. The entire review process is described in Chapter 3.
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2.0 OIL AND NATURAL GAS SECTOR OVERVIEW
The oil and natural gas sector includes operations involved in the extraction and production of oil and
natural gas, as well as the processing, transmission and distribution of natural gas. Specifically for oil,
the sector includes all operations from the well to the point of custody transfer at a petroleum refinery.
For natural gas, the sector includes all operations from the well to the customer. The oil and natural gas
operations can generally be separated into four segments: (1) oil and natural gas production, (2) natural
gas processing, (3) natural gas transmission and (4) natural gas distribution. Each of these segments is
briefly discussed below.
Oil and natural gas production includes both onshore and offshore operations. Production operations
include the wells and all related processes used in the extraction, production, recovery, lifting,
stabilization, separation or treating of oil and/or natural gas (including condensate). Production
components may include, but are not limited to, wells and related casing head, tubing head and
"Christmas tree" piping, as well as pumps, compressors, heater treaters, separators, storage vessels,
pneumatic devices and dehydrators. Production operations also include well drilling, completion and
recompletion processes; which includes all the portable non-self-propelled apparatus associated with
those operations. Production sites include not only the "pads" where the wells are located, but also
include stand-alone sites where oil, condensate, produced water and gas from several wells may be
separated, stored and treated. The production sector also includes the low pressure, small diameter,
gathering pipelines and related components that collect and transport the oil, gas and other materials and
wastes from the wells to the refineries or natural gas processing plants. None of the operations upstream
of the natural gas processing plant (i.e. from the well to the natural gas processing plant) are covered by
the existing NSPS. Offshore oil and natural gas production occurs on platform structures that house
equipment to extract oil and gas from the ocean or lake floor and that process and/or transfer the oil and
gas to storage, transport vessels or onshore. Offshore production can also include secondary platform
structures connected to the platform structure, storage tanks associated with the platform structure and
floating production and offloading equipment.
There are three basic types of wells: Oil wells, gas wells and associated gas wells. Oil wells can have
"associated" natural gas that is separated and processed or the crude oil can be the only product
processed. Once the crude oil is separated from the water and other impurities, it is essentially ready to
be transported to the refinery via truck, railcar or pipeline. The oil refinery sector is considered
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separately from the oil and natural gas sector. Therefore, at the point of custody transfer at the refinery,
the oil leaves the oil and natural gas sector and enters the petroleum refining sector.
Natural gas is primarily made up of methane. However, whether natural gas is associated gas from oil
wells or non-associated gas from gas or condensate wells, it commonly exists in mixtures with other
hydrocarbons. These hydrocarbons are often referred to as natural gas liquids (NGL). They are sold
separately and have a variety of different uses. The raw natural gas often contains water vapor, hydrogen
sulfide (H2S), carbon dioxide (€62), helium, nitrogen and other compounds. Natural gas processing
consists of separating certain hydrocarbons and fluids from the natural gas to produced "pipeline
quality" dry natural gas. While some of the processing can be accomplished in the production segment,
the complete processing of natural gas takes place in the natural gas processing segment. Natural gas
processing operations separate and recover natural gas liquids or other non-methane gases and liquids
from a stream of produced natural gas through components performing one or more of the following
processes: Oil and condensate separation, water removal, separation of natural gas liquids, sulfur and
CO2 removal, fractionation of natural gas liquid and other processes, such as the capture of CO2
separated from natural gas streams for delivery outside the facility. Natural gas processing plants are the
only operations covered by the existing NSPS.
The pipeline quality natural gas leaves the processing segment and enters the transmission segment.
Pipelines in the natural gas transmission segment can be interstate pipelines that carry natural gas across
state boundaries or intrastate pipelines, which transport the gas within a single state. While interstate
pipelines may be of a larger diameter and operated at a higher pressure, the basic components are the
same. To ensure that the natural gas flowing through any pipeline remains pressurized, compression of
the gas is required periodically along the pipeline. This is accomplished by compressor stations usually
placed between 40 and 100 mile intervals along the pipeline. At a compressor station, the natural gas
enters the station, where it is compressed by reciprocating or centrifugal compressors.
In addition to the pipelines and compressor stations, the natural gas transmission segment includes
underground storage facilities. Underground natural gas storage includes subsurface storage, which
typically consists of depleted gas or oil reservoirs and salt dome caverns used for storing natural gas.
One purpose of this storage is for load balancing (equalizing the receipt and delivery of natural gas). At
an underground storage site, there are typically other processes, including compression, dehydration and
flow measurement.
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The distribution segment is the final step in delivering natural gas to customers. The natural gas enters
the distribution segment from delivery points located on interstate and intrastate transmission pipelines
to business and household customers. The delivery point where the natural gas leaves the transmission
segment and enters the distribution segment is often called the "citygate." Typically, utilities take
ownership of the gas at the citygate. Natural gas distribution systems consist of thousands of miles of
piping, including mains and service pipelines to the customers. Distribution systems sometimes have
compressor stations, although they are considerably smaller than transmission compressor stations.
Distribution systems include metering stations, which allow distribution companies to monitor the
natural gas in the system. Essentially, these metering stations measure the flow of gas and allow
distribution companies to track natural gas as it flows through the system.
Emissions can occur from a variety of processes and points throughout the oil and natural gas sector.
Primarily, these emissions are organic compounds such as methane, ethane, VOC and organic hazardous
air pollutants (HAP). The most common organic HAP are n-hexane and BTEX compounds (benzene,
toluene, ethylbenzene and xylenes). Hydrogen sulfide and 862 are emitted from production and
processing operations that handle and treat sour gas1
In addition, there are significant emissions associated with the reciprocating internal combustion engines
and combustion turbines that power compressors throughout the oil and natural gas sector. However,
emissions from internal combustion engines and combustion turbines are covered by regulations specific
to engines and turbines and, thus, are not addressed in this action.
1 Sour gas is defined as natural gas with a maximum H2S content of 0.25 gr/100 scf (4ppmv) along with the presence of CO2
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Oil and Natural Gas Operations
Producing Wells
Drilling and Well Completion
Crude Oil to
Refineries
(not in this sector)
Gas Processing Plant
athering Lines
Gathering and Boosting
Compressors -
Underground
Storage
Transmission
Compressor
Stations—Jf^
' H —•
-~ -14* *
Li City Gate
Regulators
& Meters
Distribution Mains
Source: Adapted from American Gas Association and EPA Natural Gas STAR Program
Regulators & Meters
Production
& Processing
— * Transmission
& Storage
Transmission Pipeline *>
Large Volume Customer
Distribution
(not covered)
Residential Customers
Commercial Customer
Figure 2-1. Oil and Natural Gas Operations
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3.0 NEW SOURCE PERFORMANCE STANDARD REVIEW
As discussed in section 1.2, there are two NSPS that impact the oil and natural gas sector: (1) the NSPS
for equipment leaks of VOC at natural gas processing plants (subpart KKK) and (2) the NSPS for SO2
emissions from sweetening units located at natural gas processing plants (subpart LLL). Because they
only address emissions from natural gas processing plants, these NSPS are relatively narrow in scope.
Section 11 l(b)(l) of the CAA requires the EPA to review and revise, if appropriate, NSPS
standards. This review process consisted of the following steps:
1. Evaluation of the existing NSPS to determine whether they continue to reflect the BSER for the
emission sources that they address;
2. Evaluation of whether there were additional pollutants emitted by facilities in the oil and natural
gas sector that warrant regulation and for which there is adequate information to promulgate
standards of performance; and
3. Identification of additional processes in the oil and natural gas sector for which it would be
appropriate to develop performance standards, including processes that emit the currently
regulated pollutants as well as any additional pollutants identified in step two.
The following sections detail each of these steps.
3.1 Evaluation of BSER for Existing NSPS
Consistent with the obligations under CAA section 11 l(b), control options reflected in the current NSPS
for the Oil and Natural Gas source category were evaluated in order to distinguish if these options still
represent BSER. To evaluate the BSER options for equipment leaks the following was reviewed: EPA's
current leak detection and repair (LDAR) programs, the Reasonably Available Control Technology
(RACT)TBest Available Control Technology (BACT)/Lowest Achievable Emission Rate (LAER)
Clearinghouse (RBLC) database, and emerging technologies that have been identified by partners in the
Natural Gas STAR program.1
3.1.1 BSER for VOC Emissions from Equipment Leaks at Natural Gas Processing Plants
The current NSPS for equipment leaks of VOC at natural gas processing plants (40 CFR part 60, subpart
KKK) requires compliance with specific provisions of 40 CFR part 60, subpart VV, which is a LDAR
program, based on the use of EPA Method 21 to identify equipment leaks. In addition to the subpart VV
requirements, the LDAR requirements in 40 CFR part 60, subpart VVa were also reviewed. This LDAR
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program is considered to be more stringent than the subpart VV requirements, because it has lower
component leak threshold definitions and more frequent monitoring, in comparison to the subpart VV
program. Furthermore, subpart VVa requires monitoring of connectors, while subpart VV does not.
Options based on optical gas imaging were also reviewed.
The currently required LDAR program for natural gas processing plants (40 CFR part 60, subpart KKK)
is based on EPA Method 21, which requires the use of an organic vapor analyzer to monitor components
and to measure the concentration of the emissions in identifying leaks. Although there have been
advancements in the use of optical gas imaging to detect leaks from these same types of components,
these instruments do not yet provide a direct measure of leak concentrations. The instruments instead
provide a measure of a leak relative to an instrument specific calibration point. Since the promulgation
of 40 CFR part 60, subpart KKK (which requires Method 21 leak measurement monthly), the EPA has
updated the 40 CFR part 60 General Provisions to allow the use of advanced leak detection tools, such
as optical gas imaging and ultrasound equipment as an alternative to the LDAR protocol based on
Method 21 leak measurements (see 40 CFR 60.18(g)). The alternative work practice allowing use of
these advanced technologies includes a provision for conducting a Method 21-based LDAR check of the
regulated equipment annually to verify good performance.
In considering BSER for VOC equipment leaks at natural gas processing plants, four options were
evaluated. One option evaluated consists of changing from a 40 CFR part 60, subpart VV-level program,
which is what 40 CFR part 60, subpart KKK currently requires, to a 40 CFR part 60, subpart VVa
program, which applies to new synthetic organic chemical plants after 2006. Subpart VVa lowers the
leak definition for valves from 10,000 parts per million (ppm) to 500 ppm, and requires the monitoring
of connectors. In our analysis of these impacts, it was estimated that, for a typical natural gas processing
plant, the incremental cost effectiveness of changing from the current subpart VV-level program to a
subpart VVa-level program using Method 21 is $3,352 per ton of VOC reduction.
In evaluating 40 CFR part 60, subpart VVa-level LDAR at processing plants, the individual types of
components (valves, connectors, pressure relief devices and open-ended lines) were also analyzed
separately to determine cost effectiveness for individual components. Detailed discussions of these
component-by-component analyses are provided in Chapter 8. Cost effectiveness ranged from $144 per
ton of VOC (for valves) to $4,360 per ton of VOC (for connectors), with no change in requirements for
pressure relief devices and open-ended lines.
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Another option evaluated for gas processing plants was the use of optical gas imaging combined with an
annual EPA Method 21 check (i.e., the alternative work practice for monitoring equipment for leaks at
40 CFR 60.18(g)). It was previously determined that the VOC reduction achieved by this combination of
optical gas imaging and Method 21 would be equivalent to reductions achieved by the 40 CFR part 60,
subpart VVa-level program. Based on the emission reduction level, the cost effectiveness of this option
was estimated to be $6,462 per ton of VOC reduction. This analysis was based on the facility purchasing
an optical gas imaging system costing $85,000. However, at least one manufacturer was identified that
rents the optical gas imaging systems. That manufacturer rents the optical gas imaging system for
$3,950 per week. Using this rental cost in place of the purchase cost, the VOC cost effectiveness of the
monthly optical gas imaging combined with annual Method 21 inspection visits is $4,638 per ton of
VOC reduction.1
A third option evaluated consisted of monthly optical gas imaging without an annual Method 21 check.
The annual cost of the monthly optical gas imaging LDAR program was estimated to be $76,581 based
on camera purchase, or $51,999 based on camera rental. However, it is not possible to quantify the VOC
emission reductions achieved by an optical imaging program alone, therefore the cost effectiveness of
this option could not be determined. Finally, a fourth option was evaluated that was similar to the third
option, except that the optical gas imaging would be performed annually rather than monthly. For this
option, the annual cost was estimated to be $43,851, based on camera purchase, or $18,479, based on
cam era rental.
Because the cost effectiveness of options 3 and 4 could not be estimated, these options could not be
identified as BSER for reducing VOC leaks at gas processing plants. Because options 1 and 2 achieve
equivalent VOC reduction and are both cost effective, both options 1 and 2 reflect BSER for LDAR for
natural gas processing plants. As mentioned above, option 1 is the LDAR in 40 CFR part 60, subpart
VVa and option 2 is the alternative work practice at 40 CFR 60.18(g) and is already available to use as
an alternative to subpart VVa LDAR.
3.1.2 BSER for SO2 Emissions from Sweetening Units at Natural Gas Processing Plants
For 40 CFR part 60, subpart LLL, control systems for SO2 emissions from sweetening units located at
natural gas processing plants were evaluated, including those followed by a sulfur recovery unit. Subpart
'Because optical gas imaging is used to view multiple pieces of equipment at a facility during one leak survey, options
involving imaging are not amenable to a component by component analysis.
3-3
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LLL provides specific standards for 862 emission reduction efficiency, on the basis of sulfur feed rate
and the sulfur content of the natural gas.
According to available literature, the most widely used process for converting H^S in acid gases (i.e.,
H2S and CC>2) separated from natural gas by a sweetening process (such as amine treating) into
elemental sulfur is the Claus process. Sulfur recovery efficiencies are higher with higher concentrations
of H2S in the feed stream due to the thermodynamic equilibrium limitation of the Claus process. The
Claus sulfur recovery unit produces elemental sulfur from H2S in a series of catalytic stages, recovering
up to 97-percent recovery of the sulfur from the acid gas from the sweetening process. Further, sulfur
recovery is accomplished by making process modifications or by employing a tail gas treatment process
to convert the unconverted sulfur compounds from the Claus unit.
In addition, process modifications and tail gas treatment options were also evaluated at the time 40 CFR
part 60, subpart LLL was proposed." As explained in the preamble to the proposed subpart LLL, control
through sulfur recovery with tail gas treatment may not always be cost effective, depending on sulfur
feed rate and inlet FL:S concentrations. Therefore, other methods of increasing sulfur recovery via
process modifications were evaluated.
As shown in the original evaluation for the proposed subpart LLL, the performance capabilities and
costs of each of these technologies are highly dependent on the ratio of FL:S and CO2 in the gas stream
and the total quantity of sulfur in the gas stream being treated. The most effective means of control was
selected as BSER for the different stream characteristics. As a result, separate emissions limitations were
developed in the form of equations that calculate the required initial and continuous emission reduction
efficiency for each plant. The equations were based on the design performance capabilities of the
technologies selected as BSER relative to the gas stream characteristics.111 The emission limit for sulfur
feed rates at or below 5 long tons per day, regardless of H2S content, was 79 percent. For facilities with
sulfur feed rates above 5 long tons per day, the emission limits ranged from 79 percent at an H2S content
below 10 percent to 99.8 percent for FL:S contents at or above 50 percent.
To review these emission limitations, a search was performed of the RBLC database1 and state
regulations. No State regulations were identified that included emission limitations more stringent than
40 CFR part 60, subpart LLL. However, two entries in the RBLC database were identified having SC>2
11 49 FR 2656, 2659-2660 (1984).
111 49 FR 2656, 2663-2664 (1984).
3-4
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emission reductions of 99.9 percent. One entry is for a facility in Bakersfield, California, with a 90 long
ton per day sulfur recovery unit followed by an amine-based tailgas treating unit. The second entry is for
a facility in Coden, Alabama, with a sulfur recovery unit with a feed rate of 280 long tons of sulfur per
day, followed by selective catalytic reduction and a tail gas incinerator. However, neither of these entries
contained information regarding the H2S contents of the feed stream. Because the sulfur recovery
efficiency of these large sized plants was greater than 99.8 percent, the original data was reevaluated.
Based on the available cost information, a 99.9 percent efficiency is cost effective for facilities with a
sulfur feed rate greater than 5 long tons per day and H2S content equal to or greater than 50 percent.
Based on this review, the maximum initial and continuous efficiency for facilities with a sulfur feed rate
greater than 5 long tons per day and a H2S content equal to or greater than 50 percent is raised to 99.9
percent.
The search of the RBLC database did not uncover information regarding costs and achievable emission
reductions to suggest that the emission limitations for facilities with a sulfur feed rate less than 5 long
tons per day or H2S content less than 50 percent should be modified. Therefore, there were not any
identifiable changes to the emissions limitations for facilities with sulfur feed rate and H2S content less
than 5 long tons per day and 50 percent, respectively.1
3.2 Additional Pollutants
The two current NSPS for the Oil and Natural Gas source category address emissions of VOC and SO2.
In addition to these pollutants, sources in this source category also emit a variety of other pollutants,
most notably, air toxics. However, there are NESHAP that address air toxics from the oil and natural gas
sector, specifically 40 CFR subpart HH and 40 CFR subpart HHH.
In addition, processes in the Oil and Natural Gas source category emit significant amounts of methane.
The 1990 - 2009 U.S. GHG Inventory estimates 2009 methane emissions from Petroleum and Natural
Gas Systems (not including petroleum refineries) to be 251.55 MMtCO2e (million metric tons of CO2-
equivalents (CO2e)).lv The emissions estimated from well completions and recompletions exclude a
significant number of wells completed in tight sand plays, such as the Marcellus, due to availability of
data when the 2009 Inventory was developed. The estimate in this proposal includes an adjustment for
tight sand plays (being considered as a planned improvement in development of the 2010 Inventory).
1V U.S. EPA. Inventory of U.S. Greenhouse Gas Inventory and Sinks. 1990 - 2009.
http://www.epa.gov/climatechange/emissions/downloadslO/US-GHGInventorv2010 ExecutiveSummary.pdf
3-5
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This adjustment would increase the 2009 Inventory estimate by 76.74 MMtCO2e. The total methane
emissions from Petroleum and Natural Gas Systems, based on the 2009 Inventory, adjusted for tight
sand plays and the Marcellus, is 328.29 MMtCO2e.
Although this proposed rule does not include standards for regulating the GHG emissions discussed
above, EPA continues to assess these significant emissions and evaluate appropriate actions for
addressing these concerns. Because many of the proposed requirements for control of VOC emissions
also control methane emissions as a co-benefit, the proposed VOC standards would also achieve
significant reduction of methane emissions.
Significant emissions of oxides of nitrogen (NOX) also occur at oil and natural gas sites due to the
combustion of natural gas in reciprocating engines and combustion turbines used to drive the
compressors that move natural gas through the system, and from combustion of natural gas in heaters
and boilers. While these engines, turbines, heaters and boilers are co-located with processes in the oil
and natural gas sector, they are not in the Oil and Natural Gas source category and are not being
addressed in this action. The NOX emissions from engines and turbines are covered by the Standards of
Performance for Stationary Spark Internal Combustion Engines (40 CFR part 60, subpart JJJJ) and
Standards of Performance for Stationary Combustion Turbines (40 CFR part 60, subpart KKKK),
respectively.
An additional source of NOX emissions would be pit flaring of VOC emissions from well completions.
As discussed in Chapter 4 Well completions, pit flaring is one option identified for controlling VOC
emissions. Because there is no way of directly measuring the NOX produced, nor is there any way of
applying controls other than minimizing flaring, flaring would only be required for limited conditions.
3.3 Additional Processes
The current NSPS only cover emissions of VOC and SO2 from one type of facility in the oil and natural
gas sector, which is the natural gas processing plant. This is the only type of facility in the Oil and
Natural Gas source category where SO2is expected to be emitted directly; although H^S contained in
sour gasv forms SO2 as a product of oxidation when oxidized in the atmosphere or combusted in boilers
and heaters in the field. These field boilers and heaters are not part of the Oil and Natural Gas source
category and are generally too small to be regulated by the NSPS covering boilers (i.e., they have a heat
v Sour gas is defined as natural gas with a maximum H2S content of 0.25 gr/100 scf (4ppmv) along with the presence of CO2.
3-6
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input of less than 10 million British Thermal Units per hour). They may, however, be included in future
rulemakings.
In addition to VOC emissions from gas processing plants, there are numerous sources of VOC
throughout the oil and natural gas sector that are not addressed by the current NSPS. Pursuant to CAA
section 11 l(b), a modification of the listed category will now include all segments of the oil and natural
gas industry for regulation. In addition, VOC standards will now cover additional processes at oil and
natural gas operations. These include NSPS for VOC from gas well completions and recompletions,
pneumatic controllers, compressors and storage vessels. In addition, produced water ponds may also be
a potentially significant source of emissions, but there is very limited information available regarding
these emissions. Therefore, no options could be evaluated at this time. The remainder of this document
presents the evaluation for each of the new processes to be included in the NSPS.
3.4 References
1 Memorandum to Bruce Moore from Brad Nelson and Phil Norwood. Crude Oil and Natural Gas
Production NSPS Technology Reviews. EC/R Incorporated. July 28, 2011.
3-7
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4.0 WELL COMPLETIONS AND RECOMPLETIONS
In the oil and natural gas sector, well completions and recompletions contain multi-phase processes with
various sources of emissions. One specific emission source during completion and recompletion
activities is the venting of natural gas to the atmosphere during flowback. Flowback emissions are short-
term in nature and occur as a specific event during completion of a new well or during recompletion
activities that involve re-drilling or re-fracturing an existing well. This chapter describes completions
and recompletions, and provides estimates for representative wells in addition to nationwide emissions.
Control techniques employed to reduce emissions from flowback gas venting during completions and
recompletions are presented, along with costs, emission reductions, and secondary impacts. Finally, this
chapter discusses considerations in developing regulatory alternatives for reducing flowback emissions
during completions and recompletions.
4.1 Process Description
4.1.1 Oil and Gas Well Completions
All oil and natural gas wells must be "completed" after initial drilling in preparation for production. Oil
and natural gas completion activities not only will vary across formations, but can vary between wells in
the same formation. Over time, completion and recompletion activities may change due to the evolution
of well characteristics and technology advancement. Conventional gas reservoirs have well defined
formations with high resource allocation in permeable and porous formations, and wells in conventional
gas reservoirs have generally not required stimulation during production. Unconventional gas reservoirs
are more dispersed and found in lower concentrations and may require stimulation (such as hydraulic
fracturing) to extract gas.1
Well completion activities include multiple steps after the well bore hole has reached the target depth.
These steps include inserting and cementing-in well casing, perforating the casing at one or more
producing horizons, and often hydraulically fracturing one or more zones in the reservoir to stimulate
production. Surface components, including wellheads, pumps, dehydrators, separators, tanks, and
gathering lines are installed as necessary for production to begin. The flowback stage of a well
r\
completion is highly variable but typically lasts between 3 and 10 days for the average well.
4-1
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Developmental wells are drilled within known boundaries of a proven oil or gas field, and are located
near existing well sites where well parameters are already recorded and necessary surface equipment is
in place. When drilling occurs in areas of new or unknown potential, well parameters such as gas
composition, flow rate, and temperature from the formation need to be ascertained before surface
facilities required for production can be adequately sized and brought on site. In this instance,
exploratory (also referred to as "wildcat") wells and field boundary delineation wells typically either
vent or combust the flowback gas.
One completion step for improving gas production is to fracture the reservoir rock with very high
pressure fluid, typically a water emulsion with a proppant (generally sand) that "props open" the
fractures after fluid pressure is reduced. Natural gas emissions are a result of the backflow of the fracture
fluids and reservoir gas at high pressure and velocity necessary to clean and lift excess proppant to the
surface. Natural gas from the completion backflow escapes to the atmosphere during the reclamation of
water, sand, and hydrocarbon liquids during the collection of the multi-phase mixture directed to a
surface impoundment. As the fracture fluids are depleted, the backflow eventually contains a higher
volume of natural gas from the formation. Due to the additional equipment and resources involved and
the nature of the backflow of the fracture fluids, completions involving hydraulic fracturing have higher
costs and vent substantially more natural gas than completions not involving hydraulic fracturing.
Hydraulic fracturing can and does occur in some conventional reservoirs, but it is much more common
in "tight" formations. Therefore, this analysis assumes hydraulic fracturing is performed in tight sand,
shale, and coalbed methane formations. This analysis defines tight sand as sandstones or carbonates with
an in situ permeability (flow rate capability) to gas of less than 0.1 millidarcy.1
"Energized fractures" are a relatively new type of completion method that injects an inert gas, such as
carbon dioxide or nitrogen, before the fracture fluid and proppant. Thus, during initial flowback, the gas
stream will first contain a high proportion of the injected gas, which will gradually decrease overtime.
4.1.2 Oil and Gas Well Recompletions
Many times wells will need supplementary maintenance, referred to as recompletions (these are also
referred to as workovers). Recompletions are remedial operations required to maintain production or
minimize the decline in production. Examples of the variety of recompletion activities include
1A darcy (or darcy unit) and millidarcies (mD) are units of permeability Converted to SI units, 1 darcy is equivalent to
-,-13
9.869233 x 10 'J m2 or 0.9869233 (urn)2. This conversion is usually approximated as 1 (urn)2.
4-2
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completion of a new producing zone, re-fracture of a previously fractured zone, removal of paraffin
buildup, replacing rod breaks or tubing tears in the wellbore, and addressing a malfunctioning downhole
pump. During a recompletion, portable equipment is conveyed back to the well site temporarily and
some recompletions require the use of a service rig. As with well completions, recompletions are highly
specialized activities, requiring special equipment, and are usually performed by well service contractors
specializing in well maintenance. Any flowback event during a recompletion, such as after a hydraulic
fracture, will result in emissions to the atmosphere unless the flowback gas is captured.
When hydraulic re-fracturing is performed, the emissions are essentially the same as new well
completions involving hydraulic fracture, except that surface gas collection equipment will already be
present at the wellhead after the initial fracture. The backflow velocity during re-fracturing will typically
be too high for the normal wellhead equipment (separator, dehydrator, lease meter), while the
production separator is not typically designed for separating sand.
Backflow emissions are not a direct result of produced water. Backflow emissions are a result of free gas
being produced by the well during well cleanup event, when the well also happens to be producing
liquids (mostly water) and sand. The high rate backflow, with intermittent slugs of water and sand along
with free gas, is typically directed to an impoundment or vessels until the well is fully cleaned up, where
the free gas vents to the atmosphere while the water and sand remain in the impoundment or vessels.
Therefore, nearly all of the backflow emissions originate from the recompletion process but are vented
as the backflow enters the impoundment or vessels. Minimal amounts of emissions are caused by the
fluid (mostly water) held in the impoundment or vessels since very little gas is dissolved in the fluid
when it enters the impoundment or vessels.
4.2. Emission Data and Emissions Factors
4.2.1 Summary of Major Studies and Emission Factors
Given the potential for significant emissions from completions and recompletions, there have been
numerous recent studies conducted to estimate these emissions. In the evaluation of the emissions and
emission reduction options for completions and recompletions, many of these studies were consulted.
Table 4-1 presents a list of the studies consulted along with an indication of the type of information
contained in the study.
4-3
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Table 4-1. Major Studies Reviewed for Consideration of Emissions and Activity Data
Report Name
Greenhouse Gas Mandatory Reporting Rule
and Technical Supporting Documents 3
Inventory of Greenhouse Gas Emissions and
Sinks: 1990-2008 4'5
Methane Emissions from the Natural Gas
Industry6'7'8'9
Methane Emissions from the US Petroleum
Industry (Draft) 10
Methane Emissions from the US Petroleum
Industry u
Oil and Gas Emission Inventories for Western
States 12
Recommendations for Improvements to the
Central States Regional Air Partnership's Oil
and Gas Emission Inventories 13
Oil and Gas Producing Industry in Your
State14
Emissions from Natural Gas Production in the
Barnett Shale and Opportunities for Cost-
effective Improvements 15
Emissions from Oil and Natural Gas
Production Facilities 16
Availability, Economics and Production of
North American Unconventional Natural Gas
Supplies 1
Affiliation
EPA
EPA
Gas Research Institute
/US Environmental
Protection Agency
EPA
EPA
Western Regional Air
Partnership
Central States
Regional Air
Partnership
Independent
Petroleum Association
of America
Environmental
Defense Fund
Texas Commission for
Environmental Quality
Interstate Natural Gas
Association of
America
Year of
Report
2010
2010
1996
1996
1999
2005
2008
2009
2009
2007
2008
Activity
Factor(s)
Nationwide
Nationwide
Nationwide
Nationwide
Nationwide
Regional
Regional
Nationwide
Regional
Regional
Nationwide
Emission
Information
X
X
X
X
X
X
X
X
X
Control
Information
X
X
X
X
X
4-4
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Table 4-1. Major Studies Reviewed for Consideration of Emissions and Activity Data
Report Name
Petroleum and Natural Gas Statistical Data17
Preferred and Alternative Methods for
Estimating Air Emissions from Oil and Gas
Field Production and Processing Operations 18
Supplemental Generic Environmental Impact
Statement on the Oil, Gas and Solution
Mining Regulatory Program 19
Natural Gas STAR Program 20' 21' 22' 23' 24' 25
Affiliation
U.S. Energy
Information
Administration
EPA
New York State
Department of
Environmental
Conservation
EPA
Year of
Report
2007-
2009
1999
2009
2000-
2010
Activity
Factor(s)
Nationwide
Regional
Nationwide/
Regional
Emission
Information
X
X
X
Control
Information
X
X
4-5
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4.2.2 Representative Completion and Recompletion Emissions
As previously mentioned, one specific emission source during completion and recompletion activities is
the venting of natural gas to the atmosphere during flowback. Flowback emissions are short-term in
nature and occur as a specific event during the completion of a new well or during recompletion
activities that involve re-drilling or re-fracturing of an existing well. For this analysis, well completion
and recompletion emissions are estimated as the venting of emissions from the well during the initial
phases of well preparation or during recompletion maintenance and/or re-fracturing of an existing well.
As previously stated, this analysis assumes wells completed/recompleted with hydraulic fracturing are
found in tight sand, shale, or coal bed methane formations. A majority of the available emissions data
for recompletions is for vertically drilled wells. It is projected that in the future, a majority of
completions and recompletions will predominantly be performed on horizontal wells. However, there is
not enough history of horizontally drilled wells to make a reasonable estimation of the difference in
emissions from recompletions of horizontal versus vertical wells. Therefore, for this analysis, no
distinction was made between vertical and horizontal wells.
As shown in Table 4-1, methane emissions from oil and natural gas operations have been measured,
analyzed and reported in studies spanning the past few decades. The basic approach for this analysis was
to approximate methane emissions from representative oil and gas completions and recompletions and
then estimate volatile organic compounds (VOC) and hazardous air pollutants (HAP) using a
r\r
representative gas composition. The specific gas composition ratios used for gas wells were 0.1459
pounds (Ib) VOC per Ib methane (Ib VOC/lb methane) and 0.0106 Ib HAP/lb methane. The specific gas
composition ratios used for oil wells were 0.8374 pounds Ib VOC/lb methane and 0.0001 Ib HAP/lb
methane.
The EPA's analysis to estimate methane emissions conducted in support of the Greenhouse Gas
Mandatory Reporting Rule (Subpart W), which was published in the Federal Register on November 30,
2010 (75 FR 74458), was the foundation for methane emission estimates from natural gas completions
with hydraulic fracturing and recompletions with hydraulic fracturing. Methane emissions from oil well
completions, oil well recompletions, natural gas completions without hydraulic fracturing, and natural
gas recompletions without hydraulic fracturing were derived directly from the EPA's Inventory of
Greenhouse Gas Emissions and Sinks: 1990-2008 (Inventory).4 A summary of emissions for a
representative model well completion or recompletion is found in Table 4-2.
4-6
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Table 4-2. Uncontrolled Emissions Estimates from Oil and Natural Gas Well
Completions and Recompletions
Well Completion Category
Natural Gas Well Completion without
Hydraulic Fracturing
Natural Gas Well Completion with
Hydraulic Fracturing
Oil Well Completions
Natural Gas Well Recompletion without
Hydraulic Fracturing
Natural Gas Well Recompletion with
Hydraulic Fracturing
Oil Well Recompletions
Emissions
(Mcf/event)
Methane
38.6
7,623
0.34
2.59
7,623
0.057
Emissions
(tons/event)
Methane"
0.8038
158.55
0.0076
0.0538
158.55
0.00126
vocb
0.12
23.13
0.00071
0.0079
23.13
0.001
HAPC
0.009
1.68
0.0000006
0.0006
1.68
0.0000001
Minor discrepancies may exist due to rounding.
a. Reference 4, Appendix B., pgs 84-89. The conversion used to convert methane from volume to
weight is 0.0208 tons methane is equal to 1 Mcf of methane. It is assumed methane comprises
83.081 percent by volume of natural gas from gas wells and 46.732 percent by volume of
methane from oil wells.
b. Assumes 0.1459 Ib VOC /lb methane for natural gas wells and 0.8374 Ib VOC/lb methane for oil
wells.
c. Assumes 0.0106 lb HAP/lb methane for natural gas wells and 0.0001 lb HAP/lb methane for oil
wells.
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4.3 Nationwide Emissions from New Sources
4.3.1 Overvi ew of Approach
The first step in this analysis is to estimate nationwide emissions in absence of the proposed rulemaking,
referred to as the baseline emissions estimate. In order to develop the baseline emissions estimate, the
number of completions and recompletions performed in a typical year was estimated and then multiplied
by the expected uncontrolled emissions per well completion listed in Table 4-2. In addition, to ensure no
emission reduction credit was attributed to sources already controlled under State regulations, it was
necessary to account for the number of completions/recompletions already subject to State regulations as
detailed below. In order to estimate the number of wells that are already controlled under State
regulations, existing well data was analyzed to estimate the percentage of currently controlled wells.
This percentage was assumed to also represent the wells that would have been controlled in absence of a
federal regulation and applied to the number of well completions estimated for future years.
4.3.2 Number of Completions and Recompletions
The number of new well completions was estimated using the National Energy Modeling System
(NEMS). NEMS is a model of U.S. energy economy developed and maintained by the Energy
Information Administration (EIA). NEMS is used to produce the Annual Energy Outlook, a reference
publication that provides detailed forecasts of the energy economy from the current year to 2035. EIA is
legally required to make the NEMS source code available and fully documented for the public. The
source code and accompanying documentation is released annually when a new Annual Energy Outlook
is produced. Because of the availability of NEMS, numerous agencies, national laboratories, research
institutes, and academic and private-sector researchers have used NEMS to analyze a variety of issues.
NEMS models the dynamics of energy markets and their interactions with the broader U.S. economy.
The system projects the production of energy resources such as oil, natural gas, coal, and renewable
fuels, the conversion of resources through processes such as refining and electricity generation, and the
quantity and prices for final consumption across sectors and regions.
New well completion estimates are based on predictions from the NEMS Oil and Gas Supply Model,
drawing upon the same assumptions and model used in the Annual Energy Outlook 2011 Reference
Case. New well completions estimates were based on total successful wells drilled in 2015 (the year of
analysis for regulatory impacts) for the following well categories: natural gas completions without
hydraulic fracturing, natural gas completions with hydraulic fracturing, and oil well completions.
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Successful wells are assumed to be equivalent to completed wells. Meanwhile, it was assumed that new
dry wells would be abandoned and shut in and would not be completed. Therefore estimates of the
number of dry wells were not included in the activity projections or impacts discussion for exploratory
and developmental wells. Completion estimates are based on successful developmental and exploratory
wells for each category defined in NEMS that includes oil completions, conventional gas completions
and unconventional gas completions. The NEMS database defines unconventional reservoirs as those in
shale, tight sand, and coalbed methane formations and distinguishes those from wells drilled in
conventional reservoirs. Since hydraulic fracturing is most common in unconventional formations, this
analysis assumes new successful natural gas wells in shale, tight sand, and coalbed methane formations
are completed with hydraulic fracturing. New successful natural gas wells in conventional formations
are assumed to be completed without hydraulic fracturing.
The number of natural gas recompletions with hydraulic fracturing (also referred to as a re-fracture),
natural gas recompletions without hydraulic fracturing and oil well recompletions was based on well
count data found in the HPDI® database.11'm The HPDI database consists of oil and natural gas well
information maintained by a private organization that provides parameters describing the location,
operator, and production characteristics. HPDI® collects information on a well basis such as the operator,
state, basin, field, annual gas production, annual oil production, well depth, and shut-in pressure, all of
which is aggregated from operator reports to state governments. HPDI was used to estimate the number
of recompleted wells because the historical well data from HPDI is a comprehensive resource describing
existing wells. Well data from 2008 was used as a base year since it was the most recent available data
at the time of this analysis and is assumed to represent the number of recompletions that would occur in
a representative year. The number of hydraulically fractured natural gas recompletions was estimated by
estimating each operator and field combination found in the HPDI database and multiplying by 0.1 to
represent 10 percent of the wells being re-fractured annually (as assumed in Subpart W's Technical
Supporting Documents). This results in 14,177 total natural gas recompletions with hydraulic fracturing
in the U.S. for the year 2008; which is assumed to depict a representative year. Non-fractured
11 HPDI, LLC is a private organization specializing in oil and gas data and statistical analysis. The HPDI database is focused
on historical oil and gas production data and drilling permit data.
111 For the State of Pennsylvania, the most recent drilling information available from HPDI was for 2003. Due to the growth of
oil and gas operations occurring in the Marcellus region in Pennsylvania, this information would not accurately represent the
size of the industry in Pennsylvania for 2006 through 2008. Therefore, information from the Pennsylvania's Department of
Environmental Protection was used to estimate well completion activities for this region. Well data from remaining states
were based on available information from HPDI. From
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recompletions were based on well data for 2008 in HPDI. The number of estimated well completions
and recompletions for each well source category is listed in Table 4-3.
4.3.3 Level of Controlled Sources in Absence of Federal Regulation
As stated previously, to determine the impact of a regulation, it is first necessary to determine the
current level of emissions from the sources being evaluated, or baseline emissions. To more accurately
estimate baseline emissions for this analysis, and to ensure no emission reduction credit was attributed
for sources already being controlled, it was necessary to evaluate the number of completions and
recompletions already subject to regulation. Therefore, the number of completions and recompletions
already being controlled in the absence of federal regulation was estimated based on the existing State
regulations that require control measures for completions and recompletions. Although there may be
regulations issued by other local ordinances for cities and counties throughout the U.S., wells impacted
by these regulations were not included in this analysis because well count data are not available on a
county or local ordinance level. Therefore, the percentage calculated based on the identified State
regulations should be considered a conservative estimate.
In order to determine the number of completions and recompletions that are already controlled under
State regulations, EIA historical well count data was analyzed to determine the percentage of new wells
currently undergoing completion and recompletion in the States identified as having existing controls.1V
Colorado (CO) and Wyoming (WY) were the only States identified as requiring controls on completions
prior to NSPS review. The State of Wyoming's Air Quality Division (WAQD) requires operators to
complete wells without flaring or venting where the following criteria are met: (1) the flowback gas
meets sales line specifications and (2) the pressure of the reservoir is high enough to enable REC. If the
above criteria are not met, then the produced gas is to be flared. 2? The WAQD requires that, "emissions
of VOC and HAP associated with the flaring and venting of hydrocarbon fluids (liquids and gas)
associated with well completion and recompletion activities shall be eliminated to the extent practicable
by routing the recovered liquids into storage tanks and routing the recovered gas into a gas sales line or
collection system." Similar to WY, the Colorado Oil and Gas Conservation Commission (COOGCC)
98
requires REC for both oil and natural gas wells. It was assumed for this analysis that the ratio of
natural wells in CO and WY to the total number of wells in the U.S. represents the percentage of
controlled wells for well completions. The ratio of wells in WY to the number of total nationwide wells
See EIA's The Number of Producing Wells, http://www.eia.gov/dnav/ng/ng_prod_wells_sl_a.htm
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Table 4-3: Estimated Number of Total Oil and
Natural Gas Completions and Recompletions for a Typical Year
Well Completion Category
Natural Gas Well Completions without
Hydraulic Fracturing*
Exploratory Natural Gas Well Completions
with Hydraulic Fracturing
Developmental Natural Gas Well
Completions with Hydraulic Fracturing0
Oil Well Completions'1
Natural Gas Well Recompletions without
Hydraulic Fracturing
Natural Gas Well Recompletions with
Hydraulic Fracturing**
Oil Well Recompletions*
Estimated Number
of Total
Completions and
Recompletions8
7,694
446
10,957
12,193
42,342
14,177
39,375
Estimated
Number of
Controlled
Completions and
Recompletions
1,644
2,127
Estimated
Number of
Uncontrolled
Completions and
Recompletionsb
7,694
446
9,313
12,193
42,342
12,050
39,375
c.
d.
Natural gas completions and recompletions without hydraulic fracturing are assumed to be
uncontrolled at baseline.
Fifteen percent of natural gas well completions with hydraulic fracturing are assumed as
controlled at baseline.
Oil well completions and recompletions are assumed to be uncontrolled at baseline.
Fifteen percent of natural gas well recompletions with hydraulic fracturing are assumed to be
controlled at baseline.
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was assumed to represent the percentage of controlled well recompletions as it was the only State
identified as having regulations directly regulated to recompletions.
From this review it was estimated that 15 percent of completions and 15 percent of recompletions are
controlled in absence of federal regulation. It is also assumed for this analysis that only natural gas wells
undergoing completion or recompletion with hydraulic fracturing are controlled in these States.
Completions and recompletions that are performed without hydraulic fracturing, in addition to oil well
completions and recompletions were assumed to not be subject to State regulations and therefore, were
assumed to not be regulated at baseline. Baseline emissions for the controlled completions and
recompletions covered by regulations are assumed to be reduced by 95 percent from the use of both
REC and combustion devices that may be used separately or in tandem, depending on the individual
State regulation/ The final activity factors for uncontrolled completions and uncontrolled recompletions
are also listed in Table 4-3.
