United States Office of Air Quality
Environmental Protection Planning and Standards
Agency Research Triangle Park NC 27711
April 1997
EPA-453/R-94-079a
Air
©EPA National Emission Standards for
Hazardous Air Pollutants for
Source Categories: Oil and Natural
Gas Production and Natural Gas
Transmission and Storage -
Background Information for
Proposed Standards
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I. REPORT NO.
EPA-453/R-94-079a
4. TITLE AND SUBTITLE
National Emission Standards f
Source Categories: Oil and N£
Gas Transmission and Storage
Proposed Standards
TECHNICAL REPORT DATA
(Please read Instructions on reverse before completing)
2.
or Hazardous Air Pollutants for
itural Gas Production and Natural
- Background Information for
7. AUTHOR®
9. PERFORMING ORGANIZATION NAME AND ADDRESS
U.S. Environmental Protection Agency
Office of Air Quality Planning and Standards
Research Triangle Park, NC 27711
12. SPONSORING AGENCY NAME AND ADDRESS
Director
Office of Air Quality Planning and Standards
Office of Air and Radiation
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
3. RECIPIENT'S ACCESSION NO.
5. REPORT DATE
April 1997
6. PERFORMING ORGANIZATION CODE
8. PERFORMING ORGANIZATION REPORT NO.
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68D60008
13. TYPE OF REPORT AND PERIOD COVERED
14. SPONSORING AGENCY CODE
EPA/200/04
15. SUPPLEMENTARY NOTES
16. ABSTRACT
This background information document provides the basic information which was used as background in
the development of the two standards 1) National Emission Standards for Hazardous Air Pollutants from:
Oil and Natural Gas Production Facilities and 2) National Emission Standards for Hazardous Air
Pollutants from Natural Gas Transmission and Storage Facilities. A description of the industries, control
technologies available, cost of controls, modeling used in the estimation of national emission estimates and
costs are included.
17.
a. DESCRIPTORS
KEY WORDS AND DOCUMENT ANALYSIS
b. IDENTIFIERS/OPEN ENDED TERMS
NESHAP, MACT, OH and Natural Gas Air Pollution control
Production, Natural Gas Transmission and
Storage.
18. DISTRIBUTION STATEMENT
Release Unlimited
19. SECURITY CLASS (Report)
Unclassified
20. SECURITY CLASS (Page)
Unclassified
c. COSATI Field/Group
21. NO. OF PAGES
124
22. PRICE
EPA Form 2220-1 (Rev. 4-77) PREVIOUS EDITION IS OBSOLETE
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EPA-453/R-94-079a
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
Emission Standards Division
U.S. Environmental Protection Agency
Office of Air and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
April 1997
11
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DISCLAIMER
This report has been reviewed by the Emission Standards Division,
Office of Air Quality Planning and Standards, U.S. Environmental
Protection Agency and approved for publication. Mention of trade
names or commercial products is not intended to constitute
endorsement or recommendation for use. Copies of this report are
available through the Library Services Office (MD-35), U.S.
Environmental Protection Agency, Research Triangle Park, North
Carolina 27711, or from the National Technical Information
Services, 5285 Port Royal Road, Springfield, Virginia 22161.
111
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TABLE OF CONTENTS
1.0
2.0
INTR
1.1
1.2
1.3
1.4
1.5
1 .fi
ODUCTION .
PURPOSE OF DOCUMENT
STATUTORY BASIS OF
SCOPE OF THE SOURCE
DOCUMENT CONTENTS .
DOCKET REFERENCE
REFERENCES . . . .
RULE
CATEGORIES
1-1
1-1
..... 1-1
1-2
. . . . . 1-3
. . . . . 1-3
1-5
THE OIL AND NATURAL GAS PRODUCTION AND NATURAL GAS
TRANSMISSION AND STORAGE SOURCE CATEGORIES ....
2 .1
2.2
2.3
2.4
2
2
2
2
2.2.4
2.2.5
2.2.6
2.3.2
2.3.3
2.3.4
2.3.5
INTRODUCTION .
SOURCE CATEGORY CHARACTERIZATION
2.2.1 Production Wells
Dehydration Units
Tank Batteries . . .
Natural Gas Processing Plants ......
Offshore Production Platforms ,
Natural Gas Transmission and Storage
Facilities
EXTRACTED STREAMS AND RECOVERED PRODUCTS ....
2.3.1 Crude Oil
Condensates
Natural Gas
Produced Water
Other Recovered Hydrocarbons
HAP Constituents
DESCRIPTION OF INDUSTRY COMPONENTS .
2.4.1 Production Wells
4.1.1 Wellhead Assembly
1.2 Production Methods
2.4.1.2.1 Primary Recovery
2.4.1.2.2 Secondary Recovery
2.4.1.2.3 Tertiary (Enhanced) Recovery
Dehydration
4.2.1 Glycol Dehydration . .
4.2.2 Solid Desiccant Dehydration ....
3 Tank Batteries
2.4.3.1 Separators . .
2.4.3.2 Dehydration .... . .
2 .3
2
2.4
2.4.2
2
2
2.4
2.4.3.3 Heater Treaters
2-1
2-1
2-2
2-2
2-3
2-3
2-4
2-4
2-5
2-5
2-5
2-6
2-6
2-7
2-7
2-7
2-8
, 2-8
. 2-8
2-10
2-10
2-10
2-10
2-10
2-11
2-12
2-12
2-14
2-14
2-14
IV
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TABLE OF CONTENTS (Continued)
2.4.3.4 Free Water Knockouts (FWKOs) ... 2-14
2.4.3.5 Gun Barrel Separation Tanks .... 2-15
2.4.3.6 Storage Tanks and Other Vessels . . 2-15
2.4.3.7 Custody Transfer . 2-16
2.4.4 Natural Gas Processing Plants 2-16
2.4.4.1 Dehydration 2-17
2.4.4.2 Sweetening and Sulfur Recovery
Processes 2-17
2.4.4.3 Conditioning Processes 2-17
2.4.4.4 Fractionation 2-18
2.4.4.5 Product Transfer and Metering . . . 2-18
2.4.5 Offshore Production Platforms 2-18
2.4.6 Compressor Stations 2-19
2.4.7 Underground Storage 2-19
2.4.8 Other Processes and Operations 2-20
2.5 HAP EMISSION POINTS 2-20
2.5.1 HAP Emission Points '. • 2-20
2.5.1.1 Process Vents 2-20
2.5.1.2 Storage Vessels 2-22
2.5.1.3 Equipment Leaks 2-23
2.6 BASELINE EMISSION ESTIMATES 2-23
2.6.1 Basic Methodology 2-23
2.6.2 Facility Emission Estimates . 2-25
2.7 REFERENCES 2-31
3.0 CONTROL OPTIONS AND PERFORMANCE OF CONTROLS 3-1
3.1 INTRODUCTION 3-1
3.2 PROCESS VENTS ..3-1
3.2.1 Vapor Recovery 3-1
3.2.2 Combustion 3-3
3.2.3 Pollution Prevention 3-3
3.3 STORAGE VESSELS 3-4
3.4 EQUIPMENT LEAKS 3-5
3.4.1 Leak Detection and Repair 3-5
3.4.1.1 Summary of Control Techniques
Guideline 3-6
3.4.1.2 Summary of New Source Performance
Standards 3-6
3.4.1.3 Summary of Equipment Leak
Requirements Under the Hazardous Organic
NESHAP Regulatory Negotiation 3-6
3.4.2 Equipment Modification 3-7
3.4.2.1 Valves 3-7
3.4.2.3 Pumps and Compressors 3-7
3.4.2.3 Sampling Connections 3-7
3.4.2.4 Pressure-Relief Devices 3-8
3.4.2.5 Open-Ended Lines 3-8
3.4.2.6 Connectors (Flanges) 3-8
3.5 CONTROL OPTIONS AND HAP EMISSION POINTS 3-8
3.6 REFERENCES 3-10
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TABLE OF CONTENTS (Continued)
4.0, MODEL PLANTS .' 4-1
4.1 INTRODUCTION 4-1
4.2 DESCRIPTIONS OF MODEL PLANTS ..... 4-2
4.2.1 Glycol Dehydration Units . . . 4-2
4.2.1.1 Glycol Dehydration Units 4-2
4.2.1.2 Distribution of Model Unit
Populations 4-3
4.2.1.3 Natural Gas Life Cycle ....... 4-6
4.2.2 Condensate Tank Batteries . 4-7
4.2.3 Natural Gas Processing Plants 4-7
4.2.4 Offshore Production Platforms in State
Waters -......- 4-9
4.2.5 Natural Gas Transmission and Storage . . . 4-12
4.3 REFERENCES ....... ... 4-12
5.0 ENVIRONMENTAL AND ENERGY IMPACTS OF CONTROL OPTIONS . .5-1
5.1 INTRODUCTION 5-1
5.2 AIR POLLUTANT IMPACTS 5-2
5.2.1 Primary Air Pollutant Impacts . . . . . . .5-2
5.2.2 Secondary Air Pollutant Impacts 5-6
5.3 WATER AND SOLID WASTE IMPACTS 5-6
5.4 ENERGY IMPACTS 5-8
6.0 COSTS OF CONTROL OPTIONS 6-1
6.1 INTRODUCTION . 6-1
6.2 SUMMARY OF COST METHODOLOGY .... . . .... . . . . 6-1
6.2.1 General Approach 6-1
6.2.2 Monitoring Equipment . . . . .6-2
6.2.3 Product Recovery 6-2
6.2.4 Monitoring, Inspection, Recordkeeping, and
Reporting . 6-3
6.2.5 Costs of HAP Emission Control Options . . . 6-3
6.2.5.1 Process Vents 6-3
6.2.5.2 Storage Tanks 6-4
6.2.5.3 Equipment Leaks ... 6-4
6.3 MODEL PLANT BASED CONTROL COSTS 6-4
6.3.1 Glycol Dehydration Units 6-5
6.3.2 Condensate Tank Batteries . . .6-5
6.3.3 Natural Gas Processing Plants 6-5
6.4 EXAMPLE . 6-5
6.5 REFERENCES ..... 6-12
APPENDIX A. EVOLUTION OF THE BACKGROUND INFORMATION
DOCUMENT A-l
APPENDIX B. NATIONAL IMPACTS METHODOLOGY B-l
B.I INTRODUCTION B-l
B.2 OVERVIEW OF METHODOLOGY • B-l
B.3 MODEL PLANT DEVELOPMENT B-l
VI
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TABLE OF CONTENTS (Continued)
B.4 CONTROL OPTIONS B-3
B.5 MODEL PLANT IMPACTS B-4
B.5.1 Emissions B~4
B.5.2 Costs • B-4
B.5.3 Other Impacts B-5
B.6 NATIONAL IMPACTS ESTIMATE B-6
B.7 REFERENCES . B~6
APPENDIX C. MONITORING, INSPECTION, RECORDKEEPING, AND
REPORTING COST METHODOLOGY C-l
C.I INTRODUCTION C-l
C.2 COST METHODOLOGY C-2
C.2.1 Example Costs for Major Source MIRR .... C-2
C.2.2 Number of Major Sources C-2
C.2.3 Example Costs for Area Source MIRR C-8
C.2.4 Number of Area Sources C-8
C.2.5 Continuous Monitoring C-8
C.3 BASIS OF METHODOLOGY C-ll
C.4 REFERENCES C-ll
vi x
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LIST OF TABLES
2-1 AVERAGE HAP COMPOSITION OF EXTRACTED STREAMS AND RECOVERED
PRODUCTS . . . . . 2-9
2-2 BASIC FACILITY TYPES AND ASSOCIATED HAP EMISSION
POINTS 2-21
2-3 BASELINE NATIONAL EMISSION ESTIMATES FOR ALL IDENTIFIED HAP
EMISSION SOURCES IN THE OIL AND NATURAL GAS PRODUCTION
SOURCE CATEGORY (MAJOR AND AREA HAP SOURCES) 2-24
2-4 BASELINE NATIONAL EMISSION ESTIMATES FOR IDENTIFIED MAJOR
HAP EMISSION SOURCES IN THE OIL AND NATURAL GAS PRODUCTION
SOURCE CATEGORY 2-26
2-5 BASELINE NATIONAL EMISSION ESTIMATES FOR IDENTIFIED AREA HAP
EMISSION SOURCES IN THE OIL AND NATURAL GAS PRODUCTION
SOURCE CATEGORY 2-27
2-6 BASELINE NATIONAL EMISSION ESTIMATES FOR ALL IDENTIFIED HAP
EMISSION SOURCES IN THE NATURAL GAS TRANSMISSION AND STORAGE
SOURCE CATEGORY (MAJOR AND AREA HAP SOURCES) 2-28
2-7 BASELINE NATIONAL EMISSION ESTIMATES FOR IDENTIFIED MAJOR
HAP EMISSION SOURCES IN THE NATURAL GAS TRANSMISSION AND
STORAGE SOURCE CATEGORY 2-29
2-8 BASELINE NATIONAL EMISSION ESTIMATES FOR IDENTIFIED AREA HAP
EMISSION SOURCES IN THE NATURAL GAS TRANSMISSION AND STORAGE
SOURCE CATEGORY 2-30
3-1 SUMMARY OF CONTROL OPTIONS PER HAP EMISSION POINT . . . 3-9
4-1 MODEL TRIETHYLENE GLYCOL (TEG) DEHYDRATION UNITS . . . .4-4
4-2 MODEL ETHYLENE GLYCOL (EG) DEHYDRATION UNITS ...... 4-5
4-3 MODEL CONDENSATE TANK BATTERIES. 4-8
4-4 MODEL NATURAL GAS PROCESSING PLANTS 4-10
Vlll
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LIST OF TABLES (Continued)
4-5 MODEL OFFSHORE PRODUCTION PLATFORMS 4-11
5-1 EXAMPLE NATIONAL PRIMARY AIR POLLUTANT IMPACTS FOR MAJOR
SOURCES IN THE OIL AND NATURAL GAS PRODUCTION SOURCE
CATEGORY 5-3
5-2 EXAMPLE NATIONAL PRIMARY AIR POLLUTANT IMPACTS FOR MAJOR
SOURCES IN THE NATURAL GAS TRANSMISSION AND STORAGE SOURCE
CATEGORY • 5~4
5-3 EXAMPLE NATIONAL PRIMARY AIR POLLUTANT IMPACTS FOR AREA
SOURCE GLYCOL DEHYDRATION UNITS IN THE OIL AND NATURAL GAS
PRODUCTION SOURCE CATEGORY 5-5
5-4 EXAMPLE NATIONAL SECONDARY AIR POLLUTANT IMPACTS DUE TO
FLARING FOR MAJOR AND AREA SOURCES IN THE OIL AND NATURAL
GAS PRODUCTION SOURCE CATEGORY 5-7
5-5 EXAMPLE NATIONAL ENERGY REQUIREMENTS 5-9
6-1 EXAMPLE CONDENSER CAPITAL COSTS FOR MODEL GLYCOL DEHYDRATION
UNIT TEG-C 6~7
6-2 EXAMPLE CONDENSER ANNUAL COSTS FOR MODEL GLYCOL DEHYDRATION
UNIT TEG-C 6"8
6-3 EXAMPLE CLOSED VENT SYSTEM CAPITAL COSTS FOR MODEL
CONDENSATE TANK BATTERY TB-G 6-9
6-4 EXAMPLE CLOSED VENT SYSTEM ANNUAL COSTS FOR MODEL CONDENSATE
TANK BATTERY TB-G . 6-10
6-5 EXAMPLE MODEL PLANT COST IMPACTS 6-11
A-l EVOLUTION OF THE BACKGROUND INFORMATION DOCUMENT . . . . A-2
C-l EXAMPLE ANNUAL MIRR COSTS PER GLYCOL DEHYDRATION UNIT
DESIGNATED AS OR LOCATED AT A MAJOR HAP EMISSION
SOURCE c~4
C-2 EXAMPLE ANNUAL MIRR COSTS PER STORAGE VESSEL OR CONTAINER
LOCATED AT A MAJOR HAP EMISSION SOURCE C-5
C-3 EXAMPLE ANNUAL MIRR COSTS PER LEAK DETECTION AND REPAIR
LOCATED AT A MAJOR HAP EMISSION SOURCE C-6
C-4 TOTAL ESTIMATED EXAMPLE MIRR COSTS FOR MAJOR HAP EMISSION
SOURCES IN THE OIL AND NATURAL GAS PRODUCTION SOURCE
CATEGORY C-7
IX
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LIST OF TABLES (Continued)
C-5
C-6
EXAMPLE ANNUAL MIRR COSTS PER GLYCOL DEHYDRATION UNIT
DESIGNATED AS AN AREA HAP EMISSION SOURCE ......
C-9
TOTAL ESTIMATED MIRR COSTS FOR GLYCOL DEHYDRATION UNITS IN
THE OIL AND NATURAL GAS PRODUCTION SOURCE CATEGORY
DESIGNATED AS AREA SOURCES C-10
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LIST OF FIGURES
1-1 Oil and Natural Gas Industry
2-1 Flow Diagram of Basic Glycol Dehydration Unit
, 1-4
2-13
'XI
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1.0 INTRODUCTION
1.1 PURPOSE OF DOCUMENT
National emission standards for hazardous air pollutants
(NESHAP) are being developed for the oil and natural gas
production source category and the natural gas transmission and
storage source category by the U.S. Environmental Protection
Agency (EPA). This background information document (BID)
describes technical information and analyses supporting
development of the NESHAPs for proposal in the Federal Register.
1.2 STATUTORY BASIS OF RULE .
The NESHAPs for the oil and natural gas and natural gas
transmission and storage source categories are being developed
under the authority of §112(d) of the Clean Air Act as amended in
1990 (CAA).1 Section 112(d) of the CAA directs the EPA
Administrator to promulgate regulations establishing hazardous
air pollutant (HAP) emission standards for each category of. major
and area sources of HAP that has been listed by the EPA for
regulation under §112(c). The 188 pollutants that are designated
as HAP are listed in §112(b).
A major source is defined as a stationary source or group of
stationary sources located within a contiguous area and under
common control that emits, or has the potential-to-emit (PTE)
considering controls, 10 tons per year (tpy) or greater of any
one HAP or 25 tpy or greater of any combination of HAP. An area
source is any stationary source that is not a .major source.
Special provisions in §112(n)(4) for.oil and gas wells and
pipeline compressor and pump station facilities affect major
source determinations for these facilities and also indicate
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under what circumstances the EPA may regulate oil and natural gas
production wells as an area source category.
The CAA prescribes the minimum degree of emission reduction
that must be required by standards developed under §112(d) for
existing and new major sources of HAP. Standards for existing
major sources may not be less stringent than the average emission
limitation achieved by the best performing 12 percent of the
existing sources for which the Administrator has emissions
information. Standards that are established for major sources
are referred to as maximum achievable control technology (MACT)
standards. Standards for new major sources must reflect the
maximum degree of emission reduction achieved in practice by the
best controlled similar source (best of the best).
For source categories with fewer than 30 sources, standards
may not be less stringent than the average emission limitation
achieved by the best performing five sources. Standards for
existing major sources may be more stringent than these minimums,
but must consider cost, non-air quality health and environmental
impacts, and energy requirements.
The CAA gives discretion to the Administrator when setting
standards under §112(d) for area sources of HAP. Standards for
area sources may either be based on MACT, as for major sources,
or on generally available control technology (GACT).
1.3 SCOPE OF THE SOURCE CATEGORIES
The oil and natural gas production source category includes
the processing and upgrading of crude oil prior to the point of
custody transfer and natural gas prior to entering the pipeline
systems associated with the natural gas transmission and storage
source category. Included in this source category are offshore
production platforms located in State waters. Facilities that
handle hydrocarbon liquids from the point of custody transfer are
in the organic liquids distribution (non-gasoline) source
category.
For natural gas streams, the natural gas transmission and
storage source category includes the pipeline transport, storage,
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and processing of natural gas prior to entering the final
pipeline of the local distribution company (LDC) that delivers
natural gas to the final end user. The scopes of these source
categories are illustrated in Figure 1-1.
1.4 DOCUMENT CONTENTS
This BID is intended to provide (1) basic information on the
process operations and HAP emission points associated with oil
and natural gas production and natural gas transmission and
storage and (2) information on controls and the impacts of
controls available to reduce HAP emissions from identified HAP
emission points. The description and analysis of regulatory
alternatives will be presented in other EPA documents.
Chapter 2.0 presents an overview of the source categories.
Chapter 3.0 identifies control options for HAPs that are
applicable to identified HAP emission points in the source
categories. Chapter 4.0 presents the model plants developed for
use in estimating the impacts of applying the control options.
Chapter 5.0 addresses the environmental and other impacts
resulting from applying control options to identified HAP
emission points in the source categories. Chapter 6.0 presents
the costs and cost-effectiveness of the control options.
Additional information is presented in three appendices to
this document. The appendices include (1) Appendix A - Evolution
of the BID, (2) Appendix B - National Impacts Methodology, and
(3) Appendix C - Monitoring, Inspections, Recordkeeping, and
Reporting Cost Methodology.
1.5 DOCKET REFERENCE
The docket for these regulatory actions is designated as
Docket No. A-94-04. The docket is an organized and complete file
of the information submitted to or otherwise considered by the
EPA in the development of this proposed rulemaking. The
principal purposes of the docket are (1) to allow interested
parties a means to identify and locate documents so that they can
effectively participate in the rulemaking process and (2) to
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serve as the record in case of judicial review (except for
interagency review materials) (§307(d)(7)(A) of the CAA).
The docket is available for public inspection and copying
between 8:30 a.m. and 4:30 p.m., Monday through Friday, at the
EPA's Air and Radiation Docket, Room M1500, U.S. Environmental
Protection Agency, 401 M Street, SW, Washington, DC 20460. A
reasonable fee may be charged for copying.
1.6 REFERENCES
1. United States Congress. Clean Air Act as amended November
1990. 42 U.S.C. 7401, et seq. Washington, DC. U.S.
Government Printing Office. November 1990.
1-5
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2.0 THE OIL AND NATURAL GAS PRODUCTION AND
NATURAL GAS TRANSMISSION AND STORAGE SOURCE CATEGORIES
2.1 INTRODUCTION
The oil and natural gas production and natural gas
transmission and storage source categories include the
separation, upgrading, storage, and transfer of extracted streams
(primarily hydrocarbons) that are recovered from production
wells.1 This chapter includes a summary characterization of
these source categories, along with descriptions of extracted
streams and recovered products, and the basic processes and
operations involved with oil and natural gas production and
natural gas transmission and storage. This chapter also presents
descriptions of identified hazardous air pollutant (HAP) emission
points associated with the processing, storing, and general
handling of these materials and products.
The extracted streams and recovered products for these
source categories include crude oil, condensate, natural gas, and
produced water. The types of processes and operations in these
source categories include production wells, dehydration units,
tank batteries, natural gas processing plants, offshore
production platforms, and pipeline transmission facilities,
including underground storage operations. The primary HAP
emission points associated with these source categories that are
being evaluated include process vents, storage vessels, and
equipment leaks.
Extracted streams and recovered products, processes and
operations, and HAP emission points are described below. This
chapter also addresses HAPs associated with these streams and
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products, facilities, and emission points, and includes baseline
HAP emission estimates.
2.2 SOURCE CATEGORY CHARACTERIZATION
The oil and natural gas production source category includes
the processing and upgrading of crude oil prior to the point of
custody transfer and natural gas prior to entering the pipeline
systems associated with the natural gas transmission and storage
source category. This source category includes offshore
production platforms located in State waters. Facilities that
handle hydrocarbon liquids after the point of custody transfer
are included as part of the organic liquids distribution (non-
gasoline) source category. For natural gas streams, the natural
gas transmission and storage source category includes the
pipeline transport, storage, and processing of natural gas prior
to entering the final pipeline of the local distribution company
(LDC) that delivers natural gas to the final end user. The scope
of these source categories are illustrated in Figure 1-1 of
Chapter 1.0 of this background information document (BID).
2.2.1 Production Wells
In 1992, there were an estimated 590,000 crude oil and
condensate production wells in the U.S., with a total annual
production of over 2.6 billion barrels and approximately 3
trillion cubic feet of co-produced natural gas. This was a
decrease of 3 percent in both the number of wells and in crude
oil production as compared with 1991 levels.2
Of this total number of crude oil and condensate production
wells, over 70 percent are classified as stripper wells, which
are production wells that are (1) nearing depletion or (2) have a
production rate of less than 10 barrels of oil per day (BOPD).
Stripper well production accounts for approximately 14 percent of
total domestic crude oil production.
In addition, for 1992, there were an estimated 280,000
natural gas production wells in the U.S., with a total estimated
annual production of over 18 trillion cubic feet. This estimate
represents a 3 percent increase in the number of wells and 1
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percent increase in natural gas production as compared with 1991
levels. ^ ••
2.2.2 Dehydration Units
Once the natural gas has been separated from any liquid
materials or products (crude oil, condensate, or produced water),
residual entrained water vapor is removed from the natural gas by
dehydration. Dehydration is necessary because water vapor may
form hydrates, that are ice-like structures, that can (1) cause
corrosion or (2) plug equipment lines.
The Gas Research Institute (GRI) estimates that there are
over 44,000 dehydration units in the U.S. Triethylene glycol
(TEG) dehydration units account for most of this estimated
population of dehydration units, with ethylene glycol (EG),
diethylene glycol (DEC), and solid desiccant dehydration units
accounting for the remaining portion.4
TEG dehydration units may be (1) stand-alone units that
dehydrate natural gas from an individual well or several wells or
(2) one of various processing units at condensate tank batteries,
natural gas processing plants, offshore production platforms, and
transmission facilities, including underground storage sites.
Available information indicates that, on average, there is one
TEG dehydration unit per condensate tank battery5 and two to four
dehydration units (TEG, EG, or solid desiccant) per natural gas
processing plant, depending upon throughput capacity and type of
processing configuration.6
2.2.3 Tank Batteries
A tank battery refers to the collection of process equipment
used to separate, treat, store, and transfer crude oil,
condensate, natural gas, and produced water. These facilities
typically handle crude oil, condensate, or natural gas prior to
transfer to a refinery or natural gas processing plant.