4.3.4 Emission Estimates
Using the estimated emissions, number of uncontrolled and controlled wells at baseline, described
above, nationwide emission estimates for oil and gas well completions and recompletions in a typical
year were calculated and are summarized in Table 4-4. All values have been independently rounded to
the nearest ton for estimation purposes. As the table indicates, hydraulic fracturing significantly
increases the magnitude of emissions. Completions and recompletions without hydraulic fracturing have
lower emissions, while oil completions and recompletions have even lower emissions in comparison.
4.4 Control Techniques
4.4.1 Potential Control Techniques
Two techniques were considered that have been proven to reduce emissions from well completions and
recompletions: REC and completion combustion. One of these techniques, REC, is an approach that not
only reduces emissions but delivers natural gas product to the sales meter that would typically be vented.
The second technique, completion combustion, destroys the organic compounds. Both of these
techniques are discussed in the following sections, along with estimates of the impacts of their
application for a representative well. Nationwide impacts of chosen regulatory options are discussed in
v Percentage of controls by flares versus REC were not determined, so therefore, the count of controlled wells with REC
versus controlled wells with flares was not determined and no secondary baseline emission impacts were calculated.
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Table 4-4. Nationwide Baseline Emissions from Uncontrolled Oil and Gas Well
Completions and Recompletions
Well Completion
Category
Natural Gas Well
Completions without
Hydraulic Fracturing
Exploratory Natural Gas
Well Completions with
Hydraulic Fracturing
Developmental Natural
Gas Well Completions
with Hydraulic
Fracturing
Oil Well Completions
Natural Gas Well
Recompletions without
Hydraulic Fracturing
Natural Gas Well
Recompletions with
Hydraulic Fracturing
Oil Well Recompletions
Uncontrolled
Methane
Emissions per
event
(tpy)
0.8038
158.55
158.55
0.0076
0.0538
158.55
0.00126
Number of
Uncontrolled
Wells3
7,694
446
9,313
12,193
42,342
12,050
39,375
Baseline Nationwide Emissions
(tons/year)"
Methaneb
6,185
70,714
1,476,664
93
2,279
1,910,549
50
vocc
902
10,317
215,445
87
332
278,749
47
HAPd
66
750
15,653
.008
24
20,252
.004
Minor discrepancies may be due to rounding.
a. Baseline emissions include emissions from uncontrolled wells plus five percent of emissions
from controlled sources. The Baseline emission reductions listed in the Regulatory Impacts
(Table 4-9) represents only emission reductions from uncontrolled sources.
b. The number of controlled and uncontrolled wells estimated based on State regulations.
c. Based on the assumption that VOC content is 0.1459 pounds VOC per pound methane for
natural gas wells and 0.8374 pounds VOC per pound methane for oil wells This estimate
accounts for 5 percent of emissions assumed as vented even when controlled. Does not
account for secondary emissions from portion of gas that is directed to a combustion device.
d. Based on the assumption that HAP content is 0.0106 pounds HAP per pound methane for
natural gas wells and 0.0001 pounds HAP per pound methane for oil wells. This estimate
accounts for 5 percent of emissions assumed as vented even when controlled. Does not
account for secondary emissions from portion of gas that is directed to a combustion device.
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section 4.5.
4.4.2 Reduced Emission Completions and Recompletions
4.4.2.1 Description
Reduced emission completions, also referred to as "green" or "flareless" completions, use specially
designed equipment at the well site to capture and treat gas so it can be directed to the sales line. This
process prevents some natural gas from venting and results in additional economic benefit from the sale
of captured gas and, if present, gas condensate. Additional equipment required to conduct a REC may
9Q
include additional tankage, special gas-liquid-sand separator traps, and a gas dehydrator. In many
cases, portable equipment used for RECs operate in tandem with the permanent equipment that will
remain after well drilling is completed. In other instances, permanent equipment is designed (e.g.
oversized) to specifically accommodate initial flowback. Some limitations exist for performing RECs
since technical barriers fluctuate from well to well. Three main limitations include the following for
RECs:
• Proximity of pipelines. For exploratory wells, no nearby sales line may exist. The lack of a
nearby sales line incurs higher capital outlay risk for exploration and production companies
and/or pipeline companies constructing lines in exploratory fields. The State of Wyoming has
set a precedent by stating proximity to gathering lines for wells is not a sufficient excuse to
avoid RECs unless they are deemed exploratory, or the first well drilled in an area that has
never had oil and gas well production prior to that drilling instance (i.e., a wildcat well).30 In
instances where formations are stacked vertically and horizontal drilling could take place, it
may be possible that existing surface REC equipment may be located near an exploratory
well, which would allow for a REC.
• Pressure of produced gas. During each stage of the completion/recompletion process, the
pressure of flowback fluids may not be sufficient to overcome the sales line backpressure.
This pressure is dependent on the specific sales line pressure and can be highly variable. In
this case, combustion of flowback gas is one option, either for the duration of the flowback or
until a point during flowback when the pressure increases to flow to the sales line. Another
control option is compressor applications. One application is gas lift which is accomplished
by withdrawing gas from the sales line, boosting its pressure, and routing it down the well
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casing to push the fracture fluids up the tubing. The increased pressure facilitates flow into
the separator and then the sales line where the lift gas becomes part of the normal flowback
that can be recovered during a REC. Another potential compressor application is to boost
pressure of the flowback gas after it exits the separator. This technique is experimental
because of the difficulty operating a compressor on widely fluctuating flowback rate.
• Inert gas concentration. If the concentration of inert gas, such as nitrogen or carbon dioxide,
in the flowback gas exceeds sales line concentration limits, venting or combustion of the
flowback may be necessary for the duration of flowback or until the gas energy content
increases to allow flow to the sales line. Further, since the energy content of the flowback gas
may not be high enough to sustain a flame due to the presence of the inert gases, combustion
of the flowback stream would require a continuous ignition source with its own separate fuel
supply.
4.4.2.2. Effectiveness
RECs are an effective emissions reduction method for only natural gas completions and recompletions
performed with hydraulic fracturing based on the estimated flowback emissions described in Section
4.2. The emissions reductions vary according to reservoir characteristics and other parameters including
length of completion, number of fractured zones, pressure, gas composition, and fracturing
technology/technique. Based on several experiences presented at Natural Gas STAR technology transfer
workshops, this analysis assumes 90 percent of flowback gas can be recovered during a REC.31 Any
amount of gas that cannot be recovered can be directed to a completion combustion device in order to
achieve a minimum 95 percent reduction in emissions.
4.4.2.3 Cost Impacts
All completions incur some costs to a company. Performing a REC will add to these costs. Equipment
costs associated with RECs vary from well to well. High production rates may require larger equipment
to perform the REC and will increase costs. If permanent equipment, such as a glycol dehydrator, is
already installed or is planned to be in place at the well site as normal operations, costs may be reduced
as this equipment can be used or resized rather than installing a portable dehydrator for temporary use
during the completion. Some operators normally install equipment used in RECs, such as sand traps and
three-phase separators, further reducing incremental REC costs.
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Costs of performing a REC are projected to be between $700 and $6,500 per day, with representative
well completion flowback lasting 3 to 10 days.2 This cost range is the incremental cost of performing a
REC over a traditional completion, where typically the gas is vented or combusted because there is an
absence of REC equipment. Since RECs involve techniques and technologies that are new and
continually evolving, and these cost estimates are based on the state of the industry in 2006 (adjusted to
2008 US dollars).V1 Cost data used in this analysis are qualified below:
• $700 per day (equivalent to $806 per day in 2008 dollars) represents completion and
recompletion costs where key pieces of equipment, such as a dehydrator or three phase
separator, are already found on site and are of suitable design and capacity for use during
flowback.
• $6,500 per day (equivalent to $7,486 in 2008 dollars) represents situations where key pieces
of equipment, such as a dehydrator or three-phase separator, are temporarily brought on site
and then relocated after the completion.
Costs were assessed based on an average of the above data (for costs and number of days per
completion), resulting in an average incremental cost for a REC of $4,146 per day (2008 dollars) for an
average of 7 days per completion. This results in an overall incremental cost of $29,022 for a REC
versus an uncontrolled completion. An additional $691 (2008 dollars) was included to account for
transportation and placement of equipment, bringing total incremental costs estimated at $29,713.
Reduced emission completions are considered one-time events per well; therefore annual costs were
conservatively assumed to be the same as capital costs. Dividing by the expected emission reductions,
cost-effectiveness for VOC is $1,429 per ton, with a methane co-benefit of $208 per ton. Table 4-5
provides a summary of REC cost-effectiveness.
Monetary savings associated with additional gas captured to the sales line was also estimated based on a
natural gas price of $4.00V11 per thousand cubic feet (Mcf).32 It was assumed that all gas captured would
be included as sales gas. Therefore, assuming that 90 percent of the gas is captured and sold, this equates
V1 The Chemical Engineering Cost Index was used to convert dollar years. For REC, the 2008 value equals 575.4 and the
2006 value equals 499.6.
™ The average market price for natural gas in 2010 was approximately $4.16 per Mcf. This is much less compared to the
average price in 2008 of $7.96 per Mcf. Due to the volatility in the price, a conservative savings of $4.00 per Mcf estimate
was projected for the analysis in order to not overstate savings. The value of natural gas condensate recovered during the
REC would also be significant depending on the gas composition. This value was not incorporated into the monetary savings
in order to not overstate savings.
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Table 4-5. Reduced Emission Completion and Recompletion Emission Reductions
and Cost Impacts Summary
Well Completion
Category
Natural Gas
Completions and
Recompletions
with Hydraulic
Fracturing
Emission Reduction Per
Completion/Recompletion
(tons/year)3
voc
20.8
Methane
142.7
HAP
1.5
Total Cost Per
Completion/
Recompletionb
($/event)
29,713
VOC Cost
Effectiveness ($/ton)c
without
savings
1,429
with
savings
net
savings
Methane Cost
Effectiveness ($/ton)
without
savings
208
with
savings
net
savings
Minor discrepancies may be due to rounding.
a. This represents a ninety percent reduction from baseline for the average well.
b. Total cost for reduced emission completion is expressed in terms of incremental cost versus a
completion that vents emissions. This is based on an average incremental cost of $4,146 per
day for an average length of completion flowback lasting 7 days and an additional $691 for
transportation and set up.
c. Cost effectiveness has been rounded to the nearest dollar.
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to a total recovery of 8,258 Mcf of natural gas per completion or recompletion with hydraulic fracturing.
The estimated value of the recovered natural gas for a representative natural gas well with hydraulic
fracturing is approximately $33,030. In addition we estimate an average of 34 barrels of condensate is
recovered per completion or recompletion. Assuming a condensate value of $70 per barrel (bbl), this
result is an income due to condensate sales around $2,380.33 When considering these savings from REC,
for a completion or recompletion with hydraulic fracturing, there is a net savings on the order of $5,697
per completion.
4.4.2.4 Secondary Impacts
A REC is a pollution prevention technique that is used to recover natural gas that would otherwise be
emitted. No secondary emissions (e.g., nitrogen oxides, particulate matter, etc.) would be generated, no
wastes should be created, no wastewater generated, and no electricity needed. Therefore, there are no
secondary impacts expected due to REC.
4.4.3 Completion Combustion Devices
4.4.3.1 Description
Completion combustion is a high-temperature oxidation process used to burn combustible components,
mostly hydrocarbons, found in waste streams.34 Completion combustion devices are used to control
VOC in many industrial settings, since the completion combustion device can normally handle
fluctuations in concentration, flow rate, heating value, and inert species content.35 Completion
combustion devices commonly found on drilling sites are rather crude and portable, often installed
horizontally due to the liquids that accompany the flowback gas. These flares can be as simple as a pipe
with a basic ignition mechanism and discharge over a pit near the wellhead. However, the flow directed
to a completion combustion device may or may not be combustible depending on the inert gas
composition of flowback gas, which would require a continuous ignition source. Sometimes referred to
as pit flares, these types of combustion devices do not employ an actual control device, and are not
capable of being tested or monitored for efficiency. They do provide a means of minimizing vented gas
and is preferable to venting. For the purpose of this analysis, the term completion combustion device
represents all types of combustion devices including pit flares.
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4.4.3.2 Effectiveness
The efficiency of completion combustion devices, or exploration and production flares, can be expected
to achieve 95 percent, on average, over the duration of the completion or recompletion. If the energy
content of natural gas is low, then the combustion mechanism can be extinguished by the flowback gas.
Therefore, it is more reliable to install an igniter fueled by a consistent and continuous ignition source.
This scenario would be especially true for energized fractures where the initial flowback concentration
will be extremely high in inert gases. This analysis assumes use of a continuous ignition source with an
independent external fuel supply is assumed to achieve an average of 95 percent control over the entire
flowback period. Additionally, because of the nature of the flowback (i.e., with periods of water,
condensate, and gas in slug flow), conveying the entire portion of this stream to a flare or other control
device is not always feasible. Because of the exposed flame, open pit flaring can present a fire hazard or
other undesirable impacts in some situations (e.g., dry, windy conditions, proximity to residences, etc.).
As a result, we are aware that owners and operators may not be able to flare unrecoverable gas safely in
every case.
Federal regulations require industrial flares meet a combustion efficiency of 98 percent or higher as
outlined in 40 CFR 60.18. This statute does not apply to completion combustion devices. Concerns have
been raised on applicability of 40 CFR 60.18 within the oil and gas industry including for the production
segment.30'36'3? The design and nature of completion combustion devices must handle multiphase flow
and stream compositions that vary during the flowback period. Thus, the applicability criterion that
specifies conditions for flares used in highly industrial settings may not be appropriate for flares
typically used to control emissions from well completions and recompletions.
4.4.3.3 Cost Impacts
An analysis depicting the cost for wells including completion combustion devices was conducted for the
Petroleum Services Association of Canada (PSAC)38 in 2009 by N.L. Fisher Supervision and
Engineering, Ltd.vm The data corresponds to 34 gas wells for various types of formations, including coal
bed methane and shale. Multiple completion methods were also examined in the study including
hydraulic and energized fracturing. Using the cost data points from these natural gas well completions,
vm It is important to note that outliers were excluded from the average cost calculation. Some outliers estimated the cost of
production flares to be as low as $0 and as high as $56,000. It is expected that these values are not representative of typical
flare costs and were removed from the data set. All cost data found in the PSAC study were aggregated values of the cost of
production flares and other equipment such as tanks. It is possible the inclusion of the other equipment is not only responsible
for the outliers, but also provides a conservatively high estimate for completion flares.
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an average completion combustion device cost is approximately $3,523 (2008 dollars).1X As with the
REC, because completion combustion devices are purchased for these one-time events, annual costs
were conservatively assumed to be equal to the capital costs.
It is assumed that the cost of a continuous ignition source is included in the combustion completion
device cost estimations. It is understood that multiple completions and recompletions can be controlled
with the same completion combustion device, not only for the lifetime of the combustion device but
within the same yearly time period. However, to be conservative, costs were estimated as the total cost
of the completion combustion device itself, which corresponds to the assumption that only one device
will control one completion per year. The cost impacts of using a completion combustion device to
reduce emissions from representative completions/recompletions are provided in Table 4-6. Completion
combustion devices have a cost-effectiveness of $161 per ton VOC and a co-benefit of $23 per ton
methane for completions and recompletions with hydraulic fracturing.
4.4.3.4 Secondary Impacts
Noise and heat are the two primary undesirable outcomes of completion combustion device operation. In
addition, combustion and partial combustion of many pollutants also create secondary pollutants
including nitrogen oxides (NOX), carbon monoxide (CO), sulfur oxides (SOX, carbon dioxide (CC^), and
smoke/particulates (PM). The degree of combustion depends on the rate and extent of fuel mixing with
air and the temperature maintained by the flame. Most hydrocarbons with carbon-to-hydrogen ratios
greater than 0.33 are likely to smoke.34 Due to the high methane content of the gas stream routed to the
completion combustion device, it suggests that there should not be smoke except in specific
circumstances (e.g., energized fractures). The stream to be combusted may also contain liquids and
solids that will also affect the potential for smoke. Soot can typically be eliminated by adding steam.
Based on current industry trends in the design of completion combustion devices and in the
decentralized nature of completions, virtually no completion combustion devices include steam
assistance.34
Reliable data for emission factors from flare operations during natural gas well completions are limited.
Guidelines published in AP-42 for flare operations are based on tests from a mixture containing
1X The Chemical Engineering Cost Index was used to convert dollar years. For the combustion device the 2009 value equals
521.9. The 2009 average value for the combustion device is $3,195.
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Table 4-6. Emission Reduction and Cost-effectiveness Summary
for Completion Combustion Devices
Well Completion
Category
Natural Gas Well
Completions
without Hydraulic
Fracturing
Natural Gas Well
Completions with
Hydraulic
Fracturing
Oil Well
Completions
Natural Gas Well
Recompletions
without Hydraulic
Fracturing
Natural Gas Well
Recompletions with
Hydraulic
Fracturing
Oil Well
Recompletions
Emission Reduction Per
Completion/Workover
(tons/year)"
VOC
0.11
21.9
0.01
0.007
21.9
0.00
Methane
0.76
150.6
0.007
0.051
150.6
0.001
HAP
0.0081
1.597
0.0000007
0.0005
1.597
0.0000001
Total
Capital
Cost Per
Completion
Event ($)*
3,523
VOC Cost
Effectiveness
($/ton)b
31,619
160
520,580
472,227
160
3,134,431
Methane
Cost
Effectiveness
($/ton)
4,613
23
488,557
68,889
23
2,941,615
Minor discrepancies may be due to rounding.
a. This assumes one combustion device will control one completion event per year. This should
be considered a conservative estimate, since it is likely multiple completion events will be
controlled with the same combustion unit in any given year. Costs are stated in 2008 dollars.
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80 percent propylene and 20 percent propane.34 These emissions factors, however, are the best
indication for secondary pollutants from flare operations currently available. These secondary emission
factors are provided are provided in Table 4-7.
Since this analysis assumed pit flares achieve 95 percent efficiency over the duration of flowback, it is
likely the secondary emission estimations are lower than actuality (i.e. AP-42 assumes 98 percent
efficiency). In addition due, to the potential for the incomplete combustion of natural gas across the pit
flare plume, the likelihood of additional NOX formulating is also likely. The degree of combustion is
variable and depends on the on the rate and extent of fuel mixing with air and on the flame temperature.
Moreover, the actual NOX (and CO) emissions may be greatly affected when the raw gas contains
hydrocarbon liquids and water. For these reasons, the nationwide impacts of combustion devices
discussed in Section 4.5 should be considered minimum estimates of secondary emissions from
combustion devices.
4.5 Regulatory Options
The REC pollution prevention approach would not result in emissions of CO, NOX, and PM from the
combustion of the completion gases in the flare, and would therefore be the preferred option. As
discussed above, REC is only an option for reducing emissions from gas well completions/workovers
with hydraulic fracturing. Taking this into consideration, the following regulatory alternatives were
evaluated:
• Regulatory Option 1: Require completion combustion devices for conventional natural gas well
completions and recompletions;
• Regulatory Option 2: Require completion combustion devices for oil well completions and
recompletions;
• Regulatory Option 3: Require combustion devices for all completions and recompletions;
• Regulatory Option 4: Require REC for all completions and recompletions of hydraulically
fractured wells;
• Regulatory Option 5: Require REC and combustion operational standards for natural gas well
completions with hydraulic fracturing, with the exception of exploratory, and delineation wells;
• Regulatory Option 6: Require combustion operational standards for exploratory and delineation
wells; and
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Table 4-7. Emission Factors from Flare Operations from AP-42 Guidelines Table 13.4-la
Pollutant
Total Hydrocarbon6
Carbon Monoxide
Nitrogen Oxides
Particular Matter0
Carbon Dioxide
Emission Factor
(lb/106Btu)
0.14
0.37
0.068
0-274
60
a. Based on combustion efficiency of 98 percent.
b. Measured as methane equivalent.
c. Soot in concentration values: nonsmoking flares, 0 micrograms per liter (|ig/L); lightly smoking
flares, 40 |ig/L; average smoking flares, 177 |ig/L; and heavily smoking flares, 274 |ig/L.
d. Carbon dioxide is measured in kg CO2/MMBtu and is derived from the carbon dioxide emission
factor obtained from 40 CFR Part 98, subpart Y, Equation Y-2.
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• Regulatory Option 7: Require REC and combustion operational standards for all natural gas well
recompletions with hydraulic fracturing.
The following sections discuss these regulatory options.
4.5.1 Evaluation of Regulatory Options
The first two regulatory options (completion combustion devices for conventional natural gas well
completions and recompletions and completion combustion devices for oil well completions and
recompletions) were evaluated first. As shown in Table 4-6, the cost effectiveness associated with
controlling conventional natural gas and oil well completions and recompletions ranges from $31,600
per ton VOC to over $3.7 million per ton VOC. Therefore, Regulatory Options 1 and 2 were rejected
due to the high cost effectiveness.
The next regulatory option, to require completion combustion devices for all completions and
recompletions, was considered. Under Regulatory Option 3, all of the natural gas emitted from the well
during flowback would be destroyed by sending flowback gas through a combustion unit. Not only
would this regulatory option result in the destruction of a natural resource with no recovery of salable
gas, it also would result in an increase in emissions of secondary pollutants (e.g., nitrogen oxides, carbon
monoxide, etc.). Therefore, Regulatory Option 3 was also rejected.
The fourth regulatory option would require RECs for all completions and recompletions of hydraulically
fractured wells. As stated previously, RECs are not feasible for all well completions, such as exploratory
wells, due to their distance from sales lines, etc. Further, RECs are also not technically feasible for each
well at all times during completion and recompletion activities due to the variability of the pressure of
produced gas and/or inert gas concentrations. Therefore, Regulatory Option 4 was rejected.
The fifth regulatory option was to require an operational standard consisting of a combination of REC
and combustion for natural gas well completions with hydraulic fracturing. As discussed for Regulatory
Option 4, RECs are not feasible for every well at all times during completion or recompletion activities
due to variability of produced gas pressure and/or inert gas concentrations. In order to allow for
wellhead owners and operators to continue to reduce emissions when RECs are not feasible due to well
characteristics (e.g, wellhead pressure or inert gas concentrations), Regulatory Option 5 also allows for
the use of a completion combustion device in combination with RECs.
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Under Regulatory Option 5, a numerical limit was considered, but was rejected in favor of an
operational standard. Under section 11 l(h)(2) of the CAA, EPA can set an operational standard which
represents the best system of continuous emission reduction, provided the following criteria are met:
"(A) a pollutant or pollutants cannot be emitted through a conveyance designed and constructed
to emit or capture such pollutant, or that any requirement for, or use of, such a conveyance would
be inconsistent with any Federal, State, or local law, or
(B) the application of measurement methodology to a particular class of sources is not
practicable due to technological or economic limitations."
As discussed in section 4.4.3, emissions from a completion combustion device cannot be measured or
monitored to determine efficiency making an operational standard appropriate. Therefore, an operational
standard under this regulatory option consists of a combination of REC and a completion combustion
device to minimize the venting of natural gas and condensate vapors to the atmosphere, but allows
venting in lieu of combustion for situations in which combustion would present safety hazards, other
concerns, or for periods when the flowback gas is noncombustible due to high concentrations of inert
gases. Sources would also be required, under this regulatory option, to maintain documentation of the
overall duration of the completion event, duration of recovery using REC, duration of combustion,
duration of venting, and specific reasons for venting in lieu of combustion. It was also evaluated whether
Regulatory Option 5 should apply to all well completions, including exploratory and delineation wells.
As discussed previously, one of the technical limitations of RECs is that they are not feasible for use at
some wells due to their proximity to pipelines. Section 11 l(b)(2) of the CAA allows EPA to
".. .distinguish among classes, types, and sizes within categories of new sources for the purpose of
establishing...." performance standards. Due to their distance from sales lines, and the relatively
unknown characteristics of the formation, completion activities occurring at exploratory or delineation
wells were considered to be a different "type" of activity than the types of completion activities
occurring at all other gas wells. Therefore, two subcategories of completions were identified:
Subcategory 1 wells are all natural gas wells completed with hydraulic fracturing that do not fit the
definition of exploratory or delineation wells. Subcategory 2 wells are natural gas wells that meet the
following definitions of exploratory or delineation wells:
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• Exploratory wells are wells outside known fields or the first well drilled in an oil or gas field
where no other oil and gas production exists or
• Delineation wells means a well drilled in order to determine the boundary of a field or producing
reservoir.
Based on this subcategorization, Regulatory Option 5 would apply to the Subcategory 1 wells and a
sixth regulatory option was developed for Subcategory 2 wells.
Regulatory Option 6 requires an operational standard for combustion for the Subcategory 2 wells. As
described above, REC is not an option for exploratory and delineation wells due to their distance from
sales lines. As with the Regulatory Option 5, a numerical limitation is not feasible. Therefore, this
regulatory option requires an operational standard where emissions are minimized using a completion
combustion device during completion activities at Subcategory 2 wells, with an allowance for venting in
situations where combustion presents safety hazards or other concerns or for periods when the flowback
gas is noncombustible due to high concentrations of inert gases. Consistent with Regulatory Option 5,
records would be required to document the overall duration of the completion event, the duration of
combustion, the duration of venting, and specific reasons for venting in lieu of combustion.
The final regulatory option was considered for recompletions. Regulatory Option 7 requires an
operational standard for a combination of REC and a completion combustion device for all
recompletions with hydraulic fracturing performed on new and existing natural gas wells. Regulatory
Option 7 has the same requirements as Regulatory Option 5. Subcategorization similar to Regulatory
Option 5 was not necessary for recompletions because it was assumed that RECs would be technically
feasible for recompletions at all types of wells since they occur at wells that are producing and thus
proximity to a sales line is not an issue. While evaluating this regulatory option, it was considered
whether or not recompletions at existing wells should be considered modifications and subject to
standards.
The affected facility under the New Source Performance Standards (NSPS) is considered to be the
wellhead. Therefore, a new well drilled after the proposal date of the NSPS would be subject to emission
control requirements. Likewise, wells drilled prior to the proposal date of the NSPS would not be subject
to emission control requirements unless they underwent a modification after the proposal date. Under
section 11 l(a) of the Clean Air Act, the term "modification" means:
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"any physical change in, or change in the method of operation of, a stationary source which
increases the amount of any air pollutant emitted by such source or which results in the emission
of any air pollutant not previously emitted."
The wellhead is defined as the piping, casing, tubing, and connected valves protruding above the earth's
surface for an oil and/or natural gas well. The wellhead ends where the flow line connects to a wellhead
valve. In order to fracture an existing well during recompletion, the well would be re-perforated, causing
physical change to the wellbore and casing and therefore a physical change to the wellhead, the affected
facility. Additionally, much of the emissions data on which this analysis is based demonstrates that
hydraulic fracturing results in an increase in emissions. Thus, recompletions using hydraulic fracturing
result in an increase in emissions from the existing well producing operations. Based on this
understanding of the work performed in order to recomplete the well, it was determined that a
recompletion would be considered a modification under CAA section 11 l(a) and thus, would constitute
a new wellhead affected facility subject to NSPS. Therefore, Regulatory Option 7 applies to
recompletions using hydraulic fracturing at new and existing wells.
In summary, Regulatory Options 1, 2, 3, and 4 were determined to be unreasonable due to cost
considerations, other impacts or technical feasibility and thereby rejected. Regulatory Options 5, 6, and
7 were determined to be applicable to natural gas wells and were evaluated further.
4.5.2 Nationwide Impacts of Regulatory Options
This section provides an analysis of the primary environmental impacts (i.e., emission reductions), cost
impacts and secondary environmental impacts related to Regulatory Options 5, 6, and 7 which were
selected as viable options for setting standards for completions and recompletions.
4.5.2.1 Primary Environmental Impacts of Regulatory Options
Regulatory Options 5, 6, and 7 were selected as options for setting standards for completions and
regulatory options as follows:
• Regulatory Option 5: Operational standard for completions with hydraulic fracturing for
Subcategory 1 wells (i.e., wells which do not meet the definition of exploratory or
delineation wells), which requires a combination of REC with combustion, but allows for
venting during specified situations.
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• Regulatory Option 6: An operational standard for completions with hydraulic fracturing
for exploratory and delineation wells (i.e., Subcategory 2 wells) which requires
completion combustion devices with an allowance for venting during specified situations.
• Regulatory Option 7: An operational standard equivalent to Regulatory Option 5 which
applies to recompletions with hydraulic fracturing at new and existing wells.
The number of completions and recompletions that would be subject to the regulatory options listed
above was presented in Table 4-3. It was estimated that there would be 9,313 uncontrolled
developmental natural gas well completions with hydraulic fracturing subject to Regulatory Option 5.
Regulatory Option 6 would apply to 446 uncontrolled exploratory natural gas well completions with
hydraulic fracturing, and 12,050 uncontrolled recompletions at existing wells would be subject to
Regulatory Option 7.x
Table 4-8 presents the nationwide emission reduction estimates for each regulatory option. It was
estimated that RECs in combination with the combustion of gas unsuitable for entering the gathering
line, can achieve an overall 95 percent VOC reduction over the duration of the completion operation.
The 95 percent recovery was estimated based on 90 percent of flowback being captured to the sales line
and assuming an additional 5 percent of the remaining flowback would be sent to the combustion
device. Nationwide emission reductions were estimated by applying this 95 percent VOC reduction to
the uncontrolled baseline emissions presented in Table 4-4.
4.5.2.2 Cost Impacts
Cost impacts of the individual control techniques (RECs and completion combustion devices) were
presented in section 4.4. For Regulatory Option 6, the costs for completion combustion devices
presented in Table 4-6 for would apply to Subcategory 2 completions. The cost per completion event
was estimated to be $3,523. Applied to the 446 estimated Subcategory 2 completions, the nationwide
costs were estimated to be $1.57 million. Completion combustion devices are assumed to achieve an
overall 95 percent combustion efficiency. Since the operational standards for Regulatory Options 5 and
7 include both REC and completion combustion devices, an additional cost impact analysis was
x The number of uncontrolled recompletions at new wells is not included in this analysis. Based on the assumption that wells
are recompleted once every 10 years, any new wells that are drilled after the date of proposal of the standard would not likely
be recompleted until after the year 2015, which is the date of this analysis. Therefore, impacts were not estimated for
recompletion of new wells, which will be subject to the standards.
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Table 4-8. Nationwide Emission and Cost Analysis of Regulatory Option
Well Completion
Category
Number
of
Sources
subject to
NSPSa
Annual
Cost Per
Completio
n Event
($)b
Nationwide Emission
Reductions (tpy)c
VOC
Methane
HAP
VOC Cost
Effectiveness
($/ton)
without
savings
with
savings
Methane Cost
Effectiveness
($/ton)
without
savings
with
savings
Total Nationwide Costs
(million $/year)
Capital
Cost
without
with
Regulatory Option 5 (operational standard for REC and combustion)
Subcategory 1 :
Natural gas
Completions with
Hydraulic Fracturing
9,313
33,237
204,134
1,399,139
14,831
1,516
net
savings
221
net
savings
309.5
309.5
(20.24)
Regulatory Option 6 (operational standard for combustion)
Subcategory 2:
Natural gas
Completions with
Hydraulic Fracturing
446
3,523
9,801
67,178
712
160
160
23
23
1.57
1.57
1.57
Regulatory Option 7 (operational standard for REC and combustion)
Natural Gas Well
Recompletions with
Hydraulic Fracturing
12,050
33,237
264,115
1,810,245
19,189
1,516
net
221
net
400.5
400.5
(26.18)
Minor discrepancies may be due to rounding.
a. Number of sources in each well completion category that are uncontrolled at baseline as presented in Table 4-3.
b. Costs per event for Regulatory Options 5 and 7 are calculated by adding the costs for REC and completion combustion device
presented in Tables 4-5 and 4-6, respectively. Cost per event for Regulatory Option 6 is presented for completion combustion devices
in Table 4-6.
c. Nationwide emission reductions calculated by applying the 95 percent emission reduction efficiency to the uncontrolled nationwide
baseline emissions in Table 4-4.
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performed to analyze the nationwide cost impacts of these regulatory options. The total incremental cost
of the operational standard for Subcategory 1 completions and for recompletions is estimated at around
$33,237, which includes the costs in Table 4-5 for the REC equipment and transportation in addition to
the costs in Table 4-6 for the completion combustion device. Applying the cost for the combined REC
and completion combustion device to the estimated 9,313 Subcategory 1 completions, the total
nationwide cost was estimated to be $309.5 million, with a net annual savings estimated around $20
million when natural gas savings are considered. A cost of $400.5 million was estimated for
recompletions, with an overall savings of around $26 million when natural gas savings are considered.
The VOC cost effectiveness for Regulatory Options 5 and 7 was estimated at around $1,516 per ton,
with a methane co-benefit of $221 per ton.
4.5.2.3 Secondary Impacts
Regulatory Options 5, 6 and 7 all require some amount of combustion; therefore the estimated
nationwide secondary impacts are a direct result of combusting all or partial flowback emissions.
Although, it is understood the volume of gas captured, combusted and vented may vary significantly
depending on well characteristics and flowback composition, for the purpose of estimating secondary
impacts for Regulatory Options 5 and 7, it was assumed that ninety percent of flowback is captured and
an additional five percent of the remaining gas is combusted. For both Subcategory 1 natural gas well
completions with hydraulic fracturing and for natural gas well recompletions with hydraulic fracturing,
it is assumed around 459 Mcf of natural gas is combusted on a per well basis. For Regulatory Option 6,
Subcategory 2 natural gas completions with hydraulic fracturing, it is assumed that 95 percent
(8,716 Mcf) of flowback emissions are consumed by the combustion device. Tons of pollutant per
completion event was estimated assuming 1,089.3 Btu/scf saturated gross heating value of the "raw"
natural gas and applying the AP-42 emissions factors listed in Table 4-7.
From category 1 well completions and from recompletions, it is estimated 0.02 tons of NOX are
produced per event. This is based on assumptions that 5 percent of the flowback gas is combusted by the
combustion device. From category 2 well completions, it is estimated 0.32 tons of NOX are produced in
secondary emissions per event. This is based on the assumption 95 percent of flowback gas is
combusted by the combustion device. Based on the estimated number of completions and recompletions,
the proposed regulatory options are estimated to produce around 507 tons of NOX in secondary
emissions nationwide from controlling all or partial flowback by combustion. Table 4-9 summarizes the
estimated secondary emissions of the selected regulatory options.
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Table 4-9 Nationwide Secondary Impacts of Selected Regulatory Options"
Pollutant
Total Hydrocarbons
Carbon Monoxide
Nitrogen Oxides
Particulate Matter
Carbon Dioxide
Regulatory Options 5b
Subcategory 1 Natural Gas
Well Completions with
Hydraulic Fracturing
tons per
eventd
0.03
0.09
0.02
0.00000002
33.06
Nationwide
Annual
Secondary
Emissions
(tons/year)
326
861
158
0.0002
307,863
Regulatory Option 6C
Subcategory 2 Natural Gas
Well Completions with
Hydraulic Fracturing
tons per
eventd
0.66
1.76
0.32
0.011
628
Nationwide
Annual
Secondary
Emissions
(tons/year)
296
783
144
5
280,128
Regulatory Options 7b
Natural Gas Well
Recompletions with Hydraulic
Fracturing
tons per
eventd
0.03
0.09
0.02
0.00000002
33.06
Nationwide
Annual
Secondary
Emissions
(tons/year)
422
1,114
205
0.0003
398,341
a. Nationwide impacts are based on AP-42 Emission Guidelines for Industrial Flares as outlined in Table 4-7. As such, these emissions
should be considered the minimum level of secondary emissions expected.
b. The operational standard (Regulatory Options 5 and 7) combines REC and combustion is assumed to capture 90 percent of flowback
gas. Five percent of the remaining flowback is assumed to be consumed in the combustion device. Therefore, it is estimated 459 Mcf
is sent to the combustion device per completion event. This analysis assumes there are 9,313 Subcategory 1 wells and 12,050
recompletions.
c. Assumes 8,716 Mcf of natural gas is sent to the combustion unit per completion. This analysis assumes 446 exploratory wells fall into
this category.
d. Based on 1,089.3 Btu/scf saturated gross heating value of the "raw" natural gas.
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4.6 References
1. ICF Consulting. Availability, Economics, and Production Potential of North American
Unconventional Natural Gas Supplies. Prepared for INGAA Foundation, Inc. November 2008.
www.ingaa.org/File.aspx?id=7878.
2. U.S. Environmental Protection Agency. Lessons Learned: Reduced Emissions Completions.
Office of Air and Radiation: Natural Gas Star Program. Washington, DC. 2011.
3. U.S. Environmental Protection Agency. Greenhouse Gas Emissions Reporting From the
Petroleum and Natural Gas Industry: Background Technical Support Document. Climate Change
Division. Washington, DC. November 2010. 84-89 pp.
4 U.S Environmental Protection Agency. Methodology for Estimating CtL; and CC>2 Emissions
from Petroleum Systems. Greenhouse Gas Inventory: Emission and Sinks 1990-2008.
Washington, DC. 2010.
5. U.S Environmental Protection Agency. Methodology for Estimating CtL; and CC>2 Emissions
from Natural Gas Systems. Greenhouse Gas Inventory: Emission and Sinks 1990-2008.
Washington, DC. 2010.
6. Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 2: Technical
Report. Prepared for the Gas Research Institute and Environmental Protection Agency. EPA-
600/R-96-080b. June 1996.
7. Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 3: General
Methodology. Prepared for the Gas Research Institute and Environmental Protection Agency.
EPA-600/R-96-080c. June 1996.
8. Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 5: Activity
Factors. Prepared for the Gas Research Institute and Environmental Protection Agency. EPA-
600/R-96-080e. June 1996
9. Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 6: Vented
and Combustion Source Summary Emissions. Prepared for the Gas Research Institute and
Environmental Protection Agency. EPA-600/R-96-080f. June 1996.
10. Radian International LLC, Methane Emissions from the U.S. Petroleum Industry, draft report for
the U.S. Environmental Protection Agency, June 14, 1996.
11. ICF Consulting. Estimates of Methane Emissions from the U.S. Oil Industry. Prepared for the
U.S. Environmental Protection Agency. 1999.
12. ENVIRON International Corporation. Oil and Gas Emission Inventories for the Western States.
Prepared for Western Governors' Association. December 27, 2005.
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13. 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.
14. Independent Petroleum Association of America. Oil and Gas Producing Industry in Your State.
2008.
15. 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.
16. Eastern Research Group, Inc. Emissions from Oil and Gas Production Facilities. Prepared for the
Texas Commission on Environmental Quality. August 31, 2007.
17. U.S. Energy Information Administration. Annual U.S. Natural Gas Wellhead Price. Energy
Information Administration. Natural Gas Navigator. Retrieved December 12, 2010.
http ://www. eia.doe. gov/dnav/ng/hist/n9190us3 a.htm.
18. 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.
19. New York State Department of Environmental Conservation. Supplemental Generic
Environmental Impact Statement on the Oil, Gas and Solution Mining Regulatory Program
(DRAFT). September 2009.
20. U.S. Environmental Protection Agency. Reduced Emission Completions (Green Completions).
Natural Gas STAR. Producers Technology Transfer Workshop. 2005. Slide 12.
21. Anadarko Petroleum Corporation. Reduced Emission Completions in DJ Basin and Natural
Buttes. Producers Technology Transfer Workshop. Rock Springs, WY. 2008.
http://www.epa.gov/gasstar/documents/workshops/2008-tech-transfer/rocksprings5.pdf
22. Ellwood, B. Reduced Emissions Completions Jonah Case Study. EnCana. Denver, CO. 2009.
http://www.epa.gov/gasstar/documents/workshops/2009-annual-conf/08ellwood.pdf
23. Marathon. Excape Completion Process Reduces Gas Emissions and Speeds Well Completions.
14th Annual Natural Gas Star Workshop. Houston, TX. 2007
http://www.epa.gov/gasstar/documents/workshops/2007-annual-conf/06 phil snider.pdf
24. Werline, R. Natural Gas Star Workshop. Oklahoma City, OK. 2009.
http://www.epa.gov/gasstar/documents/workshops/okcity2009/devon_completions.pdf
25. US Environmental Protection Agency. Reducing Methane Emissions During Completion
Operations. Natural Gas STAR. Annual Implementation Workshop. Houston, TX. 2006.
http ://www. epa.gov/gasstar/documents/vincent.pdf
26. Memorandum to Bruce Moore from Heather Brown. Composition of Natural Gas for Use in the
Oil and Natural Gas Sector Rulemaking. EC/R, Incorporated. June 29, 2011.
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27 State of Wyoming Department of Environmental Quality, Air Quality Division. Well
Completions/Re-completions Permit Application. Page 2. August 2010.
http://deq.state.wy.us/aqd/Oil%20and%20Gas/AQD-
OGll_Green%20Completion%20Application.pdf
28 Colorado Oil and Gas Conservation Commission. 2 CCR-404-1. http://oil-
gas.state.co.us/RuleMaking/FinalDraftRules/COGCCFinalDraftRules_l 10708.pdf
29. U.S. Environmental Protection Agency Fact Sheet No. 703: Green Completions. Office of Air
and Radiation: Natural Gas Star Program. Washington, DC. September 2004.
30. Memorandum to Bruce Moore from Denise Grubert. American Petroleum Institute Meeting
Minutes. EC/R, Incorporated. July 2010.
31 Memorandum to Bruce Moore from ICF Consulting. Percent of Emissions Recovered by
Reduced Emission Completions. May 2011.
32. U.S. Energy Information Administration. Annual U.S. Natural Gas Wellhead Price. Energy
Information Administration. Natural Gas Navigator. Retrieved online on Dec 12, 2010.
http://www.eia.doe.gov/dnav/ng/hist/n9190us3a.htm
33 Memorandum to Bruce Moore from ICF Consulting. NSPS Unconventional Well Completions
Condensate Recovery Analysis - Recovered Volumes and Value. July 28, 2011.
34. U.S. Environmental Protection Agency. AP 42, Fifth Edition, Volume I, Chapter 13.5 Industrial
Flares. Office of Air Quality Planning & Standards. 1991
35. U.S. Environmental Protection Agency. Air Pollution Control Technology Fact Sheet: FLARES.
Clean Air Technology Center.
36. Memorandum to Bruce Moore from Denise Grubert. American Petroleum Institute Meeting
Minutes. EC/R, Incorporated. October 2010.