Based on an analysis of two studies conducted for the
American Petroleum Institute (API), the U.S. Environmental
Protection Agency (EPA) estimates that there were approximately
94,000 tank batteries in 1989.7'8'9 Over 85 percent of tank
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batteries,10 or an estimated 81,000 facilities, are classified as
black oil tank batteries. Black oil refers to crude oil that has
little, if any, associated gas production.
The remainder, or an estimated 13,000 tank beitteries, are
classified as condensate tank batteries. Condenseite, also
referred to as retrograde gas, consists of hydroccirbons that are
in a gaseous state under reservoir conditions, but become liquid
in either the wellbore or the production process.
2.2.4 Natural Gas Processing Plants
The main functions of natural gas processing plants include
(1) conditioning the gas by separation of natural gas liquids
(NGL) from field gas and (2) fractionation of NGL into separate
components. As of January 1, 1993, there were approximately 700
natural gas processing plants.1:L
2.2.5 Offshore Production Platforms
Offshore production platforms are used to produce, treat,
and separate crude oil, condensate, natural gas, and produced
water from production fields in offshore areas. Processes and
operations at offshore production platforms are similar to those
located at onshore facilities except that (1) there is generally
little or no storage capacity at offshore platforms and (2) these
facilities have limited available space.
In 1993, the U.S. Department of Interior's Minerals
Management Service (MMS) estimated that there were approximately
3,800 offshore production platforms and other structures in
Federal waters.12 The majority of these offshore production
platforms and other structures are located in the Central and
Western Gulf of Mexico, with a limited number located in other
Federal waters. The offshore facilities located in Federal
waters are under the jurisdiction of the MMS for air emissions
regulation and not the EPA.13 There are an estimated 300
offshore production platforms in State waters that are under the
EPA's jurisdiction for air emissions .regulation,1]* with the
majority of these facilities located in the State waters offshore
of Texas, Louisiana, and Alabama.
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2.2.6 Natural Gas Transmission and Storage Facilities
The natural gas transmission and storage source category
consists of gathering lines, compressor stations, and high-
pressure transmission pipeline. It is estimated that there are
approximately 1,900 compressor stations and over 480,000
kilometers (300,000 miles) of high-pressure transmission
pipeline.15'16 In addition, this sector includes over 300
underground storage sites.17'18 These sites are typically used
as temporary storage facilities to meet peak demand periods,
particularly during colder weather months. Processes and
operations that may occur at facilities in this source category
include dehydration, storage, and pipeline pigging activities.
2.3 EXTRACTED STREAMS AND RECOVERED PRODUCTS
The extracted streams and recovered products from production
wells have differing characteristics that can influence the level
of HAP emissions generated by the emission points in the oil and
natural gas production and natural gas transmission and storage
source categories. This section (Section 2.3) describes the
primary extracted streams and recovered products associated with
the two source categories.
2.3.1 Crude Oil
Each producing crude oil and natural gas field has its own
unique properties, in that the composition of the crude oil and
the attendant natural gas and reservoir (field) characteristics
are different from that of any other field.19
Crude oil can be broadly classified as paraffinic,
naphthenic (or asphalt-based), or intermediate. Generally,
paraffinic crudes are used in the manufacture of lube oils and
kerosene and have a high concentration of straight chain
hydrocarbons and are relatively low in sulfur compounds.
Naphthenic crudes are generally used in the manufacture of
gasolines and asphalt and have a high concentration of olefin and
aromatic hydrocarbons and may contain a high concentration of
sulfur compounds. Intermediate crudes are those that are not
classified in either of the above categories.20
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Another classification measure of crude oil and other
hydrocarbons is by API gravity. API gravity is a weight per unit
volume measure of a hydrocarbon liquid as determined by a method
recommended by the API.21 A heavy or paraffinic crude oil is
typically one with an API gravity of 20° or less, while a light
or naphthenic crude oil, which typically flows freely at
atmospheric conditions, usually has an API gravity in the range
of the high 30's to the low 40's.22
Crude oils recovered in the production phase of the
petroleum industry may be referred to as live crudes. Live
crudes contain entrained or dissolved gases which may be released
during processing or storage, whereas dead crudes are those that
have gone through various separation and storage phases and
contain little, if any, entrained or dissolved gases.23
2.3.2 Condensates
Condensates (by standard industry definition) are
hydrocarbons that are in a gaseous state under reservoir
conditions, but become liquid in either the wellbore or the
production process.24 Condensates, including volcitile oils,
typically have an API gravity in the 40 or greater degree
range.25 In addition, condensates may include hydrocarbon
liquids recovered from gaseous streams from various oil and
natural gas production or natural gas transmission and storage
processes and operations.
2.3.3 Natural Gas
Natural gas is a mixture of hydrocarbons and varying
quantities of non-hydrocarbons that exists in a gaseous phase or
in solution with crude oil or other hydrocarbon liquids in
natural underground reservoirs. Natural gas may contain
contaminants, such as hydrogen sulfide (H2S), carbon dioxide
(CO2)/ mercaptans, and entrained solids.
Natural gas streams that contain threshold concentrations of
H2S are classified as sour gases and those with threshold
concentrations of CO2 are classified as acid gases. The
processes by which these two contaminants are removed from the
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natural gas stream is called sweetening. The most common
sweetening method is amine treating.
Sour gas contains a H2S concentration of greater than 0.25
grain per 100 standard cubic feet, along with the presence of
CC>2. Concentrations of H2S and CO2, along with organic sulfur
compounds, vary widely among sour gases. Over 75 percent of
total onshore natural gas production and nearly all of offshore
natural gas production is classified as sweet.26
Natural gas may be classified as wet gas or dry gas. Wet
gas is unprocessed or partially processed natural gas produced
from a reservoir that contains condensable hydrocarbons.27 Dry
gas is (1) natural gas whose water content has been reduced
through dehydration or (2) natural gas that contains little or no
recoverable liquid hydrocarbons.28
2.3.4 Produced Water
Produced water is the water recovered from a production
well.2^ • Produced water is separated from the extracted
hydrocarbon streams in the various production processes and
operations described in this chapter.
2.3.5 Other Recovered Hydrocarbons
Various hydrocarbons may be recovered through the processing
of the extracted hydrocarbon streams. These hydrocarbons include
mixed NGL, natural gasoline, propane, butane, and liquefied
petroleum gas (LPG). Definitions for these hydrocarbons can be
found in Reference 27.
2.3.6 HAP Constituents
The primary identified HAP constituents associated with oil
and natural gas production facilities include benzene, toluene,
ethyl benzene, and mixed xylenes (collectively referred to as
BTEX), and n-hexane.-^O In addition, reference has been made to
the presence of 2,2,4-trimethylpentane (iso-octane), along with
general reference to the presence of formaldehyde, acetaldehyde,
and ethylene glycol in certain process and emission streams
associated with oil and natural gas production.31 Also, BTEX,
carbon disulfide (CS2), and carbonyl sulfide (COS) may be present
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in the tail gas streams associated with amine treating units and
sulfur recovery units (SRUs).32'33
Table 2-1 lists HAP constituents and concentrations for
extracted streams and recovered products for the two source
categories. The primary sources of data used in the development
of the listed HAP concentration estimates were (1) a summary of
the industry responses to the EPA's Air Emission Survey
Questionnaires,34 (2) a data base, provided by GRI, of natural
gas analyses from various source category operations,35 and (3) a
data base provided by API.36
2.4 DESCRIPTION OF INDUSTRY COMPONENTS
2.4.1 Production Wells
A well, as defined by API and used in this BID, is "... the
hole-in-the-ground drilled from the point of entry at the earth's
surface to the total depth of the hole ..." for the recovery of
crude oil, condensate, and natural gas from formations below the
earth's surface.37 The recovered products and extracted streams
from production wells are naturally or artificially brought to
the surface where the hydrocarbon products (crude oil,
condensate, and natural gas) are separated from produced water
and other impurities, such as sand. Depending on the production
characteristics of the well, and the recovery rates for crude
oil, condensate, and natural gas, a well may or may not be put
into production.
2.4.1.1 Wellhead Assembly. The wellhead assembly is the
surface equipment used to control the production from a well and
maintain production pressure. The wellhead assembly consists of
the casinghead, tubing head, Christmas tree, and pressure
gauges.38 These components are described below.
The casinghead is the collection of fittings that support
and hold the casing in place. The tubing head provides support
for the tubing. The tubing head also seals off pressure between
the casing and tubing, and provides connections for controlling
the flow of produced fluids from the well. The Christmas tree is
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TABLE 2-1. AVERAGE HAP COMPOSITION OF
EXTRACTED STREAMS AND RECOVERED PRODUCTS
HAP
Benzene
Toluene
Ethyl
benzene
Mixed
xylenes
n-Hexane
BTEXe
BTEX and
n-Hexane
HAP composition of extracted stream or recovered product
Crude oil Condensate Produced
(Weight %) (Weight %) water
(ppmw) a
0.25 0.99 10
0.48 3.50 6
0.12 0.48 6
0.55 4.90 13
1.50 2.80 4
1.40 9.90 35
2.90 13.00 39
Natural
Direct
from
wells
104
56
6
34
420
200
620
gas (ppmv)b'c
Wet Otherd
88 5
44 6
4 1
20 1
410 66
160 13
570 79
a - Parts per million weight.
b - Based on a review of the data collected in the EPA's Air Emissions
Survey Questionnaires and other references, the HAP content of the
primary fractionated products recovered in natural gas processing
operations (including propane, butane, and liquified petroleum gas) has
been identified as insignificant.
c - Parts per million volume.
d - Natural gas processed and stored at natural gas transmission facilities
and underground storage facilities.
e - Benzene, toluene, ethyl benzene, and mixed xylenes.
Note: Total BTEX and BTEX and n-hexane values have been rounded.
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the collection of valves and fittings mounted on the casinghead
and tubing head that controls the flow of product from the well.
2.4.1.2 Production Methods
2.4.1.2.1 Primary Recovery. Primary recovery of
hydrocarbon streams and produced water from a production well
occurs due to the natural pressures that exist in a production
reservoir. After some period, the natural pressures within a
reservoir will usually decline to a point where other secondary
or enhanced recovery methods must be employed to maintain a
well's production.
2.4.1.2.2 Secondary Recovery. When the natural pressure
within a reservoir is not sufficient for production, secondary
recovery methods or artificial lift methods (such as surface
pumping units, gas lift, or subsurface pumping) are applied to
increase the yield of recovered product. Waterflooding, pressure
maintenance, sucker rod pumping, and gas lift are common methods
of secondary recovery and artificial lift.39
2.4.1.2.3 Tertiary (Enhanced^ Recovery. Tertiary, or
enhanced, recovery methods are used to supplement natural
reservoir forces when primary and secondary recovery of the
product is no longer economical. These methods include chemical
and thermal methods and gas injection.
2.4.2 Dehydration40'41
As stated above, once the natural gas has been separated
from liquid materials and products, residual entrained water
vapor is removed from the natural gas stream by dehydration in
order to (1) meet contract sales specifications, (2) limit
hydrate formation, or (3) improve fuel heating values.
The formation of hydrates within a natural gas stream is
promoted by natural gas at or below its water dew point, with
liquid water present. Temperatures below the hydrate formation
temperature, high operating pressures, high velocity or agitation
through piping or equipment, presence of a small seed crystal of
hydrate, and presence of H2S or CO2 (which are more soluble in
water than hydrocarbons) also influence the formation of hydrates
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in natural gas pipelines.42 in addition, hydrate formation is
more often encountered during extended periods of cold weather.
Dehydration of natural gas may occur several times prior to
delivery to the final consumer. Locations where dehydration may
occur include (1) the production well site, (2) the tank battery,
(3) the natural gas processing plant, (4) removal from
underground storage facilities, (5) transmission compressor
stations, (6) industrial and utility customer meter stations, and
(7) at or after the transmission to distribution custody transfer
stations, which is the point where natural gas typically changes
ownership from a transmission company to a distribution company
for delivery to the final consumer. This final point of custody
transfer is typically referred to as the city gate.
Prior to the dehydration process in selected cases,
facilities may prevent hydrate formation by injecting ethylene
glycol or methanol into the natural gas stream, or using line
heaters to heat the process stream.
2.4.2.1 Glycol Dehydration. The most widely used natural
gas dehydration process is the glycol dehydration process.
Glycol dehydration is an absorption process in which a liquid
absorbent, a glycol, directly contacts the natural gas stream,
which is circulated counter current to the glycol flow, and
absorbs water vapor in a contact tower or absorption column.
The rich glycol, which has absorbed water vapor from the
natural gas stream, leaves the bottom of the absorption column
and is directed either to (1) a gas condensate glycol separator
(GGG separator or flash tank) and then a reboiler or (2) directly
to a reboiler where the water is boiled off of the rich glycol.
If the system includes a flash tank, the gas separated from the
rich glycol is typically either (1) recycled to the header
system, (2) used for fuel, or (3) used as a stripping gas. Any
hydrocarbons that condense can be removed as a separate stream
from the glycol. .
The regenerated or lean glycol is recirculated, by pump,
into the absorption tower. The vapor generated in the reboiler
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is directed to the reboiler stack. A flow diagram of a basic
glycol dehydration unit is presented in Figure 2-1.
2.4.2.2 Solid Desiccant Dehydration. Solid desiccant
dehydration uses adsorption to remove water. Adsorption refers
to the surface phenomena in which a gas or liquid is attracted to
the surface of a solid. Solid desiccant dehydration is generally
used when large dew-point depressions are required or when an
extremely dry gas is desired.43
Common solid desiccants used for natural gas dehydration
include silica-base beads, activated alumina, silica-gel,
alumina-gel balls, activated bauxite, and molecular sieves.44
Desiccant life ranges from one to five years before the desiccant
must be replaced.
Solid desiccant dehydration requires two or more adsorption
towers for continuous operation because the solid desiccant
within a tower must be regenerated when desiccant saturation is
reached. Therefore, when one tower is undergoing regeneration,
the other is switched into operation.
Regeneration may be accomplished by lowering the pressure,
or increasing the temperature of the tower or both. Hot
regeneration gas is typically circulated through the towers, and
then cooled through a heat exchanger that condenses water removed
from the tower packing.
The condensed water proceeds through a scrubber to recover
hydrocarbons. The remaining gas stream is recycled and mixed
with the incoming wet natural gas stream.45
2.4.3 Tank Batteries46'47
A tank battery refers to the collection of process equipment
used to separate, treat, and store crude oil, condensate, natural
gas, and produced water. The extracted products from production
wells enter the tank battery through the production header, which
may collect product from many wells.
Process equipment at a tank battery may include separators,
dehydrators, heater treaters, free water knockouts (FWKOs), gun
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barrel separation tanks, storage tanks, and lease automatic
custody transfer (LACT) units. Each piece of equipment is
addressed below.
2.4.3.1 Separators. The separation of hydrocarbon products
from basic sediment and water (BS&W) is accomplished by
production separators. Basic sediment refers to the gas, sand,
sediment, and other impurities mixed with the oil.
Depending on product characteristics, production separators
may be two-phase or three-phase separators. Two-phase separators
separate the product into liquid and gas streams. The liquid
stream contains crude oil and produced water. Three-phase
separators separate the product into crude oil or condensate,
natural gas and other gas streams, and produced water.
Multi-well facilities may also include test separators,
which operate in parallel to production separators, to determine
the production rate, composition, quality, and production
characteristics of individual wells.
2.4.3.2 Dehydration. The dehydration processes that may
occur at tank batteries are the same as those discussed in detail
in Section 2.4.2 of this BID.
2.4.3.3 Heater Treaters. Heater treaters are pressure
vessels used to break tight emulsions and remove water and gases
from crude oil. A heater treater is a combination of a heater, a
free water knockout, and an oil and gas separator,.
The inlet emulsion enters the heater treater at the top,
which allows the release of gas entrained in the liquid to travel
to the vapor space at the top of the column. The emulsion flows
to the bottom of the vessel through a downcomer pipe. Heat is
applied to the emulsion at the bottom of the vessel. Some
facilities add a chemical demulsifier to the process stream to
assist in the breaking of emulsions.
2.4.3.4 Free Water Knockouts (FWKOs). If large amounts of
water are produced with the crude oil, additional separation may
be accomplished by use of a FWKO. Removing the free water early
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in the separation process reduces the heating requirements and
design throughput requirements of the subsequent field equipment.
FWKOs may incorporate two-phase (liquid/gas) or three-phase
(crude oil/water/gas) separation. Heat or chemicals may be
applied to the incoming stream prior to the FWKO to assist in the
separation process.
2.4.3.5 Gun Barrel Separation Tanks. Gun barrel separation
tanks, or wash tanks, are cylindrical vessels operating at
atmospheric pressure that separate the production stream emulsion
into crude and produced water. Gun barrels may be used for
unstable emulsions that will naturally separate due to gravity,
if adequate settling time is provided.
2.4.3.6 Storage Tanks and Other Vessels. Crude oil from
the separation processes is typically directed to storage tanks
(or other storage vessels) for temporary storage. The large
majority of storage tanks used at crude oil production facilities
are fixed-roof storage tanks. In addition, over 95 percent of
the storage tanks used at tank batteries range in size from 200
to 1,000 barrel capacities.48 Vapor losses from the storage
tanks are either vented to the atmosphere or captured by a vapor
recovery device.
Storage tanks are also used for temporary storage of
produced water and slop oil. Produced water is typically
disposed of in injection wells, where water is injected back into
the producing formation for enhanced recovery applications,
transferred off-site for treatment and disposal, or (in very
limited cases) used for beneficial purposes.
Slop oil is oil that does not meet quality specifications.
This oil is either (1) recycled into the separation and treatment
process or (2) sold to an oil reclamation facility for treatment
and recovery of residual crude oil product.
Tank batteries may have various types of surface
impoundments (pits and sumps) located on-site. These pits and
sumps are typically classified as emergency or production. Most
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pits and sumps are classified as emergency pits/sumps and are
49
only used during process upset situations."
However, production pits and sumps may also be used for
separation processes at tank batteries. Most of production
surface impoundments are located in selected heavy crude oil
production areas of California.50
2.4.3.7 Custody Transfer. A LACT unit is usually used to
meter the amount of crude oil or condensate produced at a tank
battery. A LACT unit is an automated device that decreases the
need for the presence of personnel to handle the transfer of
crude oil or condensate. The unit records the amount of product
transferred and product temperature. Automatic sampling can be
incorporated into the LACT unit to determine product
quality.51'52'53
Transfer of extracted streams or recovered products is
usually accomplished in pipelines. However, transfer may also
involve loading crude oil, condensate, or produced water into
tank trucks, railcars, and barges through the use of splash
loading or submerged fill techniques.
2.4.4 Natural Gas Processing Plants
Natural gas produced from the well is separated from
hydrocarbon products (crude oil and condensate) and BS&W at tank
batteries and then transferred, via pipeline, to a natural gas
processing plant. Typical processes and operations at natural
gas processing plants are described below. Detailed descriptions
of processes and operations at natural gas processing plants are
presented in References 41 and 42.
As stated above, the primary functions of a natural gas
processing plant include (1) conditioning the natural gas by
separation of NGL from the field gas and (2) fractionation of NGL
into separate components. NGL may be fractionated into ethane,
propane, butanes, and natural gasoline products. These products
are then transported, primarily in pipeline systems, to
refineries and other points of transfer or sale.
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2.4.4.1 Dehydration. Generally, natural gas is dehydrated
prior to the other processes at a natural gas processing plant.
The natural gas dehydration process that may occur at a natural
gas processing plant is the same as natural gas dehydration
processes that may occur at other locations. Dehydration
processes are discussed in Section 2.4.2 of this BID.
2.4.4.2 Sweetening and Sulfur Recovery Processes. As
stated earlier in Section 2.3.3, some production fields produce
sour or acid gases. Sour gas is natural gas that contains
threshold concentrations of H2S. Hydrogen sulfide is a toxic,
corrosive substance which is usually removed by sweetening
operations that occur immediately after the natural gas has been
separated and dehydrated. Acid gases are those that contain
threshold concentrations of CC>2.
The most widely used method of sweetening these gases is
amine treating. Amine treating uses an amine/water solution to
absorb the H2S and CO2 from the natural gas stream. The rich
amine solution is then regenerated by steam stripping to rempve
the sour gas. The lean amine is recirculated to the absorber.
The system is similar in design to a glycol dehydration unit.
Natural gas fields may produce enough H2S so that it is
beneficial to recover sulfur. Sulfur recovery may be used at
natural gas processing facilities and offshore production
platforms. After the H2S is removed from the natural gas stream
in the sweetening process, the gas is introduced into a SRU for
further processing. At the sulfur recovery plant, the sulfur in
the H2S is converted to elemental sulfur. The recovered sulfur
can be either sold commercially or disposed of properly. Any CO2
contained in the gas stream will pass through the SRU unaltered
and vented with the tail gas. Concentrated CQ2 streams from the
sweetening process may be vented or flared to destroy any
residual hydrocarbons.
2.4.4.3 Conditioning Processes. Natural gas processing
plants may be characterized by the type of conditioning process
used at the plant. The conditioning processes most often used
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for separation in natural gas processing plants include
cryogenic-expansion, refrigeration, refrigerated absorption,
cryogenic-Joule-Thomson, absorption, adsorption, and compression.
Each conditioning process recovers the NGLs for further
treatment. Methane and other gases are removed from the NGL
stream prior to the fractionation process.
2.4.4.4 Fractionation. After separating the NGL from the
field gas, the NGL are separated into individual components, or
desired products, by a process called fractionation.
Fractionation uses the difference in volatility of the individual
components to separate the mixture.
Depending on the composition of the NGL mixture, the
fractionation system may include a deethanizer, depropanizer, and
debutanizer in series. These units are named according to the
desired product coming off the top of each fractionation unit.
Primary products include ethane, propane, butane, LPG, mixed NGL,
and natural gasoline.
2.4.4.5 Product Transfer and Metering. The primary method
used for transfer of gaseous and liquid products from natural gas
processing plants is by pipelines. However, transfer may include
loading of condensate or natural gasoline into tank trucks,
railcars, and barges through the use of splash loading or
submerged fill techniques.
The most common device used for measuring natural gas is the
orifice meter. A properly installed and maintained orifice meter
will have an overall accuracy of plus or minus 2 percent.54
2.4.5 Offshore Production Platforms55'56
The processes and equipment at offshore production platforms
that are used to produce, treat, and separate crude oil, natural
gas, and produced water in offshore areas are basically identical
to those at facilities located onshore, except that these
operations take place within a confined space.57 Offshore
production platforms are constructed.just large enough to
accommodate the necessary equipment and support facilities to
safely accomplish their tasks. This is done because the offshore
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production platforms are substantially more expensive to
construct than onshore facilities. Most offshore production
platforms have multiple deck areas stacked on top of each other
to increase the amount of work space. Detailed descriptions of
processes and operations at offshore production platforms are
presented in References 47 and 55.
Offshore production platforms may be bottom supported,
floating, or semi-submersible structures. They can be classified
as either gathering platforms or central production platforms.
Gathering platforms receive production from wells, separate the
production into liquid and gas streams, and then transfer these
streams by pipeline to a central production platform or an
onshore production facility. At central production platforms,
the liquid and gas streams undergo treatment, separation, and
(sometimes) storage. Gas treatment may include dehydration prior
to transfer to an onshore facility.
Produced water that is recovered from the production streams
may be disposed of overboard if it meets or is below certain
criteria of total oil and grease concentrations. In addition, it
may also be reinjected into a producing.zone within a reservoir
for pressure maintenance and enhanced recovery operations.
2.4.6 Compressor Stations
Compressor stations are facilities that supply energy, in
the form of increased pressure, to move natural gas in
transmission pipelines or into underground storage.^8 Typically,
compressor stations are located at intervals along a transmission
pipeline to maintain desired pressure for natural gas transport.
These stations will use either large internal combustion (1C)
engines or gas turbines as prime movers to provide the necessary
horsepower to maintain system pressure.
2.4.7 Underground Storage
Underground storage facilities are subsurface facilities
utilized for storing natural gas that has been transferred from
its original location for the primary purpose of load balancing.
Load balancing is the process of equalizing the receipt and
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delivery of natural gas.59 Processes and operations that may be
located at underground storage facilities include, but are not
limited to, compression and dehydration.
2.4.8 Other Processes and Operations
An operation that may occur throughout these source
categories is pipeline pigging. Pipeline pigging involves
inserting a pig, which is a cylindrical device made with pliable
disks that fit the internal diameter of a pipeline, into a
pipeline for the purpose of cleaning the line. Pipeline pressure
moves the pig through the line. Water vapor and hydrocarbon
liquids, such as condensate, may condense and restrict or block
pipeline flow, thus, leading to the necessity of pigging.
As the pig approaches the receiving station of a pipeline,
collected fluids (including hydrocarbon liquids) are drained to a
sump or other storage vessel that is usually referred to as a
slug catcher.60 Pigging of pipelines is a common practice for
pipelines from offshore production platforms because of the low
seabed temperatures encountered by the offshore pipelines, which
causes liquids to condense. Pigging of pipelines at onshore
facilities may be utilized during seasons with lower ambient
temperatures, such as fall and winter.
2.5 HAP EMISSION POINTS
2.5.1 HAP Emission Points
The three identified HAP emission points that may be
associated with oil and natural gas production and natural gas
transmission and storage include (1) process vents, (2) storage
vessels, and (3) equipment leaks. Table 2-2 presents the basic
facilities described above along with the identified HAP emission
points.
2.5.1.1 P-rpcess Vents. A process vent is a vent from a
process unit that discharges a gas stream into the atmosphere
during operation. Gas streams from process vents may be
discharged directly to the atmosphere or discharged through a
product recovery device.