37. Memorandum to Bruce Moore from Denise Grubert. American Petroleum Institute Meeting
Minutes Attachment 1: Review of Federal Air Regulations for the Oil and Natural Gas Sector 40
CFR Part 60, Subparts KKK and LLL; 40 CFR Part 63 Subparts HH and HHH. EC/R,
Incorporated. February 2011.
38. Petroleum Services Association of Canada. 2009 Well Cost Study. Upcoming Summer
Costs. Well Cost Data and Consulting by N.L. Fisher Supervision & Engineering Ltd. April 30,
2009.
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5.0 PNEUMATIC CONTROLLERS
The natural gas industry uses a variety of process control devices to operate valves that regulate
pressure, flow, temperature, and liquid levels. Most instrumentation and control equipment falls into one
of three categories: (1) pneumatic; (2) electrical; or (3) mechanical. Of these, only pneumatic devices are
direct sources of air emissions. Pneumatic controllers are used throughout the oil and natural gas sector
as part of the instrumentation to control the position of valves. This chapter describes pneumatic devices
including their function and associated emissions. Options available to reduce emissions from pneumatic
devices are presented, along with costs, emission reductions, and secondary impacts. Finally, this
chapter discusses considerations in developing regulatory alternatives for pneumatic devices.
5.1 Process Description
For the purpose of this document, a pneumatic controller is a device that uses natural gas to transmit a
process signal or condition pneumatically and that may also adjust a valve position based on that signal,
with the same bleed gas and/or a supplemental supply of power gas. In the vast majority of applications,
the natural gas industry uses pneumatic controllers that make use of readily available high-pressure
natural gas to provide the required energy and control signals. In the production segment, an estimated
400,000 pneumatic devices control and monitor gas and liquid flows and levels in dehydrators and
separators, temperature in dehydrator regenerators, and pressure in flash tanks. There are around
13,000 gas pneumatic controllers located in the gathering, boosting and processing segment that control
and monitor temperature, liquid, and pressure levels. In the transmission segment, an estimated
85,000 pneumatic controllers actuate isolation valves and regulate gas flow and pressure at compressor
stations, pipelines, and storage facilities.1
Pneumatic controllers are automated instruments used for maintaining a process condition such as liquid
level, pressure, pressure differential, and temperature. In many situations across all segments of the oil
and gas industry, pneumatic controllers make use of the available high-pressure natural gas to operate
control of a valve. In these "gas-driven" pneumatic controllers, natural gas may be released with every
valve movement and/or continuously from the valve control pilot. The rate at which the continuous
release occurs is referred to as the bleed rate. Bleed rates are dependent on the design and operating
characteristics of the device. Similar designs will have similar steady-state rates when operated under
similar conditions. There are three basic designs: (1) continuous bleed devices are used to modulate
flow, liquid level, or pressure, and gas is vented continuously at a rate that may vary over time; (2) snap-
5-1
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acting devices release gas only when they open or close a valve or as they throttle the gas flow; and (3)
self-contained devices release gas to a downstream pipeline instead of to the atmosphere. This analysis
assumes self-contained devices that release natural gas to a downstream pipeline instead of to the
atmosphere have no emissions. Furthermore, it is recognized "closed loop" systems are applicable only
in instances with very low pressure2 and may not be suitable to replace many applications of bleeding
pneumatic devices. Therefore, these devices are not further discussed in this analysis.
Snap-acting controllers are devices that only emit gas during actuation and do not have a continuous
bleed rate. The actual amount of emissions from snap-acting devices is dependent on the amount of
natural gas vented per actuation and how often it is actuated. Bleed devices also vent an additional
volume of gas during actuation, in addition to the device's bleed stream. Since actuation emissions serve
the device's functional purpose and can be highly variable, the emissions characterized for high-bleed
and low-bleed devices in this analysis (as described in section 5.2.2) account for only the continuous
flow of emissions (i.e. the bleed rate) and do not include emissions directly resulting from actuation.
Snap-acting controllers are assumed to have zero bleed emissions. Most applications (but not all), snap-
acting devices serve functionally different purposes than bleed devices. Therefore, snap-acting
controllers are not further discussed in this analysis.
In addition, not all pneumatic controllers are gas driven. At sites without electrical service sufficient to
power an instrument air compressor, mechanical or electrically powered pneumatic devices can be used.
These "non-gas driven" pneumatic controllers can be mechanically operated or use sources of power
other than pressurized natural gas, such as compressed "instrument air." Because these devices are not
gas driven, they do not directly release natural gas or VOC emissions. However, electrically powered
systems have energy impacts, with associated secondary impacts related to generation of the electrical
power required to drive the instrument air compressor system. Instrument air systems are feasible only at
oil and natural gas locations where the devices can be driven by compressed instrument air systems and
have electrical service sufficient to power an air compressor. This analysis assumes that natural gas
processing plants are the only facilities in the oil and natural gas sector highly likely to have electrical
service sufficient to power an instrument air system, and that most existing gas processing plants use
instrument air instead of gas driven devices.9 The application of electrical controls is further elaborated
in Section 5.3.
5-2
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5.2 Emissions Data and Information
5.2.1 Summary of Major Studies and Emissions
In the evaluation of the emissions from pneumatic devices and the potential options available to reduce
these emissions, numerous studies were consulted. Table 5-1 lists these references with an indication of
the type of relevant information contained in each study.
5.2.2 Representative Pneumatic Device Emissions
Bleeding pneumatic controllers can be classified into two types based on their emissions rates: (1) high-
bleed controllers and (2) low-bleed controllers. A controller is considered to be high-bleed when the
continuous bleed emissions are in excess of 6 standard cubic feet per hour (scfh), while low-bleed
devices bleed at a rate less than or equal to 6 scfh.1
For this analysis, EPA consulted information in the appendices of the Natural Gas STAR Lessons
Learned document on pneumatic devices, Subpart W of the Greenhouse Gas Reporting rule, as well as
obtained updated data from major vendors of pneumatic devices. The data obtained from vendors
included emission rates, costs, and any other pertinent information for each pneumatic device model (or
model family). All pneumatic devices that a vendor offered were itemized and inquiries were made into
the specifications of each device and whether it was applicable to oil and natural gas operations. High-
bleed and low-bleed devices were differentiated using the 6 scfh threshold.
Although by definition, a low-bleed device can emit up to 6 scfh, through this vendor research, it was
determined that the typical low-bleed device available currently on the market emits lower than the
maximum rate allocated for the device type. Specifically, low-bleed devices on the market today have
emissions from 0.2 scfh up to 5 scfh. Similarly, the available bleed rates for a high bleed device vary
significantly from venting as low as 7 scfh to as high as 100 scfh.3'11 While the vendor data provides
useful information on specific makes and models, it did not yield sufficient information about the
1 The classification of high-bleed and low-bleed devices originated from a report by Pacific Gas & Electric (PG&E) and the
Gas Research Institute (GPJ) in 1990 titled "Unaccounted for Gas Project Summary Volume." This classification was
adopted for the October 1993 Report to Congress titled "Opportunities to Reduce Anthropogenic Methane Emissions in the
United States". As described on page 2-16 of the report, "devices with emissions or 'bleed' rates of 0.1 to 0.5 cubic feet per
minute are considered to be 'high-bleed' types (PG&E 1990)." This range of bleed rates is equivalent to 6 to 30 cubic feet per
hour.
11 All rates are listed at an assumed supply gas pressure of 20 psig.
5-3
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Table 5-1. Major Studies Reviewed for Consideration
of Emissions and Activity Data
Report Name
Greenhouse Gas Mandatory
Reporting Rule and Technical
Supporting Document 3
Inventory of Greenhouse Gas
Emissions and Sinks: 1990-2009 4'5
Methane Emissions from the
Natural Gas Industry6'7'8'9
Methane Emissions from the
Petroleum Industry (draft) 10
Methane Emissions from the
Petroleum Industry n
Oil and Gas Emission Inventories
for Western States 12
Natural Gas STAR Program
Affiliation
EPA
EPA
Gas Research
Institute /
EPA
EPA
EPA
Western
Regional Air
Partnership
EPA
Year of
Report
2010
2011
1996
1996
1999
2005
2000-
2010
Number of
Devices
Nationwide
Nationwide/
Regional
Nationwide
Nationwide
Nationwide
Regional
Emissions
Information
X
X
X
X
X
X
X
Control
Information
X
5-4
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prevalence of each model type in the population of devices; which is an important factor in developing a
representative emission factor. Therefore, for this analysis, EPA determined that best available
emissions estimates for pneumatic devices are presented in Table W-l A and W-1B of the Greenhouse
Gas Mandatory Reporting Rule for the Oil and Natural Gas Industry (Subpart W). However, for the
natural gas processing segment, a more conservative approach was assumed since it has been
determined that natural gas processing plants would have sufficient electrical service to upgrade to non-
gas driven controls. Therefore, to quantify representative emissions from a bleed-device in the natural
gas processing segment, information from Volume 12 of the EPA/GRI report111 was used to estimate the
methane emissions from a single pneumatic device by type.
The basic approach used for this analysis was to first approximate methane emissions from the average
pneumatic device type in each industry segment and then estimate VOC and hazardous air pollutants
(HAP) using a representative gas composition.13 The specific ratios from the gas composition were
0.278 pounds VOC per pound methane and 0.0105 pounds HAP per pound methane in the production
and processing segments, and 0.0277 pounds VOC per pound methane and 0.0008 pounds HAP per
pound methane in the transmission segment. Table 5-2 summarizes the estimated bleed emissions for a
representative pneumatic controller by industry segment and device type.
5.3 Nationwide Emissions from New Sources
5.3.1 Approach
Nationwide emissions from newly installed natural gas pneumatic devices for a typical year were
calculated by estimating the number of pneumatic devices installed in a typical year and multiplying by
the estimated annual emissions per device listed in Table 5-2. The number of new pneumatic devices
installed for a typical year was determined for each segment of the industry including natural gas
production, natural gas processing, natural gas transmission and storage, and oil production. The
methodologies that determined the estimated number of new devices installed in a typical year is
provided in section 5.3.2 of this chapter.
5.3.2 Population of Devices Installed Annually
In order to estimate the average number of pneumatic devices installed in a typical year, each industry
111 Table 4-11. page 56. epa.gov/gasstar/tools/related.html
5-5
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Table 5-2. Average Bleed Emission Estimates per Pneumatic Device in the Oil and Natural
Gas Sector (tons/year)"
Industry Segment
Natural Gas Production13
Natural Gas Transmission and Storage0
Oil Productiond
Natural Gas Processing6
High-Bleed
Methane
6.91
3.20
6.91
1.00
voc
1.92
0.089
1.92
0.28
HAP
0.073
0.003
0.073
0.01
Low-Bleed
Methane
0.26
0.24
0.26
1.00
VOC
0.072
0.007
0.072
0.28
HAP
0.003
0.0002
0.003
0.01
Minor discrepancies may be due to rounding.
a. The conversion factor used in this analysis is 1 thousand cubic feet of methane (Mcf) is equal to
0.0208 tons methane. Minor discrepancies may be due to rounding.
b. Natural Gas Production methane emissions are derived from Table W-l A and W-1B of Subpart
W.
c. Natural gas transmission and storage methane emissions are derived from Table W-3 of Subpart
W.
d. Oil production methane emissions are derived from Table W-l A and W-1B of Subpart W. It is
assumed only continuous bleed devices are used in oil production.
e. Natural gas processing sector methane emissions are derived from Volume 12 of the 1996 GRI
report.9 Emissions from devices in the processing sector were determined based on data available
for snap-acting and bleed devices, further distinction between high and low bleed could not be
determined based on available data.
5-6
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segment was analyzed separately using the best data available for each segment. The number of facilities
estimated in absence of regulation was undeterminable due to the magnitude of new sources estimated
and the lack of sufficient data that could indicate the number of controllers that would be installed in
states that may have regulations requiring low bleed controllers, such as in Wyoming and Colorado.
For the natural gas production and oil production segments, the number of new pneumatics installed in a
typical year was derived using a multiphase analysis. First, data from the US Greenhouse Gas Inventory:
Emission and Sinks 1990-2009 was used to establish the ratio of pneumatic controllers installed per well
site on a regional basis. These ratios were then applied to the number of well completions estimated in
Chapter 4 for natural gas well completions with hydraulic fracturing, natural gas well completions
without hydraulic fracturing and for oil well completions. On average, one pneumatic device was
assumed to be installed per well completion for a total of 33,411 pneumatic devices. By applying the
estimated 51 percent of bleed devices (versus snap acting controllers), it is estimated that an average of
17,040 bleed-devices would be installed in the production segment in a typical year.
The number of pneumatic controllers installed in the transmission segment was approximated using the
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009. The number of new devices
installed in a given year was estimated by subtracting the prior year (e.g. 2007) from the given year's
total (e.g. 2008). This difference was assumed to be the number of new devices installed in the latter
year (e.g. Number of new devices installed during 2008 = Pneumatics in 2008 - Pneumatics in 2007). A
3-year average was calculated based on the number of new devices installed in 2006 through 2008 in
order to determine the average number of new devices installed in a typical year.
Once the population counts for the number of pneumatics in each segment were established, this
population count was further refined to account for the number of snap-acting devices that would be
installed versus a bleed device. This estimate of the percent of snap-acting and bleed devices was based
on raw data found in the GRI study, where 51 percent of the pneumatic controllers are bleed devices in
the production segment, and 32 percent of the pneumatic controllers are bleed devices in the
transmission segment.9 The distinction between the number of high-bleed and low-bleed devices was
not estimated because this analysis assumes it is not possible to predict or ensure where low bleeds will
be used in the future. Table 5-3 summarizes the estimated number of new devices installed per year.
5-7
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Table 5-3. Estimated Number of Pneumatic Devices Installed in an Typical Year
Industry Segment
Natural Gas and Oil Production
Natural Gas Transmission and
Storage0
Number of New Devices Estimated for a Typical Year"
Snap-Acting
16,371
178
Bleed-Devices
17,040
84
Total
33,411
262
National averages of population counts from the Inventory were refined to include the difference
in snap-acting and bleed devices based on raw data found in the GRI/EPA study. This is based
on the assumption that 51 percent of the pneumatic controllers are bleed devices in the
production segment, while 32 percent are bleed devices in the transmission segment.
The number of pneumatics was derived from a multiphase analysis. Data from the US
Greenhouse Gas Inventory: Emission and Sinks 1990-2009 was used to establish the number of
pneumatics per well on a regional basis. These ratios were applied to the number of well
completions estimated in Chapter 4 for natural gas wells with hydraulic fracturing, natural gas
wells without hydraulic fracturing and for oil wells.
The number of pneumatics estimated for the transmission segment was approximated from
comparing a 3 year average of new devices installed in 2006 through 2008 in order to establish
an average number of pneumatics being installed in this industry segment in a typical year. This
analysis was performed using the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-
2009.
5-8
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For the natural gas processing segment, this analysis assumes that existing natural gas plants have
already replaced pneumatic controllers with other types of controls (i.e. an instrument air system) and
any high-bleed devices that remain are safety related. As a result, the number of new pneumatic bleed
devices installed at existing natural gas processing plants was estimated as negligible. A new greenfield
natural gas processing plant would require multiple control loops. In Chapter 8 of this document, it is
estimated that 29 new and existing processing facilities would be subject to the NSPS for equipment
leak detection. In order to quantify the impacts of the regulatory options represented in section 5.5 of
this Chapter, it is assumed that half of these facilities are new sites that will install an instrument air
system in place of multiple control valves. This indicates about 15 instrument air systems will be
installed in a representative year.
5.3.3 Emission Estimates
Nationwide baseline emission estimates for pneumatic devices for new sources in a typical year are
summarized in Table 5-4 by industry segment and device type. This analysis assumed for the nationwide
emission estimate that all bleed-devices have the high-bleed emission rates estimated in Table 5-2 per
industry segment since it cannot be predicted which sources would install a low bleed versus a high
bleed controller.
5.4 Control Techniques
Although pneumatic devices have relatively small emissions individually, due to the large population of
these devices installed on an annual basis, the cumulative VOC emissions for the industry are
significant. As a result, several options to reduce emissions have been developed over the years. Table
5-5 provides a summary of these options for reducing emissions from pneumatic devices including:
instrument air, non-gas driven controls, and enhanced maintenance.
Given the various control options and applicability issues, the replacement of a high-bleed with a low-
bleed device is the most likely scenario for reducing emissions from pneumatic device emissions. This is
also supported by States such as Colorado and Wyoming that require the use of low-bleed controllers in
place of high-bleed controllers. Therefore, low-bleed devices are further described in the following
section, along with estimates of the impacts of their application for a representative device and
nationwide basis. Although snap-acting devices have zero bleed emissions, this analysis assumes the
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Table 5-4. Nationwide Baseline Emissions from Representative Pneumatic Device Installed
in a Typical Year for the Oil and Natural Gas Industry (tons/year)"
Industry
Segment
Oil and Gas
Production
Natural Gas
Transmission and
Storage
Baseline Emissions from
Representative New Unit
(tpy)
VOC
1.9213
0.09523
Methane
6.9112
3.423
HAP
0.0725
0.003
Number of
New Bleed
Devices
Expected
Per Year
17,040
84
Nationwide Baseline
Emissions from Bleeding
Pneumatic (tpy)b
VOC
32,739
8
Methane
117,766
288
HAP
1,237
0.2
Minor discrepancies may be due to rounding.
a. Emissions have been based on the bleed rates for a high-bleed device by industry segment.
Minor discrepancies may be due to rounding.
b. To estimate VOC and HAP, weight ratios were developed based on methane emissions per
device. The specific ratios used were 0.278 pounds VOC per pound methane and 0.0105 pounds
HAP per pound methane in the production and processing segments, and 0.0277 pounds VOC
per pound methane and 0.0008 pounds HAP per pound methane in the transmission segment.
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Table 5-5. Alternative Control Options for Pneumatic Devices
Option
Description
Applicability/Effectiveness
Estimated Cost
Range
Install Low
Bleed Device
in Place of
High Bleed
Device
Low-bleed devices provide the same functional control as a
high-bleed device, while emitting less continuous bleed
emissions.
Applicability may depend on the function of
instrumentation for an individual device on
whether the device is a level, pressure, or
temperature controller.
Low-bleed devices
are, on average,
around $165 more
than high bleed
versions.
Convert to
Instrument
Air14
Compressed air may be substituted for natural gas in pneumatic
systems without altering any of the parts of the pneumatic
control. In this type of system, atmospheric air is compressed,
stored in a tank, filtered and then dried for instrument use. For
utility purposes such as small pneumatic pumps, gas compressor
motor starters, pneumatic tools and sand blasting, air would not
need to be dried. Instrument air conversion requires additional
equipment to properly compress and control the pressured air.
This equipment includes a compressor, power source, air
dehydrator and air storage vessel.
Replacing natural gas with instrument air in
pneumatic controls eliminates VOC emissions
from bleeding pneumatics. It is most effective
at facilities where there are a high
concentration of pneumatic control valves and
an operator present. Since the systems are
powered by electric compressors, they require
a constant source of electrical power or a back-
up natural gas pneumatic device. These
systems can achieve 100 percent reduction in
emissions.
A complete cost
analysis is provided
in Section 5.4.2.
System costs are
dependent on size of
compressor, power
supply needs, labor
and other equipment.
Mechanical
and Solar
Powered
Systems in
place of Bleed
device15
Mechanical controls operate using a simple design comprised of
levers, hand wheels, springs and flow channels. The most
common mechanical control device is the liquid-level float to
the drain valve position with mechanical linkages. Electricity or
small electrical motors (including solar powered) have been
used to operate valves. Solar control systems are driven by solar
power cells that actuate mechanical devices using electric
power. As such, solar cells require some type of back-up power
or storage to ensure reliability.
Application of mechanical controls is limited
because the control must be located in close
proximity to the process measurement.
Mechanical systems are also incapable of
handling larger flow fluctuations. Electric
powered valves are only reliable with a
constant supply of electricity. Overall, these
options are applicable in niche areas but can
achieve 100 percent reduction in emissions
where applicable.
Depending on
supply of power,
costs can range from
below $1,000 to
$10,000 for entire
systems.
Enhanced
Maintenance
16
Instrumentation in poor condition typically bleeds 5 to 10 scf
per hour more than representative conditions due to worn seals,
gaskets, diaphragms; nozzle corrosion or wear, or loose control
tube fittings. This may not impact the operations but does
increase emissions.
Enhanced maintenance to repair and maintain
pneumatic devices periodically can reduce
emissions. Proper methods of maintaining a
device are highly variable and could incur
significant costs.
Variable based on
labor, time, and fuel
required to travel to
many remote
locations.
5-11
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devices are not always used in the same functional application as bleed devices and are, therefore, not an
appropriate form of control for all bleed devices. It is assumed snap-acting, or no-bleed, devices meet
the definition of a low-bleed. This concept is further detailed in Section 5.5 of this chapter. Since this
analysis has assumed areas with electrical power have already converted applicable pneumatic devices
to instrument air systems, instrument air systems are also described for natural gas processing plants
only. Given applicability, efficiency and the expected costs of the other options identified in Table 5-5
(i.e. mechanical controls and enhanced maintenance), were not further conducted for this analysis.
5.4.1 Low-Bleed Controllers
5.4.1.1 Emission Reduction Potential
As discussed in the above sections, low-bleed devices provide the same functional control as a high-
bleed device, but have lower continuous bleed emissions. As summarized in Table 5-6, it is estimated on
average that 6.6 tons of methane and 1.8 tons of VOC will be reduced annually in the production
segment from installing a low-bleed device in place of a high-bleed device. In the transmission segment,
the average achievable reductions per device are estimated around 3.7 tons and 0.08 tons for methane
and VOC, respectively. As noted in section 5.2, a low-bleed controller can emit up to 6 scfh, which is
higher than the expected emissions from the typical low-bleed device available on the current market.
5.4.1.1 Effectiveness
There are certain situations in which replacing and retrofitting are not feasible, such as instances where a
minimal response time is needed, cases where large valves require a high bleed rate to actuate, or a
safety isolation valve is involved. Based on criteria provided by the Natural Gas STAR Program, it is
assumed about 80 percent of high-bleed devices can be replaced with low-bleed devices throughout the
production and transmission and storage industry segments.1 This corresponds to 13,632 new high-bleed
devices in the production segment (out of 17,040) and 67 new high-bleed devices in the transmission
and storage segment (out of 84) that can be replaced with a new low-bleed alternative. For high-bleed
devices in natural gas processing, this analysis assumed that the replaceable devices have already been
replaced with instrument air and the remaining high-bleed devices are safety related for about half of the
existing processing plants.
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Table 5-6. Estimated Annual Bleed Emission Reductions from Replacing a Representative High-
Bleed Pneumatic Device with a Representative Low-Bleed Pneumatic Device
Segment/Device Type
Oil and Natural Gas Production
Natural Gas Transmission and Storage
Emissions (tons/year)11
Methane
6.65
2.96
voc
1.85
0.082
HAP
0.07
0.002
Minor discrepancies may be due to rounding.
a. Average emission reductions for each industry segment based on the typical emission flow rates from
high-bleed and low-bleed devices as listed in Table 5-2 by industry segment.
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Applicability may depend on the function of instrumentation for an individual device on whether the
device is a level, pressure, or temperature controller. High-bleed pneumatic devices may not be
applicable for replacement with low-bleed devices because a process condition may require a fast or
precise control response so that it does not stray too far from the desired set point. A slower-acting
controller could potentially result in damage to equipment and/or become a safety issue. An example of
this is on a compressor where pneumatic devices may monitor the suction and discharge pressure and
actuate a re-cycle when one or the other is out of the specified target range. Other scenarios for fast and
precise control include transient (non-steady) situations where a gas flow rate may fluctuate widely or
unpredictably. This situation requires a responsive high-bleed device to ensure that the gas flow can be
controlled in all situations. Temperature and level controllers are typically present in control situations
that are not prone to fluctuate as widely or where the fluctuation can be readily and safely
accommodated by the equipment. Therefore, such processes can accommodate control from a low-bleed
device, which is slower-acting and less precise.
Safety concerns may be a limitation issue, but only in specific situations because emergency valves are
not bleeding controllers since safety is the pre-eminent consideration. Thus, the connection between the
bleed rate of a pneumatic device and safety is not a direct one. Pneumatic devices are designed for
process control during normal operations and to keep the process in a normal operating state. If an
Emergency Shut Down (BSD) or Pressure Relief Valve (PRV) actuation occurs,lv the equipment in place
for such an event is spring loaded, or otherwise not pneumatically powered. During a safety issue or
emergency, it is possible that the pneumatic gas supply will be lost. For this reason, control valves are
deliberately selected to either fail open or fail closed, depending on which option is the failsafe.
5.4.1.2 Cost Impacts
As described in Section 5.2.2, costs were based on the vendor research described in Section 5.2 as a
result of updating and expanding upon the information given in the appendices of the Natural Gas STAR
Lessons Learned document on pneumatic devices.1 As Table 5-7 indicates, the average cost for a low
bleed pneumatic is $2,553, while the average cost for a high bleed is $2,338.v Thus, the incremental cost
of installing a low-bleed device instead of a high-bleed device is on the order of $165 per device. In
order to analyze cost impacts, the incremental cost to install a low-bleed instead of a high-bleed was
1V BSD valves either close or open in an emergency depending on the fail safe configuration. PRVs always open in an
emergency.
v Costs are estimated in 2008 U.S. Dollars.
5-14
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Table 5-7. Cost Projections for the Representative Pneumatic Devices"
Device
High-bleed controller
Low-bleed controller
Minimum
cost ($)
366
524
Maximum
cost ($)
7,000
8,852
Average cost ($)
2,388
2,553
Low-Bleed
Incremental
Cost
($)
C1 f,1^
4>1CO
a. Major pneumatic devices vendors were surveyed for costs, emission rates, and any other pertinent
information that would give an accurate picture of the present industry.
5-15
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annualized for a 10 year period using a 7 percent interest rate. This equated to an annualized cost of
around $23 per device for both the production and transmission segments.
Monetary savings associated with additional gas captured to the sales line was estimated based on a
natural gas value of $4.00 per Mcf.V1'17 The representative low-bleed device is estimated to emit 6.65
tons, or 319 Mcf, (using the conversion factor of 0.0208 tons methane per 1 Mcf) of methane less than
the average high-bleed device per year. Assuming production quality gas is 82.8 percent methane by
volume, this equals 385.5 Mcf natural gas recovered per year. Therefore, the value of recovered natural
gas from one pneumatic device in the production segment equates to approximately $1,500. Savings
were not estimated for the transmission segment because it is assumed the owner of the pneumatic
controller generally is not the owner of the natural gas. Table 5-8 provides a summary of low-bleed
pneumatic cost effectiveness.
5.4.1.3 Secondary Impacts
Low-bleed pneumatic devices are a replacement option for high-bleed devices that simply bleed less
natural gas that would otherwise be emitted in the actuation of pneumatic valves. No wastes should be
created, no wastewater generated, and no electricity needed. Therefore, there are no secondary impacts
expected due to the use of low-bleed pneumatic devices.
5.4.2 Instrument Air Systems
5.4.2.1 Process Description
The major components of an instrument air conversion project include the compressor, power source,
dehydrator, and volume tank. The following is a description of each component as described in the
Natural Gas STAR document, Lessons Learned: Convert Gas Pneumatic Controls to Instrument Air:
• Compressors used for instrument air delivery are available in various types and sizes, from
centrifugal (rotary screw) compressors to reciprocating piston (positive displacement) 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 bleed 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.
V1 The average market price for natural gas in 2010 was approximately $4.16 per Mcf. This is much less compared to the
average price in 2008 of $7.96 per Mcf. Due to the volatility in the value, a conservative savings of $4.00 per Mcf estimate
was projected for the analysis in order to not overstate savings.
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Table 5-8. Cost-effectiveness for Low-Bleed Pneumatic Devices
versus High Bleed Pneumatics
Segment
Oil and
Natural Gas
Production
Natural Gas
Transmission
and Storage
Incremental
Capital Cost
Per Unit ($)a
165
165
Total Annual Cost
Per Unit
($/yr)b
without
savings
23.50
23.50
with
savings
-1,519
23.50
VOC Cost
Effectiveness
($/ton)
without
savings
13
286
with
savings
net
savings
286
Methane Cost
Effectiveness
($/ton)
without
savings
4
8
with
savings
net
savings
8
a. Incremental cost of a low bleed device versus a high bleed device as summarized in Table 5-7.
b. Annualized cost assumes a 7 percent interest rate over a 10 year equipment lifetime.
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For reliability, a full spare compressor is normally installed. A minimum amount of electrical
service is required to power the compressors.
• A critical component of the instrument air control system is the power source required to
operate the compressor. Since high-pressure natural gas is abundant and readily available, gas
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 in 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 cost effective for remote
locations, which reduce both methane emissions and energy consumption. Small natural gas
powered fuel cells are also being developed.
• Dehydrators, or air dryers, are also 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.
• 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.
Compressed air may be substituted for natural gas in pneumatic systems without altering any of the parts
of the pneumatic control. The use of instrument air eliminates natural gas emissions from natural gas
powered pneumatic controllers. All other parts of a gas pneumatic system will operate the same way
with instrument air as they do with natural gas. The conversion of natural gas pneumatic controllers to
instrument air systems is applicable to all natural gas facilities with electrical service available.14
5.4.2.2 Effectiveness
The use of instrument air eliminates natural gas emissions from the natural gas driven pneumatic
devices; however, the system is only applicable in locations with access to a sufficient and consistent
5-18
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supply of electrical power. Instrument air systems are also usually installed at facilities where there is a
high concentration of pneumatic control valves and the presence of an operator that can ensure the
system is properly functioning.14
5.4.2.3 Cost Impacts
Instrument air conversion requires additional equipment to properly compress and control the pressured
air. The size of the compressor will depend on the number of control loops present at a location. A
control loop consists of one pneumatic controller and one control valve. The volume of compressed air
supply for the pneumatic system is equivalent to the volume of gas used to run the existing
instrumentation - adjusted for air losses during the drying process. The current volume of gas usage can
be determined by direct metering if a meter is installed. Otherwise, an alternative rule of thumb for
sizing instrument air systems is one cubic foot per minute (cfm) of instrument air for each control loop.14
As the system is powered by electric compressors, the system requires a constant source of electrical
power or a back-up pneumatic device. Table 5-9 outlines three different sized instrument air systems
including the compressor power requirements, the flow rate provided from the compressor, and the
associated number of control loops.
The primary costs associated with conversion to instrument air systems are the initial capital
expenditures for installing compressors and related equipment and the operating costs for electrical
energy to power the compressor motor. This equipment includes a compressor, a power source, a
dehydrator and a storage vessel. It is assumed that in either an instrument air solution or a natural gas
pneumatic solution, gas supply piping, control instruments, and valve actuators of the gas pneumatic
system are required. The total cost, including installation and labor, of three representative sizes of
compressors were evaluated based on assumptions found in the Natural Gas STAR document, "Lessons
Learned: Convert Gas Pneumatic Controls to Instrument Air"14 and summarized in Table 5-10.V11
For natural gas processing, the cost-effectiveness of the three representative instrument air system sizes
was evaluated based on the emissions mitigated from the number of control loops the system can
provide and not on a per device basis. This approach was chosen because we assume new processing
plants will need to provide instrumentation of multiple control loops and size the instrument air system
accordingly. We also assume that existing processing plants have already upgraded to instrument air
™ Costs have been converted to 2008 US dollars using the Chemical Engineering Cost Index.
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Table 5-9. Compressor Power Requirements and Costs for Various Sized Instrument Air
Systems"
Compressor Power Requirements'5
Size of Unit
small
medium
large
hp
10
30
75
kW
13.3
40
100
Flow Rate
(cfm)
30
125
350
Control Loops
Loops/Compressor
15
63
175
a. Based on rules of thumb stated in the Natural Gas STAR document, Lessons Learned:
Convert Gas Pneumatic Controls to Instrument Air14
b. Power is based on the operation of two compressors operating in parallel (each assumed to be
operating at full capacity 50 percent of the year).
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Table 5-10 Estimated Capital and Annual Costs of Various Sized Representative Instrument Air Systems
Instrument
Air System
Size
Small
Medium
Large
Compressor
$3,772
$18,855
$33,183
Tank
$754
$2,262
$4,525
Air Dryer
$2,262
$6,787
$15,083
Total
Capital3
$16,972
$73,531
$135,750
Annualized
Capitalb
$2,416
$10,469
$19,328
Labor
Cost
$1,334
$4,333
$5,999
Total
Annual
Costs0
$8,674
$26,408
$61,187
Annualized Cost
of Instrument Air
System
$11,090
$36,877
$80,515
b.
c.
Total Capital includes the cost for two compressors, tank, an air dryer and installation. Installation costs are assumed to be equal to 1.5
times the cost of capital. Equipment costs were derived from the Natural Gas Star Lessons Learned document and converted to 2008
dollars from 2006 dollars using the Chemical Engineering Cost Index.
The annualized cost was estimated using a 7 percent interest rate and 10 year equipment life.
Annual Costs include the cost of electrical power as listed in Table 5-9 and labor.
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unless the function has a specific need for a bleeding device, which would most likely be safety related.9
Table 5-11 summarizes the cost-effectiveness of the three sizes of representative instrument air systems.
5.4.2.4 Secondary Impacts
The secondary impacts from instrument air systems are indirect, variable and dependent on the electrical
supply used to power the compressor. No other secondary impacts are expected.
5.5 Regulatory Options
The affected facility definition for pneumatic controllers is defined as a single natural gas pneumatic
controller. Therefore, pneumatic controllers would be subject to a New Source Performance Standard
(NSPS) at the time of installation. The following Regulatory alternatives were evaluated:
• Regulatory Option 1: Establish an emissions limit equal to 0 scfh.
• Regulatory Option 2: Establish an emissions limit equal to 6 scfh.
5.5.1 Evaluation of Regulatory Options
By establishing an emission limit of 0 scfh, facilities would most likely install instrument air systems to
meet the threshold limit. This option is considered cost effective for natural gas processing plants as
summarized in Table 5-11. A major assumption of this analysis, however, is that processing plants are
constructed at a location with sufficient electrical service to power the instrument air compression
system. It is assumed that facilities located outside of the processing plant would not have sufficient
electrical service to install an instrument air system. This would significantly increase the cost of the
system at these locations, making it not cost effective for these facilities to meet this regulatory option.
Therefore, Regulatory Option 1 was accepted for natural gas processing plants and rejected for all other
types of facilities.
Regulatory Option 2 would establish an emission limit equal to the maximum emissions allowed for a
low-bleed device in the production and transmissions and storage industry segments. This would most
likely be met by the use of low-bleed controllers in place of a high-bleed controller, but allows
flexibility in the chosen method of meeting the requirement. In the key instances related to pressure
control that would disallow the use of a low-bleed device, specific monitoring and recordkeeping criteria
5-22
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Table 5-11 Cost-effectiveness of Representative Instrument Air Systems in the Natural Gas Processing Segment
System
Size
Small
Medium
Large
Number of
Control
Loops
15
63
175
Annual Emissions
Reductiona(tons/year)
VOC
4.18
17.5
48.7
CH4
15
63
175
HAP
0.16
0.66
1.84
Value of
Product
Recovered
($/year)b
3,484
14,632
40,644
Annualized Cost of
System
without
savings
11,090
36,877
80,515
with
savings
7,606
22,245
39,871
VOC Cost-
effectiveness ($/ton)
without
savings
2,656
2,103
1,653
with
savings
1,822
1,269
819
Methane Cost-
effectiveness ($/ton)
without
savings
738
585
460
with
savings
506
353
228
Minor discrepancies may be due to rounding.
a. Based on the emissions mitigated from the entire system, which includes multiple control loops.
b. Value of recovered product assumes natural gas processing is 82.8 percent methane by volume. A natural gas price of $4 per Mcf was
assumed.
5-23
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would be required to ensure the device function dictates the precision of a high bleed device. Therefore,
Regulatory Option 2 was accepted for locations outside of natural gas processing plants.
5.5.2 Nationwide Impacts of Regulatory Options
Table 5-12 summarizes the costs impacts of the selected regulatory options by industry segment.
Regulatory Option 1 for the natural gas processing segment is estimated to affect 15 new processing
plants with nationwide annual costs discounting savings of $166,000. When savings are realized the net
annual cost is reduced to around $114,000. Regulatory Option 2 has nationwide annual costs of
$320,000 for the production segment and around $1,500 in the natural gas transmission and storage
segment. When annual savings are realized in the production segment there is a net savings of
$20.7 million in nationwide annual costs.
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Table 5-12 Nationwide Cost and Emission Reduction Impacts for Selected Regulatory Options by Industry Segment
Industry
Segment
Number
of
Sources
subject to
NSPS*
Capital Cost
Per
Device/IAS
($)••
Annual Costs
(S/year)
without
savings
with
savings
Nationwide Emission
Reductions (tpy)f
voc
Methane
HAP
VOC Cost
Effectiveness
(S/ton)
without
savings
with
savings
Methane Cost
Effectiveness
(S/ton)
without
savings
with
savings
Total Nationwide Costs
(S/year)
Capital
Cost
Annual
without
savings
Annual with
savings
Regulatory Option 1 (emission threshold equal to 0 scfh)
Natural Gas
Processing
15
16,972
11,090
7,606
63
225
2
2,656
1,822
738
506
254,576
166,351
114,094
Regulatory Option 2 (emission threshold equal to 6 scfh)
Oil and
Natural Gas
Production
Natural Gas
Transmission
and Storage
13,632
67
165
165
23
23
(1,519)
23
25,210
6
90,685
212
952
0.2
13
262
net
savings
262
4
7
net
savings
7
2,249,221
11,039
320,071
1,539
(20,699,918)
1,539
Minor discrepancies may be due to rounding.
a. The number of sources subject to NSPS for the natural gas processing and the natural gas transmission and storage segments represent
the number of new devices expected per year reduced by 20 percent. This is consistent with the assumption that 80 percent of high
bleed devices can be replaced with a low bleed device. It is assumed all new sources would be installed as a high bleed for these
segments. For the natural gas processing segment the number of new sources represents the number of Instrument Air Systems (IAS)
that is expected to be installed, with each IAS expected to power 15 control loops (or replace 15 pneumatic devices).
b. The capital cost for regulatory option 2 is equal to the incremental cost of a low bleed device versus a new high bleed device. The
capital cost of the IAS is based on the small IAS as summarized in Table 5-10.
c. Nationwide emission reductions vary based on average expected emission rates of bleed devices typically used in each segment
industry segment as summarized in Tables 5-2.
5-25
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5.6 References
1 U.S. Environmental Protection Agency. Lessons Learned: Options for Reducing Methane
Emissions From Pneumatic Devices in the Natural Gas Industry. Office of Air and Radiation:
Natural Gas Star. Washington, DC. February 2004
2 Memorandum to Bruce Moore from Denise Grubert. Meeting Minutes from EPA Meeting with
the American Petroleum Institute. October 2011
3 U.S. Environmental Protection Agency. Greenhouse Gas Emissions Reporting From the
Petroleum and Natural Gas Industry: Background Technical Support Document. Climate Change
Division. Washington, DC. November 2010.
4 U.S Environmental Protection Agency. Methodology for Estimating CH4 and CO2 Emissions
from Natural Gas Systems. Greenhouse Gas Inventory: Emission and Sinks 1990-2008.
Washington, DC.
5 U.S Environmental Protection Agency. Methodology for Estimating CH4 and CO2 Emissions
from Petroleum Systems. Greenhouse Gas Inventory: Emission and Sinks 1990-2008.
Washington, DC.
6 Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 2: Technical
Report. Prepared for the Gas Research Institute and Environmental Protection Agency. EPA-
600/R-96-080b. June 1996.
7 Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 3: General
Methodology. Prepared for the Gas Research Institute and Environmental Protection Agency.
EPA-600/R-96-080c. June 1996.
8 Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 5: Activity
Factors. Prepared for the Gas Research Institute and Environmental Protection Agency. EPA-
600/R-96-080e. June 1996.
9 Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 12:
Pneumatic Devices. Prepared for the Gas Research Institute and Environmental Protection
Agency. EPA-600/R-96-080k. June 1996.
10 Radian International LLC, Methane Emissions from the U.S. Petroleum Industry, draft report for
the U.S. Environmental Protection Agency, June 14, 1996.
11 ICF Consulting. Estimates of Methane Emissions from the U.S. Oil Industry. Prepared for the
U.S. Environmental Protection Agency. 1999.
12 ENVIRON International Corporation. Oil and Gas Emission Inventories for the Western States.
Prepared for Western Governors' Association. December 27, 2005.
13 Memorandum to Bruce Moore from Heather Brown. Gas Composition Methodology. July 2011
5-26
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14 U.S. Environmental Protection Agency. Lessons Learned: Convert Gas Pneumatic Controls to
Instrument Air. Office of Air and Radiation: Natural Gas Star. Washington, DC. February 2004
15 U.S. Environmental Protection Agency. Pro Fact Sheet No. 301. Convert Pneumatics to
Mechanical Controls. Office of Air and Radiation: Natural Gas Star. Washington, DC.
September 2004.
16 CETAC WEST. Fuel Gas Best Management Practices: Efficient Use of Fuel Gas in Pneumatic
Instruments. Prepared for the Canadian Association of Petroleum Producers. May 2008.
17 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
5-27
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6.0 COMPRESSORS
Compressors are mechanical devices that increase the pressure of natural gas and allow the natural gas
to be transported from the production site, through the supply chain, and to the consumer. The types of
compressors that are used by the oil and gas industry as prime movers are reciprocating and centrifugal
compressors. This chapter discusses the air pollutant emissions from these compressors and provides
emission estimates for reducing emission from these types of compressors. In addition, nationwide
emissions estimates from new sources are estimated. Options for controlling pollutant emissions from
these compressors are presented, along with costs, emission reductions, and secondary impacts. Finally,
this chapter discusses considerations in developing regulatory alternatives for both reciprocating and
centrifugal compressors.
6.1 Process Description
6.1.1 Reciprocating Compressors
In a reciprocating compressor, natural gas enters the suction manifold, and then flows into a
compression cylinder where it is compressed by a piston driven in a reciprocating motion by the
crankshaft powered by an internal combustion engine. Emissions occur when natural gas leaks around
the piston rod when pressurized natural gas is in the cylinder. The compressor rod packing system
consists of a series of flexible rings that create a seal around the piston rod to prevent gas from escaping
between the rod and the inboard cylinder head. However, over time,during operation of the compressor,
the rings become worn and the packing system will need to be replaced to prevent excessive leaking
from the compression cylinder.
6.1.2 Centrifugal Compressors
Centrifugal compressors use a rotating disk or impeller to increase the velocity of the gas where it is
directed to a divergent duct section that converts the velocity energy to pressure energy. These
compressors are primarily used for continuous, stationary transport of natural gas in the processing and
transmission systems. Many centrifugal compressors use wet (meaning oil) seals around the rotating
shaft to prevent natural gas from escaping where the compressor shaft exits the compressor casing. The
wet seals use oil which is circulated at high pressure to form a barrier against compressed natural gas
leakage. The circulated oil entrains and absorbs some compressed natural gas which is released to the
6-1
-------
atmosphere during the seal oil recirculation process. Alternatively, dry seals can be used to replace the
wet seals in centrifugal compressors. Dry seals prevent leakage by using the opposing force created by
hydrodynamic groves and springs. The opposing forcescreate a thin gap of high pressure gas between
the rings through which little gas can leak. The rings do not wear or need lubrication because they are
not in contact with each other. Therefore, operation and maintenance costs are lower for dry seals in
comparison to wet seals.
6.2 Emissions Data and Emission Factors
6.2.1 Summary of Major Studies and Emissions Factors
There are a few studies that have been conducted that provide leak estimates from reciprocating and
centrifugal compressors. These studies are provided in Table 6-1, along with the type of information
contained in the study.
6.2.2 Representative Reciprocating and Centrifugal Compressor Emissions
The methodology for estimating emission from reciprocating compressor rod packing was to use the
methane emission factors referenced in the EPA/GRI study1 and use the methane to pollutant ratios
developed in the gas composition memorandum.2 The emission factors in the EPA/GRI document were
expressed in thousand standard cubic feet per cylinder (Mscf/cyl), and were multiplied by the average
number of cylinder per reciprocating compressor at each oil and gas industry segment. The volumetric
methane emission rate was converted to a mass emission rate using a density of 41.63 pounds of
methane per thousand cubic feet. This conversion factor was developed assuming that methane is an
ideal gas and using the ideal gas law to calculate the density. A summary of the methane emission
factors is presented in Table 6-2. Once the methane emissions were calculated, ratios were used to
estimate volatile organic compounds (VOC) and hazardous air pollutants (HAP). The specific ratios that
were used for this analysis were 0.278 pounds VOC per pound of methane and 0.105 pounds HAP per
pound of methane for the production and processing segments, and 0.0277 pounds VOC per pound of
methane and 0.0008 pounds HAP per pound of methane for the transmission and storage segments. A
summary of the reciprocating compressor emissions are presented in Table 6-3.
The compressor emission factors for wet seals and dry seals are based on data used in the GHG
inventory. The wet seals methane emission factor was calculated based on a sampling of 48 wet seal
centrifugal compressors. The dry seal methane emission factor was based on data collected by the
6-2
-------
Table 6-1. Major Studies Reviewed for Consideration
Of Emissions and Activity Data
Report Name
Inventory of Greenhouse
Gas Emissions and Sinks:
1990-20081
Greenhouse Gas Mandatory
Reporting Rule and
Technical Supporting
Document2
Methane Emissions from
the Natural Gas Industry3
Natural Gas STAR
Program4'5
Affiliation
EPA
EPA
Gas Research
Institute/EPA
EPA
Year of
Report
2010
2010
1996
1993-2010
Activity
Information
Nationwide
Nationwide
Nationwide
Nationwide
Emissions
Information
X
X
X
X
Control
Information
X
6-3
-------
Table 6-2. Methane Emission Factors for Reciprocating and Centrifugal Compressors
Oil and Gas
Industry
Segment
Production
(Well Pads)
Gathering &
Boosting
Processing
Transmission
Storage
Reciprocating Compressors
Methane
Emission Factor
(scf/hr-cylinder)
0.271s
25. 9b
57C
57d
51e
Average
Number of
Cylinders
4
3.3
2.5
3.3
4.5
Pressurized
Factor (% of
hour/year
Compressor
Pressurized)
100%
79.1%
89.7%
79.1%
67.5%
Centrifugal Compressors
Wet Seal
Methane
Fmission
Factor
(scf/minute)
N/Af
N/Af
47.7s
47.7s
47.7s
Dry Seals
Methane
Fmission
Factor
(scf/minute)
N/Af
N/Af
6s
6s
6s
a. EPA/GRI. (1996). "Methane Emissions from the Natural Gas Industry: Volume 8 - Equipment
Leaks." Table 4-8.
b. Clearstone Engineering Ltd. Cost-Effective Directed Inspection and Maintenance Control
Opportunities at Five Gas Processing Plants and Upstream Gathering Compressor Stations and
Well Sites. (Draft): 2006.
c. EPA/GRI. (1996). Methane Emissions from the Natural Gas Industry: Volume 8 - Equipment
Leaks. Table 4-14.
d. EPA/GRI. (1996). "Methane Emissions from the Natural Gas Industry: Volume 8 - Equipment
Leaks." Table 4-17.
e. EPA/GRI. (1996). "Methane Emissions from the Natural Gas Industry: Volume 8 - Equipment
Leaks." Table 4-24.
f. The 1996 EPA/GRI Study Volume II3, does not report any centrifugal compressors in the
production or gathering/boosting sectors, therefore no emission factor data were published for
those two sectors.
g. U.S Environmental Protection Agency. Methodology for Estimating CH4 and CO2 Emissions
from Petroleum Systems. Greenhouse Gas Inventory: Emission and Sinksl990-2009.
Washington, DC. April 2011. Annex 3. Page A-153.
6-4
-------
Table 6-3.Baseline Emission Estimates for Reciprocating and Centrifugal Compressors
Industry Segment/
Compressor Type
Baseline Emission Estimates
(tons/year)
Methane
voc
HAP
Reciprocating Compressors
Production (Well Pads)
Gathering & Boosting
Processing
Transmission
Storage
0.198
12.3
23.3
27.1
28.2
0.0549
3.42
6.48
0.751
0.782
0.00207
0.129
0.244
0.0223
0.0232
Centrifugal Compressors (Wet seals)
Processing
Transmission
Storage
228
126
126
20.5
3.50
3.50
0.736
0.104
0.104
Centrifugal Compressors (Dry seals)
Processing
Transmission
Storage
28.6
15.9
15.9
2.58
0.440
0.440
0.0926
0.0131
0.0131
6-5
-------
Natural Gas STAR Program. The methane emissions were converted to VOC and HAP emissions using
the same gas composition ratios that were used for reciprocating engines.4 A summary of the emission
factors are presented in Table 6-2 and the individual compressor emission are shown in Table 6-3 for
each of the oil and gas industry segments.
6.3 Nationwide Emissions from New Sources
6.3.1 Overview of Approach
The number of new affected facilities in each of the oil and gas sectors was estimated using data from
the U.S. Greenhouse Gas Inventory,5'6 with some exceptions. This basis was used whenever the total
number of existing facilities was explicitly estimated as part of the Inventory, so that the difference
between two years can be calculated to represent the number of new facilities. The Inventory was not
used to estimate the new number of reciprocating compressor facilities in gas production, since more
recent information is available in the comments received to subpart W of the mandatory reporting rule.
Similarly, the Inventory was not used to estimate the new number of reciprocating compressor facilities
in gas gathering, since more recent information is available in comments received as comments to
subpart W of the mandatory reporting rule. For both gas production and gas gathering, information
received as comments to subpart W of the mandatory reporting rule was combined with additional EPA
estimates and assumptions to develop the estimates for the number of new affected facilities.
Nationwide emission estimates for new sources were then determined by multiplying the number of new
sources for each oil and gas segment by the expected emissions per compressor using the emission data
in Table 6-3. A summary of the number of new reciprocating and centrifugal compressors for each of
the oil and gas segments is presented in Table 6-4.
6.3.2 Activity Data for Reciprocating Compressors
6.3.2.1 Wellhead Reciprocating Compressors
The number of wellhead reciprocating compressors was estimated using data from industry comments
on Subpart W of the Greenhouse Gas Mandatory Reporting Rule.7 The 2010 U.S. GHG Inventory
reciprocating compressor activity data was not considered in the analysis because it does not distinguish
between wellhead and gathering and boosting compressors. Therefore, using data submitted to EPA
o
during the subpart W comment period from nine basins supplied by the El Paso Corporation, the
6-6
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Table 6-4.Approximate Number of New Sources in the Oil and Gas Industry in 2008
Industry Segment
Wellheads
Gathering and Boosting
Processing
Transmission
Storage
Number of New Reciprocating
Compressors
6,000
210
209
20
4
Number of New Centrifugal
Compressors
0
0
16
14
6-7
-------
average number of new wellhead compressors per new well was calculated using the 315 well head
compressors provided in the El Paso comments and 3,606 wells estimated in the Final Subpart W
onshore production threshold analysis. This produced an average of 0.087 compressors per wellhead.
The average wellhead compressors per well was multiplied by the total well completions (oil and gas)
determined from the HPDI® database9 between 2007 and 2008, which came to 68,000 new well
completions. Using this methodology, the estimated number of new reciprocating compressors at
production pads was calculated to be 6,000 for 2008. A summary of the number of new reciprocating
compressors located at well pads is presented in Table 6-4.
6.3.2.2 Gathering and Boosting Reciprocating Compressors
The number of gathering & boosting reciprocating compressors was also estimated using data from
industry comments on Subpart W. DCP Midstream stated on page 3 of its 2010 Subpart W comments
that it operates 48 natural gas processing plants and treaters and 700 gathering system compressor
stations. Using this data, there were an average of 14.583 gathering and boosting compressor stations per
processing plant. The number of new gathering and boosting compressors was determined by taking the
average difference between the number of processing plants for each year in the 2010 U.S Inventory,
which references the total processing plants in the Oil and Gas Journal. This was done for each year up
to 2008. An average was taken of only the years with an increase in processing plants, up to 2008. The
resulting average was multiplied by the 14.583 ratio of gathering and boosting compressor stations to
processing plants and the 1.5 gathering and boosting compressors per station yielding 210 new source
gathering and boosting compressor stations and is shown in Table 6-4.
6.3.2.3 Processing Reciprocating Compressors
The number of new processing reciprocating compressors at processing facilities was estimated by
averaging the increase of reciprocating compressors at processing plants in the greenhouse gas inventory
data for 2007, 2008, and 2009.10'u The estimated number of existing reciprocating compressors in the
processing segment was 4,458, 4,781, and 4,876 for the years 2007, 2008, and 2009 respectively. This
calculated to be 323 new reciprocating compressors between 2007 and 2008, and 95 new reciprocating
compressors between 2008 and 2009. The average difference was calculated to be 209 reciprocating
compressors and was used to estimate the number of new sources in Table 6-4.
6-8
-------
6.3.2.4 Transmission and Storage Reciprocating Compressors
The number of new transmission and storage reciprocating compressors was estimated using the
1 O 1 Q
differences in the greenhouse gas inventory ' data for 2007, 2008, and 2009 and calculating an
average of those differences. The estimated number of existing reciprocating compressors at
transmission stations was 7,158, 7,028, and 7,197 for the years 2007, 2008, and 2009 respectively. This
calculated to be -130 new reciprocating compressors between 2007 and 2008, and 169 new reciprocating
compressors between 2008and 2009. The average difference was calculated to be 20 reciprocating
compressors and was used to estimate the number of new sources at transmission stations. The number
of existing reciprocating compressors at storage stations was 1,144, 1,178, and 1,152 for the years 2007,
2008, and 2009 respectively. This calculated to be 34 new reciprocating compressors between 2007 and
2008, and -26 new reciprocating compressors between 2008and 2009. The average difference was
calculated to be 4 reciprocating compressors and was used to estimate the number of new sources at
storage stations in Table 6-4.
6.3.3 Activity Data for Centrifugal Compressors
The number of new centrifugal compressors in 2008 for the processing and transmission/storage
segments was determined by taking the average difference between the centrifugal compressor activity
data for each year in the 2008 U.S. Inventory . For example, the number of compressors in 1992 was
subtracted from the number of compressors in 1993 to determine the number of new centrifugal
compressors in 1993. This was done for each year up to 2008. An average was taken of only the years
with an increase in centrifugal compressors, up to 2008, to determine the number of new centrifugal
compressors in 2008. The result was 16 and 14 new centrifugal compressors in the processing and
transmission segments respectively. A summary of the estimates for new centrifugal compressor is
presented in Table 6-4.
6.3.4 Emission Estimates
Nationwide baseline emission estimates for new reciprocating and centrifugal compressors are
summarized in Table 6-5 by industry segment.
6-9
-------
Table 6-5.Nationwide Baseline Emissions for New Reciprocating and Centrifugal Compressors
Industry Segment/
Compressor Type
Nationwide baseline Emissions
(tons/year)
Methane
voc
HAP
Reciprocating Compressors
Production (Well Pads)
Gathering & Boosting
Processing
Transmission
Storage
1,186
2,587
4,871
529
113
330
719
1,354
14.6
3.13
12.4
27.1
51.0
0.435
0.0929
Centrifugal Compressors
Processing
Transmission/Storage
3,640
1,768
329
48.9
11.8
1.45
6-10
-------
6.4 Control Techniques
6.4.1 Potential Control Techniques
The potential control options reviewed for reducing emissions from reciprocating compressors include
control techniques that limit the leaking of natural gas past the piston rod packing. This
includesreplacement of the compressor rod packing, replacement of the piston rod, and the refitting or
realignment of the piston rod.
The replacement of the rod packing is a maintenance task performed on reciprocating compressors to
reduce the leakage of natural gas past the piston rod. Over time the packing rings wear and allow more
natural gas to escape around the piston rod. Regular replacement of these rings reduces methane and
VOC emissions. Therefore, this control technique was determined to be an appropriate optionfor
reciprocating compressors.
Like the packing rings, piston rods on reciprocating compressors also deteriorate. Piston rods, however,
wear more slowly than packing rings, having a life of about 10 years.14 Rods wear "out-of-round" or
taper when poorly aligned, which affects the fit of packing rings against the shaft (and therefore the
tightness of the seal) and the rate of ring wear. An out-of-round shaft not only seals poorly, allowing
more leakage, but also causes uneven wear on the seals, thereby shortening the life of the piston rod and
the packing seal. Replacing or upgrading the rod can reduce reciprocating compressor rod packing
emissions. Also, upgrading piston rods by coating them with tungsten carbide or chrome reduces wear
over the life of the rod. This analysis assumes operators will choose, at their discretion, when to replace
the rod and hence, does not consider this control technique to be a practical control option for
reciprocating compressors. A summary of these techniques are presented in the following sections.
Potential control options to reduce emissions from centrifugal compressors include control techniques
that limit the leaking of natural gas across the rotating shaft, or capture and destruction of the emissions
using a flare. A summary of these techniques are presented in the following sections.
A control technique for limiting or reducing the emission from the rotating shaft of a centrifugal
compressor is a mechanical dry seal system. This control technique uses rings to prevent the escape of
natural gas across the rotating shaft. This control technique was determined to be a viable option for
reducing emission from centrifugal compressors.
6-11
-------
For centrifugal compressors equipped with wet seals, a flare was considered to be a reasonable option
for reducing emissions from centrifugal compressors. Centrifugal compressors require seals around the
rotating shaft to prevent natural gas from escaping where the shaft exits the compressor casing. "Beam"
type compressors have two seals, one on each end of the compressor, while "over-hung" compressors
have a seal on only the "inboard" (motor end) side. These seals use oil, which is circulated under high
pressure between three rings around the compressor shaft, forming a barrier against the compressed gas
leakage. The center ring is attached to the rotating shaft, while the two rings on each side are stationary
in the seal housing, pressed against a thin film of oil flowing between the rings to both lubricate and act
as a leak barrier. The seal also includes "O-ring" rubber seals, which prevent leakage around the
stationary rings. The oil barrier allows some gas to escape from the seal, but considerably more gas is
entrained and absorbed in the oil under the high pressures at the "inboard" (compressor side) seal oil/gas
interface, thus contaminating the seal oil. Seal oil is purged of the absorbed gas (using heaters, flash
tanks, and degassing techniques) and recirculated back to the seal. As a control measure, the recovered
gas would then be sent to a flare or other combustion device.
6.4.2 Reciprocating Compressor Rod Packing Replacement
6.4.2.1 Description
Reciprocating compressor rod packing consists of a series of flexible rings that fit around a shaft to
create a seal against leakage. As the rings wear, they allow more compressed gas to escape, increasing
rod packing emissions. Rod packing emissions typically occur around the rings from slight movement of
the rings in the cups as the rod moves, but can also occur through the "nose gasket" around the packing
case, between the packing cups, and between the rings and shaft. If the fit between the rod packing rings
and rod is too loose, more compressed gas will escape. Periodically replacing the packing rings ensures
the correct fit is maintained between packing rings and the rod.
6.4.2.2 Effectiveness
As discussed above, regular replacement of the reciprocating compressor rod packing can reduce the
leaking of natural gas across the piston rod. The potential emission reductions were calculated by
comparing the average rod packing emissionswith the average emissions from newly installed and worn-
in rod packing. Since the estimate for newly installed rod packing was intended for larger processing
and transmission compressors, this analysis uses the estimate to calculate reductions from only gathering
6-12
-------
and boosting compressors and not wellhead compressor which are known to be smaller. The calculation
for gathering and boosting reductions is shown in Equation 1.
C&B Comp°&B (EC,R -EN }xCxOx 8760
RG&B = - FN™ \ G&B - ^j_ - Equation 1
106
where,
methane emission reductions from gathering and boosting compressors
switching from wet seals to dry seals, in million cubic feet per year (MMcf/year);
Comp^ff = Number of new gathering and boosting compressors;
EG&B = Methane emission factor for gathering and boosting compressors inTable 6-2, in cubic
feet per hour per cylinder;
£Vew=Average emissions from a newly installed rod packing, assumed to be 11.5 cubic feet per
hour per cylinder15 for this analysis;
C = Average number of cylinders for gathering and boosting compressors in Table 6-2;
O = Percent of time during the calendar year the average gathering and boosting compressor is in
the operating and standby pressurized modes, 79.1%;
8760 = Number of days in a year;
106 = Number of cubic feet in a million cubic feet.
For wellhead reciprocating compressors, this analysis calculates a percentage reduction using the
transmission emission factor from the 1996 EPA/GRI report and the minimum emissions rate from a
newly installed rod packing to determine methane emission reductions. The calculation for wellhead
compressor reductions is shown in Equation 2 below.
Camp™(EWia)xCxOx8760( ETrans -ENew]
Rwen ~ —6 Equation 2
106 I ETrans
where,
RWM = Potential methane emission reductions from wellhead compressors switching from wet
seals to dry seals, in million cubic feet per year (MMcf/year);
Compel = Number of new wellhead compressors;
Eweii = Methane emission factor for wellhead compressors from Table 6-2, cubic feet per hour
per cylinder;
C = Average number of cylinders for wellhead compressors in Table 6-2;
O = Percent of time during the calendar year the average gathering and boosting compressor is in
the operating and standby pressurized modes, 100%;
6-13
-------
= Methane emissions factor for transmission compressors from Table 6-2 in cubic feet per
hour per cylinder;
ENOW = Average emissions from a newly installed rod packing, assumed to be 11.5 cubic feet per
hour per cylinder16 for this analysis;
8760 = Number of days in a year;
106 = Number of cubic feet in a million cubic feet.
The emission reductions for the processing, transmission, and storage segments were calculated by
multiplying the number of new reciprocating compressors in each segment by the difference between the
average rod packing emission factors in Table 6-2 by the average emission factor from newly installed
rod packing. This calculation, shown in the Equation 3 below, was performed for each of the natural gas
processing, transmission, and storage/LNG sectors.
ComppJs(EC,R -EN }xCxOx8760 „ . „
Rpr, = ^New^ G&B ^ Equation 3
PTS 1Q6 1
where,
RPTS = Potential methane emission reductions from processing, transmission, or storage
compressors switching from wet seals to dry seals, in million cubic feet per year (MMcf/year);
Comp^ = Number of new processing, transmission, or storage compressors;
EG&B = Methane emission factor for processing, transmission, or storage compressors in Table 6-
2, in cubic feet per hour per cylinder;
£Vew=Average emissions from a newly installed rod packing, assumed to be 11.5 cubic feet per
hour per cylinder17 for this analysis;
C = Average number of cylinders for processing, transmission, or storage compressors in Table
6-2;
O = Percent of time during the calendar year the average processing, transmission, or storage
compressor is in the operating and standby pressurized modes, 89.7%, 79.1%, 67.5%
respectively;
8760 = Number of days in a year;
106 = Number of cubic feet in a million cubic feet.
A summary of the potential emission reductions for reciprocating rod packing replacement for each of
the oil and gas segments is shown in Table 6-6. The emissions of VOC and HAP were calculated using
the methane emission reductions calculated above the gas composition18 for each of the segments.
Reciprocating compressors in the processing sector were assumed to be used to compress production
gas.
6-14
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Table 6-6.Estimated Annual Reciprocating Compressor Emission Reductions from Replacing Rod Packing
Oil & Gas Segment
Production (Well
Pads)
Gathering & Boosting
Processing
Transmission
Storage
Number of
New Sources
Per Year
6,000
210
375
199
9
Individual Compressor Emission Reductions
(tons/compressor-year)
Methane
0.158
6.84
18.6
21.7
21.8
voc
0.0439
1.90
5.18
0.600
0.604
HAP
0.00165
0.0717
0.195
0.0178
0.0179
Nationwide Emission Reductions
(tons/year)
Methane
947
1,437
3,892
423
87.3
VOC
263
400
1,082
11.7
2.42
HAP
9.91
15.1
40.8
0.348
0.0718
6-15
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6.4.2.3 Cost Impacts
Costs for the replacement of reciprocating compressor rod packing were obtained from a Natural Gas
Star Lessons Learned document19 which estimated the cost to replace the packing rings to be $1,620 per
cylinder. It was assumed that rod packing replacement would occur during planned shutdowns and
maintenance and therefore, no travel costs will be incurred for implementing the rod packing
replacement program. In addition, no costs were included for monitoring becausethe rod
packingplacement is based on number of hours that the compressor operates. The replacement of rod
packing for reciprocating compressors occurs on average every four years based on industry information
90
from the Natural Gas STAR Program. The cost impacts arebased on the replacement of the rod
packing 26,000 hours that the reciprocating compressor operates in the pressurized mode. The number
of hours used for the cost impacts was determined using a weighted average of the annual percentage
that the reciprocating compressors are pressurized for all of the new sources. This weighted hours, on
average, per year the reciprocating compressor is pressurized was calculated to be 98.9 percent. This
percentage was multiplied by the total number of hours in 3 years to obtain a value of 26,000 hours. This
calculates to an average of 3 years for production compressors, 3.8 years for gathering and boosting
compressors, 3.3 years for processing compressors, 3.8 years for transmission compressors, and 4.4
years for storage compressors using the operating factors in Table 6-2. The calculated years were
assumed to be the equipment life of the compressor rod packing and were used to calculate the capital
recovery factor for each of the segments. Assuming an interest rate of 7 percent, the capital recovery
factors were calculated to be 0.3848, 0.3122, 0.3490, 0.3122, and 0.2720 for the production, gathering
and boosting, processing, transmission, and storage sectors, respectively. The capital costs were
calculated using the average rod packing cost of $1,620 and the average number of cylinders per
segment in Table 6-2. The annual costs were calculated using the capital cost and the capital recovery
factors. A summary of the capital and annual costs for each of the oil and gas segments is shown in
Table 6-7.
Monetary savings associated with the amount of gas saved with reciprocating compressor rod packing
91
replacement was estimated using a natural gas price of $4.00 per Mcf This cost was used to calculate
theannual cost with gas savings using the methane emission reductions in Table 6-6. The annual cost
with savings is shown in Table 6-7 for each of the oil and gas segments. The cost effectiveness for the
reciprocating rod packing replacement option is presented in Table 6-7. There is no gas savings cost
benefits for transmission and storage facilities, because they do not own the natural gas that is
6-16
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Table 6-7. Cost Effectiveness for Reciprocating Compressor Rod Packing Replacement
Oil and Gas
Segment
Production
Gathering &
Boosting
Processing
Transmission
Storage
Capital Cost
($2008)
$6,480
$5,346
$4,050
$5,346
$7,290
Annual Cost per Compressor
($/compressor-year)
Without
savings
$2,493
$1,669
$1,413
$1,669
$2,276
With savings
$2,457
$83
-$2,903
N/A
N/A
VOC Cost Effectiveness ($/ton)
Without
savings
$56,847
$877
$273
$2,782
$3,766
With savings
$56,013
$43
-$561
N/A
N/A
Methane Cost Effectiveness
($/ton)
Without
savings
$15,802
$244
$76
$77
$104
With savings
$15,570
$12
-$156
N/A
N/A
6-17
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compressed at their compressor stations.
6.4.2.4 Secondary Impacts
The reciprocating compressor rod packing replacement is an option that prevents the escape of natural
gas from the piston rod. No wastes should be created, no wastewater generated, and no electricity
maintenance and therefore, no travel costs will be incurred for implementing the rod packing
replacement program. In addition, no costs were included for monitoring becausethe rod packing
6.4.3 Centrifugal Compressor Dry Seals
6.4.3.1 Description
Centrifugal compressor dry seals operate mechanically under the opposing force created by
hydrodynamic grooves and springs. The hydrodynamic grooves are etched into the surface of the
rotating ring affixed to the compressor shaft. When the compressor is not rotating, the stationary ring in
the seal housing is pressed against the rotating ring by springs. When the compressor shaft rotates at
high speed, compressed gas has only one pathway to leak down the shaft, and that is between the
rotating and stationary rings. This gas is pumped between the rings by grooves in the rotating ring. The
opposing force of high-pressure gas pumped between the rings and springs trying to push the rings
together creates a very thin gap between the rings through which little gas can leak. While the
compressor is operating, the rings are not in contact with each other, and therefore, do not wear or need
lubrication. O-rings seal the stationary rings in the seal case.
Dry seals substantially reduce methane emissions. At the same time, they significantly reduce operating
costs and enhance compressor efficiency. Economic and environmental benefits of dry seals include:
• Gas Leak Rates. During normal operation, dry seals leak at a rate of 6scfmmethane per
compressor.22 While this is equivalent to a wet seal's leakage rate at the seal face, wet seals
generate additional emissions during degassing of the circulating oil. Gas separated from the seal
oil before the oil is re-circulated is usually vented to the atmosphere, bringing the total leakage
rate for tandem wet seals to 47.7 scfm methane per compressor.23'24
• Mechanically Simpler. Dry seal systems do not require additional oil circulation components and
treatment facilities.
6-18
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• Reduced Power Consumption. Because dry seals have no accessory oil circulation pumps and
systems, they avoid "parasitic" equipment power losses. Wet seal systems require 50 to 100 kW
per hour, while dry seal systems need about 5 kW of power per hour.
• Improved Reliability. The highest percentage of downtime for a compressor using wet seals is
due to seal system problems. Dry seals have fewer ancillary components, which translates into
higher overall reliability and less compressor downtime.
• Lower Maintenance. Dry seal systems have lower maintenance costs than wet seals because they
do not have moving parts associated with oil circulation (e.g., pumps, control valves, relief
valves, and the seal oil cost itself).
• Elimination of Oil Leakage from Wet Seals. Substituting dry seals for wet seals eliminates seal
oil leakage into the pipeline, thus avoiding contamination of the gas and degradation of the
pipeline.
Centrifugal compressors were found in the processing and transmission sectors based on information in
the greenhouse gas inventory.25 Therefore, it was assumed that new compressors would be located in
these sectors only.
6.4.3.2 Effectiveness
The control effectiveness of the dry seals was calculated by subtracting the dry seal emissions from a
centrifugal compressor equipped with wet seals. The centrifugal compressor emission factors in Table 6-
2 were used in combination with an operating factor of 43.6 percent for processing centrifugal
compressors and 24.2 percent for transmission centrifugal compressors. The operating factors are used
to account for the percent of time in a year that a compressor is in the operating mode. The operating
factors for the processing and transmission sectors are based on data in the EPA/GRI study.26 The wet
seals emission factor is an average of 48 different wet seal centrifugal compressors. The dry seal
emission factor is based on information from the Natural Gas STAR Program.27 A summary of the
emission reduction from the replacement of wet seals with dry seals is shown in Table 6-8.
6.4.3.3 Cost Impacts
The price difference between a brand new dry seal and brand new wet seal centrifugal compressor is
insignificant relative to the cost for the entire compressor. General Electric (GE) stated that a natural gas
transmission pipeline centrifugal compressor with dry seals cost between $50,000 and $100,000 more
than the same centrifugal compressor with wet seals. However, this price difference is only about 1 to 3
6-19
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Table 6-8. Estimated Annual Centrifugal Compressor Emission Reductions from Replacing Wet Seals with Dry Seals
Oil & Gas Segment
Transmission/Storage
Storage
Number of
New Sources
Per Year
16
14
Individual Compressor Emission Reductions
(ton/compressor-year)
Methane
199
110
voc
18.0
3.06
HAP
0.643
0.0908
Nationwide Emission Reductions
(ton/year)
Methane
3,183
1,546
VOC
287
42.8
HAP
10.3
1.27
6-20
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percent of the total cost of the compressor. The price of a brand new natural gas transmission pipeline
centrifugal compressor between 3,000 and 5,000 horsepower runs between $2 million to $5 million
depending on the number of stages, desired pressure ratio, and gas throughput. The larger the
compressor, the less significant the price difference is between dry seals and wet seals. This analysis
assumes the additional capital cost for a dry seal compressor is $75,000. The annual cost was
calculatedas the capital recovery of this capital cost assuming a 10-year equipment life and 7 percent
interest which came to $10,678 per compressor. The Natural Gas STAR Program estimated that the
operation and maintenance savings from the installation of dry seals is $88,300 in comparison to wet
seals. Monetary savings associated with the amount of gas saved with the replacement of wet seals with
9R
dry seals for centrifugal compressors was estimated using a natural gas price of $4.00 per Mcf This
cost was used to calculate the annual cost with gas savings using the methane emission reductions in
Table 6-8. A summary of the capital and annual costs for dry seals is presented in Table 6-9. The
methane and VOC cost effectiveness for the dry seal option is also shown in Table 6-9. There is no gas
savings cost benefits for transmission and storage facilities, because it is assumed the owners of the
compressor station may not own the natural gas that is compressed at the station.
6.4.3.4 Secondary Impacts
Dry seals for centrifugal compressors are an option that prevents the escape of natural gas across the
rotating compressor shaft. No wastes should be created, no wastewater generated, and no electricity
needed. Therefore, there are no secondary impacts expected due to the installation of dry seals on
centrifugal compressors.
6.4.4 Centrifugal Compressor Wet Seals with a Flare
6.4.4.1 Description
Another control option used to reduce pollutant emissions from centrifugal compressors equipped
withwet seals is to route the emissions to a combustion device or capture the emissions and route them
to afuel system. A wet seal system uses oil that is circulated under high pressure between three rings
aroundthe compressor shaft, forming a barrier against the compressed gas. The center ring is attached to
the rotating shaft, while the two rings on each side are stationary in the seal housing, pressed against a
thin film of oil flowing between the rings to both lubricate and act as a leak barrier. Compressed gas
becomes absorbed and entrained in the fluid barrier and is removed using a heater, flash tank, or other
degassing technique so that the oil can be recirculated back to the wet seal. The removed gas is either
6-21
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Table 6-9. Cost Effectiveness for Centrifugal Compressor Dry Seals
Oil and Gas Segment
Processing
Transmission/Storage
Capital
Cost
($2008)
$75,000
$75,000
Annual Cost per Compressor
($/compressor-yr)
without
savings
$10,678
$10,678
with O&M
and gas
savings
-$123,730
-$77,622
VOC Cost Effectiveness
($/ton)
without
savings
$595
$3,495
with O&M
and gas
savings
-$6,892
-$25,405
Methane Cost Effectiveness
($/ton)
without
savings
$54
$97
with O&M and
gas savings
-$622
-$703
6-22
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combusted or released to the atmosphere. The control technique investigated in this section is the use of
wet seals with the removed gas sent to an enclosed flare.
6.4.4.2 Effectiveness
Flares have been used in the oil and gas industry to combust gas streams that have VOC and HAP. A
flare typically achieves 95 percent reduction of these compounds when operated according to the
manufacturer instructions. For this analysis, it was assumed that the entrained gas from the seal oil that
is removed in the degassing process would be directed to a flare that achieves 95 percent reduction of
methane, VOC, and HAP. The wet seal emissions in Table 6-5 were used along with the control
efficiency to calculate the emissions reductions from this option. A summary of the emission reductions
is presented in Table 6-10.
6.4.4.3 Cost Impacts
The capital and annual cost of the enclosed flare was calculated using the methodology in the EPA
Control Cost Manual.29 The heat content of the gas stream was calculated using information from the
gas composition memorandum.30 A summary of the capital and annual costs for wet seals routed to a
flare is presented in Table 6-11. The methane and VOC cost effectiveness for the wet seals routed to a
flare option is also shown in Table 6-12. There is no cost saving estimated for this option because the
recovered gas is combusted.
6.4.4.4 Secondary Impacts
There are secondary impacts with the option to use wet seals with a flare. The combustion of the
recovered gas creates secondary emissions of hydrocarbons, nitrogen oxide (NOx), carbon dioxide
(CO2), and carbon monoxide (CO) emissions. A summary of the estimated secondary emission are
presented in Table 6-11. No other wastes should be created or wastewater generated.
6.5 Regulatory Options
The affected facility definition for a reciprocating compressor is defined as a piece of equipment that
increases the pressure of a process gas by positive displacement, employing linear movement of
thedriveshaft. A centrifugal compressor is defined as a piece of equipment that compresses a process gas
by means of mechanical rotating vanes or impellers. Therefore these types of compressor would be
6-23
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Table 6-10. Estimated Annual Centrifugal Compressor Emission Reductions from Wet Seals Routed to a Flare
Oil & Gas Segment
Processing
Transmission/Storage
Number of
New Sources
Per Year
16
14
Individual Compressor Emission Reductions
(tons/compressor-year)
Methane
216
120
voc
19.5
3.32
HAP
0.699
0.0986
Nationwide Emission Reductions
(tons/year)
Methane
3,283
1,596
VOC
296
44.2
HAP
10.6
1.31
6-24
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Table 6-11. Secondary Impacts from Wet Seals Equipped with a Flare
Industry Segment
Processing
Transmission/Storage
Secondary Impacts from Wet Seals Equipped with a Flare
(tons/year)
Total
Hydrocarbons
0.0289
0.00960
Carbon
Monoxide
0.0205
0.00889
Carbon
Dioxide
7.33
3.18
Nitrogen
Oxides
0.00377
0.00163
Particulate
Matter
Negligible
Negligible
6-25
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Table 6-12. Cost Effectiveness for Centrifugal Compressor Wet Seals Routed to a Flare
Oil and Gas Segment
Processing
Transmission/Storage
Capital
Cost
($2008)
$67,918
$67,918
Annual Cost per Compressor
($/compressor-year)
without
savings
$103,371
$103,371
with gas
savings
N/A
N/A
VOC Cost Effectiveness
($/ton)
without savings
$5,299
$31,133
with gas
savings
N/A
N/A
Methane Cost Effectiveness
($/ton)
without
savings
$478
$862
with gas
savings
N/A
N/A
6-26
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subject to a New Performance Standard (NSPS) at the time of installation. The following Regulatory
options were evaluated:
• Regulatory Option 1: Require replacement of the reciprocating compressor rod packing based
on26,000 hours of operation while the compressor is pressurized.
• Regulatory Option 2: Require all centrifugal compressors to be equipped with dry seals.
• Regulatory Option 3: Require centrifugal compressors equipped with a wet seal to route the
recovered gas emissions to a combustion device.
6.5.1 Evaluation of Regulatory Options
The first regulatory option for replacement of the reciprocating compressor rod packing based on the
number of hours that the compressor operates in the pressurized mode was described in Section 6.4.1.
The VOC cost effectiveness from $56,847 for reciprocating compressors located at production pads to
$273 for reciprocating compressors located at processing plants. The VOC cost effectiveness for the
gathering and boosting, transmission, and storage segments were $877, $2,782, and 3,766 respectively.
Based on these cost effectiveness values, Regulatory Option 1 was accepted for the processing,
gathering and boosting, transmission, and storage segments and rejected for the production segment.
The second regulatory option would require all centrifugal compressors to be equipped with dry seals.
As presented in Section 6.4.2, dry seals are effective at reducing emissions from the rotating shaft of a
centrifugal compressor. Dry seals also reduce operation and maintenance costs in comparison to wet
seals. In addition, a vendor reported in 2003 that 90 percent of new compressors that were sold by the
company were equipped with dry seals. Another vendor confirmed in 2010 that the rate at which new
compressor sales have dry seals is still 90 percent; thus, it was assumed that from 2003 onward,
90 percent of new compressors are equipped with dry seals. The VOC cost effectiveness of dry seals
was calculated to be $595 for centrifugal compressors located at processing plants, and $3,495 for
centrifugal compressors located at transmission or storage facilities. Therefore, Regulatory Option 2 was
accepted as a regulatory option for centrifugal compressors located at processing, transmission, or
storage facilities.
The third regulatory option would allow the use of wet seals if the recovered gas emissions were routed
to a flare. Centrifugal compressors with wet seals are commonly used in high pressure applications over
3,000 pounds per square inch (psi). None of the applications in the oil and gas industry operate at these
6-27
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pressures. Therefore, it does not appear that any facilities would be required to operate a centrifugal
compressor with wet seals. The VOC control effectiveness for the processing and transmission/storage
segments were $5,299 and $31,133 respectively. Therefore, Regulatory Option 3 was rejected due to the
high VOC cost effectiveness.
6.5.2 Nationwide Impacts of Regulatory Options
Tables 6-13 and 6-14 summarize the impacts of the selected regulatory options by industry segment.
Regulatory Option 1 is estimated to affect 210 reciprocating compressors at gathering and boosting
stations, 209 reciprocating compressors at processing plants, 20 reciprocating compressors at
transmission facilities, and 4 reciprocating compressors at underground storage facilities. A summary of
the capital and annual costs and emission reductions for this option is presented in Table 6-13.
Regulatory Option 2 is expected to affect 16 centrifugal compressors in the processing segment and 14
centrifugal compressors in the transmission and storage segments. A summary of the capital and annual
costs and emission reductions for this option is presented in Table 6-14.
6-28
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Table 6-13. Nationwide Cost Impacts for Regulatory Option 1
Oil & Gas Segment
Gathering & Boosting
Processing
Transmission
Storage
Number of
New Sources
Per Year
210
209
20
4
Nationwide Emission Reductions
(tons/year)
voc
400
1,082
11.7
2.42
Methane
1,437
3,892
423
87.3
HAP
15.1
40.8
0.348
0.0718
Total Nationwide Costs
Capital Cost
($)
$1,122,660
$846,450
$104,247
$29,160
Annual Cost
without
savings ($/yr)
$350,503
$295,397
$32,547
$9,104
Annual Cost
with savings
($/yr)
$17,337
-$606,763
$32,547
$9,104
6-29
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Table 6-14. Nationwide Cost Impacts for Regulatory Option 2
Oil & Gas Segment
Production (Well Pads)
Gathering & Boosting
Processing
Transmission/Storage
Number of
New Sources
Per Year
0
0
16
14
Nationwide Emission Reductions1
(tons/year)
voc
0
0
118
3.24
Methane
0
0
422
117
HAP
0
0
4.42
0.0962
Total Nationwide Costs"
Capital Cost
($)
0
0
$100,196
$50,098
Annual Cost
w/o Savings
($/year)
0
0
$14,266
$7,133
Annual Cost
w/ Savings
($/year)
0
0
-$120,144
-$37,017
a. The nationwide emission reduction and nationwide costs are based on the emission reductions and costs for 2 centrifugal
compressors with wet seals located a processing facility and 1 centrifugal compressor equipped with wet seal located at a
transmission or storage facility.
6-30
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6.6 References
1 National Risk Management Research Laboratory. GRI/EPA Research and Development,
Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks.
Prepared for the U.S. Department of Energy, Energy Information Administration.EPA-
600/R-96-080h. June 1996.
2 Memorandum to Bruce Moore, U.S. Environmental Protection Agency from Heather
Brown, EC/R. Gas Composition Methodology. July 2011.
3 EPA/GRI (1996) Methane Emission from the Natural Gas Industry.Vol. 11 .Pages 11 -
15. Available at: http://epa.gov/gasstar/documents/emissions_report/l l_compressor.pdf
4 Memorandum to Bruce Moore, U.S. Environmental Protection Agency from Heather
Brown, EC/R. Gas Composition Methodology. July 2011.
5 U.S Environmental Protection Agency.Methodology for Estimating CH4 and CO2
Emissions from Petroleum Systems. Greenhouse Gas Inventory: Emission and
Sinksl990-2008. Washington, DC. 2010.
6 U.S Environmental Protection Agency.Methodology for Estimating CH4 and CO2
Emissions from Petroleum Systems. Greenhouse Gas Inventory: Emission and
Sinksl990-2009. Washington, DC. April 2011.
7 EPA (2010), Mandatory Reporting of Greenhouse Gases from Petroleum and Natural Gas
Systems - Subpart W,
8 El Paso (2010), Comments from El Paso Corporation on the Proposed Rule for
Mandatory Reporting of Greenhouse Gases: Petroleum and Natural Gas Systems. Federal
Register, Vol. 75, No. 69, Docket ID No.EPA-HQ-OAR-2009-0923.
9 HPDILLC (2008), U.S. Production.
10 U.S Environmental Protection Agency.Methodology for Estimating CH4 and CO2
Emissions from Petroleum Systems. Greenhouse Gas Inventory: Emission and
Sinksl990-2008. Washington, DC. 2010.
11 U.S Environmental Protection Agency.Methodology for Estimating CH4 and CO2
Emissions from Petroleum Systems. Greenhouse Gas Inventory: Emission and
Sinksl990-2009. Washington, DC. April 2011.
12 U.S Environmental Protection Agency.Methodology for Estimating CH4 and CO2
Emissions from Petroleum Systems. Greenhouse Gas Inventory: Emission and
Sinksl990-2008. Washington, DC. 2010.