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TABLE 2-2. BASIC FACILITY TYPES AND
ASSOCIATED HAP EMISSION POINTS
Facility type
HAP emission points
Stand-alone glycol dehydration unit
Condensate tank battery
Natural gas processing plant
Offshore production platform in
State waters
Natural gas transmission and
underground storage
Glycol dehydration unit reboiler
vent and flash tank vent
Glycol dehydration unit reboiler
vent and flash tank vent
Storage vessels
Glycol dehydration unit reboiler
vent and flash tank vent
Storage vessels
Equipment leaks
Glycol dehydration unit reboiler
vent and flash tank vent
Glycol dehydration unit reboiler
vent and flash tank vent
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The glycol dehydration unit reboiler vent is a source of HAP
emissions. In the glycol contact tower, glycol not only absorbs
water but also absorbs selected hydrocarbons, including BTEX and
n-hexane. The water and hydrocarbons are boiled-off in the
reboiler and, unless a control device is present, vented to the
atmosphere.
The GCG separator or flash tank is also a potential HAP
process vent emission point. HAP emissions will occur if the
glycol dehydration unit includes a flash tank in the system
design and any separated gases are vented to the atmosphere,
instead of being either (1) recycled to the header system, (2)
used for fuel, or (3) used as a stripping gas.
A process vent associated with natural gas sweetening
operations is the acid gas vent. This stream may contain high
concentrations of hydrogen sulfide and carbon dioxide. In
addition, BTEX, CS2, and COS may be present in this stream. If
high concentrations of H2S are present, a sulfur recovery plant
is installed to produce elemental sulfur. Otherwise, the stream
is flared.
Recent research conducted by GRI indicates the potential for
significant HAP emissions (primarily BTEX) from amine-based gas
sweetening processes.61'62 The EPA is conducting followup to
this research in an effort to determine emission levels of this
potential HAP process vent emission point.
2.5.1.2 Storage Vessels. Crude oil and condensate are
typically stored in fixed-roof storage tanks. Emissions are a
result of working, breathing, and flash losses.
Working losses occur due to the emptying and filling of
storage tanks. 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
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production source category, flashing occurs when live crude oils
or condensates flow into a storage tank from a processing vessel
operated at a higher pressure. Typically, the larger the
pressure drop, the more flashing emissions will occur in the
storage stage.63 Temperature of the liquid may also influence
the amount of flash emissions.
In addition, HAP emissions may occur when hydrocarbon
liquids, collected by slug catchers64 during pipeline pigging
(cleaning) operations, are transferred to storage tanks or other
vessels.65 HAP emissions may occur with the flashing of these
hydrocarbon liquids due to a reduction in pressure as collected
fluids are drained to a sump or other storage vessel.
2.5.1.3 Equipment Leaks. Equipment leaks (fugitive
emissions) are emissions emanating from valves, pump seals,
flanges, compressor seals, pressure relief valves, open-ended
lines, and other process and operation components. The amount of
HAP emissions from equipment leaks is proportional to (1) the
type and number of equipment components and (2) the concentration
of HAP constituents of the stream in the components.
Since tank batteries are usually small facilities as
compared with other industrial operations, they are generally
characterized by a smaller number of components. Natural gas
processing plants, especially those using refrigerated
absorption, tend to have a large number of components.
2.6 BASELINE EMISSION ESTIMATES
2.6.1 Basic Methodology
Based on available information, estimates were developed for
HAP, volatile organic compound (VOC), and methane66 emissions
from identified HAP emission points in the oil and natural gas
production and natural gas transmission and storage source
categories. Estimates of emissions before the implementation of
a national emissions standard for hazardous air pollutants
(NESHAP) are referred to as baseline.emission estimates.
Table 2-3 presents baseline HAP, VOC, and methane national
emission estimates for each facility type in the oil and natural
2-23
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TABLE 2-3. BASELINE NATIONAL EMISSION ESTIMATES FOR
ALL IDENTIFIED HAP EMISSION SOURCES IN THE
OIL AND NATURAL GAS PRODUCTION SOURCE CATEGORY
(MAJOR AND AREA HAP SOURCES)
Facility type
Glycol
dehydration
unitsa
Storage tanks at
condensate tank
batteries
Natural gas
processing
plants"
Total
Baseline emission estimates (Megagrams per year)
HAP
VOC
Methane
55,000
6,300
3,200
65,000
130,000
20,000
10,000
160,000
16,000
11,000
7,000
34,000
a -
b -
Includes estimated emissions from all glycol dehydration units,
including stand alone units and those located at condensate tank
batteries, natural gas processing plants, and offshore production
platforms in State waters. Does not include those units in the natural
gas transmission and storage source category.
Only includes emissions from storage tanks and equipment leaks.
Note; Numbers may vary due to rounding.
2-24
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gas production source category. These estimates are based on
model plant parameters that have been developed for the various
types of facilities in this source category (see Chapter 4.0 of
this BID). Tables 2-4 and 2-5 present a breakdown of these
emissions based on potential major versus area source HAP
emission designations for the oil and natural gas production
source category.
Table 2-6 presents baseline HAP, VOC, and methane national
emission estimates for each basic facility type in the natural
gas transmission and storage source category. These estimates
are based on model TEG dehydration unit parameters that have been
developed for various facility types in this source category (see
Chapter 4.0 of this BID). Tables 2-7 and 2-8 present a breakdown
of these emissions based on potential major versus area source
HAP emission designations for the natural gas transmission and
storage source category.
These estimates were developed using a model plant approach.
In this approach, emissions were first estimated for model plants
selected to characterize the range of facilities in the source
categories. National estimates were developed by extrapolating
from model plant estimates. The methodology for developing
nationwide emission estimates is further described in Chapter 5.0
and Appendix B of this BID.
2.6.2 Facility Emission Estimates
For glycol dehydration units, emissions are based on results
generated from GRI-GLYCalc (Version 3.0).67 This is a personal
computer-based screening program developed by GRI for evaluating
HAP and VOC emissions from TEG and EG dehydration units.
VOC emissions from production storage tanks have been
evaluated previously and these factors have been applied to the
estimated populations of these tanks in these source categories
and used as the basis for estimating HAP and methane emissions
from storage tanks.68 Fugitive emissions from components are
2-25
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TABLE 2-4. BASELINE NATIONAL EMISSION ESTIMATES FOR
IDENTIFIED MAJOR HAP EMISSION SOURCES IN THE
OIL AND NATURAL GAS PRODUCTION SOURCE CATEGORY
Facility type
Qlycol
dehydration
unitsa
Storage tanks at
condensate tank
batteries
Natural gas
processing
plantsb
Total
3. *"
Baseline emission estimates (Megagrams per year)
HAP
VOC
Methane
36,000
1,800
770
39,000
85,000
5,900
2,500
94,000
6,200
3,200
1,800
11,000
Includes estimated emissions from all glycol dehydration units,
including stand alone units and those located at condensate tank
batteries, natural gas processing plants, and offshore production
platforms in State waters designated as or located at; major sources of
HAP emissions. Does not include those units in the natural gas
transmission and storage source category.
b - Only includes emissions from storage tanks and equipment leaks.
Note; Numbers may vary due to rounding.
2-26
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TABLE 2-5. BASELINE NATIONAL EMISSION ESTIMATES FOR
IDENTIFIED AREA HAP EMISSION SOURCES IN THE
OIL AND NATURAL GAS PRODUCTION SOURCE CATEGORY
Facility type
Baseline emission estimates (Megagrams per year)
HAP
VOC
Methane
Glycol
dehydration
units3
Storage tanks at
condensate tank
batteries
Natural gas
processing
plantsb
Total
19,000
4,500
2,400
26,000
43,000
14,0.00
7,800
65,000
9,600
8,100
5,000
23,000
a - Includes estimated emissions from all glycol dehydration units,
including stand alone units and those located at condensate tank
batteries, natural gas processing plants, and offshore production
platforms in State waters that are not designated as potential major
sources of HAP emissions. Does not include those units in the natural
gas transmission and storage source category.
b - Only includes emissions from storage tanks and equipment leaks.
Note: Numbers may vary due to rounding.
2-27
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TABLE 2-6. BASELINE NATIONAL EMISSION ESTIMATES FOR
ALL IDENTIFIED HAP EMISSION SOURCES IN THE
NATURAL GAS TRANSMISSION AND STORAGE SOURCE CATEGORY
(MAJOR AND AREA HAP SOURCES)
Facility type
Qlycol
dehydration
units3-
Baseline emission estimates (Megagr.
HAP VOC
320 4,200
Methane
170
a - Includes estimated emissions from all glycol dehydration units in the
natural gas transmission and storage source category.
Note; Numbers may vary due to rounding.
2-28
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TABLE 2-7. BASELINE NATIONAL EMISSION ESTIMATES FOR
IDENTIFIED MAJOR HAP EMISSION SOURCES IN THE
NATURAL GAS TRANSMISSION AND STORAGE SOURCE CATEGORY
Facility type
Glycol
dehydration
units3
Baseline emission estimates (Megagrams per year)
HAP VOC Methane
120 1,500 59
a - Includes estimated emissions from all glycol dehydration units in the
natural gas transmission and storage source category, designated as or
located at major sources of HAP emissions.
Note: Numbers may vary due to rounding.
2-29
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TABLE 2-8. BASELINE NATIONAL EMISSION ESTIMATES FOR
IDENTIFIED AREA HAP EMISSION SOURCES IN THE
NATURAL GAS TRANSMISSION AND STORAGE SOURCE CATEGORY
Facility type
Glycol
dehydration
unitsa
Baseline emission estimates (Megagrc
HAP voc
200 2,700
Methane
110
a - Includes estimated emissions from all glycol dehydration units in the
natural gas transmission and storage source category that are not
designated as potential major sources of HAP emissions.
Npte; Numbers may vary due to rounding.
2-30
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based on (1) standard equipment leak emission factors69 and (2)
estimated component count distributions.
HAP emissions associated with pipeline pigging operations
were not estimated due to the lack of data on (1) how often this
procedure occurs in this industry and (2) the quantity of
hydrocarbons transferred from slug receivers to fixed-roof
storage tanks or other storage vessels. As stated earlier,
pipeline pigging will occur more often (1) at offshore production
operations and (2) during the winter months.
2.7 REFERENCES
1. U.S. Environmental Protection Agency. Documentation for
Developing the Initial Source Category List (EPA 450/3-91-
030). Research Triangle Park, NC. January 1992.
2. World Oil. February 1993. Gulf Publishing Company, Houston,
TX. -
3 . Reference 2.
4. Gas Research Institute. Natural Gas Dehydration: Status and
Trends. Final Report (GRI-94/0099). Chicago, IL. January
1994.
5. Memorandum from Akin, T., EC/R Incorporated, to Smith, M.E.,
EPA/CPB. July 30, 1993. Revised preliminary estimate of the
number and size ranges of tank batteries on a national
basis.
6. Memorandum from Viconovic, G., EC/R Incorporated, to Smith,
M.E., EPA/CPB. April 8, 1993. Summary of meeting with the
Gas Research Institute.
7. Gruy Engineering Corporation. Estimates of RCRA
Reauthorization Economic Impacts on the Petroleum Extraction
Industry. Dallas, TX. July 20, 1991.
8. Entropy Limited. Aboveground Storage Tank Survey. Lincoln,
MA. April 1989.
9. Reference 5.
10. Memorandum from Akin, T., and G. Viconovic, EC/R
Incorporated, to Smith, M.E., EPA/CPB. April 21, 1993.
Summary of the oil and natural gas production roundtable
workshop.
2-31
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11. Oil and Gas Journal. July 12, 1993. PennWell Publishing
Company, Tulsa, OK.
12 US Department of the Interior/Minerals Management Service.
" Federal Offshore Statistics: 1993 (OCS Report MMS 94-0060).
Herndon, VA. 1994.
13 US. Environmental Protection Agency. Regulatory Impact
Analysis and Regulatory Flexibility Act Screening for Outer
Continental Shelf Air Regulations. Research Triangle Park,
NC. April 1992.
14. U.S. Environmental Protection Agency/Office of Water.
Development Document for Effluent Limitations Guidelines and
New Source Performance Standards for the Offshore
Subcategory of the Oil and Gas Extraction Point Source
Category: Final (EPA 821-R-93-003). Washington, DC. January
1993.
15 Gas Research Institute. Preliminary Assessment of Air Toxic
Emissions in the Natural Gas Industry: Phase I (GRI-94-
0268). Chicago, IL. April 1994.
16. Gas Research Institute. The Vital Link: Moving Natural Gas
from Wellhead to Burner Tip. Chicago, IL. Fall 1990 (GRID
Reprint).
17. American Gas Association. Survey of Underground Gas Storage
Facilities in the United States and Canada. Catalog No.
XU9307. Arlington, VA. 1993.
18 US. Department of Energy/Energy Information Administration.
Natural Gas Annual 1990, Volume 1 (DOE/EIA-0131(90)/I).
Washington, DC. December 1991.
19 Speight, J.G. The Chemistry and Technology of Petroleum
(Second Edition, Revised and Expanded). New York, NY, Marcel
Dekker, Incorporated. 1991.
20 US. Environmental Protection Agency. Oil Field Emissions of
Volatile Organic Compounds (EPA 450/2-89-007). Research
Triangle Park, NC. April 1989.