6-31
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13 U.S Environmental Protection Agency.Methodology for Estimating CH4 and CO2
Emissions from Petroleum Systems. Greenhouse Gas Inventory: Emission and
Sinksl990-2009. Washington, DC. April 2011.
14 EPA (2006).Lessons Learned: Reducing Methane Emissions from Compressor Rod
Packing Systems. Natural Gas STAR. Environmental Protection Agency.
15 EPA (2006).Lessons Learned: Reducing Methane Emissions from Compressor Rod
Packing Systems. Natural Gas STAR. Environmental Protection Agency.
16 EPA (2006).Lessons Learned: Reducing Methane Emissions from Compressor Rod
Packing Systems. Natural Gas STAR. Environmental Protection Agency.
17 EPA (2006).Lessons Learned: Reducing Methane Emissions from Compressor Rod
Packing Systems. Natural Gas STAR. Environmental Protection Agency.
18 Memorandum to Bruce Moore, U.S. Environmental Protection Agency from Heather
Brown, EC/R. Gas Composition Methodology. July 2011.
19 EPA (2006).Lessons Learned: Reducing Methane Emissions from Compressor Rod
Packing Systems. Natural Gas STAR. Environmental Protection Agency.
20 EPA (2006).Lessons Learned: Reducing Methane Emissions from Compressor Rod
Packing Systems. Natural Gas STAR. Environmental Protection Agency.
21 U.S. Energy Information Administration.Annual U.S. Natural Gas Wellhead
Price.Energy Information Administration Natural Gas Navigator. Retrieved online on
December 12, 2010 at
22 EPA (2006), Lessons Learned Document. "Replacing Wet Seals with Dry Seals in
Centrifugal Compressors." October 2006.
http://epa.gov/gasstar/documents/ll_wetseals.pdf
23 "Methane's Role in Promoting Sustainable Development in the Oil and Natural Gas
Industry". US EPA, ICF International, PEMEX, EnCana Oil & Gas, Hy-Bon
Engineering, Pluspetrol, Gazprom, VNIIGAZ. World Gas Conference 10/2009. Available
at: http://www.epa.gov/gasstar/documents/best_paper_award.pdf
24 U.S Environmental Protection Agency.Methodology for Estimating CH4 and CO2
Emissions from Petroleum Systems. Greenhouse Gas Inventory: Emission and
Sinksl990-2009. Washington, DC. April 2011. Annex 3. Page A-
153.http://epa.gov/climatechange/emissions/downloadsll/US-GHG-Inventory-2011-
Annex-3.pdf
25 U.S Environmental Protection Agency.Methodology for Estimating CH4 and CO2
Emissions from Petroleum Systems. Greenhouse Gas Inventory: Emission and
Sinksl990-2008. Washington, DC. 2010.
6-32
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26 National Risk Management Research Laboratory. GRI/EPA Research and Development,
Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks.
Prepared for the U.S. Department of Energy, Energy Information Administration.EPA-
600/R-96-080h. June 1996.
27 EPA (2006).Lessons Learned: Replacing Wet Seals with Dry Seals in Centrifugal
Compressors. Natural Gas STAR. Environmental Protection Agency.
28 U.S. Energy Information Administration.Annual U.S. Natural Gas Wellhead
Price.Energy Information Administration Natural Gas Navigator. Retrieved online on
December 12, 2010 at
29 EPA Air Pollution Control Cost Manual - Sixth Edition, (EPA 452/B-02-001)
30 Memorandum to Bruce Moore, U.S. Environmental Protection Agency from Heather
Brown, EC/R. Gas Composition Methodology. July 2011.
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7.0 STORAGE VESSELS
Storage vessels, or storage tanks, are sources of air emissions in the oil and natural gas sector. This
chapter provides a description of the types of storage vessels present in the oil and gas sector, and
provides emission estimates for a typical storage vessel as well as nationwide emission estimates.
Control techniques employed to reduce emissions from storage vessels are presented, along with costs,
emission reductions, and secondary impacts. Finally, this chapter provides a discussion of considerations
used in developing regulatory alternatives for storage vessels.
7.1 Process Description
Storage vessels in the oil and natural gas sector are used to hold a variety of liquids, including crude oil,
condensates, produced water, etc. Underground crude oil contains many lighter hydrocarbons in
solution. When the oil is brought to the surface and processed, many of the dissolved lighter
hydrocarbons (as well as water) are removed through as series of high-pressure and low-pressure
separators. Crude oil under high pressure conditions is passed through either a two phase separator
(where the associated gas is removed and any oil and water remain together) or a three phase separator
(where the associated gas is removed and the oil and water are also separated). At the separator, low
pressure gas is physically separated from the high pressure oil. The remaining low pressure oil is then
directedto a storage vessel where it is stored for a period of time before being shipped off-site. The
remaining hydrocarbons in the oil are released from the oil as vapors in the storage vessels. Storage
vessels are typically installed with similar or identical vessels in a group, referred to in the industry as a
tank battery.
Emissions of the remaining hydrocarbons from storage vessels are a function of working, breathing (or
standing), and flash losses. Working losses occur when vapors are displaced due to the emptying and
filling of storage vessels. Breathing losses are the release of gas associated with daily temperature
fluctuations and other equilibrium effects. Flash losses occur when a liquid with entrained gases is
transferred from a vessel with higher pressure to a vessel with lower pressure, thus allowing entrained
gases or a portion of the liquid to vaporize or flash. In the oil and natural gas production segment,
flashing losses occur when live crude oils or condensates flow into a storage vesselfrom a processing
vessel operated at a higher pressure. Typically, the larger the pressure drop, the more flash emissions
will occur in the storage stage. Temperature of the liquid may also influence the amount of flash
emissions.
7-1
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The volume of gas vapor emitted from a storage vessel depends on many factors. Lighter crude oils flash
more hydrocarbons than heavier crude oils. In storage vessels where the oil is frequently cycled and the
overall throughput is high, working losses are higher. Additionally, the operating temperature and
pressure of oil in the separator dumping into the storage vesselwill affect the volume of flashed gases
coming out of the oil.
The composition of the vapors from storage vessels varies, and the largest component is methane, but
also includes ethane, butane, propane, and hazardous air pollutants (HAP) such as benzene, toluene,
ethylbenzene, xylene (collectively referred to as BTEX), and n-hexane.
7.2 Emissions Data
.2.1 Summary of Major Studies and Emissions
Given the potentially significant emissions from storage vessels, there have been numerous studies
conducted to estimate these emissions. Many of these studies were consulted to evaluate the emissions
and emission reduction options for emissions from storage vessels. Table 7-1 presents a summary of
these studies, along with an indication of the type of information available in each study.
7.2.2 Representative Storage Vessel Emissions
Due to the variability in the sizes and throughputs, model tank batteries were developed to represent the
ranges of sizes and population distribution of storage vessels located attank batteries throughout the
sector. Model tank batteries were not intended to represent any single facility, but rather a range of
facilities with similar characteristics that may be impacted by standards. Model tank batteries were
developed for condensate tank batteries and crude oil tank batteries. Average VOC emissions were then
developed and applied to the model tank batteries.
7.2.2.1 Model Condensate Tank Batteries
During the development of the national emissions standards for HAP (NESHAP) for oil and natural gas
production facilities (40 CFR part 63, subpart HH), model plants were developed to represent
condensate tank batteries across the industry, ^or this current analysis, the most recent inventory data
9 'I
available was the 2008 U.S. Greenhouse Gas Emissions Inventory. ' Therefore, 2008 was chosen to
represent the base year for this impacts analysis.To estimate the current condensate battery population
and distribution across the model plants, the number of tanks represented by the model plants was scaled
7-2
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Table 7-1. Major Studies Reviewed for Consideration of Emissions and Activity Data
Report Name
VOC Emissions from Oil and Condensate Storage
Tanks4
Lessons Learned from Natural Gas STAR
Partners installing Vapor Recovery Units on
Crude Oil Storage Tanks5
Upstream Oil and Gas Storage Tank Project Flash
Emissions Models Evaluation - Final Report6
Initial Economics Impact Analysis for Proposed
State Implementation Plan Revisions to the Air
Quality Control Commission's Regulation
Number 7
E&P TANKS"
Inventory of U.S. Greenhouse Gas Emissions and
Sinks2'3
Affiliation
Texas Environmental
Research Consortium
EPA
Texas Commission on
Environmental Quality
Colorado
American Petroleum
Institute
EPA
Year
of
Report
2009
2003
2009
2008
2008
and
2009
Activity
Factors
Regional
National
Regional
n/a
National
National
Emission
Figures
X
X
X
X
Control
Information
X
X
X
7-3
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from 1992 (the year for which that the model plants were developed under the NESHAP) to 2008 for
this analysis. Based on this approach, it was estimated that there were a total of 59,286 existing
condensate tanks in 2008. Condensate throughput data from the U.S. Greenhouse Gas Emissions
Inventory was used to scale up from 1992 the condensate tank populations for each model condensate
tank battery under the assumption that an increase in condensate production would be accompanied by a
proportional increase in number of condensate tanks. The inventory data indicate that condensate
production increased from a level of 106 million barrels per year (MMbbl/yr) in 1992to 124 MMbbl/yr
in 2008.This increase in condensate production was then distributed across the model condensate tank
batteriesin the same proportion as was done for the NESHAP. The model condensate tank batteries are
presented in Table 7-2.
7.2.2.2 Model Crude Oil Tank Batteries
According to the Natural Gas STAR program,5 there were 573,000 crude oil storage tanksin 2003.
According to the U.S. Greenhouse Gas Emissions Inventory, crude oil production decreased from 1,464
MMbbl/yr in 2003 to 1,326 MMbbl/yr (a decrease of approximately 9.4 percent) in 2008. Therefore, it
was assumed that the number of crude oil tanks in 2008 were approximately 90.6 percent of the number
of tanks identified in 2003. Therefore, for this analysis it was assumed that there were 519,161 crude oil
storage tanks in 2008. During the development of the NESHAP, model crude oil tank batteries were not
developed and a crude oil tank population was not estimated. Therefore, it was assumed that the
percentage distribution of crude oil storage tanks across the four model crude oil tank battery
classifications was the same as for condensate tank batteries.Table 7-3 presents the model crude oil tank
batteries.
7.2.2.3 VOC Emissions from Condensate and Crude Oil Storage Vessels
Once the model condensate and crude oil tank battery distributionswere developed, VOC emissions from
a representative storage vessel were estimated. Emissions from storage vessels vary considerably
depending on many factors, including, but not limited to, throughput, API gravity, Reid vapor pressure,
separator pressure, etc. The American Petroleum Institute (API) has developed a software program
o
called E&P TANKS which contains a dataset of more than 100 storage vessels from across the country.
A summary of the information contained in the dataset, as well as the output from the E&P TANKS
program, is presented in Appendix A of this document. According to industry representatives, this
7-4
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Table 7-2. Model Condensate Tank Batteries
Parameter
Condensate throughput (bbl/day)a
Condensate throughput (bbl/yr) a
Number of fixed-roof product storage vessels51
210 barrel capacity
500 barrel capacity
1,000 barrel capacity
Estimated tank battery population (1992)a
Estimated tank battery population (2008) b
Total number of storage vessels (2008) b
Percent of number of storage vessels in model condensate
tank battery
Percent of throughput per model condensate tank batterya
Total tank battery condensate throughput (MMbbl/yr)°
Condensate throughput per model condensate battery
(bbl/day)
Condensate throughput per storage vessel (bbl/day)
Model Condensate Tank Battery
E
15
5,475
4
12,000
14,038
56,151
94.7%
26%
32.8
6.41
1.60
F
100
36,500
2
2
500
585
2,340
3.95%
7%
9.11
42.7
10.7
G
1,000
365,000
2
2
100
117
468
0.789%
15%
18.2
427
106.8
H
5,000
1,825,000
4
70
82
328
0.552%
51%
63.8
2,135
534
Minor discrepancies may be due to rounding.
a. Developed for NESHAP (Reference 1).
b. Population of tank batteries for 2008 determined based on condensate throughput increase from
106 MMbbl/yr in 1992 to 124 MMbbl/yr in 2008 (References2,3).
c. 2008 condensate production rate of 124 MMbbl/yr distributed across model tank batteries using
same relative ratio as developed for NESHAP (Reference 1).
7-5
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Table 7-3. Model Crude Oil Tank Batteries
Parameter
Percent of number of condensate storage vessels in
model size rangea
Number of storage vessels
Percent of throughput across condensate tank batteries
Crude oil throughput per model plant category
(MMbbl/yr)
Crude oil throughput per storage vessel (bbl/day)
Model Crude Oil Tank Battery
E
94.7%
491,707
26%
351
1.96
F
3.95%
20,488
7%
97.5
13.0
G
0.789%
4,098
15%
195
130
H
0.552%
2,868
51%
683
652
Minor discrepancies may be due to rounding.
a. Same relative percent of storage vessel population developed for model condensate tank
batteries.Refer to Table 7-2.
b. Calculated by applying the percent of number of condensate storage vessels in model size range
to total number of crude oil storage vessels (519,161 crude oil storage vessels estimated for
2008) (Reference 5).
c. Same relative percent of throughput developed for model condensate tank batteries.Refer to
Table 7-2.
7-6
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dataset in combination with the output of the E&P TANKS program is representative of the various
VOC emissions from storage vessels across the country.9
The more than 100 storage vesselsprovided with the E&P TANKS program, which had varying
characteristics, were modeled with a constant throughput (based on the assumption that emissions would
increase in proportion with throughput) and the relationship of these different characteristics and
emissionswas studied. While many of the characteristics impacted emissions, a correlation was found to
exist between API gravity and emissions. The average API gravity for all storage vessels in the data set
was approximately 40 degrees. Therefore, we selected an API gravity of 40 degrees as a parameter to
distinguish between lower emitting storage vessels and higher emitting storage vessels.1 While the liquid
type was not specified for the storage vessels modeled in the study, it was assumed that condensate
storage vessels would have higher emissions than crude oil storage vessels. Therefore, based on this
study using the E&P TANKS program, it was assumed for this analysis that liquids with API gravity
equal to or greater than 40 degrees should be classified as condensate and liquids with API gravity less
than 40 degrees should be classified as crude oil.
The VOC emissions from all storage vessels in the analysis are presented in Appendix A.Table 7-4
presents a summary of the average VOC emissions from all storage vessels as well as the average VOC
emissions from the storage vessels identified as being condensate storage vessels and those identified as
being crude oil storage vessels. As shown in Table 7-4, the storage vessels were modeled at a constant
throughput of 500 bpd."An average emission factor was developed for each type of liquid. The average
of condensate storage vessel VOC emissions was modeled to be 1,046 tons/year or 11.5 Ib VOC/bbl and
the average of crude oil storage vessel VOC emissions was modeled to be 107 tons/year or
1.18 Ib VOC/bbl. These emission factors were then applied to each of the two sets of model storage
vessels in Tables 7-2 and 7-4 to develop the VOC emissions from the model tank batteries. These are
presented in Table 7-5.
1 The range of VOC emissions within the 95 percent confidence interval for storage vessels with an API gravity greater than
40 degrees was from 667 tons/year to 1425 tons/year. The range for API gravity less than 40 degrees was 76 tons/year to 138.
11 This throughput was originally chosen for this analysis to be equal to the 500 bbl/day throughput cutoff in subpart HH.
While not part of the analysis described in this document, one of the original objectives of the E&P TANKS analysis was to
assess the level of emissions associated with a storage vessel with a throughput below this cutoff. Due to the assumption that
emissions increase and decrease in proportion with throughput, it was decided that using a constant throughput of 500
bbl/day would still provide the information necessary to determine VOC emissions from model condensate and crude oil
storage vessels for this document.
7-7
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Table 7-4. Summary of Data from E&P TANKS Modeling
Parameter"
Throughput Rate (bbl)
API Gravity
VOC
Emissions (tons/year)
Emission factor (Ib/bbl)
Average of
Dataset
500
40.6
531
5.8
Average of
Storage
Vessels with
API Gravity
> 40 degrees
500
52.8
1046
11.5
Average of
Storage
Vessels with
API Gravity
< 40 degrees
500
30.6
107
1.18
a. Information from analysis of E&P Tanks dataset, refer to Appendix A.
7-8
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Table 7-5. Model Storage Vessel VOC Emissions
Parameter
Model Tank Battery
E
F
G
H
Model Condensate Tank Batteries
Condensate throughput per storage vessel (bbl/day)
VOC Emissions (tons/year)
1.60
3.35
10.7
22.3
107
223
534
1117
Model Crude Oil Tank Batteries
Crude Oil throughput per storage vessel (bbl/day)0
VOC Emissions (tons/year)"
2.0
0.4
13
2.80
130
28
652
140
a. Condensate throughput per storage vessel from table 7-2.
b. Calculated using the VOC emission factor for condensate storage vessels of 11.5 Ib
VOC/bbl condensate.
c. Crude oil throughput per storage vessel from table 7-3.
d. Calculated using the VOC emission factor for crude oil storage vessels of 1.18 Ib
VOC/bbl crude oil.
7-9
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7.3 Nationwide Baseline Emissions from New or Modified Sources
7.3.1 Overvi ew of Approach
The first step in this analysis is to estimate nationwide emissions in absence of a federal rulemaking,
referred to as the nationwide baseline emissions estimate. In order to develop the baseline emissions
estimate, the number of new storage vessels expected in a typical year was calculated and then
multiplied by the expected uncontrolled emissions per storage vessels presented in Table 7-5. In
addition, to ensure no emission reduction credit was attributed to new sources that would already be
required to be controlled under State regulations, it was necessary to account for the number of storage
vessels already subject to State regulations as detailed below.
7.3.2 Number of New Storage Vessels Expected to be Constructed or Reconstructed
The number of new storage vessels expected to be constructed was determined for the year 2015 (the
year of analysis for the regulatory impacts). To do this, it was assumed that the number of new or
modified storage vessels would increase in proportion with increases in production. The Energy
Information Administration (EIA), published crude oil production rates up to the year 201 l.10Therefore,
using the forecast function in Microsoft Excel® , crude oil production was predicted for the year 2015.111
From 2009 to 2015,1V the expected growth of crude oil production was projected to be 8.25 percent (from
5.36 bpd to 5.80 bpd). Applying this expected growth to the number of existing storage vessels results in
an estimate of 4,890 new or modified condensate storage vessels and 42,811 new or modified crude oil
storage vessels. The number of new or modified condensate and crude oil storage vessels expected to be
constructed or reconstructed is presented in Table 7-6.
7.3.3 Level of Controlled Sources in Absence of Federal Regulation
As stated previously, to determine the impact of a regulation, it was first necessary to determine the
current level of emissions from the sources being evaluated, or baseline emissions. To more accurately
estimate baseline emissions for this analysis, and to ensure no emission reduction credit was attributed
111 The crude oil production values published by the EIA include leased condensate. Therefore, the increase in crude oil
production was assumed to be valid for both crude oil and condensate tanks for the purpose of this analysis.
1V For the purposes of estimating growth, the crude oil production rate in the year 2008 was considered an outlier for
production and therefore was not used in this analysis.
7-10
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Table 7-6. Nationwide Baseline Emissions for Storage Vessels
Model Tank Battery
E
F
G
H
Total
Model Condensate Tank Batteries
Total number of storage vessels (2008)
Total projected number of new or modified
storage vessels (2015) a
Number of uncontrolled storage vessels in
absence of federal regulation
Uncontrolled VOC Emissions from storage vessel
at model tank battery0
Total Nationwide Uncontrolled VOC Emissions
56,151
4,630
1,688
3.35
5,657
2,340
193
70
22.3
1,572
468
39
14
223
3,143
328
27
10
1,117
11,001
59,286
4,889
1,782
1,366
21,373
Model Crude Oil Tank Batteries
Total number of storage vessels (2008)
Total projected number of new or modified
storage vessels (2015) a
Number of uncontrolled storage vessels in
absence of federal regulation
Uncontrolled VOC Emissions from storage vessel
at model tank battery0
Total Nationwide Uncontrolled VOC Emissions
491,707
40,548
14,782
0.4
6,200
20,488
1,689
616
2.80
1,722
4,098
338
123
28
3,444
2,868
237
86
140
12,055
519,161
42,812
15,607
171
23,421
Minor discrepancies may be due to rounding
a.
vessels in 2008.
b. Calculated by applying the estimated 36 percent of storage vessels that are uncontrolled in the
absence of a Federal Regulation to the total projected number of new or modified storage vessels
in 2015.
c. VOC Emissions from individual storage vessel at model tank battery, see Table 7-5.
7-11
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for sources already being controlled, it was necessary to determine which storage vessels were already
being controlled. To do this, the 2005 National Emissions Inventory (NEI) was used.Storage vessels in
the oil and natural gas sector were identified under the review of the maximum achievable control
technology (MACT) standards.11 There were 5,412 storage vessels identified in the NEI, and of these,
1,973 (or 36 percent) were identified as being uncontrolled. Therefore, this percent of storage vessels
that would not require controls under State regulations was applied to the number of new or modified
storage vessels results in an estimate of 1,782 new or modified condensate storage vessels and 15,607
new or modified crude oil storage vessels.These are also presented in Table 7-6.
7.3.4 Nationwide Emission Estimates for New or Modified Storage Vessels
Nationwide emissions estimates are presented in Table 7-6 for condensate storage vessels and crude oil
storage vessels. Model storage vessel emissions were multiplied by the number of expected new or
modified storage vessels that would be uncontrolled in the absence of a federal regulation. As shown in
Table 7-6, the baseline nationwide emissions are estimated to be 21,373 tons/year for condensate storage
vessels and 23,421 tons/year for crude oil storage vessels.
7.4 Control Techniques
7.4.1 Potential Control Techniques
In analyzing controls for storage vessels, we reviewed control techniques identified in the Natural Gas
STAR program and state regulations. We identified two ways of controlling storage vessel emissions,
both of which can reduce VOC emissions by 95 percent. One option would be to install a vapor recovery
unit (VRU) and recover all the vapors from the storage vessels. The other option would be to route the
emissions from the storage vessels to a combustor. These control technologies are described below
along with their effectiveness as they apply to storage vessels in the oil and gas sector, cost impacts
associated with the installation and operation of these control technologies, and any secondary impacts
associated with their use.
7.4.2 Vapor Recovery Units
7.4.2.1 Description
Typically, with a VRU, hydrocarbon vapors are drawn out of the storage vessel under low pressure and
are piped to a separator, or suction scrubber, to collect any condensed liquids, which are typically
7-12
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recycled back to the storage vessel. Vapors from the separator flow through a compressor that provides
the low-pressure suction for the VRU system. Vapors are then either sent to the pipeline for sale or used
as on-site fuel.
7.4.2.2 Effectiveness
Vapor recovery units have been shown to reduce VOC emissions from storage vessels by approximately
95 percent.-Emv/ Bookmark not defined. A VRU recovers hydrocarbon vapors that potentially can be
used as supplemental burner fuel, or the vapors can be condensed and collected as condensate that can
be sold.If natural gas is recovered, it can be sold as well, as long as a gathering line is available to
convey the recovered salable gas product to market or to further processing. A VRU also does not have
secondary air impacts, as described below. However, a VRU cannot be used in all instances. Some
conditions that affect the feasibility of VRU are: availability of electrical service sufficient to power the
compressor; fluctuations in vapor loading caused by surges in throughput and flash emissions from the
storage vessel; potential for drawing air into condensate storage vessels causing an explosion hazard;
and lack of appropriate destination or use for the vapor recovered.
7.4.2.3 Cost Impacts
Cost data for a VRU was obtained from an Initial Economic Impact Analysis (EIA) prepared for
proposed state-only revisions to a Colorado regulation.Cost information contained in the EIA was
assumed to be giving in 2007 dollars.7Therefore costs were escalated to 2008 dollars using the CE
Indices for 2007 (525.4) and 2008 (575.4).12 According to the EIA, the purchased equipment cost of a
VRU was estimated to be $85,423 (escalated to 2008 dollars from $75,000 in 2007 dollars). Total
capital investment, including freight and design and installation was estimated to be $98,186. These cost
data are presented in Table 7-7. Total annual costs were estimated to be $18,983/year.
7.4.2.4 Secondary Impacts
A VRU is a pollution prevention technique that is used to recover natural gas that would otherwise be
emitted. No secondary emissions (e.g., nitrogen oxides, particulate matter, etc.) would be generated, no
wastes should be created, no wastewater generated, and no electricity needed. Therefore, there are no
secondary impacts expected due to the use of a VRU.
7-13
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Table 7-7. Total Capital Investment and Total Annual Cost of a Vapor Recovery Unit
Cost Item3
VRU
Freight and Design
VRU Installation
Maintenance
Recovered natural gas
Subtotal Costs (2007)
Subtotal Costs
(2008)d
Annualized costs
(using 7% interest, 1 5
year equipment life)
Capital
Costs
($)
$78,000
$78,000
$85,423
$9,379
Non-
Recurring,
One-time
Costs ($)
$1,500
$10,154
$11,654
$12,763
$1,401
Total
Capital
Investment
($)b
$98,186
O&M
Costs ($)
$8,553
$8,553
$9,367
n/a
Savings
due to Fuel
Sales
($/yr)
($1,063)
($1,063)
($1,164)
n/a
Annualized
Total Cost
($/yr)c
$18,983
Minor discrepancies may be due to rounding
a. Assume cost data provided is for the year 2007. Reference 7.
b. Total Capital Investment is the sum of the subtotal costs for capital costs and nonrecurring one-
time costs.
c. Total Annual Costs is the sum of the annualized capital and recurring costs, O&M costs, and
savings due to fuel sales.
d. Costs are escalated to 2008 dollars using the CE Indices for 2007 (525.4) and 2008 (575.4).
Reference 12.
7-14
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7.4.3 Combustors
7.4.3.1 Description and Effectiveness
Combustors are also used to control emissions from condensate and crude oil storage vessels.The type of
combustor used is a high-temperature oxidation process used to burn combustible components, mostly
hydrocarbons, found in waste streams.13 Combustors are used to control VOC in many industrial
settings, since thecombustorcan normally handle fluctuations in concentration, flow rate, heating value,
and inert species content.14 For this analysis, the types of combustors installed for the oil and gas sector
are assumed to achieve 95 percent efficiency.7 Combustors do not have the same operational issues as
VRUs, however secondary impacts are associated with combustors as discussed below.
7.4.3.2 Cost Impacts
Cost data for a combustor was also obtained from the Initial EIA prepared for proposed state-only
revisions to the Colorado regulation.7 As performed for the VRU, costs were escalated to 2008 dollars
using the CE Indices for 2007 (525.4) and 2008 (575.4).12 According to the EIA, the purchased
equipment cost of a combustor, including an auto igniter and surveillance system was estimated to be
$23,699 (escalated to 2008 dollars from $21,640 in 2007 dollars). Total capital investment, including
freight and design and installation was estimated to be $32,301. These cost data are presented in Table
7-8. Total annual costs were estimated to be $8,909/year.
7.4.3.3 Secondary Impacts
Combustion and partial combustion of many pollutants also create secondary pollutants including
nitrogen oxides, carbon monoxide, sulfur oxides, carbon dioxide, and smoke/particulates. Reliable data
for emission factors from combustors on condensate and crude oil storage vessels are limited.
Guidelines published in AP-42 for flare operations are based on tests from a mixture containing
80 percent propylene and 20 percent propane.13 These emissions factors, however, are thebest indication
for secondary pollutants from combustors currently available. The secondary emissionsper storage
vessel are provided in Table 7-9.
7-15
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Table 7-8. Total Capital Investment and Total Annual Cost of a Combustor
Cost Item"
Combustor
Freight and Design
Combustor Installation
Auto Igniter
Surveillance System
Pilot Fuel
Maintenance
Data Management
Subtotal Costs (2007)
Subtotal Costs (2008) e
Annualized costs (using 7%
interest, 1 5 year equipment life)
Capital
Costs
($)
$16,540
$1,500
$3,600
$21,640
$23,699
$2,602
Non-
Recurring,
One-time
Costs ($)
$1,500
$6,354
$7,854
$8,601
$944
Total
Capital
Investment
($)b
$32,301
O&M
Costs ($)
$1,897
$2,000
$1,000
$4,897
$5,363
n/a
Annualized
Total Cost
($/yr)c
$8,909
Minor discrepancies may be due to rounding
a. Assume cost data provided is for the year 2007. Reference 7.
b. Total Capital Investment is the sum of the subtotal costs for capital costs and nonrecurring one-
time costs.
c. Total Annual Costs is the sum of the annualized capital and recurring costs, O&M costs, and
savings due to fuel sales.
d. Surveillance system identifies when pilot is not lit and attempt to relight it, documents the
duration of time when the pilot is not lit, and notifies and operator that repairs are necessary.
e. Costs are escalated to 2008 dollars using the CE Indices for 2007 (525.4) and 2008 (575.4).
Reference 12.
7-16
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Table 7-9. Secondary Impacts for Combustors used to Control Condensate and Crude Oil
Storage Vessels
Pollutant
THC
CO
C02
NOX
PM
Emission
Factor
0.14
0.37
60
0.068
40
Units
Ib/MMBtu
Ib/MMBtu
Kg/MMBtub
Ib/MMBtu
ug/1 (used lightly smoking flares
due to criteria that flares should
not have visible emissions i.e.
should not smoke)
Emissions per
Storage Vessel
(tons/year)"
0.0061
0.0160
5.62
2.95E-03
5.51E-05
a. Converted using average saturated gross heating value of the storage vessel vapor
(1,968 Btu/scf) and an average vapor flow rate of 44.07 Mcf per storage vessel. See
Appendix A.
b. CO2 emission factor obtained from 40 CFR Part 98, subpart Y, Equation Y-2.
7-17
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7.5 Regulatory Options and Nationwide Impacts of Regulatory Options
7.5.1 Consideration of Regulatory Options for Condensate and Crude Oil Storage Vessels
The VOC emissions from storage vessels vary significantly, depending on the rate of liquid entering and
passing through the vessel (i.e., its throughput), the pressure of the liquid as it enters the atmospheric
pressure storage vessel, the liquid's volatility and temperature of the liquid. Some storage vessels have
negligible emissions, such as those with very little throughput and/or handling heavy liquids entering at
atmospheric pressure. Therefore, in order to determine the most cost effective means of controlling the
storage vessels, a cutoff was evaluated to limit the applicability of the standards to these storage vessels.
Rather than require a cutoff in terms of emissions that would require a facility to conduct an emissions
test on their storage vessel, a throughput cutoff was evaluated. It was assumed that facilities would have
storage vessel throughput data readily available. Therefore, we evaluated the costs of controlling storage
vessels with varying throughputs to determine which throughput level would provide the most cost
effective control option.
The standard would require an emission reduction of 95 percent, which, as discussed above, could be
achieved with a VRU or a combustor. A combustoris an option for tank batteries because of the
operational issues associated with a VRU as discussed above.However the use of a VRU is preferable to
a combustorbecause a combustordestroys, rather than recycles, valuable resources and there are
secondary impacts associated with the use of a combustor. Therefore, the cost impacts associated a VRU
installed for the control of storage vessels were evaluated.
To conduct this evaluation, emission factor data from a study prepared for the Texas Environmental
Research Consortium15 was used to represent emissions from the different throughputs being evaluated.
For condensate storage vessels, an emission factor of 33.3 Ib VOC/bbl was used and for crude oil
storage vessels, an emission factor of 1.6 Ib VOC/bbl was used.Using the throughput for each control
option, an equivalent emissions limit was determined.Table 7-10 presents the following regulatory
options considered for condensate storage vessels:
• Regulatory Option 1: Control condensate storage vessels with a throughput greater than 0.5
bbl/day (equivalent emissions of 3.0 tons/year);
7-18
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Table 7-10. Options for Throughput Cutoffs for Condensate Storage Vessels
Regulatory
Option
1
2
3
4
Throughput
Cutoff
(bbl/day)
0.5
1
2
5
Equivalent
Emissions
Cutoff
(tons/year)
a
3.0
6.1
12.2
30.4
Emission
Reduction
(tons/year)
2.89
5.77
11.55
28.87
Annual
Costs for
VRU
($/yr)c
$18,983
$18,983
$18,983
$18,983
Cost
Effectiveness
($/ton)
$6,576
$3,288
$1,644
$658
Number
of
impacted
units'1
1782
94
94
24
Minor discrepancies may be due to rounding
a. Emissions calculated using emission factor of 33.3 Ib VOC/bbl condensate and the
throughput associated with each option.
b. Calculated using 95 percent reduction
c. Refer to Table 7-7 for VRU Annual Costs.
d. Number of impacted units determined by evaluating which of the model tank batteries and
storage vessel populations associated with each model tank battery (refer to Table 7-6) would
be subject to each regulatory option. A storage vessel at a model tank battery was considered
to be impacted by the regulatory option if its throughput and emissions were greater than the
cutoffs for the option.
7-19
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• Regulatory Option 2: Control condensate storage vessels with a throughput greater than 1
bbl/day (equivalent emissions of 6 tons/year);
• Regulatory Option 3: Control condensate storage vessels with a throughput greater than 2
bbl/day (equivalent emissions of 12 tons/year);
• Regulatory Option 1: Control condensate storage vessels with a throughput greater than 5.0
bbl/day (equivalent emissions of 30 tons/year);
As shown in Table 7-10, Regulatory Option 1 is not cost effective for condensate storage vessels with a
throughput of 0.5 bbl/day.Therefore Regulatory Option 1 is rejected.Since the cost effectiveness
associated with Regulatory Option 2 is acceptable ($3,288/ton), this option was selected. As shown in
Table 7-5, Model Condensate Storage Vessel Categories F, G, and H have throughputs greater than 1
bbl/day and emissions greater than 6 tons/year. Therefore, for the purposes of determining impacts, the
populations of new and modified condensate storage vessels associated with categories F, G, and H are
assumed to be required to reduce their emissions by 95 percent, a total of 94 new or modified
condensate storage vessels.
A similar evaluation was performed for crude oil vessels and is presented in Table 7-11 for the
following regulatory options:
• Regulatory Option 1: Control crude oil storage vessels with a throughput greater than 1 bbl/day
(equivalent emissions of 0.3 tons/year);
• Regulatory Option 2: Control condensate storage vessels with a throughput greater than 5
bbl/day (equivalent emissions of 1.5 tons/year);
• Regulatory Option 3: Control condensate storage vessels with a throughput greater than 20
bbl/day (equivalent emissions of 6 tons/year);
• Regulatory Option 1: Control condensate storage vessels with a throughput greater than 50
bbl/day (equivalent emissions of 15 tons/year);
As shown in Table 7-11, Regulatory Options 1 and 2 are not cost effective crude oil storage vessels with
a throughput of 1 and 5 bbl/day, respectively. Therefore Regulatory Options 1 and 2 are rejected.Since
the cost effectiveness associated with Regulatory Option 3 is acceptable ($3,422/ton), this option was
selected. As shown in Table 7-5, Model Crude Oil Storage Vessel CategoriesG and H have throughputs
greater than 20 bbl/day and emissions greater than 6 tons/year. Therefore, for the purposes of
determining impacts, the populations of new and modified crude oil storage vessels associated with
categories G
7-20
-------
Table 7-11. Options for Throughput Cutoffs for Crude Oil Storage Vessels
Regulatory
Option
1
2
3
4
Throughput
Cutoff
(bbl/day)
1
5
20
50
Equivalent
Emissions
Cutoff
(tons/year)
a
0.3
1.5
5.8
14.6
Emission
Reduction
(tons/year)
0.28
1.4
5.55
13.87
Annual
Costs for
VRU
($/yr)c
$18,983
$18,983
$18,983
$18,983
Cost
Effectiveness
($/ton)
$68,432
$13,686
$3,422
$1,369
Number
of
impacted
units'1
15607
825
209
209
Minor discrepancies may be due to rounding
a. Emissions calculated using emission factor of 1.6 Ib VOC/bbl condensate and the
throughput associated with each option.
b. Calculated using 95 percent reduction
c. Refer to Table 7-7 for VRU Annual Costs.
d. Number of impacted units determined by evaluating which of the model tank batteries and
storage vessel populations associated with each model tank battery (refer to Table 7-6)
would be subject to each regulatory option. A storage vessel at a model tank battery was
considered to be impacted by the regulatory option if its throughput and emissions were
greater than the cutoffs for the option.
7-21
-------
and H are assumed to be required to reduce their emissions by 95 percent, a total of 209 new or modified
condensate storage vessels.
7.5.2 Nationwide Impacts of Regulatory Options
This section provides an analysis of the primary environmental impacts (i.e., emission reductions), cost
impacts and secondary environmental impacts related to Regulatory Option 2 for condensate storage
vessels and Regulatory Option 3 for crude oil storage vessels which were selected as viable options for
setting standards for storage vessels.In addition, combined impacts for a typical storage vessel are
presented.
7.5.3 Primary Environmental Impacts of Regulatory Options
Regulatory Option2 (condensate storage vessels) and 3 (crude oil storage vessels) were selected as
options for setting standards for storage vessels as follows:
• Regulatory Option 2 (Condensate Storage Vessels): Reduce emissions from condensate storage
vessels with an average throughput greater than 1 bbl/day.
Regulatory Option 3 (Crude Oil Storage Vessels): Reduce emissions from crude oil storage
vessels with an average throughput greater than 20 bbl/day.
The number of storage vessels that would be subject to the regulatory options listed above are presented
in Tables7-10 and 7-11. It was estimated that there would be 94 new or modified condensate storage
vessels not otherwise subject to State regulationsand impacted by Regulatory Option 2 (condensate
storage vessels). As shown in Table 7-11, 209 new or modified crude oil storage vessels not otherwise
subject to State regulations would be impacted by Regulatory Option 3 (crude oil storage tanks).
Table 7-12 presents the nationwide emission reduction estimates for each regulatory option. Emissions
reductions were estimated by applying 95 percent control efficiency to the VOC emissions presented in
Table 7-6 for each storage vessel in the model condensate and crude oil tank batteries and multiplying
by the number of impacted storage vessels. For Regulatory Option 2 (condensate storage vessels), the
total nationwide VOC emission reduction was estimated to be 15,061 tons/year and 14,710 tons/year for
Regulatory Option 3 (crude oil storage vessels).
7-22
-------
Table 7-12. Nationwide Impacts of Regulatory Options
Model
Tank
Battery
Number of
Sources
subject to
Regulatory
Option3
voc
Emissions
for a
Typical
Storage
Vessel
(tons/year)
Capital
Cost
forTypi
cal
Storage
Vessel"
($)
Annual Cost for a
Typical Storage
Vessel"
($/yr)
without
savings
with
savings
Nationwide Emission
Reductions
(tons/year)0
VOC
Methane11
Regulatory Option 2: Condensate Storage Vessels
F
G
H
70
14
10
22.3
223
1117
65,243
65,243
65,243
14,528
14,528
14,528
13,946
13,946
13,946
Total for Regulatory Option 2
1,483
2,966
10,612
15,061
325
649
2,322
3,296
Regulatory Option 3: Crude Oil Storage Vessels
G
H
123
86
28
140
65,243
65,243
14,528
14,528
13,946
13,946
Total for Regulatory Option 3
3,272
11,438
14,710
716
2,503
3,219
Combined Impacts"
Typical
Storage
Vessel
304
103
65,243
14,528
13,946
29,746
6,490
VOC Cost Effectiveness
(S/ton)
without
savings
with
savings
Methane Cost
Effectiveness
(S/ton)
without
savings
with
savings
Total Nationwide Costs
(million S/year)
Capital
Cost
Annual
without
savings
Annual
with
savings
685
68
14
'/////A
658
66
13
'///////
3129
313
62.6
y///A
3004
301
60.1
'//////
4.57
0.913
0.652
6.14
1.02
0.203
0.145
1.37
0.98
0.195
0.139
1.31
546
109
S/////A
524
104
y/////s
2496
499
'////A
2396
479
'//////
8.02
5.61
13.6
1.79
1.25
3.04
1.71
1.20
2.91
149
143
680
652
19.8
4.41
4.24
Minor discrepancies may be due to rounding
a. Number of storage vessels in each model tank battery (refer to Table 7-6) determined to be subject to the regulatory option as outlined
in Table 7-10.
b. It was assumed for the purposes of estimating nationwide impacts that 50 percent of facilities would install a combustor and 50
percent a VRU.This accounts for the operational difficulties of using a VRU. Capital and Annual Costs determined using the average
of costs presented in Tables 7-7 and 7-8.
c. Nationwide emission reductions calculated by applying a 95 percent emissions reduction to the VOC emissions for a typical storage
vessel multiplied by the number of sources subject to the regulatory option.
d. Methane Reductions calculated by applying the average Methane to VOC factor from the E&P Tanks Study (see Appendix
A).Methane:VOC = 0.219
e. For purposes of evaluating NSPS impact, impacts were determined for an average storage vessel by calculating total VOC emissions
from all storage vessels and dividing by the total number of impacted storage vessels to obtain the average VOC emissions per storage
vessel.
7-23
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7.5.4 Cost Impacts
Cost impacts of the individual control techniques (VRU and combustors) were presented in Section 7.4.
For both regulatory options, it was assumed that 50 percent of facilities would install a combustor and
50 percent a VRU. This accounts for the operational difficulties of using a VRU. Therefore, the average
capital cost of control for each storage vessel was estimated to be $65,243 (the average of the total
capital investment for a VRU of $98,186 and $32,301 for a combustor from Tables 7-7 and 7-8,
respectively). Similarly, the average annual cost for a typical storage vessel was estimated to be
$14,528/yr (average of the total annual cost for a VRU of $20,147/yr and $8,909/yr for a combustor
from Tables 7-7 and 7-8, respectively) without including any cost savings due to fuel sales and
$13,946/yr (average of the total annual cost for a VRU of $18,983/yr and $8,909/yr for a combustorfrom
Tables 7-7 and 7-8, respectively) including cost savings.
Nationwide capital and annual costs were calculated by applying the number of storage vessels subject
to the regulatory option. As shown in Table 7-12, the nationwide capital cost of Regulatory Option 2
(condensate storage vessels) was estimated to be $6.14 million and for RegulatoryOption 3 (crude oil
storage vessels) nationwide capital cost was estimated to be $13.6 million.Total annual costs without
fuel savings were estimated to be $1.37 million/yr for Regulatory Option 2 (condensate storage vessels)
and $3.04 million/yr for Regulatory Option 3 (crude oil storage vessels). Total annual costs with fuel
savings were estimated to be $1.31 million/yr for Regulatory Option 2 (condensate storage vessels) and
$2.91 million/yr for Regulatory Option 3 (crude oil storage vessels).