21. Langenkamp, R. (ed.). The Illustrated Petroleum Reference
Dictionary (Third Edition). Tulsa, OK, PennWell Publishing
Company. 1985.
22. Reference 21.
23. Reference 21.
2-32
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24. American Petroleum Institute. Glossary of Oilfield
Production Terminology (First Edition). Washington, DC.
January 1, 1988.
25. McCain, W.D. Heavy Components Control Reservoir Fluid
Behavior. Journal of Petroleum Technology (Richardson, TX).
September 1994.
26. U.S. Environmental Protection Agency. SO2 Emissions in
Natural Gas Production Industry - Background Information for
Proposed Standards (EPA 450/3-82-023a). Research Triangle
Park, NC. November 1983.
27. American Gas Association. Glossary for the Gas Industry
(Fifth Edition). Arlington, VA. 1990.
28. Reference 27.
29. Ray, J.P., and F.R. Engelhardt. (ed.). Produced Water:
Technological/Environmental Issues and Solutions. New York,
NY, Plenum Press. 1990.
30. Gas Research Institute. Proceedings of the 1992 Gas Research
Institute Glycol Dehydrator Air Emissions Conference.
Chicago, IL. September 1992.
31. Oil and Gas Journal. May 17, 1993. PennWell Publishing
Company, Tulsa, OK.
32. Kohl, A.L. and F.C. Riesenfeld. Gas Purification (Third
Edition). Houston, TX, Gulf Publishing Company. 1987.
33. American Petroleum Institute. Review of Air Toxics Emissions
Calculations from Storage Tanks (Phase I) and Air Toxic
Emissions Calculation Validation Program: Analysis of Crude
Oil and Refined Product Samples and Comparison of Vapor
Concentration to Model Predictions (Phase II) (API
Publication 2525). Washington, DC. December 1992.
34. Responses to the U.S. Environmental Protection Agency's Air
Emissions Survey Questionnaires for the Oil and Natural Gas
Production Source Category (EPA Air Docket A-94-04, Items
II-D-1 through II-D-25). 1993.
35. Letter and attachment from Evans, J.M., Gas Research
Institute, to Viconovic, G., EC/R Incorporated. April 19,
1995. Natural gas BTEX content.
36. American Petroleum Institute. Triethylene Glycol Dehydrator
Operating Parameters for Estimating BTEX Emissions
(Prepublication Draft). Washington, DC. February 1996.
2-33
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37. Reference 24.
38. Reference 24.
39. American Petroleum Institute. Introduction to Oil & Gas
Production (Fourth Edition). Washington, DC. 1983
(Reaffirmed, May 1988).
40 Howell Training Company. Glycol Dehydration. American
Petroleum Institute PROFIT Series. Developed and distributed
for American Petroleum Institute. Houston, TX. 1987.
41. Gas Processors Suppliers Association in cooperation with the
Gas Processors Association. Engineering Data Book .- Volumes
I and II (Revised Tenth Edition). Tulsa, OK. 1994.
42. Ikoku, C.U. Natural Gas Production Engineering. New York,
NY, John Wiley & Sons. 1984.
43. Reference 32.
44. Reference 32.
45 The University of Texas at Austin, Petroleum Extension
Service. Field Handling of Natural Gas (Third Edition).
Austin, TX. 1977.
46. Arnold, K. and M. Stewart. Surface Production Operations.
Volume 1 - Design of Oil-Handling Systems and Facilities and
Volume 2 - Design of Gas-Handling Systems and Facilities.
Houston, TX, Gulf Publishing Company. 1986.
47. Bradley, H.R. Petroleum Engineering Handbook. Richardson,
TX, Society of Petroleum Engineers. 1987.
48. U.S. Environmental Protection Agency. Evaluation of
Emissions from Onshore Drilling, Producing, and Storing of
Oil and Gas (EPA 450/3-78-047). Research Triangle Park, NC.
August 1978.
49. American Petroleum Institute. Environmental OJuidance
Document. Onshore Solid Waste Management in Exploration and
Production Operations. Washington, DC. January 15, 1989.
50. California Air Resources Board/Stationary Source Division.
Technical Support Document for Suggested Control Measure for
the Control of Organic Compound Emissions from Sumps used in
Oil Production Operations. Sacramento, CA. August 11, 1988.
51. Reference 24.
52. Reference 47.
2-34
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53. Standards of Performance for Volatile Organic Liquid Storage
Vessels (including Petroleum Liquid Storage Vessels) for
Which Construction, Reconstruction, or Modification
Commenced after July 23, 1984. Code of Federal Regulations,
Title 40, Part 60, Subpart Kb. April 8, 1987. U.S.
Government Printing Office, Washington, DC.
54. Reference 41.
55. The University of Texas at Austin, Petroleum Extension
Service. A Primer of Offshore Operations (Second Edition).
Austin, TX. 1985.
56. Reference 47. .
57. Reference 39.
58. Reference 27.
59. Reference 27.
60. Reference 21.
61. Gas Research Institute. BTEX and Other VOC Emissions from a
Natural Gas Amine Treater (GRI-96/0048). Chicago, IL.
February 1996.
62. Gas Research Institute. Amine-Based Gas Sweetening and
Sulfur Recovery Process Chemistry and Waste Stream Survey
(GRI-95/0187). Chicago, IL. December 1995.
63. Canadian Petroleum Association. A Detailed Inventory of CH4
and VOC Emissions From Upstream Oil and Gas Operations in
Alberta. Volumes I through III. Alberta, Canada. March 1992.
64. Reference 21.
65. Memorandum from Akin, T. and G. Viconovic, EC/R
Incorporated, to Smith, M.E., EPA/CPB. May 27, 1994. Summary
of meeting with U.S. Enertek, Incorporated on May 23rd,
1994.
66. U.S. Department of Energy. Emissions of Greenhouse Gases in
the United States 1985 - 1990 (DOE/EIA-0573). Washington,
DC. September 1993.
67. Gas Research Institute. Technical Reference Manual for GRI-
GLYCalc™: A Program for Estimating Emissions from Glycol
Dehydration of Natural Gas, Version 3.0 (GRI-96/0091).
Chicago, IL. March 1996.
68. Reference 48.
2-35
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69 Standards of Performance for Equipment Leaks of VOC from
Onshore Natural Gas Processing Plants. Code of Federal
Regulations, Title 40, Part 60, Subpart KKK. July 1, 1992
U.S. Government Printing Office, Washington, DC.
2-36
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3.0 CONTROL OPTIONS AND PERFORMANCE OF CONTROLS
3.1 INTRODUCTION
This chapter addresses control options applicable to
identified hazardous air pollutant (HAP) emission points in the
oil and natural gas production and natural gas transmission and
storage source categories. As discussed in Chapter 2.0, HAP
emission points in these source categories include (1) process
vents, (2) storage vessels, and (3) equipment leaks. Control
options that may be applicable to each of these identified HAP
emission points are described below.
In addition, performance (measured as control efficiency) of
each control option was estimated based on best engineering
judgement and referenced literature. Referenced control
efficiencies of control options for volatile organic compounds
(VOC) emission points were deemed applicable for these HAP
emission points because of similar chemical properties of the HAP
constituents and VOC. These control efficiencies are consistent
with those demonstrated for similar applications.
3 . 2' PROCESS VENTS
As discussed in Chapter 2.0, the glycol dehydration unit
reboiler vent is the primary identified process vent HAP emission
point in these source categories. Several control techniques can
be used to reduce emissions from this process vent emission
point. These include vapor recovery (condensation), combustion,
and pollution prevention.
3.2.1 Vapor Recovery
Condensation is the most common vapor recovery control
technique used for glycol dehydration unit reboiler vents.
3-1
-------
Condensers convert condensable components in the vapor phase to
the liquid phase by reducing the temperature of the process vent
stream. Condensers not only reduce emissions, but also recover
condensable hydrocarbon vapors that may increase hydrocarbon
liquid production.
In addition, the dry non-condensable off-gas from the
condenser may be used as fuel.1 If the off-gas is not used as
fuel, it may be recycled into the production process or directed
to a flare, incinerator, or other combustion device. Since
combustion devices are sensitive to the amount of water content
in the process stream, condensers are typically installed prior
to combustion processes.
The HAP emission reduction efficiency of condensers varies
depending upon application.2 Some glycol dehydration units use
gas condensate glycol separators (GCG separators or flash tanks)
prior to the reboiler to separate entrained gases, primarily
methane and ethane, from the glycol. The flash tank off-gases
are typically recovered as fuel or recycled to the natural gas
production header. However, this process vent may also be vented
directly to the atmosphere.
Flash tanks typically enhance a condenser's emission
reduction efficiency by reducing the concentration of non-
condensable gases present in the stream introduced to the
condenser. Thus, condensers applied to those units with flash
tanks typically achieve higher emission reduction efficiencies as
compared to condensers used at glycol dehydration units that do
not incorporate flash tanks in their system design.
Condensers, used in conjunction with flash tanks
incorporated into the glycol circulation loop, typically achieve
95 percent HAP/VOC emission reduction.3 Condensers used on
glycol dehydration units without flash tanks incorporated into
the glycol circulation loop may have HAP/VOC reduction
efficiencies as low as 50 percent.4 .
3-2
-------
3.2.2 Combustion
Destruction of the HAP components in a process stream may be
accomplished by combustion. Combustion equipment includes
flares, thermal incinerators, industrial boilers, and process
heaters.
Flares are a common combustion device found at oil and
natural gas production facilities and at some natural gas
transmission operations. A flare is an open combustion device
where the air around the flame provides the necessary oxygen for
combustion. The flare combustion efficiency depends on vent gas
flammability, auto-ignition temperature, heating value, density,
and mixing of the components in the combustion zone.^ Facilities
that treat sour gas sometimes use flares to destroy hydrogen
sulfide. The hydrogen sulfide is oxidized to form sulfur
dioxide, a less toxic compound.
Flares were evaluated as a control option for glycol
dehydration unit reboiler vents. Because large amounts of water
are usually present in the glycol dehydration unit reboiler vent
stream, problems with incomplete combustion may occur. Flares
are most suitable when used in combination with condensers to
combust the non-condensable stream, or when vapor collected from
storage tanks must be destroyed.
Flares may achieve greater than a 98 percent HAP/VOC
reduction efficiency.^ Based on an emission reduction efficiency
of 95 percent for a condenser and a 98 percent emission reduction
efficiency for the combustion device, directing the non-
condensable stream through a closed-vent system to a combustion
device in conjunction with a condenser can achieve a HAP emission
reduction of 99 percent or greater.
3.2.3 Pollution Prevention
System optimization is a pollution prevention technique that
may be an applicable control option for some glycol dehydration
units. System optimization involves.the adjustment of glycol
dehydration unit process variables to reduce emissions.
3-3
-------
For example, glycol dehydration units may circulate more
glycol than is necessary to meet contract specifications.
Circulation rates of 2.0 to 3.0 gallons of glycol per pound of
water removed are recommended rates that are usually adequate to
meet typical contract pipeline specifications for water content
in the natural gas stream.7 Based on a recent report from the
American Petroleum Institute (API), the national average glycol
circulation rate for triethylene glycol (TEG) dehydration units
is 5.9 gallons of glycol per pound of water removed.8
This control option can be applied to glycol dehydration
units to improve process performance and reduce associated HAP
emissions from glycol dehydration unit reboiler vents. High
glycol circulation rates increase the amount of benzene, toluene,
ethyl benzene, and mixed xylenes (collectively referred to as
BTEX) and n-hexane absorbed from the natural gas stream.
Therefore, more BTEX and n-hexane are released from the glycol
dehydration unit reboiler vent during regeneration of the glycol
from these units that over circulate glycol. Thus, optimizing
the glycol dehydration process by adjusting the glycol
circulation rate may reduce associated HAP emissions.9
3.3 STORAGE VESSELS
The majority of storage tanks and vessels used in these
source categories are" fixed-roof storage tanks. Most of the
storage tanks used in the oil production segment (over 95
percent) have shell capacities in the range of 200 to 1,000
barrels.10
Internal floating roofs typically cannot be retrofitted to
these tanks because internal friction between the interior of
these small diameter tanks will inhibit proper operation of the
floating roof. In addition, the small quantities of liquid
stored in these tanks do not provide sufficient buoyancy to
support floating roofs.11
Emissions from fixed-roof storage tanks may be reduced by
using a vapor recovery unit (VRU) to capture escaping hydrocarbon
vapors. Once the vapor from the tanks is captured, it may be
3-4
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returned to the natural gas line for processing or be routed to a
control device.
Natural gas processing plants typically use pressurized
storage tanks to store light natural gas liquids (ethane,
propane, butane) and natural gasoline and to suppress evaporative
losses.12 However, hydrocarbons, including those collected in
slug receivers during pipeline pigging operations, may be
transferred to non-pressurized fixed-roof storage vessels.-^
3.4 EQUIPMENT LEAKS
The primary control option used to reduce emissions from
equipment leaks is a leak detection and repair (LDAR) program. A
LDAR program includes equipment monitoring (usually with a leak
detection instrument) on a prescribed schedule and the repairing
of equipment in instances where a leak is detected. Aspects of a
LDAR program are discussed below.