For purposes of evaluating the impact of a federal standard, impacts were determined for an average
storage vessel by calculating the total VOC emissions from all storage vessels and dividing by the total
number of impacted storage vessels (304) to obtain the average VOC emissions per storage vessel
(103 tons/year).Therefore, the nationwide annual costs were estimated to be $4.41 million/yr. A total
nationwide VOC emission reduction of 29,746 tons/year results in a cost effectiveness of $149/ton.
7.5.5 Nationwide Secondary Emission Impacts
Regulatory Options 2 (condensate storage vessels) and 3 (crude oil storage vessels) allow for the use of
a combustor; therefore the estimated nationwide secondary impacts are a result of combusting 50
percent of all storage vessel emissions. The secondary impacts for controlling a single storage vessel
using a combustor are presented in Table 7-9. Nationwide secondary impacts are calculated by
7-24
-------
Table 7-13. Nationwide Secondary Combined Impacts for Storage Vessels
Pollutant
THC
CO
C02
NOX
PM
Emissions per
Storage Vessel
(tons/year) a
0.0061
0.0160
5.62
2.95E-03
5.51E-05
Nationwide
Emissions
(tons/year)"5
0.927
2.43
854
0.448
0.0084
a. Emissions per storage vessel presented in Table 7-9.
b. Nationwide emissions calculated by assuming that 50 percent of the 304
impacted storage vessels would install a combustor.
7-25
-------
multiplying 50 percent of the estimated number of impacted storage vessels (152) by the secondary
emissions and are presented in Table 7-13.
7.6 References
1. National Emissions Standards for Hazardous Air Pollutants for Source Categories: Oil and
Natural Gas Production and Natural Gas Transmission and Storage - Background Information
for Proposed Standards. U. S. Environmental Protection Agency, Research Triangle Park, NC.
Publication No.EPA-453/R-94-079a. April 1997.
2. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 - 2008. U.S. Environmental
Protection Agency, Research Triangle Park, NC.Publication No.EPA 430-R-10-006. April 15,
2010.
3. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 - 2007. U.S. Environmental
Protection Agency, Research Triangle Park, NC.Publication No.EPA 430-R-09-004. April 15,
2009.
4. Hendler, A., (URS Corporation), Nunn, J. (COMM Engineering), and J. Lundeen (Trimeric
Corporation). VOC Emissions from Oil and Condensate Storage Tanks - Final Report.Prepared
for Texas Environmental Research Consortium. The Woodlands, TX. October 31, 2006 (revised
April 2, 2009)
5. U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners:
Installing Vapor Recovery Units on Crude Oil Storage Tanks. Publication No.EPA 430-B-03-
015. October 2003.
6. Gidney, B., and S. Pena, Hy-Bon Engineering Company, Inc. Upstream Oil and Gas Storage
Tank Project Flash Emissions Models Evaluation. Final Report.Prepared for Texas Commission
on Environmental Quality and Eastern Research Group, Inc. July 16, 2009.
7. Initial Economic Impact Analysis for Proposed State-Only Revisions to the Air Quality Control
Commission's Regulation Number 7, "Emissions of Volatile Organic Compounds." September
18,2008.
8. Production Tank Emissions Model.E&P TANK Version 2.0, User's Manual.A Program for
Estimating Emissions from Hydrocarbon Production Tanks. American Petroleum
Institute.Software Number 4697. April 2000.
9. Grubert, D., EC/R Incorporated, to B. Moore, Fuels and Incineration Group, U.S. Environmental
Protection Agency, Research Triangle Park, NC. Summary of the October 12, 2010 Meeting
Between the EPA andAmerican Petroleum Institute. July 28, 2011.
10. U.S. Energy Information Administration.Table 4a.U.S. Crude Oil and Liquid Fuels Supply,
Consumption, and Inventories. Available on the Internet at
http://www.eia.gov/emeu/steo/pub/cf tables/steotables.cfm?tableNumber=9
7-26
-------
11. Memorandum from Wilson, D., et al, ERG, to A. Pope, U.S. Environmental Protection
Agency.Documentation for NEI Updates for Oil and Natural Gas Production and Natural Gas
Transmission and Storage.March 15, 2011.
12. Economic Indicators: Chemical Engineering Plant Cost Index. Chemical Engineering Magazine.
13. U.S. Environmental Protection Agency. AP 42, Fifth Edition, Volume I, Chapter 13.5 Industrial
Flares.Office of Air Quality Planning & Standards. 1991
14. U.S. Environmental Protection Agency. Air Pollution Control Technology Fact Sheet: FLARES.
Clean Air Technology Center.
15. Hendler, A., URS Corporation, Austin, TX, et al. VOC Emissions From Oil and Condensate
Storage Tanks. Prepared for Texas Environmental Research Consortium, The Woodlands, TX.
October 31, 2006 (revised April 2, 2009).
7-27
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8.0 EQUIPMENT LEAKS
Leaks from components in the oil and natural gas sector are a source of pollutant emissions. This chapter
explains the causes for these leaks, and provides emission estimates for "model" facilities in the various
segments of the oil and gas sector. In addition, nationwide equipment leak emission estimates from new
sources are estimated. Programs that are designed to reduce equipment leak emissions are explained,
along with costs, emission reductions, and secondary impacts. Finally, this chapter discusses
considerations in developing regulatory alternatives for equipment leaks.
8.1 Equipment Leak Description
There are several potential sources of equipment leak emissions throughout the oil and natural gas
sector. Components such as pumps, valves, pressure relief valves, flanges, agitators, and compressors
are potential sources that can leak due to seal failure. Other sources, such as open-ended lines, and
sampling connections 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 volatile emissions from
typical facilities in the oil and gas industry.
Due to the large number of valves, pumps, and other components within oil and natural gas production,
processing, and/or transmission facilities, total equipment leak VOC emissions from these components
can be significant. Tank batteries or production pads are generally small facilities as compared with
other oil and gas operations, and are generally characterized by a small number of components. Natural
gas processing plants, especially those using refrigerated absorption, and transmission stations tend to
have a large number of components.
8.2. Equipment leak Emission Data and Emissions Factors
8.2.1 Summary of Major Studies and Emission Factors
Emissions data from equipment leaks have been collected from chemical manufacturing and petroleum
I r\ o
production to develop control strategies for reducing HAP and VOC emissions from these sources. ' ' In
the evaluation of the emissions and emission reduction options for equipment leaks, many of these
studies were consulted. Table 8-1 presents a list of the studies consulted along with an indication of the
type of information contained in the study.
8-1
-------
8.2.2 Model Plants
Facilities in the oil and gas sector can 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 emissions from leaking equipment, a model plant approach was
used. The following sections discuss the creation of these model plants.
Information related to equipment counts was obtained from a natural gas industry report. This document
provided average equipment counts for gas production, gas processing, natural gas transmission and
distribution. These average counts were used to develop model plants for wellheads, well pads, and
gathering line and boosting stations in the production segment of the industry, for a natural gas
processing plant, and for a compression/transmission station in the natural gas transmission segment.
These equipment counts are consistent with those contained in EPA's analysis to estimate methane
emissions conducted in support of the Greenhouse Gas Mandatory Reporting Rule (subpart W), which
was published in the Federal Register on November 30, 2010 (75 FR 74458), These model plants are
discussed in the following sections.
5.2.2.1 Oil and Natural Gas Production
Oil and natural gas production varies from site-to site. Many production sites may include only a
wellhead that is extracting oil or natural gas from the ground. Other production sites consist of
wellheads attached to a well pad. A well pad 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
pad can serve one well on a pad or several wells on a pad. A wellhead site consisting of only the
wellhead and affiliated piping is not considered to be a well pad. The number of wells feeding into a
well pad can vary from one to as many as 7 wells. Therefore, the number of components with potential
for equipment leaks can vary depending on the number of wells feeding into the production pad and the
amount of processing equipment located at the site.
8-2
-------
Table 8-1. Major Studies Reviewed for Consideration or Emissions and Activity Data
Report Name
Greenhouse Gas Mandatory
Reporting Rule and Technical
Supporting Documents
Inventory of Greenhouse Gas
Emissions and Sinks: 1990-20084
Methane Emissions from the
Natural Gas Industry567
Methane Emissions from the US
Petroleum Industry (Draft) 8
Methane Emissions from the US
Petroleum Industry 9
Oil and Gas Emission Inventories
for Western States10
Recommendations for
Improvements to the Central States
Regional Air Partnership's Oil and
Gas Emission Inventories n
Oil and Gas Producing Industry in
Your State12
Emissions from Natural Gas
Production in the Barnett Shale and
Opportunities for Cost-effective
Improvements 13
Emissions from oil and Natural
Gas Production Facilities 14
Petroleum and Natural Gas
Statistical Data15
Preferred and Alternative Methods
for Estimating Air Emissions from
Oil and Gas Field Production and
Processing Operations 16
Protocol for Equipment Leak
Emission Estimates17
Affiliation
EPA
EPA
Gas Research Institute
/EPA
EPA
EPA
Western Regional Air
Partnership
Central States
Regional Air
Partnership
Independent
Petroleum Association
of America
Environmental
Defense Fund
Texas Commission for
Environmental Quality
U.S. Energy
Information
Administration
EPA
EPA
Year of
Report
2010
2010
1996
1996
1999
2005
2008
2009
2009
2007
2007-
2009
1999
1995
Activity
Factor (s)
Nationwide
Nationwide
Nationwide
Nationwide
Nationwide
Regional
Regional
Nationwide
Regional
Regional
Nationwide
Nationwide
Emissions
Data
X
X
X
X
X
X
X
X
X
X
X
Control
Options
X
X
X
X
X
X
X
X
8-3
-------
In addition to wellheads and well pads, model plants were developed for gathering lines and boosting
stations. The gathering lines and boosting stations are sites that collect oil and gas from well pads and
direct them to the gas processing plants. These stations have similar equipment to well pads; however
they are not directly connected to the wellheads.
The EPA/GRI report provided the average number of equipment located at a well pad and the average
number of components for each of these pieces of equipment.4The type of production equipment located
at a well pad include: gas wellheads, separators, meters/piping, gathering compressors, heaters, and
dehydrators. The types of components that are associated with this equipment include: valves,
connectors, open-ended lines, and pressure relief valves. Four model plants were developed for well
pads and are presented in Table 8-2. These model plants were developed starting with one, three, five
and seven wellheads, and adding the average numberof other pieces of equipment per wellhead.
Gathering compressors are not included at well pads and were included in the equipment for gathering
lines and boosting stations.
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
summary of the component counts for oil and gas production well pads is presented in Table 8-3.
Gathering line and boosting station model plants were developed using the average equipment counts for
oil and gas production. The average equipment count was assigned Model Plant 2 and Model Plants 1
and 3 were assumed to be equally distributed on either side of the average equipment count. Therefore,
Model Plant 1 can be assumed to be a small gathering and boosting station, and Model Plant 3 can be
assumed to be a large gathering and boosting station. A summary of the model plant production
equipment counts for gathering lines and boosting stations is provided in Table 8-4.
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. from the EPA/GRIdocument. The
components for gathering compressors were included in the model plant total counts, but the compressor
seals were excluded. Compressors seals are addressed in a Chapter 6 of this document. A summary of
the component counts for oil and gas gathering line and boosting stations are presented in Table 8-5.
8-4
-------
Table 8-2.Average Equipment Count for Oil and Gas Production Well Pad Model Plants
Equipment
Gas Wellheads
Separators
Meter/Piping
In-Line Heaters
Dehydrators
Model Plant 1
1
—
—
—
—
Model Plant 2
5
4
2
2
2
Model Plant 3
48
40
24
26
19
Data Source: EPA/GRI, Methane Emissions from the Natural Gas Industry, Volume 8: Equipment
Leaks, Table 4-4 and Table 4-7, June 1996. (EPA-600/R-96-080h)
8-5
-------
Table 8-3.Average Component Count for Oil and Gas Production Well Pad Model Plants
Component
Valve
Connectors
Open-Ended Line
Pressure Relief Valve
Model
Plant 1
9
37
1
0
Model
Plant 2
122
450
15
5
Model
Plant 3
235
863
29
10
Model
Plant 4
348
1,276
43
15
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)
8-6
-------
Table 8-4.Average Equipment Count for Oil and Gas Production Gathering Line and Boosting
Station Model Plants
Equipment
Separators
Meter/Piping
Gathering Compressors
In-Line Heaters
Dehydrators
Model Plant 1
7
4
3
4
3
Model Plant 2
11
7
5
7
5
Model Plant 3
15
10
7
10
7
Data Source: EPA/GRI, Methane Emissions from the Natural Gas Industry, Volume 8: Equipment
Leaks, Table 4-4 and Table 4-7, June 1996. (EPA-600/R-96-080h)
8-7
-------
Table 8-5. Average Component Count for Oil and Gas Production Gathering Line and Boosting
Station Model Plants
Component
Valve
Connectors
Open-Ended Line
Pressure Relief Valve
Model Plant 1
547
1,723
51
29
Model Plant 2
906
2,864
83
48
Model Plant 3
1,265
4,005
115
67
DataSource: 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)
-------
8.2.2.2 Oil and Natural Gas Processing
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 gas from the processing facility to the
transmission stations.
New Source Performance Standards (NSPS) have already been promulgated for equipment leaks at new
natural gas processing plants (40 CFR Part 60, subpart KKK), and were assumed to be the baseline
emissions for this analysis. Only one model plant was developed for the processing sector. A summary
of the model plant production components counts for an oil and gas processing facility is provided in
Table 8-6.
8.2.2.3 Natural Gas Transmission/Storage
Natural gas transmission/storage stations are facilities that use compressors that move natural gas at
elevated pressure from production fields or natural gas processing facilities, in transmission pipelines, to
natural gas distribution pipelines, or into storage. In addition, transmission stations may include
equipment for liquids separation, natural gas dehydration, and tanks for the storage of water and
hydrocarbon liquids. Residue (sales) gas compression operated by natural gas processing facilities are
included in the onshore natural gas processing segment and are excluded from this segment. This source
category also does not include emissions from gathering lines and boosting stations. Component counts
were obtained from the EPA/GRI report and are presented in Table 8-7.
8.3 Nationwide Emissions from New Sources
8.3.1 Overview of Approach
Nationwide emissions were calculated by using the model plant approach for estimating emissions.
Baseline model plant emissions for the natural gas production, processing, and transmission sectors were
calculated using the component counts and the component gas service emission factors.5Annual
emissions were calculated assuming 8,760 hours of operation each year. The emissions factors are
provided for total organic compounds (TOC) and include non-VOCs such as methane and ethane. The
emission factors for the production and processing sectors that were used to estimate the new source
emissions are presented in Table 8-8. Emission factors for the transmission sector are presented in
8-9
-------
Table 8-6.Average Component Count for Oil and Gas Processing Model Plant
Component
Valve
Connectors
Open-Ended Line
Pressure Relief Valve
Gas Plant (non-compressor
components)
1,392
4,392
134
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)
8-10
-------
Table 8-7.Average Component Count for a Gas TransmissionFacility
Component
Valve
Connection
Open-Ended Line
Pressure Relief Valve
Processing Plant Component
Count
704
3,068
55
14
Data Source: EPA/GRI, Methane Emissions from the Natural Gas Industry,
Volume 8: Equipment Leaks, Table 4-16, June 1996. (EPA-600/R-96-080h)
8-11
-------
Table 8-8 Oil and Gas Production and Processing Operations Average Emissions Factors
Component Type
Valves
Connectors
Open-Ended Line
Pressure Relief Valve
Component Service
Gas
Gas
Gas
Gas
Emission Factor
(kg/hr/source)
4.5E-03
2.0E-04
2.0E-03
8.8E-03
Data Source: EPA, Protocol for Equipment Leak Emission Estimates, Table 2-4, November 1995.
(EPA-453/R-95-017)
8-12
-------
Table 8-9. Emissions for VOC, hazardous air pollutants (HAP), and methane were calculated using TOC
weight fractions.6 A summary of the baseline emissions for each of the sectors are presented in Table 8-
10.
8.3.2 Activity Data
Data from oil and gas technical documents and inventories were used to estimate the number of new
sources for each of the oil and gas sectors. Information from the Energy Information Administration
(EIA) was used to estimate the number of new wells, well pads, and gathering and boosting stations. The
number of processing plants and transmission/storage facilities was estimated using data from the Oil
and Gas Journal, and the EPA Greenhouse Gas Inventory. A summary of the steps used to estimate the
new sources for each of the oil and gas sectors is presented in the following sections.
8.3.2.1 Well Pads
The EIA provided a forecast of the number of new conventional and unconventional gas wells for the
Year 2015 for both exploratory and developmental wells. The EIA projected 19,097 conventional and
unconventional gas wells in 2015. The number of wells was converted to number of well pads by
dividing the total number of wells by the average number of wells serving a well pad which is estimated
to be 5. Therefore, the number of new well pads was estimated to be 3,820. The facilities were divided
into the model plants assuming a normal distribution of facilities around the average model plant (Model
Plant 2).
8.3.2.2 Gathering and Boosting
The number of new gathering and boosting stations was estimated using the current inventory of
gathering compressors listed in the EPA Greenhouse Gas Inventory. The total number of gathering
compressors was listed as 32,233 in the inventory. The GRI/EPA document does not include a separate
list of compressor counts for gathering and boosting stations, but it does list the average number of
compressors in the gas production section. It was assumed that this average of 4.5 compressors for gas
production facilities is applicable to gathering and boosting stations. Therefore, using the inventory of
32,233 compressors and the average number of 4.5 compressors per facility, we estimated the number of
gathering and boosting stations to be 7,163. To estimate the number of new gathering and boosting
stations, we used the same increase of 3.84 percent used to estimate well pads to estimate the number of
new gathering and boosting stations. This provided an estimate of 275 new gathering and boosting
8-13
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Table 8-9 Oil and Gas Transmission/Storage Average Emissions Factors
Component Type
Valves
Connectors
Open-Ended Line
Pressure Relief Valve
Component Service
Gas
Gas
Gas
Gas
Emission Factor
(kg/hr/source)
5.5E-03
9.3E-04
7.1E-02
3.98E-02
Data Source:EPA/GRI, Methane Emissions from the Natural Gas Industry, Volume 8: Equipment
Leaks, Table 4-17, June 1996. (EPA-600/R-96-080h)
8-14
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Table 8-10. Baseline Emissions for the Oil and Gas Production, Processing, and Transmission/Storage Model Plants
Oil and Gas Sector
Well Pads
Gathering & Boosting
Processing
Transmission/Storage
Model Plant
1
2
3
1
2
3
1
1
TOC Emissions
(Tons/yr)
0.482
13.3
139
30.5
50.6
70.6
74.0
108.1
Methane
Emissions
(Tons/yr)
0.335
9.24
96.5
21.2
35.2
49.1
51.4
98.1
VOC Emissions
(Tons/yr)
0.0930
2.56
26.8
5.90
9.76
13.6
14.3
2.71
HAP Emissions
(Tons/yr)
0.00351
0.0967
1.01
0.222
0.368
0.514
0.539
0.0806
8-15
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stations that would be affected sources under the proposed NSPS. The new gathering and boosting
stations were assumed to be normally distributed around the average model plant (Model Plant 2).
8.3.2.3 Processing Facilities
The number of new processing facilities was estimated using gas processing data from the Oil and Gas
Journal. The Oil and Gas Journal Construction Survey currently shows 6,303 million cubic feet of gas
per day (MMcf/day) additional gas processing capacity in various stages of development. The OGJ Gas
Processing Survey shows that there is 26.9 trillion cubic feet per year (tcf/year) in existing capacity, with
a current throughput of 16.6 tcf/year or 62 percent utilization rate. If the utilization rate remains
constant, the new construction would add approximately 1.4 tcf/year to the processing system. This
would be an increase of 8.5 percent to the processing sector. The recent energy outlook published by the
EIApredicts a 1.03 tcf/year increase in natural gas processing from 21.07 to22.104 tcf/year. This would
be an annual increase of 5 percent over the next five years.
The EPA Greenhouse Gas Inventory estimates the number of existing processing facilities to be 577
plants operating in the U.S. Based on the projections provided in Oil and Gas Journal and EIA, it was
assumed that the processing sector would increase by 5 percent annually. Therefore the number of new
sources was estimated to be 29 new processing facilities in the U.S.
8.3.2.4 Transmission/Storage Facilities
The number of new transmission and storage facilities was estimated using the annual growth rate of 5
percent used for the processing sector and the estimated number of existing transmission and storage
facilities in the EPA Greenhouse Inventory. The inventory estimates 1,748 transmission stations and 400
storage facilities for a total of 2,148. Therefore, the number of new transmission/storage facilities was
estimated to be 107.
8.3.3 Emission Estimates
Nationwide emission estimates for the new sources for well pads, gathering and boosting, processing,
and transmission/storage are summarized in Table 8-11. For well pads and gathering and boosting
stations, the numbers of new facilities were assumed to be normally distributed across the range of
model plants.
8-16
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Table 8-11. Nationwide Baseline Emissions for New Sources
Oil and Gas Sector
Well Pads
Gathering &
Boosting
Processing
Transmission/Storage
Model Plant
1
2
3
Total
1
2
3
Total
1
1
Number of
New Facilities
605
2,610
605
3,820
44
187
44
275
29
107
TOC
Emissions
(tons/yr)
292
34,687
84,035
119,014
1,312
9,513
3,106
13,931
2,146
11,567
Methane
Emissions
(tons/yr)
203
24,116
58,389
82,708
912
6,618
2,160
9,690
1,490
10,497
voc
Emissions
(tons/yr)
56.3
6,682
16,214
22,952
254
1,835
598
2,687
415
290
HAP
Emissions
(tons/yr)
2.12
252
612
866
9.55
69.2
22.6
101
15.6
8.62
8-17
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8.4 Control Techniques
8.4.1 Potential Control Techniques
EPA has determined that leaking equipment, such as valves, pumps, and connectors, are a significant
source of VOC and HAP emissions from oil and gas facilities. The following section describes the
techniques used to reduce emissions from these sources.
The most effective control technique for equipment leaks is the implementation of a leak detection and
repair program (LDAR). Emissions reductions from implementing an LDAR program can potentially
reduce product losses, increase safety for workers and operators, decrease exposure of hazardous
chemicals to the surrounding community, reduce emissions fees, and help facilities avoid enforcement
actions. The elements of an effective LDAR program include:
• Identifying Components;
• Leak Definition;
• Monitoring Components;
• Repairing Components; and
• Recordkeeping.
The primary source of equipment leak emissions from oil and gas facilities are from valves and
connectors, because these are the most prevalent components and can number in the thousands. 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,
component 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 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
components), sound (such as hissing), and smell.
8-18
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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).
Method 21 is a procedure used to detect VOC leaks from process equipment using toxic vapor analyzer
(TVA) or organic vapor analyzer (OVA). In addition, other monitoring tools such as; infrared camera,
soap solution, acoustic leak detection, and electronic screening device, can be used to monitor process
components.
In optical gas imaging, a live video image is produced by illuminating the view area with laser light in
the infrared frequency range. In this range, hydrocarbons absorb the infrared light and are revealed as a
dark image or cloud on the camera. 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 is easy to use
and very efficient in monitoring many components in a short amount of time. However, the optical
imaging camera cannot quantify the amount or concentration of equipment leak. To quantify the leak,
the user would need to measure the concentration of the leak using a TVA or OVA. In addition, the
optical imaging camera has a high upfront capital cost of purchasing the camera.
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.
Monitoring intervals vary according to the applicable regulation, but are typically weekly, monthly,
quarterly, and yearly. For connectors, the monitoring interval can be every 1, 2, 4, or 8 years. The
monitoring interval depends on the component type and periodic leak rate for the component type. Also,
many LDAR requirements specify weekly visual inspections of pumps, agitators, and compressors for
indications of liquids leaking from the seals. For each component that is found to be leaking, the first
attempt at repair is to be made 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:
• Tightening of bonnet bolts;
8-19
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• Replacement of bonnet bolts;
• Tightening of packing gland nuts; and
• Inj ection of lubricant into lubricated packing.
Once the component is repaired; it should be monitored daily over the next several days to ensure the
leak has been successfully repaired. Another method that can be used to repair component is to replace
the leaking component with "leakless" or other technologies.
The LDAR recordkeeping requirement for each regulated process requires that a list of all ID numbers
be maintained for all equipment subject to an equipment leak regulation. A list of components that are
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, which may include leak monitoring
results per the leak frequency, monitoring leakless equipment, and non-periodic event monitoring.
Other factors that can improve the efficiency of an LDAR program that are not addressed by the
standards 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).
The first LDAR option is the implementation of a subpart VVa LDAR program. This program is similar
to the VV monitoring, but finds more leaks due to the lower leak definition, thereby achieving better
emission reductions. The VVa LDAR program requires the annual monitoring of connectors using an
OVA or TVA (10,000 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 monitoring of each of the equipment types were also analyzed as a possible option
for reducing equipment leak emissions. The second option involves using the monitoring requirements
in subpart VVa for each type of equipment which include: valves; connectors; pressure relief devices;
and open-ended lines for each of the oil and gas sectors.
The thirdoption that was investigated was the implementation of a LDAR program using an optical gas
imaging system. 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 components using the optical gas imaging system and an
8-20
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annual monitoring of all components using a Method 21 monitoring device. The Method 21 monitoring
allows the facility to quantify emissions from equipment leaks, since the optical gas imaging system can
only provide the magnitude of the equipment leaks.
A fourth option that was investigated is a modification of the 40 CFR Part 60, subpart Aalternative work
practice. The alternative work practice was modified by removing the required annual monitoring using
a Method 21 instrument. This option only requires the monthly monitoring of components using the
optical gas imaging system.
8.4.2 Subpart VVa LDAR Program
8.4.2.1 Description
The subpart VVa LDAR 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 parts per million by volume (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
LDAR option and are regulated separately.
8.4.2.2 Effectiveness
The control effectiveness of the 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. A summary of the chemical manufacturing and petroleum refinery control effectiveness for each
of the components is shown in Table 8-12. As shown in the table the control effectiveness for all of the
components varies 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 component is
checked for leaks. For an example, quarterly monitoring requires that each component be
checked for leaks 4 times per year, and annual monitoring requires that each component be
checked for leaks once per year. As shown in Table 8-12, monthly monitoring provides higher
control effectiveness than quarterly
8-21
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Table 8-12. Control Effectiveness for an LDAR program at a Chemical Process Unit
and a Petroleum Refinery
Equipment Type and Service
Control Effectiveness (% Reduction)
Monthly Monitoring
10,000 ppmv
Leak Definition
Quarterly
Monitoring 10,000
ppmv Leak
Definition
500 ppm Leak
Definition8
Chemical Process Unit
Valves - Gas Serviceb
Valves - Light Liquid Service0
Pumps - Light Liquid Servicec
Connectors - All Services
87
84
69
—
67
61
45
—
92
88
75
93
Petroleum Refinery
Valves - Gas Serviceb
Valves - Light Liquid Service0
Pumps - Light Liquid Service0
Connectors - All Services
88
76
68
—
70
61
45
—
96
95
88
81
Source: Protocol for Equipment Leak Emission Estimates, EPA-453/R-95-017, Nov 1995.
a. Control effectiveness attributable to the HON-negotiated equipment leak regulation (40 CFR 63,
Subpart H) is estimated based on equipment-specific leak definitions and performance levels.
However, pumps subject to the HON at existing process units have a 1,000 to 5,000 ppm leak
definition, depending on the type of process.
b. Gas (vapor) service means the material in contact with the equipment component is in a gaseous
state at the process operating conditions.
c. Light liquid service means the material in contact with the equipment component is in a liquid
state in which the sum of the concentration of individual constituents with a vapor pressure
above 0.3 kilopascals (kPa) at 20°C is greater than or equal to 20% by weight.
8-22
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monitoring. This is because leaking components are found and repaired more quickly, which lowers the
amount of emissions that are leaked to the atmosphere.
Leak Definition: The leak definition describes the local VOC concentration at the surface of a
leak source that indicates that a VOC emission (leak) is present. The leak definition is an
instrument meter reading based on a reference compound. Decreasing the leak definition
concentration generally increases the number of leaks found during a monitoring period, which
generally increases the number of leaks that are repaired.
The control effectiveness for the well pad, gathering and boosting stations, processing facilities, and
transmissions and storage facilities were calculated using the LDAR control effectiveness and leak
fraction equations for oil and gas production operation units in the EPA equipment leaks protocol
document. The leak fraction equation uses the average leak rate (e.g., the component emission factor)
and leak definition to calculate the leak fraction.7 This leak fraction is used in a steady state set of
o
equations to determine the final leak rate after implementing a LDAR program. The initial leak rate and
the final leak rate after implementing a LDAR program were then used to calculate the control
effectiveness of the program. The control effectiveness for implementing a subpart VVa LDAR program
was calculated to be 93.6 perccent for valves, 95.9 percent for connectors, 100 percent for open-ended
lines, and 100 percent for pressure relief devices.
8.4.2.3 Cost Impacts
Costs were calculated using a LDAR cost spreadsheet developedfor estimating capital and annual costs
for applying LDAR to the Petroleum Refinery and Chemical Manufacturing industry. The costs are
based on the following assumptions:
• Subpart VVa monitoring frequency and leak definition were used for processing plants since
they are already required to do subpart VV requirements. Connectors were assumed to be
monitored over a 4-year period after initial annual compliance monitoring.
• Initial monitoring and setup costs are $17.70 for valves, $1.13 per connector, $78.00 for pressure
relief valve disks, $3,852 for pressure relief valve disk holder and valves, and $102 for open-
ended lines.
• Subsequent monitoring costs are $1.50 for valves and connectors, $2.00 for pressure relief valve
disks, and $5.00 for pressure relief valve devices and open-ended lines.
• A wage rate of $30.46 per hour was used to determine labor costs for repair.
8-23
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• Administrative costs and initial planning and training costs are based on the Miscellaneous
Organic NESHAP (MON) analysis. The costs were based on 340 hours for planning and training
and 300 hours per year for reporting and administrative tasks at $48.04 per hour.
• The capital cost also includes $14,500 for a data collection system for maintaining the inventory
and monitoring records for the components at a facility.
• Recovery credits were calculated assuming the methane reduction has a value of $4.00 per 1000
standard cubic feet.
It was assumed that a single Method 21 monitoring device could be used at multiple locations for
production pads, gathering and boosting stations, and transmission and storage facilities. To calculate
the shared cost of the Method 21 device, the time required to monitor a single facility was estimated. For
production pads and gathering and boosting stations, it was assumed that it takes approximately 1
minute to monitor a single component, and approximately 451 components would have to be monitored
at an average facility in a month. This calculates to be 451 minutes or 7.5 hours per day. Assuming 20
working days in a typical month, a single Method 21 device could monitor 20 facilities. Therefore, the
capital cost of the Method 21 device ($6,500) was divided by 20 to get a shared capital cost of $325 per
facility. It was assumed for processing facilities that the full cost of the Method 21 monitoring device
would apply to each individual plant. The transmission and storage segment Method 21 device cost was
estimated using assuming the same 1 minute per component monitoring time. The average number of
components that would need to be monitored in a month was estimated to be 1,440, which calculates to
be 24 hours of monitoring time or 3 days. Assuming the same 20 day work month, the total number of
facilities that could be monitored by a single Method 21 device is 7. Therefore, the shared cost of the
Method 21 monitoring device was calculated to be $929 per site.
A summary of the capital and annual costs and the cost effectiveness for each of the model plants in the
oil and gas sectors are provided in Table 8-13. In addition to the full subpart VVa LDAR monitoring, a
component by component LDAR analysis was performed for each of the oil and gas sectors using the
component count for an average size facility. This Model Plant 2 for well pads, Model Plant 2 for
gathering and boosting stations, and Model Plant 1 for processing plants and transmission and storage
facilities.
8-24
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Table 8-13. Summary of the Model Plant Cost Effectiveness for the Subpart Wa Option
Model Plant
Annual Emission Reductions
(tons/year)
voc
HAP
Methane
Capital
Cost ($)
Annual Cost
($/year)
without
savings
with savings
Cost Effectiveness
($/ton)
VOC
HAP
Methane
Well Pads
1
2
3
0.0876
2.43
25.3
0.00330
0.0915
0.956
0.315
8.73
91.3
$15,418
$69,179
$584,763
$23,423
$37,711
$175,753
$23,350
$35,687
$154,595
$267,386
$15,549
$6,934
$7,088,667
$412,226
$183,835
$74,253
$4,318
$1,926
Gathering and Boosting Stations
1
2
3
5.58
9.23
12.9
0.210
0.348
0.486
20.1
33.2
46.4
$148,885
$255,344
$321,203
$57,575
$84,966
$105,350
$52,921
$77,259
$94,591
$10,327
$9,203
$8,174
$273,769
$243,987
$216,692
$2,868
$2,556
$2,270
Processing Plants
1
13.5
0.508
48.5
$7,522
$45,160
$33,915
$3,352
$88,870
$931
Transmission/Storage Facilities
1
2.62
0.0780
94.9
$94,482
$51,875
N/A
$19,769
$665,155
$546
Note: Transmission and storage facilities do not own the natural gas; therefore they do not receive any cost benefits from reducing the amount
of natural gas as the result of equipment leaks.
8-25
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The component costs were calculated using a LDAR cost spreadsheet developedfor estimating capital
and annual costs for applying LDAR to the Petroleum Refinery and Chemical Manufacturing industry.
The costs are based on the following assumptions:
• Initial monitoring and setup costs are $17.70 for valves, $1.13 per connector, $78.00 for pressure
relief valve disks, $3,852 for pressure relief valve disk holder and valves, and $102 for open-
ended lines.
• Subsequent monitoring costs are $1.50 for valves and connectors, $2.00 for pressure relief valve
disks, and $5.00 for pressure relief valve devices and open-ended lines.
• A wage rate of $30.46 per hour was used to determine labor costs for repair.
• Administrative costs and initial planning and training costs are were included for the component
option and are based on the Miscellaneous Organic NESHAP (MON) analysis. The costs were
based on 340 hours for planning and training and 300 hours per year for reporting and
administrative tasks at $48.04 per hour.
• The capital cost for purchasing a TVA or OVA monitoring system was estimated to be $6,500.
The component control effectiveness for the subpart VVa component option were 93.6 percent for
valves, 95.9 percent for connectors, 100 percent for open-ended lines, and 100 percent for pressure relief
devices. These were the same control effectiveness's that were used for the subpart VVa facility option.
The control effectiveness for the modified subpart VVa option with less frequent monitoring was
estimated assuming the control effectiveness follows a hyperbolic curve or a 1/x relationship with the
monitoring frequency. Using this assumption the component cost effectiveness's were determined to be
87.2 percent for valves, 81.0 percent for connectors, 100 percent for open-ended lines, and 100 percent
for pressure relief devices. The assumption is believed to provide a conservative estimate of the control
efficiency based on less frequent monitoring. A summary of the capital and annual costs and the cost
effectiveness for each of the components for each of the oil and gas sectors are provided in Tables 8-14,
8-15, 8-16, and 8-17.
8.4.2.4 Secondary Impacts
The implementation of a LDAR program reduces pollutant emissions from equipment leaks. No
secondary gaseous pollutant emissions or wastewater are generated during the monitoring and repair of
equipment leaks. Therefore, there are no secondary impacts expected from the implementation of a
LDAR program.
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Table 8-14. Summary of Component Cost Effectiveness for Well Pads for the Subpart Wa Options
Component
Average
Number of
Components
Monitoring
Frequency
(Times/yr)
Annual Emission Reductions
(tons/year)
voc
HAP
Methane
Capital
Cost ($)
Annual
Cost
($/yr)
Cost-effectiveness
($/ton)
VOC
HAP
Methane
Subpart Wa Option
Valves
Connectors
PRO
OEL
235
863
10
29
12
l/0.25a
0
0
1.84
0.308
0.164
0.108
0.0696
0.0116
0.00619
0.00408
6.64
1.11
0.591
0.389
$11,175
$7,830
$48,800
$9,458
$27,786
$22,915
$29,609
$22,915
$15,063
$74,283
$180,537
$211,992
$399,331
$1,969,328
$4,786,215
$5,620,108
$4,183
$20,628
$50,135
$58,870
Modified Subpart Wa- Less Frequent Monitoring
Valves
Connectors
PRO
OEL
235
863
5
29
1
l/0.125b
0
0
1.31
0.261
0.164
0.108
0.0496
0.00983
0.00619
0.00408
4.73
0.938
0.591
0.389
$11,175
$7,830
$48,800
$9,458
$23,436
$22,740
$29,609
$22,915
$17,828
$87,277
$180,537
$211,992
$472,640
$2,313,795
$4,786,215
$5,620,108
$4,951
$24,237
$50,135
$58,870
Minor discrepancies may be due to rounding.
a. It was assumed that all the connectors are monitored in the first year for initial compliance and every 4 years thereafter.
b. It was assumed that all the connectors are monitored in the first year for initial compliance and every 8 years thereafter.
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Table 8-15. Summary of Component Cost Effectiveness for Gathering and Boosting Stations for the Subpart Wa Options
Component
Average
Number of
Components
Monitoring
Frequency
(Times/yr)
Annual Emission Reductions
(tons/year)
voc
HAP
Methane
Capital
Cost ($)
Annual
Cost
($/yr)
Cost-effectiveness
($/ton)
VOC
HAP
Methane
Subpart Wa Option
Valves
Connectors
PRO
DEL
906
2,864
48
83
12
1/0.253
0
0
7.11
1.02
0.787
0.309
0.268
0.0386
0.0297
0.0117
25.6
3.69
2.83
1.11
$24,524
$10,914
$195,140
$14,966
$43,234
$24,164
$57,091
$23,917
$6,079
$23,603
$72,523
$77,310
$161,162
$625,752
$1,922,648
$2,049,557
$1,688
$6,555
$20,139
$21,469
Modified Subpart Wa - Less Frequent Monitoring
Valves
Connectors
PRO
DEL
906
2,864
48
83
1
l/0.125b
0
0
5.07
0.865
0.787
0.309
0.191
0.0326
0.0297
0.0117
18.2
3.11
2.83
1.11
$24,524
$10,914
$195,140
$14,966
$24,461
$23,584
$57,091
$23,917
$5,221
$27,274
$72,523
$77,310
$138,417
$723,067
$1,922,648
$2,049,557
$1,450
$7,574
$20,139
$21,469
Minor discrepancies may be due to rounding.
a. It was assumed that all the connectors are monitored in the first year for initial compliance and every 4 years thereafter.
b. It was assumed that all the connectors are monitored in the first year for initial compliance and every 8 years thereafter.
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Table 8-16. Summary of Incremental Component Cost Effectiveness for Processing Plants for the Subpart Wa Option
Component
Average
Number of
Components
Monitoring
Frequency
(Times/yr)
Annual Emission Reductions
(tons/year)
voc
HAP
Methane
Capital
Cost ($)
Annual
Cost
($/yr)
Cost-effectiveness
($/ton)
VOC
HAP
Methane
Incremental Component Cost for Subpart W to Subpart Wa Option
Valves
Connectors
PRO
OEL
1,392
4,392
29
134
12
1/0.253
0
0
10.9
1.57
0.499
0.476
0.412
0.0592
0.0188
0.0179
39.3
5.65
1.80
1.71
$6,680
$2,559
$0
$0
$1,576
$6,845
$0
$0
$144
$4,360
$0
$0
$3,824
$115,585
$0
$0
$40
$1,211
$0
$0
Minor discrepancies may be due to rounding.
a. It was assumed that all the connectors are monitored in the first year for initial compliance and every 4 years thereafter.
8-29
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Table 8-17. Summary of Component Cost Effectiveness for Transmission and Storage Facilities for the Subpart Wa Options
Component
Average
Number of
Components
Monitoring
Frequency
(Times/yr)
Annual Emission Reductions
(tons/year)
voc
HAP
Methane
Capital
Cost ($)
Annual
Cost ($/yr)
Cost-effectiveness
($/ton)
VOC
HAP Methane
Subpart Wa Option
Valves
Connectors
PRO
OEL
673
3,068
14
58
12
1/0.253
0
0
0.878
0.665
0.133
0.947
0.0261
0.0198
0.00397
0.0282
31.8
24.1
4.83
34.3
$19,888
$11,229
$61,520
$12,416
$37,870
$24,291
$32,501
$23,453
$43,111
$36,527
$243,525
$24,762
$1,450,510
$1,229,005
$8,193,684
$833,137
$1,192
$1,010
$6,732
$684
Modified Subpart Wa - Less Frequent Monitoring
Valves
Connectors
PRO
OEL
673
3,068
14
58
1
l/0.125b
0
0
0.626
0.562
0.133
0.947
0.0186
0.0167
0.00397
0.0282
22.6
20.3
4.83
34.3
$19,888
$11,229
$61,520
$12,416
$25,410
$23,669
$32,501
$23,453
$40,593
$42,140
$243,525
$24,762
$1,365,801
$1,417,844
$8,193,684
$833,137
$1,122
$1,165
$6,732
$684
Minor discrepancies may be due to rounding.
a. It was assumed that all the connectors are monitored in the first year for initial compliance and
b. It was assumed that all the connectors are monitored in the first year for initial compliance and
every 4 years thereafter.
every 8 years thereafter.
8-30
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8.4.3 LDAR with Optical Gas Imaging
8.4.3.1 Description
The alternative work practice for equipment leaks in §60.18 of 40 CFR Part 60, subpart A allows the use
of an optical gas imaging system to monitor leaks from components. This LDAR requires monthly
monitoring and repair of components using an optical gas imaging system, and annual monitoring of
components using a Method 21 instrument. This requirement does not have a leak definition because the
optical gas imaging system can only measure the magnitude of a leak and not the concentration.
However, this alternative work practice does not require the repair of leaks below 500 ppm.
Compressors are not included in this LDAR option and arediscussed in Chapter 6 of this document.
8.4.3.2 Effectiveness
No data was found on the control effectiveness of the alternative work practice. It is believed that this
option would provide the same control effectiveness as the subpart VVa monitoring program. Therefore,
the control effectiveness's for implementing an alternative work practice was 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.