An alternative control option to a LDAR program is modifying
or replacing existing equipment to reduce emissions. This option
is also discussed below.
3.4.1 Leak Detection and Repair
LDAR programs involve regularly scheduled instrument
monitoring of equipment to determine the presence of leaks. Once
a leak is detected, the equipment is tagged and repaired on a
prescribed schedule.
The major factors affecting the control efficiency of a LDAR
program are (1) the frequency of equipment inspection and (2) the
leak definition that triggers repair requirements. Another
important component of a LDAR program is that it provides that
accurate records be kept on leak frequencies and repairs.
LDAR programs may include performance specifications for
individual equipment types. An example performance specification
might state that "... if 2 percent or more of the valves in light
liquid service leak more than 10,000 parts per million by volume
(ppmv) of VOC, then more frequent inspection is required."
Three different levels of LDAR were evaluated as options for
the oil and natural gas production source category. The three
3-5
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control options are summarized below. Detailed descriptions of
the LDAR programs are provided in References 14 through 17.
3.4.1.1 Summary of Control Techniques Guideline. The
Control Techniques Guideline (CTG) document, Control of Volatile
Organic Compound Equipment Leaks from Natural Gas/Gasoline
Processing Plants14 provides guidance for leak detection and
repair at plants located in ozone non-attainment areas. The
guideline includes quarterly monitoring of pressure relief
valves, valves in light liquid and vapor service, pumps in light
liquid service, and compressors. Pumps in light liquid service
are to be visually inspected on a weekly basis. Caps are to be
installed on open-ended lines when not in use. Equipment
servicing process streams with a VOC concentration of 1.0 percent
by weight or greater are subject to the requirements of the CTG.
3.4.1.2 Summary of New Source por-f o-rmanrg Standards. The
New Source Performance Standard (NSPS) for Equipment Leaks of VOC
from Onshore Natural Gas Processing Plants15 applies to such
plants with affected equipment constructed or modified after
January 20, 1984. The NSPS leak detection and repair, program
requires monthly monitoring of pressure relief valves, valves in
light liquid and vapor service, and pumps in light liquid
service. Valves in gas/vapor service and light liquid service
for which a leak is not detected for two consecutive months may
be monitored quarterly.
Weekly visual inspection of pumps in light liquid service is
also required. In addition to capping open-ended lines, capture
and vent systems are to be installed on compressor seals.
Equipment servicing process streams with a VOC concentration of
10 percent by weight or greater are subject to the requirements
of the NSPS.
3.4.1.3 Summary of Equipment Leak Requirements Under the
Hazardous Oraanin NESHAP Regulatory Negotiation. The Hazardous
Organic NESHAP (HON) Regulatory Negotiation16 was developed for
the synthetic organic chemical manufacturing industry. The
provisions of this regulation include monthly monitoring of
3-6
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valves in light liquid and vapor service and pumps in light
liquid service. Pumps in light liquid service are to be visually
inspected on a weekly basis.
The HON Regulatory Negotiation also phases-in more stringent
requirements for valves and pumps by using a combination of LDAR
programs and performance levels. In addition to capping open-
ended lines and vent systems on compressor seals, pressure relief
valves are to be equipped with rupture disk assemblies and
sampling lines are to be equipped with closed-purge systems.
Equipment servicing process streams with a HAP concentration
greater than 5.0 percent by weight are subject to the
requirements of the HON Regulatory Negotiation.
3.4.2 Equipment Modification
An equipment modification for reducing equipment leak
emissions may include the installation of additional equipment,
or the replacement of existing equipment. Equipment modification
is an alternative to LDAR programs for reducing emissions from
equipment leaks. Examples of equipment modification or
replacement are described below. Control efficiencies are cited
from the EPA's "Protocol for Equipment Leak Emission
Estimates."17
3.4.2.1 Valves. Emissions from valves can be reduced by
replacing old valves with bellows valves and diaphragm valves
(sealless valves). The control efficiency for sealless valves is
estimated to be 100-percent.
3.4.2.2 Pumps and Compressors. Emissions from pumps and
compressors may be collected by a closed-vent system and routed
to a control device. The control efficiency of this system
depends on the percentage of vapors collected and the efficiency
of the control device. Pumps and compressors may also be
equipped with dual mechanical seals with barrier fluid at a
higher pressure than the process stream. The control efficiency
of the dual mechanical seal system is approximately 100-percent.
3.4.2.3 Sampling Connections. Emissions from sampling
connections can be reduced by installing a closed-loop system,
3-7
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which has an estimated control efficiency of 100-percent. A
closed-loop sampling system collects the purged process fluid and
transfers it to a control device or directs it back into the
process stream.
3.4.2.4 Pressure-Relief Devices. To reduce emissions from
pressure-relief devices, rupture disks may be installed. Rupture
disk systems are estimated to have a 100 percent control
efficiency. Emissions from pressure-relief devices may also be
collected by a closed-vent system and routed to a control device.
The control efficiency of this option is dependent on the
percentage of vapors collected and the efficiency of the control
device.
3.4.2.5 Open-Ended Lines. Emissions from open-ended lines
can be reduced 100 percent by installing a plug, cap, or second
valve on the open end.
3.4.2.6 Connectors (Flanges). If allowable in the process,
connectors may be welded together to obtain a 100--percent control
efficiency.
3.5 CONTROL OPTIONS AND HAP EMISSION POINTS
A summary of control options applicable to the identified
HAP emission points at facilities in the oil and natural gas
production and natural gas transmission and storage source
categories are identified in Table 3-1. This table includes
estimated emission reduction efficiencies for each applicable
control option. These reduction efficiencies are based on the
control level achieved through reduction of VOC emissions, unless
otherwise specified.
3-8
-------
TABLE 3-1. SUMMARY OF CONTROL OPTIONS PER HAP EMISSION POINT
HAP emission point
Control options
Estimated
control
efficiency
Glycol reboiler vent
Open-top storage tank
Fixed-roof storage tank
Equipment leaks
Condenser, with
flash tank in
dehydration system
design
Condenser without
flash tank
Combustion
System optimization
Cover plus vapor
collection and
redirect
Vapor collection
and redirect
CTGC
NSPSd
HONe
95
50
98
Variable
99
95b
65
70
88
a -
b -
c -
d -
e -
Estimates based on referenced literature and engineering
j udgement.
Vapor redirected to a control device operating at a 95
percent control efficiency.
Estimated level of control based on Reference 13.
Estimated level of control based on Reference 14.
Estimated level of control based on Reference 15.
3-9
-------
-------
3.6 REFERENCES
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
Gas Research Institute. Proceedings of the 1992 Gas Research
Institute Glycol Dehydrator Air Emissions Conference.
Chicago, IL. September 1992.
U.S. Environmental Protection Agency. Alternative Control
Technology Document - Organic Waste Process Vents (EPA
450/3-91-007). Research Triangle Park, NC. December 1990.
Gas Research Institute. Glycol Dehydration Operations,
Environmental Regulations, and Waste Stream Survey (GRI-
96/0049). Chicago, IL. June 1996.
U.S. Environmental Protection Agency'. Condensation Systems
for Glycol Dehydrator Emissions Modeling and Design (Revised
Draft Report, Contract No. 68-01-0031, Work Assignment 067).
Research Triangle Park, NC. August 31, 1994.
U.S. Environmental Protection Agency. OAQPS Control Cost
Manual (Fourth Edition, EPA 450/3-90-006). Research Triangle
Park, NC. January 1990.
Reference 2.
American Petroleum Institute. Specification for Glycol-Type
Gas Dehydration Units (API Specification 12GDU, First
Edition). Washington, DC. December 15, 1990.
American Petroleum Institute. Triethylene Glycol Dehydrator
Operating Parameters for Estimating BTEX Emissions
(Prepublication Draft). Washington, DC. February 1996.
Gas Research Institute. Glycol Dehydrator Emissions:
Sampling and Analytical Methods and Estimation Techniques.
Volume I (GRI-94/0324). Chicago, IL. March 1995.
Entropy Limited. Aboveground Storage Tank Survey (Final
Report). Lincoln, MA. April 1989.
Memorandum from Viconovic, G., EC/R Incorporated, to Project
Files. March 6, 1992. Summary of conversation with Rob
Ferry, Conservatek Industries, on production tank emission
control systems.
Responses to the U.S. Environmental Protection Agency's Air
Emissions Survey Questionnaires for the Oil and Natural Gas
Production Source Category (EPA Air Docket A-94-04, Items
II-D-1 through II-D-25). 1993. . ' .
Memorandum from Viconovic, G., EC/R Incorporated, to Smith,
M.E., EPA:WCPG. July 10, 1996. Site visit report -
3-10
-------
14.
15.
16.
17.
Transcontinental Gas Pipe Line Corporation, Compressor
Station, District 160, Reidsville, North Carolina.
U.S. Environmental Protection Agency. Control of Volatile
Organic Compound Equipment Leaks from Natural Gas/Gasoline
Processing Plants (EPA-450/3-83-007). Research Triangle
Park, NC. December 1983.
Standards of Performance for Equipment Leaks of VOC From
Onshore Natural Gas Processing Plants. Code of Federal
Regulations, Title 40, Part 60, Subpart KKK. July 1, 1992.
U.S. Government Printing Office, Washington, DC.
National Emission Standards for Hazardous Air Pollutants;
Announcement of Negotiated Regulation for Equipment Leaks.
Federal Register, Vol. 56, No. 44, pp. 9315-9339. March 6,
1991. Office of the Federal Register, Washington, DC.
U S Environmental Protection Agency. Protocol for Equipment
Leak Emission Estimates (EPA-453/R-93-026). Research
Triangle Park, NC. June 1993.
3-11
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4.0 MODEL PLANTS
4.1 INTRODUCTION
Due to the large number of facilities in the oil and natural
gas production and natural gas transmission and storage source
categories, and the time and resources it would take to gather
information on each facility, it was not possible to simulate the
effects of applying control options at all potentially impacted
facilities in these source categories. Therefore, an alternative
approach involving the use of model plants was taken to estimate
plant-level and nationwide impacts of control options. The model
plants developed for these source categories are described in
this chapter.
A model plant does not represent any single actual facility,
but rather it represents a range of facilities with similar
characteristics that may be impacted by a standard. Each model
plant.is characterized in terms of facility type, size, and other
parameters that affect estimates of emissions, control costs, and
secondary environmental impacts. Impacts of control options are
estimated for each model plant and then extrapolated to estimate
impacts on a nationwide level.
To span the range of types and sizes of facilities in these
source categories, a number of model plants were developed.
Model plants were developed for (1) glycol dehydration units, (2)
condensate tank batteries, (3) natural gas processing plants, and
(4) offshore production platforms in State waters.
These model plants were developed based on available
information collected on processes, operations, and hazardous air
pollutant (HAP) emission points in the oil and natural gas
I
4-1
-------
production and natural gas transmission and storage source
categories. The information considered include (1) data from
industry responses to the U.S. Environmental Protection Agency's
(EPA's) Air Emissions Survey Questionnaires,1 (2) observations
made during four series of site visits to oil and natural gas
production and natural gas transmission and storage facilities
that were designed to collect information on processes and
operations and HAP emission points,2 (3) recommendations and
comments received from members of the American Petroleum
Institute (API) and its associated Clean Air Issues Group
(CAIG),3 (4) a data base of natural gas analyses for various
industry operations provided by the Gas Research Institute
(GRI),4 and (5) data provided by API.5
4.2 DESCRIPTIONS OF MODEL PLANTS
4.2.1 Glycol Dehydration Units
4.2.1.1 Glycol Dehydration Units. The glycol dehydration
unit reboiler vent has been identified as a significant source of
HAP emissions in the oil and natural gas production and natural
gas transmission and storage source categories. Glycol
dehydration units may be (1) stand-alone facilities that
dehydrate natural gas streams from an individual or series of
production wells or (2) part of the overall production process
located at condensate tank batteries, natural gas processing
plants, offshore production platforms in State and Federal
waters, and throughout the natural gas transmission source
category, including underground storage facilities.
Triethylene glycol (TEG) dehydration units account for most
of glycol dehydration units, with ethylene glycol (EG) and
diethylene glycol (DEC) dehydration units accounting for the
remaining estimated population of glycol dehydration units.
Based on information received from API's CAIG and GRI, the EPA
established an average number of (1) one TEG dehydration unit per
condensate tank battery6'7 and offshore production platform and
(2) two to four dehydration units (TEG, EG, or solid desiccant)
4-2
-------
per natural gas processing plant, depending upon throughput
capacity and type of processing configuration.^
Five separate model TEG dehydration units that represent the
size range for these units within the oil and natural gas
production and natural gas transmission and storage source
categories (based on natural gas design and throughput
capacities) were developed. The natural gas throughput capacity
ranges of the five model TEG dehydration units are (1) <5 million
standard cubic feet per day (MMSCF/D), (2) >5 to 20 MMSCF/D, (3)
>20 to 50 MMSCF/D, (4) >50 to 500 MMSCF/D, and (5) >500 MMSCF/D.