8.4.3.3 Cost Impacts
Costs were calculated using a LDAR cost spreadsheet developedfor estimating capital and annual costs
for applying LDAR to the Petroleum Refinery and Chemical Manufacturing industry. The costs are
based on the following assumptions:
• Initial monitoring and setup costs are $17.70 for valves, $1.13 per connector, $78.00 for pressure
relief valve disks, $3,852 for pressure relief valve disk holder and valves, and $102 for open-
ended lines.
• Monthly optical gas imaging monitoring costs are estimated to be $0.50 for valves, connectors,
pressure relief valve devices, and open-ended lines.
• Annual monitoring costs using a Method 21 device are estimated to be $1.50 for valves and
connectors, $2.00 for pressure relief valve disks, and $5.00 for pressure relief devices and open-
ended lines.
• A wage rate of $30.46 per hour was used to determine labor costs for repair.
8-31
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• Administrative costs and initial planning and training costs are based on the Miscellaneous
Organic NESHAP (MON) analysis. The costs were based on 340 hours for planning and training
and 300 hours per year for reporting and administrative tasks at $48.04 per hour.
• The capital cost also includes $14,500 for a data collection system for maintaining the inventory
and monitoring records for the components at a facility.
• Recovery credits were calculated assuming the methane reduction has a value of $4.00 per 1000
standard cubic feet.
It was assumed that a single optical gas imaging and a Method 21 monitoring device could be used at
multiple locations for production pads, gathering and boosting stations, and transmission and storage
facilities. To calculate the shared cost of the optical gas imaging system and the Method 21 device, the
time required to monitor a single facility was estimated. For production pads and gathering and boosting
stations, it was assumed that 8 production pads could be monitored per day. This means that 160
production facilities could be monitored in a month. In addition, it was assumed 13 gathering and
boosting station would service these wells and could be monitored during the same month for a total of
173 facilities. Therefore, the capital cost of the optical gas imaging system (Flir Model GF320, $85,000)
and the Method 21 device ($6,500) was divided by 173 to get a shared capital cost of $529 per facility. It
was assumed for processing facilities that the full cost of the optical gas imaging system and the Method
21 monitoring device would apply to each individual plant. The transmission and storage segment
Method 21 device cost was estimated assuming that one facility could be monitored in one hour, and the
travel time between facilities was one hour. Therefore, in a typical day 4 transmission stations could be
monitored in one day. Assuming the same 20 day work month, the total number of facilities that could
be monitored by a single optical gas imaging system and Method 21 device is 80. Therefore, the shared
cost of the Method 21 monitoring device was calculated to be $1,144 per site.
A summary of the capital and annual costs and the cost effectiveness for each of the model plants in the
oil and gas sectorusing the alternative work practice monitoring is provided in Table 8-18. A component
cost effectiveness analysis for the alternative work practice was not performed, because the optical gas
imaging system is not conducive to component monitoring, but is intended for facility-wide monitoring.
8.4.3.4 Secondary Impacts
The implementation of a LDAR program reduces pollutant emissions from equipment leaks. No
secondary gaseous pollutant emissions or wastewater are generated during the monitoring and repair of
8-32
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Table 8-18. Summary of the Model Plant Cost Effectiveness for the Optical Gas Imaging and Method 21 Monitoring Option
Model Plant
Annual Emission Reductions (tons/year)
VOC
HAP
Methane
Capital
Cost ($)
Annual Cost
($/year)
without
savings
with savings
Cost Effectiveness
( $/ton)
VOC
HAP
Methane
Well Pads
1
2
3
0.0876
2.43
25.3
0.00330
0.0915
0.956
0.315
8.73
91.3
$15,428
$64,858
$132,891
$21,464
$39,112
$135,964
$21,391
$37,088
$114,807
$245,024
$16,127
$5,364
$6,495,835
$427,540
$142,216
$68,043
$4,478
$1,490
Gathering and Boosting Stations
1
2
3
5.58
9.23
12.9
0.210
0.348
0.486
20.1
33.2
46.4
$149,089
$240,529
$329,725
$63,949
$93,210
$121,820
$59,295
$85,503
$111,060
$11,470
$10,096
$9,451
$304,078
$267,659
$250,567
$3,185
$2,804
$2,625
Processing Plants
1
13.5
0.508
48.5
$92,522
$87,059
$75,813
$6,462
$171,321
$1,795
Transmission/Storage Facilities
1
2.62
0.0780
94.9
$20,898
$51,753
N/A
$19,723
$663,591
$545
Minor discrepancies may be due to rounding.
Note: Transmission and storage facilities do not own the natural gas; therefore cost benefits from reducing the amount of natural
gas as the result of equipment leaks was not estimated for the transmission segment..
8-33
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equipment leaks. Therefore, there are no secondary impacts expected from the implementation of a
LDAR program.
8.4.4 Modified Alternative Work Practice with Optical Gas Imaging
8.4.4.1 Description
The modified alternative work practice for equipment leaks in §60.18 of 40 CFR Part 60, subpart A
allows the use of an optical gas imaging system to monitor leaks from components, but removes the
requirement of the annual Method 21 device monitoring. Therefore, the modified work practice would
require only monthly monitoring and repair of components using an optical gas imaging system. This
requirement does not have a leak definition because the optical gas imaging system can only measure
the magnitude of a leak and not the concentration. However, this alternative work practice does not
require the repair of leaks below 500 ppm. Compressors are not included in this LDAR option and are
regulated separately.
8.4.4.2 Effectiveness
No data was found on the control effectiveness of this modified alternative work practice. However, it is
believed that this option would provide the similar control effectiveness and emission reductions as the
subpart VVa monitoring program. Therefore, the control effectiveness's for implementing an alternative
work practice was 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.
8.4.4.3 Cost Impacts
Costs were calculated using a LDAR cost spreadsheet developedfor estimating capital and annual costs
for applying LDAR to the Petroleum Refinery and Chemical Manufacturing industry. The costs are
based on the following assumptions:
• Initial monitoring and setup costs are $17.70 for valves, $1.13 per connector, $78.00 for pressure
relief valve disks, $3,852 for pressure relief valve disk holder and valves, and $102 for open-
ended lines.
• Monthly optical gas imaging monitoring costs are estimated to be $0.50 for valves, connectors,
pressure relief valve devices, and open-ended lines.
• A wage rate of $30.46 per hour was used to determine labor costs for repair.
8-34
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• Administrative costs and initial planning and training costs are based on the Miscellaneous
Organic NESHAP (MON) analysis. The costs were based on 340 hours for planning and training
and 300 hours per year for reporting and administrative tasks at $48.04 per hour.
• The shared capital cost for optical gas imaging system is $491 for production and gathering and
boosting, $85,000 for processing, and $1,063 for transmission for a FLIR Model GF320 optical
gas imaging system.
• The capital cost also includes $14,500 for a data collection system for maintaining the inventory
and monitoring records for the components at a facility.
• Recovery credits were calculated assuming the methane reduction has a value of $4.00 per 1000
standard cubic feet.
A summary of the capital and annual costs and the cost effectiveness for each of the model plants in the
oil and gas sectors using the alternative work practice monitoring is provided in Table 8-19. A
component cost effectiveness analysis for the alternative work practice was not performed, because the
optical gas imaging system is not conducive to component monitoring, but is intended for facility-wide
monitoring.
8.4.4.4 Secondary Impacts
The implementation of a LDAR program reduces pollutant emissions from equipment leaks. No
secondary gaseous pollutant emissions or wastewater are generated during the monitoring and repair of
equipment leaks. Therefore, there are no secondary impacts expected from the implementation of a
LDAR program.
8.5 Regulatory Options
The LDAR pollution prevention approach is believed to be the best method for reducing pollutant
emissions from equipment leaks. Therefore, the following regulatory options were considered for
reducing equipment leaks from well pads, gathering and boosting stations, processing facilities, and
transmission and storage facilities:
• Regulatory Option 1: Require the implementation of a subpart VVa LDAR program;
• Regulatory Option 2: Require the implementation of a component subpart VVa LDAR program;
• Regulatory Option 3: Require the implementation of the alternative work practice in §60.18 of
40 CFR Part 60;
8-35
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Table 8-19. Summary of the Model Plant Cost Effectiveness for Monthly Gas Imaging Monitoring
Model
Plant
Annual Emission Reductions
(tons/year)
voc
HAP
Methane
Capital
Cost ($)
Annual Cost
($/year)
without
savings
with
savings
Cost Effectiveness
( $/ton)
VOC
HAP
Methane
Well Pads
1
2
O
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
$15,390
$64,820
$537,313
$21,373
$37,049
$189,174
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Gathering and Boosting Stations
1
2
3
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
$149,051
$240,491
$329,687
$59,790
$86,135
$11,940
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Processing Plants
1
N/A
N/A
N/A
$92,522
$76,581
N/A
N/A
N/A
N/A
Transmission/Storage Facilities
1
N/A
N/A
N/A
$20,817
$45,080
N/A
N/A
N/A
N/A
Note: This option only provides the number and magnitude of the leaks. Therefore, the emission reduction from this program cannot
be quantified and the cost effectiveness values calculated.
8-36
-------
• Regulatory Option 4: Require the implementation of a modified alternative work practice in
§60.18 of 40 CFR Part 60 that removes the requirement for annual monitoring using a Method
21 device.
The following sections discuss these regulatory options.
8.5.1 Evaluation of Regulatory Options for Equipment Leaks
8.5.1.1 Well pads
The first regulatory option of a subpart VVa LDAR program was evaluated for well pads, which include
the wells, processing equipment (separators, dehydrators, acid gas removal), as well as any heaters and
piping. The equipment does not include any of the compressors which will be regulated separately. For
well pads the VOC cost effectiveness for the model plants ranged from $267,386 per ton of VOC for a
single well head facility to $6,934 ton of VOC for a well pad servicing 48 wells. Because of the high
VOC cost effectiveness, Regulatory Option 1 was rejected for well pads.
The second regulatory option that was evaluated for well pads was Regulatory Option 2, which would
require the implementation of a component subpart VVa LDAR program. The VOC cost effectiveness
of this option ranged from $15,063 for valves to $211,992 for open-ended lines. These costs were
determined to be unreasonable and therefore this regulatory option was rejected.
The third regulatory option requires the implementation of a monthly LDAR program using an Optical
gas imaging system with annual monitoring using a Method 21 device. The VOC cost effectiveness of
this option ranged from $5,364 per ton of VOC for Model Plant 3to $245,024 per ton of VOC for Model
Plant 1. This regulatory option was determined to be not cost effective and was rejected.
The fourth regulatory option would require the implementation of a monthly LDAR program using an
optical imaging instrument. The emission reductions from this option could not be quantified; therefore
this regulatory option was rejected.
8.5.1.2 Gathering and Boosting Stations
The first regulatory option was evaluated for gathering and boosting stations which include the
processing equipment (separators, dehydrators, acid gas removal), as well as any heaters and piping. The
equipment does not include any of the compressors which will be regulated separately. The VOC cost
effectiveness for the gathering and boosting model plants ranged from $10,327 per ton of VOC for
8-37
-------
Model Plant 1 to $8,174per ton of VOC for Model Plant 3. Regulatory Option 1 was rejected due to the
high VOC cost effectiveness.
The second regulatory option that was evaluated for gathering and boosting stations was Regulatory
Option 2. The VOC cost effectiveness of this option ranged from $6,079 for valves to $77,310 per ton of
VOC for open-ended lines. These costs were determined to be unreasonable and therefore this
regulatory option was also rejected.
The third regulatory option requires the implementation of a monthly LDAR program using an Optical
gas imaging system with annual monitoring using a Method 21 device. The VOC cost effectiveness of
this option was calculated to be $10,724 per ton of VOC for Model Plant 1 and $8,685 per ton of VOC
for Model Plant 3. This regulatory option was determined to be not cost effective and was rejected.
The fourth regulatory option would require the implementation of a monthly LDAR program using an
optical imaging instrument. The emission reductions from this option could not be quantified; therefore
this regulatory option was rejected.
8.5.1.3 Processing Plants
The VOC cost effectiveness of the first regulatory option was calculated to be $3,352 per ton of VOC.
This cost effectiveness was determined to be reasonable and therefore this regulatory option was
accepted.
The second option was evaluated for processing plants and the VOC cost effectiveness ranged from $0
for open-ended lined and pressure relief devices to $4,360 for connectors. Because the emission benefits
and the cost effectiveness of Regulatory Option 1 were accepted, this option was not accepted.
The third regulatory option requires the implementation of a monthly LDAR program using an Optical
gas imaging system with annual monitoring using a Method 21 device. The VOC cost effectiveness of
this option was calculated to be $6,462 per ton of VOC and was determined to be not cost effective.
Therefore, this regulatory option was rejected.
The fourth regulatory option would require the implementation of a monthly LDAR program using an
optical imaging instrument. The emission reductions from this option could not be quantified; therefore
this regulatory option was rejected.
8.5.1.4 Transmission and Storage Facilities
8-38
-------
The first regulatory option was evaluated for transmission and storage facilities which include separators
and dehydrators, as well as any heaters and piping. The equipment does not include any of the
compressors which will be regulated separately. This sector moves processed gas from the processing
facilities to the city gates. The VOC cost effectiveness for Regulatory Option 1 was $19,769per ton of
VOC. The high VOC cost effectiveness is due to the inherent low VOC concentration in the processed
natural gas, therefore the VOC reductions from this sector are low in comparison to the other sectors.
Regulatory Option 1 was rejected due to the high VOC cost effectiveness.
The second option was evaluated for transmission facilities and the VOC cost effectiveness ranged from
$24,762 for open-ended lined to $243,525 for connectors. This option was not accepted because of the
high cost effectiveness.
The third regulatory option that was evaluated for transmission and storage facilities was Regulatory
Option 3. The VOC cost effectiveness of this option was calculated to be $19,723 per ton of VOC.
Again, because of the low VOC content of the processed gas, the regulatory option has a low VOC
reduction. This cost was determined to be unreasonable and therefore this regulatory option was also
rejected.
The fourth regulatory option would require the implementation of a monthly LDAR program using an
optical imaging instrument. The emission reductions from this option could not be quantified; therefore
this regulatory option was rejected.
8.5.2 Nationwide Impacts of Regulatory Options
Regulatory Option 1 was selected as an option for setting standards for equipment leaks at processing
plants. This option would require the implementation of an LDAR program using the subpart VVa
requirements. For production facilities, 29 facilities per year are expected to be affected sources by the
NSPS regulation annually. Table 8-20 provides a summary of the expected emission reductions from the
implementation of this option.
8-39
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Table 8-20. Nationwide Emission and Cost Analysis of Regulatory Options
Category
Estimated
Number of
Sources
subject to
NSPS
Facility
Capital
Cost ($)
Nationwide Emission
Reductions (tpy)
VOC
Methane
HAP
VOC Cost
Effectiveness
($/ton)
without
savings
with
savings
Methane Cost
Effectiveness
($/ton)
without
savings
with
savings
Total Nationwide Costs
(million $/year)
Capital
Cost
Annual
without
savings
Annual
with
savings
Regulatory Option 2 (Subpart VVa LDAR Program)
Processing
Plants
29
$7,522
392
1,407
14.7
$3,352
$2,517
$931
$699
0.218
1.31
0.984
8-40
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8.6 References
1 Memorandum from David Randall, RTI and Karen Schaffner, RTI to Randy McDonald,
U.S. Environmental Protection Agency. Control Options and Impacts for Equipment
Leaks: Chemical Manufacturing Area Source Standards. September 2, 2008.
2 Memorandum from Kristen Parrish, RTI and David Randall, RTI to Karen Rackley, U.S.
Environmental Protection Agency.Final Impacts for Regulatory Options for Equipment
Leaks of VOC on SOCMI. October 30, 2007.
3 Memorandum from Kristen Parrish, RTI, David Randall, RTI, and Jeff Coburn, RTI to
Karen Rackley, U.S. Environmental Protection Agency.Final Impacts for Regulatory
Options for Equipment Leaks of VOC in Petroleum Refineries. October 30, 2007.
4 U.S. Environmental Protection Agency. Methodology for Estimating CH4 and CO2
Emissions from Petroleum Systems. Greenhouse Gas Inventory: Emission and
Sinksl990-2008. Washington, DC.
5 Radian International LLC.Methane Emissions from the Natural Gas Industry, Vol. 2:
Technical Report. Prepared for the Gas Research Institute and Environmental Protection
Agency .EPA-600/R-96-080b.June 1996.
6 Radian International LLC.Methane Emissions from the Natural Gas Industry, Vol. 3:
General Methodology. Prepared for the Gas Research Institute and Environmental
Protection Agency.EPA-600/R-96-080c.June 1996.
7 Radian International LLC.Methane Emissions from the Natural Gas Industry, Vol. 5:
Activity Factors. Prepared for the Gas Research Institute and Environmental Protection
Agency.EPA-600/R-96-080e.June 1996
8 Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 5:
Activity Factors. Prepared for the Gas Research Institute and Environmental Protection
Agency.EPA-600/R-96-080e.June 1996
9 Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 6:
Vented and Combustion Source Summary Emissions. Prepared for the Gas Research
Institute and Environmental Protection Agency.EPA-600/R-96-080f. June 1996.
10 Radian International LLC, Methane Emissions from the U.S. Petroleum Industry, draft
report for the U.S. Environmental Protection Agency, June 14, 1996.
11 ICF Consulting. Estimates of Methane Emissions from the U.S. Oil Industry.Prepared for
the U.S. Environmental Protection Agency. 1999.
12 ENVIRON International Corporation. Oil and Gas Emission Inventories for the Western
States.Prepared for Western Governors' Association. December 27, 2005.
8-41
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13 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
14 Independent Petroleum Association of America. Oil and Gas Producing Industry in Your
State.
15 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.
16 Eastern Research Group, Inc. Emissions from Oil and Gas Production Facilities. Prepared
for the Texas Commission on Environmental Quality. August 31, 2007.
17 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
18 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.
8-42
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APPENDIX A
E&P TANKS ANALYSIS FOR STORAGE VESSELS
-------
Tank ID
E&P Tank Number
Total Emissions (tpy)
VOC Emissions (tpy)
Methane Emissions (tpy)
HAP Emissions (tpy)
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Separator Pressure (psig)
Separator Temperature (F)
Ambient Pressure (psia)
Ambient Temperature (F)
C10+ SG
C10+ MW
API Gravity
Production Rate (bbl/day)
Reid Vapor Pressure (psia)
GOR (scf/bbl)
Heating Value of Vapor (Btu/s
LP Oil Component
H2S
O2
CO2
N2
Cl
C2
C3
i-C4
n-C4
i-C5
n-C5
C6
C7
C8
C9
C10+
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Sample Tank No. 1
Tank No. 58
289.778
43.734
0.197
4.236
0.828
1.194
0.041
0.165
2.008
0.000
66
83
14.7
83
0.848
234
40.0
500
3.00
25.96
398.80
mol%
0.0000
0.0000
5.0200
0.0000
0.0100
0.0400
0.2000
0.2800
0.4800
0.7600
0.7400
1.5100
4.6600
6.6100
4.8700
70.1100
0.5700
2.1400
0.1700
0.7600
1.0700
0.0000
100.0000
Sample Tank No. 2
Tank No. 59
230.196
111.414
56.006
13.100
6.343
3.539
0.083
0.327
2.809
0.000
66
90
14.7
90
0.865
237
40.0
500
4.10
30.32
1689.70
0.0000
0.0000
0.2700
0.0100
2.2600
1.2000
1.3200
0.7100
1.0800
1.2000
1.1300
2.0000
6.7600
9.4200
6.5600
49.2600
4.9100
7.7900
0.4600
2.0500
1.6100
0.0000
100.0000
Sample Tank No. 3
Tank No. 60
129.419
101.853
10.064
5.050
0.501
0.648
0.040
0.233
3.623
0.000
13
110
14.7
110
0.879
294
40.0
500
4.80
12.30
2486.42
0.0000
0.0000
0.0000
0.0000
0.4700
0.4800
1.5800
0.6200
2.6100
1.8100
2.9300
3.8800
10.7300
12.5300
6.9400
47.3100
0.5800
1.9900
0.2900
1.9000
3.3500
0.0000
100.0000
Sample Tank No. 4
Tank No. 61
129.853
63.343
50.910
2.730
0.285
0.243
0.008
0.066
2.132
0.000
64
74
14.7
74
0.866
301
40.0
500
3.90
19.58
1567.19
0.0000
0.0000
0.0800
0.0200
2.6500
0.3900
0.9200
0.9800
1.4700
2.0500
2.1600
3.4500
7.9400
9.6900
6.5600
56.3900
0.4300
1.1000
0.1000
0.9000
2.7200
0.0000
100.0000
Sample Tank No. 5
Tank No. 62
201.547
154.313
8.343
3.500
0.051
0.067
0.002
0.046
3.333
0.000
28
78
14.7
78
0.864
281
42.0
500
4.20
19.68
2261.27
0.0000
0.0000
0.0400
0.3100
0.4000
0.6500
1.7500
0.9200
2.4500
2.3900
2.9500
2.7600
10.8800
11.6400
6.1800
52.0200
0.0700
0.2700
0.0200
0.5500
3.7500
0.0000
100.0000
Sample Tank No. 6
Tank No. 63
738.511
578.379
47.831
37.840
7.568
5.950
0.086
0.679
23.553
0.000
95
118
14.7
118
0.862
312
42.0
500
8.10
68.74
2529.29
0.0000
0.0000
0.0000
0.0200
2.2500
3.1100
4.1100
1.3300
3.8100
2.5400
3.5100
3.0900
8.0100
7.6800
4.4400
47.6400
1.3400
2.6800
0.0900
0.8000
3.5500
0.0000
100.0000
Sample Tank No. 7
Tank No. 64
294.500
205.794
26.305
4.480
0.116
0.085
0.006
0.018
4.252
0.000
29
60
14.7
60
0.841
224
44.0
500
5.70
32.46
2162.56
0.0000
0.0000
0.0100
0.0200
1.1300
1.4100
3.2900
0.4500
4.0200
0.7000
4.0700
0.9600
5.5900
5.5200
4.2700
63.0500
0.1600
0.3700
0.0700
0.2500
4.6600
0.0000
100.0000
Sample Tank No. 8
Tank No. 65
142.371
89.728
24.276
2.680
0.219
0.301
0.020
0.152
1.989
0.000
44
71
14.7
71
0.849
349
44.0
500
7.00
16.92
2003.83
0.0000
0.0000
0.0200
0.0100
1.2900
1.0300
2.3000
1.1200
3.2200
2.3600
2.9600
3.0600
9.5000
11.5900
6.3200
47.7200
0.3600
1.4900
0.2600
2.2900
3.1000
0.0000
100.0000
-------
Tank ID
E&P Tank Number
Total Emissions (tpy)
VOC Emissions (tpy)
Methane Emissions (tpy)
HAP Emissions (tpy)
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Separator Pressure (psig)
Separator Temperature (F)
Ambient Pressure (psia)
Ambient Temperature (F)
C10+ SG
C10+ MW
API Gravity
Production Rate (bbl/day)
Reid Vapor Pressure (psia)
GOR (scf/bbl)
Heating Value of Vapor (Btu/s
LP Oil Component
H2S
O2
CO2
N2
Cl
C2
C3
i-C4
n-C4
i-C5
n-C5
C6
C7
C8
C9
C10+
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Sample Tank No. 9
Tank No. 66
357.688
243.348
56.846
5.590
0.244
0.440
0.039
0.208
4.661
0.000
60
60
14.7
60
0.878
270
44.0
500
10.10
41.30
2060.54
0.0000
0.0000
0.0500
0.0000
2.3400
1.5600
3.8500
1.3600
3.9600
3.1300
4.0300
3.6100
7.7900
13.7700
4.8300
42.2300
0.2400
1.3400
0.3200
1.9700
3.6200
0.0000
100.0000
Sample Tank No. 10
Tank No. 67
134.789
79.118
37.876
5.680
1.308
1.184
0.029
0.488
2.671
0.000
41
72
14.7
72
0.854
270
45.0
500
5.20
17.66
1812.87
0.0000
0.0000
0.0400
0.0100
1.8400
0.6100
1.2700
0.8900
1.5600
1.8000
1.8800
3.4300
10.7400
12.6900
7.8700
43.0100
1.5600
3.8100
0.2200
4.1900
2.5800
0.0000
100.0000
Sample Tank No. 11
Tank No. 68
314.446
224.158
18.892
7.030
0.242
0.385
0.043
0.167
6.191
0.000
20
68
14.7
68
0.926
290
45.0
500
8.10
30.80
2234.66
0.0000
0.0000
0.3100
0.0200
0.6900
0.9400
2.7300
1.7300
3.9300
3.8800
4.1000
5.1500
12.0700
18.2000
8.8800
27.3600
0.3000
1.4700
0.4400
1.9600
5.8400
0.0000
100.0000
Sample Tank No. 12
Tank No. 69
505.131
437.555
21.472
13.450
0.119
0.146
0.019
0.162
13.008
0.000
23
85
14.7
85
0.848
275
46.0
500
4.70
43.26
2651.81
0.0500
0.0000
0.2400
0.0100
0.9400
0.6600
2.1500
1.1100
4.5400
3.0600
4.9800
4.1100
10.2100
10.6800
5.4300
45.2800
0.0600
0.2100
0.0700
0.6700
5.5400
0.0000
100.0000
Sample Tank No. 13
Tank No. 70
306.443
252.987
15.159
15.330
1.048
1.488
0.062
0.734
12.001
0.000
24
114
14.7
114
0.87
274
46.0
500
5.00
26.30
2611.90
0.0700
0.0000
0.1700
0.0000
0.6200
0.5200
1.6800
0.9900
3.1200
2.4500
3.4200
4.4300
8.8900
18.5800
8.7200
36.2600
0.5300
1.9700
0.1900
2.5500
4.8400
0.0000
100.0000
Sample Tank No. 14
Tank No. 71
256.029
204.571
21.237
6.500
0.464
0.927
0.051
0.590
4.468
0.000
52
108
14.7
108
0.886
269
47.0
500
5.30
24.28
2491.55
0.0000
0.0000
0.0000
0.0000
0.9700
0.7700
2.0200
1.5500
2.1400
3.3400
2.8800
3.2600
9.0800
11.7900
5.8500
49.3100
0.3000
1.6000
0.2100
2.7300
2.2000
0.0000
100.0000
Sample Tank No. 15
Tank No. 72
1061.274
987.647
32.940
56.780
5.791
6.793
0.303
4.255
39.634
0.000
45
140
14.7
140
0.893
277
47.0
500
6.00
78.80
3120.85
0.0000
0.0000
0.0400
0.0000
1.2100
0.7600
2.9200
4.1500
3.0600
3.9300
3.0900
4.9100
13.0800
14.6200
7.6300
31.1400
0.6900
1.9400
0.1900
2.9800
3.6600
0.0000
100.0000
-------
Tank ID
E&P Tank Number
Total Emissions (tpy)
VOC Emissions (tpy)
Methane Emissions (tpy)
HAP Emissions (tpy)
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Separator Pressure (psig)
Separator Temperature (F)
Ambient Pressure (psia)
Ambient Temperature (F)
C10+ SG
C10+ MW
API Gravity
Production Rate (bbl/day)
Reid Vapor Pressure (psia)
GOR (scf/bbl)
Heating Value of Vapor (Btu/s
LP Oil Component
H2S
O2
CO2
N2
Cl
C2
C3
i-C4
n-C4
i-C5
n-C5
C6
C7
C8
C9
C10+
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Sample Tank No. 16
Tank No. 73
464.597
383.349
18.132
10.980
0.222
0.208
0.058
0.193
10.296
0.000
40
76
14.7
76
0.885
318
47.0
500
10.60
41.32
2421.27
0.0000
0.0000
0.0400
0.8400
0.7800
0.7500
3.5300
2.0700
6.8800
5.0000
7.4800
4.1000
11.3200
11.7900
6.1100
32.0700
0.1400
0.3800
0.2700
1.0300
5.4200
0.0000
100.0000
Sample Tank No. 17
Tank No. 74
214.658
135.482
32.283
7.530
1.269
0.708
0.019
0.411
5.124
0.000
31
76
14.7
76
0.839
296
49.0
500
5.00
24.48
2045.68
0.0000
0.0000
0.0800
0.0100
1.4000
0.9700
1.3500
1.0500
2.4200
2.7100
3.2900
4.6900
11.3500
12.4100
9.3100
36.0900
1.4000
2.3200
0.1600
4.0200
4.9700
0.0000
100.0000
Sample Tank No. 18
Tank No. 75
1331.488
1146.617
31.967
77.780
7.661
3.775
0.113
0.929
65.304
0.000
50
125
14.7
125
0.842
287
49.0
500
8.90
106.60
2822.40
1.2800
0.0000
0.0300
0.0000
1.2700
2.0800
4.5700
1.8900
6.4800
3.8800
7.0400
3.0500
6.8200
7.7800
7.2300
37.9300
0.8300
1.0200
0.0700
0.6500
6.1000
0.0000
100.0000
Sample Tank No. 19
Tank No. 76
3972.618
2331.105
755.826
82.380
12.470
23.584
0.056
0.635
45.632
0.000
700
100
14.7
100
0.878
178
50.0
500
7.40
491.90
1916.15
0.0000
0.0000
0.4200
0.0700
15.3300
8.9600
8.2100
2.3100
4.1900
2.4300
2.3500
3.1100
8.4700
8.8400
3.7100
23.5600
0.8200
4.6700
0.0300
0.3900
2.1300
0.0000
100.0000
Sample Tank No. 20
Tank No. 77
540.533
399.555
38.624
7.580
2.447
1.643
0.051
0.256
3.186
0.000
20
48
14.7
48
0.877
179
50.0
500
9.40
56.44
2275.04
0.0000
0.0000
0.0100
0.0100
1.1400
1.6000
4.0100
2.3400
4.7300
4.1700
2.9700
4.3800
8.8100
12.3800
5.4900
32.1400
2.8900
6.4200
0.5700
3.3000
2.6400
0.0000
100.0000
Sample Tank No. 21
Tank No. 78
1228.897
940.078
105.184
13.230
0.543
0.466
0.006
0.052
12.160
0.000
98
40
14.7
40
0.929
324
51.0
500
11.20
128.16
2279.83
0.0000
0.0000
0.0100
0.0400
3.2200
2.9500
6.4800
2.2000
8.5300
4.6800
7.4700
5.7300
15.8300
12.6400
4.0800
18.1600
0.3400
1.0200
0.0400
0.4000
6.1800
0.0000
100.0000
-------
Tank ID
E&P Tank Number
Total Emissions (tpy)
VOC Emissions (tpy)
Methane Emissions (tpy)
HAP Emissions (tpy)
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Separator Pressure (psig)
Separator Temperature (F)
Ambient Pressure (psia)
Ambient Temperature (F)
C10+ SG
C10+ MW
API Gravity
Production Rate (bbl/day)
Reid Vapor Pressure (psia)
GOR (scf/bbl)
Heating Value of Vapor (Btu/s
LP Oil Component
H2S
O2
CO2
N2
Cl
C2
C3
i-C4
n-C4
i-C5
n-C5
C6
C7
C8
C9
C10+
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Sample Tank No. 22
Tank No. 79
362.298
175.304
109.676
7.150
0.353
0.102
0.120
0.437
6.133
0.000
115
73
14.7
73
0.873
200
54.0
500
5.30
51.34
1678.80
0.0000
0.0000
0.0900
0.0300
3.5600
1.4300
1.8700
0.6800
2.0000
1.6600
2.0600
2.4100
15.0800
25.1900
12.4900
24.3900
0.2400
0.2100
0.6600
2.7600
3.1900
0.0000
100.0000
Sample Tank No. 23
Tank No. 80
790.092
665.349
24.115
28.770
3.892
6.465
0.119
2.017
16.273
0.000
30
100
14.7
100
0.901
220
54.0
500
9.40
68.32
2676.21
0.0000
0.0000
0.1100
0.0200
0.7100
1.5400
4.5900
2.3400
4.4400
3.9000
3.8000
5.0900
12.9700
19.0700
6.9500
18.9200
1.2000
5.5400
0.2500
4.8300
3.7300
0.0000
100.0000
Sample Tank No. 24
Tank No. 81
557.188
483.599
10.288
14.580
1.930
1.651
0.055
0.631
10.317
0.000
15
86
14.7
86
0.878
254
54.0
500
10.30
47.12
2764.90
0.0000
0.0000
0.0200
0.0100
0.3300
1.0900
3.8300
3.7000
4.8700
4.4800
3.9800
6.0500
15.6400
17.5800
6.1000
21.1300
1.0500
2.6000
0.2200
2.8900
4.4300
0.0000
100.0000
Sample Tank No. 25
Tank No. 82
5007.636
3386.300
842.206
101.610
9.782
12.547
0.040
0.716
78.528
0.000
770
100
14.7
100
0.858
195
55.0
500
7.80
578.20
2043.18
0.0000
0.0000
0.5500
0.0300
16.1500
7.1400
9.6600
3.8100
5.9600
3.5300
3.7200
3.8400
8.7600
8.9200
3.1000
17.9300
0.5800
2.3000
0.0200
0.4200
3.5800
0.0000
100.0000
Sample Tank No. 26
Tank No. 83
175.911
77.584
54.660
4.770
0.929
0.909
0.050
0.221
2.665
0.000
39
66
14.7
66
0.854
175
57.0
500
5.70
25.46
1632.00
0.0000
0.0000
0.0700
0.0000
1.7200
0.9000
1.3800
1.0000
1.4900
1.4600
1.5300
4.0600
14.5700
23.7200
13.7700
20.9800
1.4900
4.5300
0.6700
3.4200
3.2400
0.0000
100.0000
Sample Tank No. 27
Tank No. 84
714.052
639.895
18.553
30.190
4.165
2.542
0.192
1.424
21.871
0.000
38
95
14.7
95
0.823
375
57.0
500
9.60
57.38
2897.16
0.0000
0.0000
0.0400
0.0000
0.7000
1.0900
3.5600
2.9000
6.2100
6.0400
5.8400
7.3200
13.0000
12.2200
7.9600
20.0200
1.2200
2.0500
0.3800
3.2200
6.2300
0.0000
100.0000
-------
Tank ID
E&P Tank Number
Total Emissions (tpy)
VOC Emissions (tpy)
Methane Emissions (tpy)
HAP Emissions (tpy)
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Separator Pressure (psig)
Separator Temperature (F)
Ambient Pressure (psia)
Ambient Temperature (F)
C10+ SG
C10+ MW
API Gravity
Production Rate (bbl/day)
Reid Vapor Pressure (psia)
GOR (scf/bbl)
Heating Value of Vapor (Btu/s
LP Oil Component
H2S
O2
CO2
N2
Cl
C2
C3
i-C4
n-C4
i-C5
n-C5
C6
C7
C8
C9
C10+
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Sample Tank No. 28
Tank No. 85
801.228
757.176
5.307
29.510
3.415
5.329
0.192
1.786
18.788
0.000
65
80
14.7
80
0.899
166
57.0
500
4.80
61.26
3046.83
0.0000
0.0000
0.0100
0.0000
0.1500
0.5700
2.4100
1.7300
3.5500
4.1400
3.8600
6.5100
18.7100
19.4300
6.8400
15.5200
1.1800
5.2100
0.4600
4.8600
4.8600
0.0000
100.0000
Sample Tank No. 29
Tank No. 86
983.881
750.313
49.123
14.080
1.119
1.453
0.049
0.263
11.194
0.000
54
60
14.7
60
0.868
268
57.0
500
13.10
97.00
2390.47
0.0000
0.0000
0.0800
0.0000
1.4800
2.9100
6.9600
2.6300
7.2100
4.6400
5.7100
5.0100
13.5500
15.0600
6.2300
18.8400
0.5900
2.5000
0.2400
1.4900
4.8700
0.0000
100.0000
Sample Tank No. 30
Tank No. 87
4326.573
2406.579
1088.727
58.180
4.653
5.785
0.186
0.989
46.561
0.000
870
78
14.7
78
0.868
268
57.0
500
13.10
578.20
1789.23
0.0000
0.0000
0.4200
0.0800
21.2000
8.2900
8.5400
2.3000
5.8400
3.3500
4.0400
3.4200
9.1200
10.0900
4.1700
12.5900
0.4000
1.6800
0.1600
1.0000
3.3100
0.0000
100.0000
Sample Tank No. 31
Tank No. 88
3074.670
1892.668
746.499
47.230
5.891
6.575
0.022
0.316
34.427
0.000
600
70
14.7
70
0.847
176
57.0
500
7.50
396.24
1831.51
0.0000
0.0000
0.5800
0.0200
16.0200
4.1200
6.9000
2.7500
4.9100
3.6000
3.9000
3.9500
10.3800
11.3000
4.2100
19.2800
0.8200
3.0600
0.0300
0.5000
3.6700
0.0000
100.0000
Sample Tank No. 32
Tank No. 89
2951.879
1439.584
999.175
44.040
1.409
2.934
0.159
1.136
38.406
0.000
780
70
14.7
70
0.905
174
58.0
500
8.00
436.98
1633.60
0.0000
0.0000
0.2700
0.0200
20.3000
5.1800
5.6800
1.4200
4.1400
2.5400
3.1000
3.7700
11.2200
14.7500
7.0600
13.5400
0.1800
1.2600
0.2000
1.6700
3.7000
0.0000
100.0000
Sample Tank No. 33
Tank No. 90
616.490
332.126
120.918
9.140
0.576
1.658
0.079
0.806
6.016
0.000
60
56
14.7
60
0.905
174
58.0
500
8.00
79.54
1851.14
0.0000
0.0000
0.0800
0.0100
3.3900
2.4300
3.8400
1.3000
3.2000
2.4100
2.5600
3.7700
13.2600
22.4400
11.1300
16.0600
0.4100
3.8600
0.5200
6.1500
3.1800
0.0000
100.0000
-------
Tank ID
E&P Tank Number
Total Emissions (tpy)
VOC Emissions (tpy)
Methane Emissions (tpy)
HAP Emissions (tpy)
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Separator Pressure (psig)
Separator Temperature (F)
Ambient Pressure (psia)
Ambient Temperature (F)
C10+ SG
C10+ MW
API Gravity
Production Rate (bbl/day)
Reid Vapor Pressure (psia)
GOR (scf/bbl)
Heating Value of Vapor (Btu/s
LP Oil Component
H2S
O2
CO2
N2
Cl
C2
C3
i-C4
n-C4
i-C5
n-C5
C6
C7
C8
C9
C10+
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Sample Tank No. 34
Tank No. 91
2575.122
1494.749
581.208
65.980
9.303
14.114
0.019
0.409
42.130
0.000
500
84
14.7
84
0.909
204
58.0
500
9.10
323.88
1892.64
0.0000
0.0000
0.2300
0.0600
12.9800
5.7800
4.6400
2.0900
4.1800
4.9600
4.0700
6.0700
13.1100
11.9500
4.8600
14.1100
1.1400
5.4100
0.0200
0.5000
3.8400
0.0000
100.0000
Sample Tank No. 35
Tank No. 92
2774.089
2092.925
346.071
48.710
2.750
2.311
0.128
0.872
42.650
0.000
300
80
14.7
80
0.882
296
58.0
500
10.60
287.10
2289.04
0.0000
0.0000
0.0300
0.0900
8.4300
4.2300
5.9100
5.1700
6.2200
8.9100
4.9700
9.1100
11.3400
10.3900
5.9600
11.7500
0.3700
0.9800
0.1500
1.1900
4.8000
0.0000
100.0000
Sample Tank No. 36
Tank No. 93
653.459
394.781
121.446
14.210
0.871
2.688
0.136
1.400
9.111
0.000
110
72
14.7
72
0.901
162
59.0
500
10.00
79.90
1946.32
0.0000
0.0000
0.0800
0.0100
3.3900
2.4300
3.8400
1.3000
3.2000
2.4100
2.5600
3.7700
13.2600
22.4400
11.1300
16.0600
0.4100
3.8600
0.5200
6.1500
3.1800
0.0000
100.0000
Sample Tank No. 37
Tank No. 94
3495.242
2876.860
169.818
93.030
10.232
11.558
0.034
0.580
70.629
0.000
750
90
14.7
90
0.898
215
60.0
500
9.40
320.48
2541.49
0.0000
0.0000
0.3400
0.0200
3.7500
4.7700
9.2600
4.8100
7.0200
5.5900
6.1200
6.1300
12.8200
12.5200
4.0100
11.4200
1.1000
3.7900
0.0300
0.5900
5.9100
0.0000
100.0000
Sample Tank No. 38
Tank No. 95
363.650
223.772
84.912
10.760
0.500
0.279
0.060
0.256
9.661
0.000
85
85
14.7
85
0.9
202
61.0
500
7.00
45.04
1921.87
0.0000
0.0000
0.0400
0.0200
2.6100
1.1600
2.2100
0.9300
2.4900
2.1300
2.9200
3.5400
19.5300
27.1600
14.7000
13.8800
0.2900
0.4700
0.2600
1.2600
4.4000
0.0000
100.0000
Sample Tank No. 39
Tank No. 96
4744.399
3658.384
381.967
89.970
11.564
11.735
0.033
0.472
66.162
0.000
730
84
14.7
84
0.898
225
61.0
500
9.80
475.20
2340.56
0.0000
0.0000
0.4100
0.0300
7.3900
6.6400
10.9400
4.5800
8.3400
5.5000
5.8200
5.3200
11.2900
11.1800
3.1900
8.8000
1.1400
3.7600
0.0300
0.5000
5.1400
0.0000
100.0000
-------
Tank ID
E&P Tank Number
Total Emissions (tpy)
VOC Emissions (tpy)
Methane Emissions (tpy)
HAP Emissions (tpy)
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Separator Pressure (psig)
Separator Temperature (F)
Ambient Pressure (psia)
Ambient Temperature (F)
C10+ SG
C10+ MW
API Gravity
Production Rate (bbl/day)
Reid Vapor Pressure (psia)
GOR (scf/bbl)
Heating Value of Vapor (Btu/s
LP Oil Component
H2S
O2
CO2
N2
Cl
C2
C3
i-C4
n-C4
i-C5
n-C5
C6
C7
C8
C9
C10+
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Sample Tank No. 40
Tank No. 97
907.495
734.651
49.578
24.160
1.573
3.102
0.094
1.079
18.314
0.000
57
82
14.7
82
0.884
240
62.0
500
10.40
84.20
2521.70
0.0000
0.0000
0.0800
0.0100
1.4000
1.7700
4.8200
2.8200
5.9700
4.3100
4.1900
6.5100
17.7500
18.6400
7.4400
11.6100
0.5600
3.2800
0.2600
3.4100
5.1700
0.0000
100.0000
Sample Tank No. 41
Tank No. 98
277.197
158.333
75.426
8.820
0.204
0.854
0.042
0.375
7.344
0.000
72
80
14.7
80
0.869
190
63.0
500
7.00
36.56
1805.12
0.0000
0.0000
0.0400
0.0300
2.3500
1.0000
2.0700
0.7100
2.2600
1.7000
2.7400
3.4900
17.7300
27.9100
16.1500
12.2800
0.1600
1.9800
0.2500
2.5800
4.5700
0.0000
100.0000
Sample Tank No. 42
Tank No. 99
3410.034
2732.261
159.904
67.500
9.290
9.192
0.016
0.371
48.628
0.000
730
80
14.7
80
0.883
226
63.0
500
11.90
321.62
2477.18
0.0000
0.0000
0.3200
0.0200
3.4800
5.5300
10.1700
4.9900
8.1400
5.8700
6.1600
5.7200
12.3800
12.3100
3.7900
9.9100
1.2800
4.0500
0.0200
0.5300
5.3300
0.0000
100.0000
Sample Tank No. 43
Tank No. 100
2122.607
1066.705
736.341
64.680
9.500
15.007
0.161
1.585
38.425
0.000
580
77
14.7
77
0.85
190
64.0
500
6.40
309.64
1622.20
0.0000
0.0000
0.0700
0.0700
16.3500
3.6400
3.5600
1.6900
2.9800
2.6800
2.7900
3.8200
18.1400
19.4700
4.5900
6.7300
1.2200
6.0700
0.1800
2.0600
3.8900
0.0000
100.0000
Sample Tank No. 44
Tank No. 101
8152.118
5678.554
1206.981
81.710
10.844
8.516
0.012
0.288
62.050
0.000
730
80
14.7
80
0.895
197
64.0
500
11.00
924.96
2083.02
0.0000
0.0000
0.5600
0.0300
16.9100
8.6200
12.0400
5.2700
9.0700
5.6500
5.8200
5.1000
8.0600
7.5500
2.2200
5.6700
0.8500
2.3800
0.0100
0.2900
3.9000
0.0000
100.0000
Sample Tank No. 45
Tank No. 102
6780.555
4276.160
1045.765
48.890
5.934
1.416
0.222
1.359
39.961
0.000
807
96
14.7
96
0.811
173
66.0
500
11.80
804.54
2013.21
0.0000
0.0000
0.2200
0.0800
16.2600
11.7100
11.6100
4.3900
7.5600
4.5200
3.9400
3.3600
5.9200
11.6900
5.9200
8.9300
0.3700
0.3000
0.1400
1.0100
2.0700
0.0000
100.0000
-------
Tank ID
E&P Tank Number
Total Emissions (tpy)
VOC Emissions (tpy)
Methane Emissions (tpy)
HAP Emissions (tpy)
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Separator Pressure (psig)
Separator Temperature (F)
Ambient Pressure (psia)
Ambient Temperature (F)
C10+ SG
C10+ MW
API Gravity
Production Rate (bbl/day)
Reid Vapor Pressure (psia)
GOR (scf/bbl)
Heating Value of Vapor (Btu/s
LP Oil Component
H2S
O2
CO2
N2
Cl
C2
C3
i-C4
n-C4
i-C5
n-C5
C6
C7
C8
C9
C10+
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Sample Tank No. 46
Tank No. 103
927.902
623.038
167.129
20.320
1.625
1.876
0.062
0.696
16.059
0.000
170
75
14.7
75
0.801
196
68.0
500
12.50
106.60
2081.33
0.0000
0.0000
0.0100
0.0100
4.9300
2.5800
3.4200
3.4300
3.7300
5.5500
3.6500
8.0700
14.6500
13.2600
7.8000
19.6300
0.5400
1.9200
0.1700
2.2200
4.4300
0.0000
100.0000
Sample Tank No. 47
Tank No. 1
95.816
6.175
0.115
0.460
0.006
0.013
0.007
0.018
0.421
0.000
45
106
14.7
106
0.972
425
15.0
500
0.80
8.88
181.43
0.1100
0.0000
2.8500
0.0000
0.0100
0.0100
0.0200
0.0500
0.1800
0.3200
0.4500
0.6000
1.7200
2.1800
1.8400
88.7100
0.0100
0.0600
0.0800
0.2300
0.5700
0.0000
100.0000
Sample Tank No. 48
Tank No. 2
112.738
61.936
1.927
2.960
0.076
0.060
0.019
0.105
2.704
0.000
22
155
14.7
155
0.972
436
17.0
500
2.00
9.60
1738.61
0.0000
0.0000
1.3000
0.0000
0.1500
0.4000
0.7800
0.5600
1.2600
0.8700
1.2400
1.9800
3.4500
4.2600
3.6600
78.1500
0.0500
0.0900
0.0600
0.3700
1.3700
0.0000
100.0000
Sample Tank No. 49
Tank No. 3
74.503
28.446
0.309
0.990
0.012
0.031
0.002
0.041
0.904
0.000
20
160
14.7
160
0.952
458
18.0
500
0.60
6.44
1076.97
0.0400
0.0000
1.5400
0.0300
0.0300
0.0400
0.2200
0.1600
0.4700
0.4300
0.6500
0.6100
1.5800
2.0700
2.2800
88.9700
0.0100
0.0600
0.0100
0.1800
0.6200
0.0000
100.0000
Sample Tank No. 50
Tank No. 4
155.244
61.470
46.064
1.760
0.010
0.037
0.025
0.069
1.616
0.000
53
101
14.7
101
0.961
394
19.0
500
2.30
17.78
1365.68
0.5100
0.0000
1.1900
0.0100
1.5300
0.5300
0.8100
0.5000
1.2000
1.1500
1.3400
1.7500
3.6200
3.5300
3.5300
76.8100
0.0100
0.1000
0.1600
0.5100
1.2100
0.0000
100.0000
Sample Tank No. 51
Tank No. 5
93.073
51.471
0.440
3.190
0.218
0.074
0.006
0.048
2.845
0.000
15
120
14.7
120
0.984
551
19.0
500
4.80
7.52
1718.17
0.1400
0.0000
1.5000
0.0000
0.0400
0.2400
0.8500
0.6500
1.6500
2.1900
3.1500
4.7300
6.2500
10.2800
5.9300
57.9100
0.3000
0.2600
0.0500
0.4300
3.4500
0.0000
100.0000
-------
Tank ID
E&P Tank Number
Total Emissions (tpy)
VOC Emissions (tpy)
Methane Emissions (tpy)
HAP Emissions (tpy)
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Separator Pressure (psig)
Separator Temperature (F)
Ambient Pressure (psia)
Ambient Temperature (F)
C10+ SG
C10+ MW
API Gravity
Production Rate (bbl/day)
Reid Vapor Pressure (psia)
GOR (scf/bbl)
Heating Value of Vapor (Btu/s
LP Oil Component
H2S
O2
CO2
N2
Cl
C2
C3
i-C4
n-C4
i-C5
n-C5
C6
C7
C8
C9
C10+
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Sample Tank No. 52
Tank No. 6
24.484
3.087
15.587
0.190
0.003
0.006
0.000
0.005
0.175
0.000
23
79
14.7
79
0.947
368
20.0
500
1.20
4.98
1067.32
0.0100
0.0000
0.0700
0.0900
1.2500
0.2000
0.0800
0.0900
0.1800
0.4000
0.4500
1.0500
2.3300
2.9800
2.6000
87.0300
0.0200
0.1100
0.0200
0.2700
0.7700
0.0000
100.0000
Sample Tank No. 53
Tank No. 7
26.091
17.629
2.836
0.510
0.007
0.014
0.001
0.012
0.474
0.000
17
106
14.7
106
0.967
383
20.0
500
3.30
2.82
2208.23
0.0000
0.0000
0.0000
0.0000
0.1900
0.2300
0.7500
0.4900
1.5700
1.5300
1.9100
2.7500
3.9000
6.8100
4.0100
73.0300
0.0400
0.2200
0.0500
0.5100
2.0100
0.0000
100.0000
Sample Tank No. 54
Tank No. 8
29.739
11.288
5.908
0.330
0.013
0.008
0.003
0.007
0.298
0.000
18
75
14.7
75
0.963
401
20.0
500
3.80
3.94
1236.41
0.0000
0.0000
0.2500
0.2100
0.5300
0.3300
0.7500
0.4900
1.5000
1.3500
1.7700
2.3700
4.3000
5.5200
3.5700
74.2800
0.1000
0.1900
0.1900
0.4700
1.8300
0.0000
100.0000
Sample Tank No. 55
Tank No. 9
114.630
74.707
25.400
2.120
0.039
0.071
0.007
0.090
1.919
0.000
54
125
14.7
125
0.943
363
21.0
500
1.10
13.90
1980.20
0.0000
0.0000
0.0000
0.0100
1.8000
0.5400
0.5200
0.2800
0.9200
0.9800
0.9700
1.6800
3.0100
3.7300
3.5400
80.2500
0.0300
0.1400
0.0300
0.4500
1.1200
0.0000
100.0000
Sample Tank No. 56
Tank No. 10
42.075
8.263
27.176
0.090
0.028
0.010
0.000
0.001
0.052
0.000
35
76
14.7
76
0.923
278
23.0
500
1.80
8.52
1192.63
0.0000
0.0000
0.0600
0.0100
1.7700
0.2900
0.3700
0.2300
0.3100
0.4900
0.2400
0.2500
0.5900
0.5000
0.2500
94.2100
0.1100
0.1200
0.0100
0.0500
0.1400
0.0000
100.0000
Sample Tank No. 57
Tank No. 11
0.0000
-------
Tank ID
E&P Tank Number
Total Emissions (tpy)
VOC Emissions (tpy)
Methane Emissions (tpy)
HAP Emissions (tpy)
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Separator Pressure (psig)
Separator Temperature (F)
Ambient Pressure (psia)
Ambient Temperature (F)
C10+ SG
C10+ MW
API Gravity
Production Rate (bbl/day)
Reid Vapor Pressure (psia)
GOR (scf/bbl)
Heating Value of Vapor (Btu/s
LP Oil Component
H2S
O2
CO2
N2
Cl
C2
C3
i-C4
n-C4
i-C5
n-C5
C6
C7
C8
C9
C10+
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Sample Tank No. 58
Tank No. 12
134.719
63.729
16.689
1.170
0.020
0.014
0.007
0.027
1.104
0.000
30
66
14.7
66
0.946
382
23.0
500
4.00
15.42
1553.86
0.4400
0.0000
0.6400
0.0100
1.0700
0.5400
1.4100
0.7000
1.9400
1.8900
2.3600
2.7100
5.1800
5.3700
3.9800
68.6500
0.0500
0.1100
0.1500
0.6500
2.1500
0.0000
100.0000
Sample Tank No. 59
Tank No. 13
26.214
5.207
12.924
0.430
0.008
0.032
0.002
0.019
0.371
0.000
20
122
14.7
122
0.926
336
24.0
500
0.60
4.60
1059.39
0.0000
0.0000
0.1200
0.1000
0.9400
0.0500
0.0700
0.0600
0.1000
0.2400
0.2300
0.9100
2.8000
4.2200
4.3400
84.5400
0.0200
0.2100
0.0300
0.3100
0.7100
0.0000
100.0000
Sample Tank No. 60
Tank No. 14
195.573
109.615
7.759
2.810
0.033
0.032
0.023
0.064
2.659
0.000
20
88
14.7
88
0.945
381
24.0
500
3.90
19.12
1747.39
0.5200
0.0000
0.9600
0.1200
0.4900
0.6500
1.7300
0.7400
2.4600
1.7900
2.3100
2.6100
5.3300
5.5400
4.2100
67.0700
0.0400
0.1100
0.2000
0.6300
2.4900
0.0000
100.0000
Sample Tank No. 61
Tank No. 15
142.068
69.135
5.438
1.760
0.024
0.053
0.003
0.041
1.640
0.000
22
86
14.7
86
0.944
404
24.0
500
4.60
13.74
1543.44
0.4500
0.0000
1.1500
0.0200
0.3600
0.5000
1.5900
0.7600
2.4000
1.7300
2.1400
2.6400
5.5200
6.0700
4.6000
66.9000
0.0400
0.2600
0.0400
0.5800
2.2500
0.0000
100.0000
Sample Tank No. 62
Tank No. 16
191.224
105.838
4.313
2.110
0.041
0.079
0.003
0.016
1.969
0.000
20
68
14.7
68
0.964
444
24.0
500
4.80
17.84
1703.42
0.0000
0.0000
1.4200
0.0200
0.2700
0.6200
1.9400
1.1000
3.0100
2.1900
3.2100
3.9300
5.6800
11.3000
6.7600
54.5000
0.0800
0.4700
0.0400
0.2900
3.1700
0.0000
100.0000
Sample Tank No. 63
Tank No. 17
35.095
25.578
3.029
0.750
0.011
0.022
0.003
0.011
0.701
0.000
19
133
14.7
133
0.928
327
25.0
500
4.10
3.48
2314.31
0.0000
0.0000
0.0500
0.0000
0.2500
0.4900
1.1600
0.6000
1.5900
1.4300
1.4400
1.9900
3.5100
4.4100
4.4400
76.8100
0.0300
0.1500
0.0400
0.1800
1.4300
0.0000
100.0000
-------
Tank ID
E&P Tank Number
Total Emissions (tpy)
VOC Emissions (tpy)
Methane Emissions (tpy)
HAP Emissions (tpy)
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Separator Pressure (psig)
Separator Temperature (F)
Ambient Pressure (psia)
Ambient Temperature (F)
C10+ SG
C10+ MW
API Gravity
Production Rate (bbl/day)
Reid Vapor Pressure (psia)
GOR (scf/bbl)
Heating Value of Vapor (Btu/s
LP Oil Component
H2S
O2
CO2
N2
Cl
C2
C3
i-C4
n-C4
i-C5
n-C5
C6
C7
C8
C9
C10+
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Sample Tank No. 64
Tank No. 18
139.887
89.426
21.590
1.190
0.011
0.035
0.010
0.025
1.109
0.000
30
60
14.7
60
0.94
380
25.0
500
4.90
16.66
1966.88
0.0000
0.0000
0.0600
0.0400
1.3500
0.8500
2.0900
1.1400
2.7100
2.1900
2.4600
2.2400
5.7900
4.7900
4.4800
66.3000
0.0300
0.2900
0.2200
0.6500
2.3200
0.0000
100.0000
Sample Tank No. 65
Tank No. 19
70.761
46.290
4.142
2.570
0.371
0.697
0.039
0.176
1.292
0.000
25
136
14.7
136
0.916
431
27.0
500
3.30
6.76
2041.97
0.3800
0.0000
0.2200
0.1000
0.3200
0.4100
1.0700
0.5700
1.4500
1.5700
1.5100
2.5400
3.5300
4.9600
4.1700
72.0600
0.4300
1.9600
0.2400
1.2100
1.3000
0.0000
100.0000
Sample Tank No. 66
Tank No. 20
171.538
110.120
15.382
1.670
0.013
0.017
0.004
0.025
1.613
0.000
31
64
14.7
64
0.938
340
27.0
500
5.20
18.46
1887.18
0.2400
0.0000
0.2100
0.3000
0.8600
0.5400
1.7500
1.1600
3.1500
2.9100
2.5900
3.7200
5.8600
5.6200
3.7300
63.8500
0.0300
0.1200
0.0800
0.5400
2.7400
0.0000
100.0000
Sample Tank No. 67
Tank No. 21
38.394
12.834
16.424
0.720
0.224
0.209
0.007
0.066
0.216
0.000
23
79
14.7
79
0.908
324
29.0
500
3.10
6.36
1405.21
0.0000
0.0000
0.0900
0.0000
1.1200
0.5300
0.7000
0.4500
0.6300
0.6400
0.4600
0.8400
4.7900
8.9000
5.8000
67.7100
1.0000
2.7600
0.2400
2.5900
0.7500
0.0000
100.0000
Sample Tank No. 68
Tank No. 22
215.631
164.956
8.875
4.240
0.985
0.787
0.020
0.118
2.331
0.000
17
86
14.7
86
0.946
323
29.0
500
4.80
20.11
2354.30
0.2700
0.0000
0.0800
0.0000
0.4400
0.7000
2.0600
0.9700
2.7500
2.7000
2.3200
3.5000
8.3100
7.2900
7.0500
53.9500
1.2400
2.8500
0.1800
1.2300
2.1100
0.0000
100.0000
Sample Tank No. 69
Tank No. 23
148.757
138.780
1.515
5.310
1.086
0.854
0.025
0.122
3.227
0.000
20
120
14.7
120
0.932
326
29.0
500
4.90
11.50
2985.81
0.0000
0.0000
0.0300
0.0000
0.0800
0.2000
1.3000
1.0400
3.8800
2.2100
3.2000
2.5500
7.2000
7.2300
4.7500
59.2600
1.1600
2.3500
0.1600
0.8600
2.5400
0.0000
100.0000
-------
Tank ID
E&P Tank Number
Total Emissions (tpy)
VOC Emissions (tpy)
Methane Emissions (tpy)
HAP Emissions (tpy)
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Separator Pressure (psig)
Separator Temperature (F)
Ambient Pressure (psia)
Ambient Temperature (F)
C10+ SG
C10+ MW
API Gravity
Production Rate (bbl/day)
Reid Vapor Pressure (psia)
GOR (scf/bbl)
Heating Value of Vapor (Btu/s
LP Oil Component
H2S
O2
CO2
N2
Cl
C2
C3
i-C4
n-C4
i-C5
n-C5
C6
C7
C8
C9
C10+
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Sample Tank No. 70
Tank No. 24
243.873
151.292
7.881
2.480
0.188
0.276
0.007
0.114
1.896
0.000
22
98
14.7
98
0.917
311
29.0
500
6.20
24.26
2141.84
1.0100
0.0000
0.1100
0.0000
0.4000
1.6600
2.2300
1.1500
1.9500
2.8400
1.3600
3.0700
6.9000
7.6500
5.8200
61.2100
0.1500
0.6100
0.0400
0.7000
1.1400
0.0000
100.0000
Sample Tank No. 71
Tank No. 25
502.831
330.274
124.465
13.120
0.954
1.256
0.086
0.732
10.096
0.000
280
106
14.7
106
0.921
450
30.0
500
4.80
61.80
1933.26
0.0000
0.0000
0.1200
0.0500
7.9800
1.5600
2.8200
1.4300
2.4400
2.1200
2.0900
2.5400
6.3500
8.0300
3.5600
54.9600
0.2000
0.6800
0.1100
1.0600
1.9000
0.0000
100.0000
Sample Tank No. 72
Tank No. 26
13.397
4.231
6.395
0.070
0.008
0.003
0.000
0.008
0.055
0.000
4
80
14.7
80
0.893
313
30.0
500
2.60
2.34
1394.74
0.0000
0.0000
0.0200
0.0000
0.5900
0.4000
0.5500
0.4500
0.6300
0.4800
0.4500
1.0000
4.3100
4.9000
4.1700
80.5100
0.0900
0.1100
0.0200
0.8100
0.5100
0.0000
100.0000
Sample Tank No. 73
Tank No. 27
154.387
125.001
4.603
10.900
0.053
0.110
0.031
0.305
10.401
0.000
25
180
14.7
180
0.916
304
30.0
500
2.70
11.76
2814.20
0.0300
0.0000
0.2700
0.0000
0.2600
0.4800
0.8100
0.3600
1.1800
1.2900
2.0600
2.6800
6.5200
7.3900
4.8600
68.2000
0.0200
0.0900
0.0500
0.5400
2.9100
0.0000
100.0000
Sample Tank No. 74
Tank No. 28
119.805
48.333
45.716
1.090
0.189
0.076
0.004
0.033
0.785
0.000
64
70
14.7
70
0.898
368
30.0
500
2.80
18.78
1478.45
0.0000
0.0000
0.1700
0.0200
3.1300
0.7000
1.0700
0.8800
1.1100
1.0500
1.0000
1.5300
4.4300
5.8900
4.2200
72.4400
0.3100
0.3800
0.0500
0.5000
1.1200
0.0000
100.0000
Sample Tank No. 75
Tank No. 29
263.134
168.558
54.016
3.440
0.435
0.413
0.046
0.285
2.257
0.000
80
77
14.7
77
0.896
309
33.0
500
2.20
32.78
1920.70
0.0000
0.0000
0.0300
0.0200
2.9000
1.1000
1.7100
1.0700
1.1500
1.5000
1.2300
2.3300
6.0000
8.7700
6.3100
60.3600
0.3800
1.0700
0.3100
2.2000
1.5600
0.0000
100.0000
-------
Tank ID
E&P Tank Number
Total Emissions (tpy)
VOC Emissions (tpy)
Methane Emissions (tpy)
HAP Emissions (tpy)
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Separator Pressure (psig)
Separator Temperature (F)
Ambient Pressure (psia)
Ambient Temperature (F)
C10+ SG
C10+ MW
API Gravity
Production Rate (bbl/day)
Reid Vapor Pressure (psia)
GOR (scf/bbl)
Heating Value of Vapor (Btu/s
LP Oil Component
H2S
O2
CO2
N2
Cl
C2
C3
i-C4
n-C4
i-C5
n-C5
C6
C7
C8
C9
C10+
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Sample Tank No. 76
Tank No. 30
75.697
48.997
15.026
1.330
0.115
0.088
0.010
0.038
1.075
0.000
20
115
14.7
115
0.885
280
33.0
500
3.10
8.96
1989.27
0.0000
0.0000
0.0300
0.0000
0.8400
0.3700
0.9200
1.0000
1.3200
1.3500
1.2200
1.8500
4.6800
5.5400
3.8000
74.8700
0.1700
0.3400
0.0900
0.3900
1.2200
0.0000
100.0000
Sample Tank No. 77
Tank No. 31
67.111
21.176
39.198
0.460
0.055
0.025
0.002
0.011
0.362
0.000
60
78
14.7
78
0.866
324
34.0
500
2.00
12.60
1308.40
0.0000
0.0000
0.0500
0.0000
2.8100
0.3100
0.6200
0.4700
0.7300
0.7100
0.6600
1.0800
2.3500
2.9600
1.9300
84.1900
0.1100
0.1500
0.0300
0.2000
0.6400
0.0000
100.0000
Sample Tank No. 78
Tank No. 32
33.481
9.640
18.906
0.290
0.025
0.040
0.004
0.023
0.196
0.000
18
70
14.7
70
0.875
277
34.0
500
2.20
6.20
1280.62
0.0000
0.0000
0.0700
0.0000
1.1600
0.2400
0.4900
0.4300
0.6500
0.8000
0.7000
1.2900
3.6200
5.5500
3.8000
78.1200
0.1400
0.6900
0.1800
1.2000
0.8700
0.0000
100.0000
Sample Tank No. 79
Tank No. 33
98.139
41.538
45.393
1.230
0.118
0.085
0.008
0.165
0.852
0.000
40
110
14.7
110
0.87
297
34.0
500
3.20
16.18
1473.81
0.0000
0.0000
0.0400
0.0100
2.9100
0.4400
0.6800
0.5800
0.6300
0.5300
0.4900
0.8900
4.6300
5.3100
4.5800
76.3800
0.1000
0.1900
0.0400
0.9800
0.5900
0.0000
100.0000
Sample Tank No. 80
Tank No. 34
246.837
186.576
13.777
7.150
1.477
1.336
0.030
0.263
4.047
0.000
18
80
14.7
80
0.923
346
35.0
500
4.70
24.36
2361.43
0.0100
0.0000
0.0600
0.0100
0.6400
1.0500
2.2200
0.8300
2.7600
2.1100
3.1100
3.5800
11.4200
11.2400
8.3200
40.2000
1.6600
4.4100
0.2500
2.5500
3.5700
0.0000
100.0000
Sample Tank No. 81
Tank No. 35
206.565
136.694
5.258
4.120
0.060
OJ22
0.010
OJOO
3.833
0.000
15
108
14.7
108
0.887
272
35.0
500
4.50
18.78
2135.62
0.0500
0.0000
0.6100
0.0500
0.2600
0.7800
1.7400
0.8400
2.3700
2.2400
2.2500
3.1500
6.1800
6.7100
5.0700
64.3300
0.0500
0.2700
0.0500
0.5900
2.4100
0.0000
100.0000
-------
Tank ID
E&P Tank Number
Total Emissions (tpy)
VOC Emissions (tpy)
Methane Emissions (tpy)
HAP Emissions (tpy)
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Separator Pressure (psig)
Separator Temperature (F)
Ambient Pressure (psia)
Ambient Temperature (F)
C10+ SG
C10+ MW
API Gravity
Production Rate (bbl/day)
Reid Vapor Pressure (psia)
GOR (scf/bbl)
Heating Value of Vapor (Btu/s
LP Oil Component
H2S
O2
CO2
N2
Cl
C2
C3
i-C4
n-C4
i-C5
n-C5
C6
C7
C8
C9
C10+
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Sample Tank No. 82
Tank No. 36
176.370
121.493
10.526
3.520
0.068
0.092
0.019
0.072
3.266
0.000
17
100
14.7
100
0.887
283
35.0
500
4.90
17.62
2307.25
0.0000
0.0000
0.0900
0.0100
0.5300
1.1100
1.7600
0.8000
2.3800
2.1600
2.6700
3.3700
6.0700
6.8700
6.0400
62.5300
0.0700
0.2600
0.1300
0.5600
2.5900
0.0000
100.0000
Sample Tank No. 83
Tank No. 37
34.019
16.601
12.380
1.050
0.262
0.297
0.011
0.048
0.435
0.000
30
125
14.7
125
0.863
276
36.0
500
2.50
5.02
1616.36
0.0000
0.0000
0.0300
0.0000
0.9100
0.3200
0.5700
0.3900
0.5800
0.6500
0.5700
1.0700
3.3600
5.7300
4.2600
77.9200
0.5500
1.5800
0.1300
0.6500
0.7300
0.0000
100.0000
Sample Tank No. 84
Tank No. 38
82.578
32.683
40.189
1.820
0.364
0.293
0.016
OJ25
1.023
0.000
50
68
14.7
68
0.879
356
36.0
500
3.80
14.02
1437.32
0.0000
0.0000
0.0300
0.0100
2.4200
0.4500
0.8100
0.5400
1.1700
1.3400
1.6000
2.4800
7.6400
10.3500
5.9100
57.3100
0.8300
2.0500
0.2900
2.6900
2.0800
0.0000
100.0000
Sample Tank No. 85
Tank No. 39
113.253
56.649
30.738
2.310
0.285
0.292
0.018
0.138
1.573
0.000
57
80
14.7
80
0.883
294
36.0
500
3.90
15.52
1721.01
0.0000
0.0000
0.0600
0.0100
1.5900
0.7200
1.1100
0.7700
1.6000
1.5200
1.6700
2.5900
7.1400
9.7000
5.1000
59.8700
0.5000
1.5100
0.2400
2.1000
2.2000
0.0000
100.0000
Sample Tank No. 86
Tank No. 40
204.693
107.904
57.039
3.540
0.530
0.386
0.030
0.208
2.383
0.000
75
81
14.7
81
0.883
288
36.0
500
4.10
27.84
1718.90
0.0000
0.0000
0.1400
0.0100
2.9000
0.9500
1.4500
1.0000
1.8400
1.6700
1.7900
2.1500
6.1000
7.9700
5.2600
61.4100
0.5100
1.0900
0.2200
1.7300
1.8100
0.0000
100.0000
Sample Tank No. 87
Tank No. 41
178.190
100.629
28.323
2.460
0.307
0.280
0.012
0.068
1.789
0.000
28
60
14.7
60
0.891
277
36.0
500
3.80
22.04
1846.39
0.2000
0.0000
0.0600
0.0100
1.3300
0.9300
1.7200
0.4400
1.9800
1.2300
2.2100
2.4300
9.4100
10.5500
6.0500
54.5600
0.6300
1.8200
0.2100
1.4100
2.8200
0.0000
100.0000
-------
Tank ID
E&P Tank Number
Total Emissions (tpy)
VOC Emissions (tpy)
Methane Emissions (tpy)
HAP Emissions (tpy)
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Separator Pressure (psig)
Separator Temperature (F)
Ambient Pressure (psia)
Ambient Temperature (F)
C10+ SG
C10+ MW
API Gravity
Production Rate (bbl/day)
Reid Vapor Pressure (psia)
GOR (scf/bbl)
Heating Value of Vapor (Btu/s
LP Oil Component
H2S
O2
CO2
N2
Cl
C2
C3
i-C4
n-C4
i-C5
n-C5
C6
C7
C8
C9
C10+
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Sample Tank No. 88
Tank No. 42
264.744
197.667
4.156
5.070
0.536
6.120
0.040
0.205
3.677
0.000
18
95
14.7
95
0.9
288
36.0
500
7.20
23.68
2352.89
0.8700
0.0000
0.1200
0.0200
0.1900
0.6800
2.5400
1.1400
3.8100
2.9900
2.9100
3.7100
9.0500
7.1100
5.9500
52.8400
0.4700
1.5000
0.2400
1.4100
2.4500
0.0000
100.0000
Sample Tank No. 89
Tank No. 43
77.810
45.796
20.047
1.720
0.269
0.232
0.014
0.121
1.081
0.000
18
98
14.7
98
0.871
270
37.0
500
3.90
10.02
1820.80
0.0000
0.0000
0.0500
0.0000
1.0400
0.4200
0.9700
1.1500
1.3100
1.6600
1.2800
2.1200
5.2700
7.7200
4.7200
67.1300
0.5000
1.1900
0.1800
1.7200
1.5700
0.0000
100.0000
Sample Tank No. 90
Tank No. 44
341.571
126.289
121.935
2.060
0.294
0.161
0.036
0.106
1.462
0.000
190
70
14.7
70
0.861
270
37.0
500
3.00
53.74
1489.35
0.0000
0.0000
0.3100
0.0300
6.2500
2.2000
2.0200
0.5500
1.1800
0.8300
0.7100
1.3200
3.8300
6.7800
2.8000
69.1900
0.1800
0.3000
0.1800
0.6100
0.7300
0.0000
100.0000
Sample Tank No. 91
Tank No. 45
746.422
598.797
12.450
7.990
3.587
0.449
0.061
0.072
3.820
0.000
22
50
14.7
50
0.918
372
37.0
500
4.90
67.22
2491.03
0.1400
0.0000
0.5300
0.0000
0.5600
2.3100
4.1000
1.9100
5.0000
3.4000
3.5100
3.0200
13.2800
13.1300
5.9600
36.1900
2.6100
1.0600
0.4000
0.5500
2.3400
0.0000
100.0000
Sample Tank No. 92
Tank No. 46
120.452
71.033
24.855
1.310
OJ26
OJ99
0.009
0.077
0.900
0.000
24
68
14.7
68
0.872
239
38.0
500
3.60
15.46
1867.10
0.0000
0.0000
0.0200
0.0000
1.1400
0.5800
1.2600
0.9300
1.4400
1.6100
1.3900
2.3200
6.5000
8.7200
5.9100
62.7500
0.3100
1.5000
0.1800
1.7900
1.6500
0.0000
100.0000
Sample Tank No. 93
Tank No. 47
114.826
53.659
41.873
1.960
0.496
0.291
0.009
0.052
1.109
0.000
60
72
14.7
72
0.863
318
38.0
500
4.50
17.44
1590.85
0.0000
0.0000
0.0500
0.0000
2.5500
0.8600
1.3500
0.9700
1.3600
1.4200
1.3400
2.1100
5.5300
7.6500
5.6600
64.2400
0.8400
1.4900
0.1200
0.8100
1.6500
0.0000
100.0000
-------
Tank ID
E&P Tank Number
Total Emissions (tpy)
VOC Emissions (tpy)
Methane Emissions (tpy)
HAP Emissions (tpy)
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Separator Pressure (psig)
Separator Temperature (F)
Ambient Pressure (psia)
Ambient Temperature (F)
C10+ SG
C10+ MW
API Gravity
Production Rate (bbl/day)
Reid Vapor Pressure (psia)
GOR (scf/bbl)
Heating Value of Vapor (Btu/s
LP Oil Component
H2S
O2
CO2
N2
Cl
C2
C3
i-C4
n-C4
i-C5
n-C5
C6
C7
C8
C9
C10+
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Sample Tank No. 94
Tank No. 48
54.705
37.588
8.963
2.550
0.263
0.317
0.024
0.218
1.726
0.000
32
149
14.7
149
0.862
251
38.0
500
3.00
5.82
2216.65
0.0000
0.0000
0.0100
0.0000
0.5100
0.4400
0.5900
0.5400
0.6500
1.3500
1.1500
2.5000
6.4600
8.5600
3.4500
69.3200
0.3200
0.9100
0.1500
1.4800
1.6100
0.0000
100.0000
Sample Tank No. 95
Tank No. 49
437.309
181.269
1.079
4.660
0.041
0.110
0.053
0.149
4.311
0.000
62
80
14.7
80
0.894
310
38.0
500
5.20
37.60
1206.29
0.0000
0.0000
4.1200
0.0200
0.0500
0.3200
1.4800
0.8700
3.3500
3.0800
2.8200
4.7100
10.0400
11.8100
6.4100
46.8100
0.0300
0.2400
0.3000
0.9700
2.5700
0.0000
100.0000
Sample Tank No. 96
Tank No. 50
165.905
149.208
0.600
4.640
0.202
0.380
0.035
0.168
3.855
0.000
13
113
14.7
113
0.882
294
38.0
500
5.70
13.60
2853.46
0.0000
0.0000
0.0100
0.0000
0.0300
0.4500
2.4200
1.1900
3.2300
2.0600
3.0500
2.3400
7.7900
8.3700
6.4400
57.0400
0.2000
0.9900
0.2100
1.1500
3.0300
0.0000
100.0000
Sample Tank No. 97
Tank No. 51
279.758
103.605
12.141
1.630
0.453
0.085
0.015
0.017
1.063
0.000
28
45
14.7
45
0.904
294
38.0
500
7.40
28.24
1313.43
0.0000
0.0000
2.0000
0.0000
0.5300
1.0400
1.9800
1.4200
3.7800
2.9700
2.9500
2.6800
11.8900
11.7900
6.6500
45.6300
1.1100
0.7100
0.3600
0.4800
2.0300
0.0000
100.0000
Sample Tank No. 98
Tank No. 52
608.810
571.582
8.030
17.380
0.424
0.458
0.025
0.441
16.032
0.000
22
114
14.7
114
0.877
337
38.0
500
3.10
45.82
3053.30
0.0000
0.0000
0.0400
0.2000
0.4200
0.5700
2.1600
1.1400
4.2600
2.9000
4.2900
3.5200
10.3400
9.9300
4.4300
51.0200
0.1100
0.3100
0.0400
0.7800
3.5400
0.0000
100.0000
Sample Tank No. 99
Tank No. 53
254.487
161.927
48.433
7.830
2.228
1.268
0.039
0.399
3.892
0.000
66
89
14.7
89
0.877
282
39.0
500
3.70
30.08
1945.58
0.0000
0.0000
0.1800
0.0000
2.2600
0.8400
1.4800
1.0300
1.6000
2.0600
1.8600
3.4100
8.6400
11.0300
5.1000
51.2400
1.6600
2.6900
0.2100
2.4200
2.2900
0.0000
100.0000
-------
Tank ID
E&P Tank Number
Total Emissions (tpy)
VOC Emissions (tpy)
Methane Emissions (tpy)
HAP Emissions (tpy)
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Separator Pressure (psig)
Separator Temperature (F)
Ambient Pressure (psia)
Ambient Temperature (F)
C10+ SG
C10+ MW
API Gravity
Production Rate (bbl/day)
Reid Vapor Pressure (psia)
GOR (scf/bbl)
Heating Value of Vapor (Btu/s
LP Oil Component
H2S
O2
CO2
N2
Cl
C2
C3
i-C4
n-C4
i-C5
n-C5
C6
C7
C8
C9
C10+
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Sample Tank No. 100
Tank No. 54
173.095
97.629
52.151
4.410
0.242
0.281
0.031
0.164
3.689
0.000
60
80
14.7
60
0.891
265
39.0
500
5.60
23.36
1766.66
0.0000
0.0000
0.0500
0.0100
2.3200
0.7200
1.1900
0.8900
1.8300
2.3500
3.2400
3.9900
9.9400
11.5600
6.0600
48.9900
0.3000
1.0300
0.2900
1.7800
3.4600
0.0000
100.0000
Sample Tank No. 101
Tank No. 55
363.718
237.995
56.163
2.820
0.369
0.045
0.026
0.129
2.253
0.000
60
58
14.7
58
0.877
309
39.0
500
6.80
43.14
2016.56
0.0000
0.0000
0.0300
0.0100
2.6700
1.7300
3.6000
1.8800
3.2300
2.4900
2.1100
2.7200
8.1600
11.9800
4.9500
50.3400
0.3800
0.1500
0.2400
1.3700
1.9600
0.0000
100.0000
Sample Tank No. 102
Tank No. 56
391.465
191.567
3.830
5.090
0.970
0.836
0.019
0.135
3.127
0.000
33
60
14.7
60
0.907
295
39.0
500
6.40
36.04
1509.76
0.1100
0.0000
2.4000
0.0000
0.1600
0.7600
2.6400
0.9100
3.5800
2.6500
3.4400
3.7800
10.7700
11.8300
6.1900
40.8600
1.2700
3.4900
0.2200
1.8000
3.1400
0.0000
100.0000
Sample Tank No. 103
Tank No. 57
274.631
204.825
22.453
19.640
5.674
4.267
0.070
0.436
9J94
0.000
42
110
14.7
110
0.879
283
39.0
500
5.40
26.60
2428.31
0.0000
0.0000
0.0100
0.0000
1.0900
1.5000
2.1200
0.8400
2.2800
1.6400
2.5200
2.6100
9.7300
8.9300
5.8900
47.7300
2.7500
5.3000
0.2000
1.3900
3.4700
0.0000
100.0000
-------
Tank ID
E&P Tank Number
Total Emissions (tpy)
VOC Emissions (tpy)
Methane Emissions (tpy)
HAP Emissions (tpy)
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Separator Pressure (psig)
Separator Temperature (F)
Ambient Pressure (psia)
Ambient Temperature (F)
C10+ SG
C10+ MW
API Gravity
Production Rate (bbl/day)
Reid Vapor Pressure (psia)
GOR (scf/bbl)
Heating Value of Vapor (Btu/s
LP Oil Component
H2S
O2
CO2
N2
Cl
C2
C3
i-C4
n-C4
i-C5
n-C5
C6
C7
C8
C9
C10+
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Total
VOC
Methane
HAP
Separator Pressure
Separator Temperature
API Gravity
RVP
GOR
Heating value
Average
785.812
530.750
116.167
15.685
126.451
88.657
0.893
292.72
40.6
5.691
88.149
1968.085
Composition
0.0679
0.0000
0.3661
0.0360
2.9248
1.6262
2.7564
1.3958
2.9738
2.4711
2.7194
3.2723
8.5230
10.3202
5.6686
48.1339
0.6044
1.6882
0.1797
1.4353
2.8369
0.0000
100.0000
ratios to HAP
33.837
7.406
Ratio to VOC
0.219
0.030
API > 40
Maximum Minimum
8152.118 129.419
5678.554 43.734
1206.981 0.197
101.610 2.680
870.000
140.000
13.100
924.960
13.000
40.000
0.929 0.801
375.000 162.000
68.0 40.0
3.000
12.300
Average
1530.229
1046.343
230.569
30.684
231.870
82.500
0.873
241.304
52.8
7.983
172.479
-------
Tank ID
E&P Tank Number
Total Emissions (tpy)
VOC Emissions (tpy)
Methane Emissions (tpy)
HAP Emissions (tpy)
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
Separator Pressure (psig)
Separator Temperature (F)
Ambient Pressure (psia)
Ambient Temperature (F)
C10+ SG
C10+ MW
API Gravity
Production Rate (bbl/day)
Reid Vapor Pressure (psia)
GOR (scf/bbl)
Heating Value of Vapor (Btu/s
LP Oil Component
H2S
O2
CO2
N2
Cl
C2
C3
i-C4
n-C4
i-C5
n-C5
C6
C7
C8
C9
C10+
Benzene
Toluene
E-Benzene
Xylenes
n-C6
224Trimethylp
API <40
Maximum
746.422
598.797
124.465
19.640
5.674
6.120
0.086
0.732
16.032
0.000
280.000
Minimum
13.397
3.087
0.115
0.070
0.003
0.003
0.000
0.001
0.052
0.000
4.000
Average
174.327
107.227
22.193
3.366
0.445
0.431
0.019
0.120
2.449
0.000
39.857
0.984 0.861 0.910
551.000 239.000 334.946
39.0 15.0 30.6
7.400
67.220
0.600
2.340
3.809
18.878
-------
API Gravity >40
API Gravity <40
VOC Emissions (tpy)
Mean
Standard Error
Median
Mode
Standard Deviation
Sample Variance
Kurtosis
Skewness
Range
Minimum
Maximum
Sum
Count
Largest(l)
Confidence Level(95.0%)
VOC
1046.343
188.1410357
530.989
#N/A
1276.034588
1628264.269
3.35522263
1.864492873
5634.82
43.734
5678.554
48131.778
46
5678.554
378.9354921
667.4075079
1046.343
1425.278492
VOC Emissions (tpy)
Mean 107.2265
Standard Error 15.51304
Median 72.87
Mode #N/A
Standard Deviation 116.0889
Sample Variance 13476.64
Kurtosis 9.02191
Skewness 2.680349
Range 595.71
Minimum 3.087
Maximum 598.797
Sum 6004.685
Count 56
Largest(l) 598.797
Confidence Level(95.0%) 31.08882
VOC
76.1377
107.2265
138.3153
-------
United States Office of Air Quality Planning and Standards EPA-453/R-11 -002
Environmental Protection Sector Policies and Programs Division July 2011
Agency Research Triangle Park, NC
------- |