In addition, four separate model EG dehydration units that
represent the size range of these units within the oil and
natural gas production source category (based on natural gas
design and throughput capacities) were developed. The natural
gas throughput capacity ranges of the four model EG dehydration
units are (1) <20 MMSCF/D, (2) 20 to 100 MMSCF/D, (3) >100 to 500
MMSCF/D, and (4) >500 MMSCF/D.
Table 4-1 presents parameters for the five model TEG
dehydration units and Table 4-2 presents parameters for the four
model EG dehydration units. The parameters in this table are the
basic inputs used in GRI-GLYCalc™ (Version 3.0),9 a personal
computer-based emissions screening program developed by GRI for
evaluating HAP. and volatile organic compound (VOC) emissions from
TEG and EG dehydration units.
4.2.1.2 Distribution of Model Unit Populations. Tables 4-1
and 4-2 include the estimated number of glycol dehydration units
based on application (stand-alone, condensate tank batteries,
natural gas processing plants, offshore production platforms, and
natural gas transmission and storage). Estimates of the total
number of dehydration units in the U.S. range from 20,00010 to
recent projections of over 44, 0.00 . H'-^
The EPA standardized the analysis for dehydration units in
this regulatory development process by using a total national
estimated dehydration unit population of approximately 40,000,
which represents all dehydration units in every sector of
4-3
-------
TABLE 4-1. MODEL TRIETHYLENE GLYCOL (TEG) DEHYDRATION UNITS
p^—— ======= —
Parameter
Natural gas
Capacity (MMSCF/D)
Throughput (MMSCF/D)
Temperature (°F)
Pressure (psig)
1
•j Dry gas water content
(Pounds of water per
MMSCF/D)
1
Percent with flash tank in
system design
II
1 Glycol circulation rate
(Gallons of glycol per Ibs
of water removed)
Estimated population
distribution of TEG units
11
Stand-alone
Condensate tank battery
Natural gas processing
planta
Offshore production
platform in State waters
Natural gas transmission
1 and underground storage
Model TEG unit
ABC
^5 >5 to >20 to
20 50
0.28 10 35
90 90 90
700 700 700
777
10 40 55
5.9 5.9 5.9
24,000 200 25
12,000 500 100
66 110
260 40
200 125 25
>50 to
500
100
90
700
7
100
5.9
20
70
54
10
E
>500
500
90
700
7
100
5.9
10
MMSCF/D - Million of standard cubic feet per day
psig - Pounds per square inch gauge
a - Based on one of two parallel processing lines on-line at any one time
for the small natural gas processing plant and two of three on-line for
the larger model natural gas processing plants.
4-4
-------
TABLE 4-2. MODEL ETHYLENE GLYCOL (EG) DEHYDRATION UNITS
Parameter
Natural gas
Capacity (MMSCF/D)
Throughput (MMSCF/D)
Inlet Temperature (°F)
Contactor Temperature (°F)
Pressure (psig)
Dry gas water content (Pounds of
water per MMSCF/D)
Percent with flash tank in system
design
Glycol circulation rate (Gallons of
glycol per Ibs of water removed)
Estimated population distribution of
EG units
Natural gas processing plant3
Model EG units
A B C
<20 20 to >100
100 to 500
10 35 100
75 75 75
00 0
1,000 1,000 1,000
5 5 5
100 100 100
0.5 0.5 0.5
66 110 54
D
>500
500
75
0
1,000
5
100
0.5
30
MMSCF/D - Million of standard cubic feet per day
psig - Pounds per square inch gauge
a - Based on one of two parallel processing lines on-line at any one time
for the small natural gas processing plant and two of three on-line for
the larger model natural gas processing plants.
4-5
-------
both source categories, including the offshore production sector.
Of this, approximately 38,000 are glycol dehydration units
(primarily TEG and EG dehydration units) and 2,000 are solid
desiccant dehydration units.
The model glycol dehydration unit distribution for natural
gas processing plants reflects comments received from members of
API's CAIG. These comments indicate that the majority of natural
gas processing plants primarily employ non-glycol dehydration
units (some form of solid desiccant system) within their
processing stream, with the remaining natural gas processing
plants using either TEG or EG dehydration units within their
overall processing system design.13
4.2.1.3 Natural Gas Life Cycle. The number of times that
natural gas is dehydrated by glycol dehydration units during its
life cycle (life cycle being defined as from the point of
production of natural gas at a well, through its various
processing and storage stages, to the time when it is consumed by
the end user) is one of the components in the overall methodology
of determining model plant and nationwide impacts. In its
initial analyses, the EPA selected two times (2x) as the number
of times that natural gas is dehydrated by glycol dehydration
units in its life cycle. This was based on information from GRI,
which stated a lower limit of over Ix and an unknown upper
estimate that natural gas is dehydrated several times with glycol
systems in its life cycle.14
The EPA revised its estimate to approximately 1.6x for
natural gas dehydrated through all forms of dehydration units
(including solid desiccant units) located at all operational
sectors throughout the oil and natural gas production and natural
gas transmission and storage source categories. This revision
was based on comments received from members of API's CAIG and
through studies conducted by this group.15'16'17 This total
estimated life cycle factor includes accounting for offshore
dehydration (approximately 0.2x) that is not under the EPA's air
emissions regulatory jurisdiction.
4-6
-------
A recent GRI report estimated the natural gas life cycle at
between 2x and 3x. This report states "... In our discussions •
with the industry, it was stated that natural gas is frequently
dried multiple times, usually during production, before gas
processing, and in the transfer from underground storage."^
4.2.2 Condensate Tank Batteries
Four separate model condensate tank batteries that represent
the size range of condensate tank batteries (based on condensate
and natural gas design and throughput capacities) were developed.
The natural gas throughput capacity ranges of the four condensate
model batteries are (1) <5 MMSCF/D, (2) >5 to 20 MMSCF/D, (3) >20
to 50 MMSCF/D, and (4) >50 MMSCF/D.
Condensate tank batteries generally have a glycol
dehydration unit as a process unit within the overall system
design of the tank battery.-^ However, because glycol
dehydration units are addressed as separate model plants,
parameters for glycol dehydration units are not included with the
model condensate tank battery parameters. The parameters (other
than glycol dehydration unit parameters) for the model condensate
tank batteries are presented in Table 4-3.
Approximately 15 percent of all tank batteries, or an
estimated 13,000 tank batteries, are classified as condensate
tank batteries.20 A further breakdown of the number of
condensate tank batteries in each model condensate tank battery
size range is shown in Table 4-3. Parameters for model glycol
dehydration units are presented in Section 4.2.1 and Tables 4-1
and 4-2 of this BID.
4.2.3 Natural Gas Processing Plants
Three separate model natural gas processing plants that
represent different size ranges of natural gas processing plants
(based on natural gas design and throughput capacities) were
developed. The natural gas throughput capacity ranges of the
three model processing plants are (1) <20 MMSCF/D, (2) 20 to 100
MMSCF/D, and (3) >100 MMSCF/D.
4-7
-------
TABLE 4-3. MODEL COMPENSATE TANK BATTERIES
Parameter
Natural gas
Capacity (MMSCF/D)
Throughput (MMSCF/D)
Condensate throughput (BOPD)
Fixed-roof product storage tanks
210 barrel capacity
500 barrel capacity
1,000 barrel capacity
Components
Valves
Gas /vapor
Light liquid
Heavy liquid
Pump seals
Light liquid
Heavy liquid
Compressor seals
Pressure relief valves
Flanges and connections
Sampling connections
Open-ended lines
Total components
Estimated population
Model
E
£5
0.28
15
4
30
30
20
2
2
2
6
170
2
4
270
12, 000
condensate
F
>5 to
20
10
100
2
2
60
60
20
4
2
4
10
290
4
8
460
500
tank
G
H
>20 to >50
50
35
1,000
2
2
90
90
40
6
4
6
16
460
6
12
730
100
100
5,000
4
150
150
60
10
6
10
26
750
10
20
1,200
70
MMSCF/D - Million of standard cubic feet per day
BOPD - Barrels of,oil per day
4-8
-------
Parameters for the model natural gas processing plants are
presented in Table 4-4. As with the model condensate tank
batteries, parameters for model glycol dehydration units at
natural gas processing plants are not presented in Table 4-5.
Parameters for model glycol dehydration units are presented in
Section 4.2.1 and Tables 4-1 and 4-2.
As of January 1, 1993, there were approximately 700 domestic
natural gas processing plants.21 The cited reference includes a
listing of these natural gas processing plants by State, along
with design capacities and estimated 1992 throughputs. Based on
this annual survey, estimates of the number of natural gas
processing plants corresponding to each model plant size range
were made and are included in Table 4-4.
4.2.4 Offshore Production Platforms in State Waters
Two model offshore production platforms designed to be
representative of a small and a medium offshore production
platform that are typical of those located in State water areas
were developed. The parameters and values selected to
characterize these model offshore production platforms are
presented in Table 4-5.
As with the model condensate tank batteries and natural gas
processing plants, parameters for model glycol dehydration units
at offshore production platforms are not presented in this table.
Parameters for model glycol dehydration units are presented in
Section 4.2.1 and Tables 4-1 and 4-2 of this BID.
There are approximately 300 offshore production platforms in
State waters that are under the EPA's jurisdiction for air
emissions regulation.22 To characterize this segment of the oil
and natural gas production source category, the EPA requested
technical data from members of API's CAIG to assist in developing
model offshore production platforms that would be representative
of those located in State waters.23
4-9
-------
TABLE 4-4. MODEL NATURAL GAS PROCESSING PLANTS
Parameter
Natural gas
Capacity (MMSCF/D)
Throughput (MMSCF/D)
Fixed-roof product storage tanks
1,000 barrel capacity
Components
Valves
Gas /vapor
Light liquid
Heavy liquid
Pump seals
Light liquid
Heavy liquid
Compressor seals
Pressure relief valves
Flanges and connections
Sampling connections
Open-ended lines
Total components
Estimated population
A
<20
10
4
300
60
20
4
2
4
10
1,200
4
8
1,600
260
Model natural gas
processing plant
B
20 to 100
35
4
750
150
40
10
4
10
24
3,200
10
10
4,200
300
C
>100
200
4
1,800
360
60
24
6
24
54
12,000
24
48
14, 000
140
MMSCF/D - Million of standard cubic feet
a - Primary products loaded are natural
per day
gasoline and condensate.
4-10
-------
TABLE 4-5. MODEL OFFSHORE PRODUCTION PLATFORMS
Parameter
Number of well slots
Production wells
Crude oil capacity (BOPD)
Crude oil production (BOPD)
Natural gas capacity (MMSCF/D)
Natural gas production (MMSCF/D)
Components
Valves
Gas /vapor
Light liquid
Heavy liquid
Pump seals
Light liquid
Heavy liquid
Compressor seals
Pressure relief valves
Flanges and connections
Sampling connections
Open-ended lines
Total components
Estimated population
Small
2
1
1,000
200
10
5
60
15
2
1
1
3
2
500
1
2
590
260
Medium
18
8
5,000
2,000
20
10
540
120
8
1
3
7
16
4,000
3
2
4,700
40
BOPD - Barrels of oil per day
MMSCF/D - Million of standard cubic feet per day
4-11
-------
However, as of the date of this background information
document (BID), the requested technical data on State water
offshore production platforms have not been received from API's
CAIG. Due to this, the EPA developed its characterization of
offshore production platforms located in State waters and
estimated model parameters based on data appearing in an U.S.
Department of Interior's Minerals Management Service (MMS) report
on Federal offshore statistics.24
4.2.5 Natural Gas Transmission and Storage
The only HAP emission point of concern for the national
emission standards for hazardous air pollutants (NESHAP) for
natural gas transmission and storage facilities is any process
vent associated with a glycol dehydration unit at these
facilities. According to industry representatives, 80 percent of
dehydration units used in the natural gas transmission and
storage source category are TEG dehydration units, with solid
'25
desiccant systems accounting for most of the remaining units.
There are few, if any, EG dehydration units in this source
category.26'27
Thus, as with the model condensate tank batteries, natural
gas processing plants, and offshore production platforms located
in State waters, parameters for model TEG dehydration units at
natural gas transmission, and storage facilities are not presented
in this section of the BID. The parameters for model TEG
dehydration units are presented in Section 4.2.1 and Table 4-1 of
this BID.
4.3 REFERENCES
1. Responses to the U.S. Environmental Protection Agency's Air
Emissions Survey Questionnaires for the Oil and Natural Gas
Production Source Category (EPA Air Docket A-94-04, Items
II-D-1 through II-D-25). 1993.
2 Site Visit Trip Report Series from Viconovic, G., EC/R
Incorporated, to Smith, M.E., EPA/CPB (EPA/WCPG). 1992,
1993, and 1996.
3 Memorandum from Akin, T., and G. Viconovic, EC/R
Incorporated, to Smith, M.E., EPA/CPB. April 21, 1993.
4-12
-------
Summary of the oil and natural gas production roundtable
workshop.
4. Letter, and attachment from Evans, J.M., Gas Research
Institute, to Viconovic, G., EC/R Incorporated. April 19,
1995. Natural gas BTEX content.
5. American Petroleum Institute. Triethylene Glycol Dehydrator
Operating Parameters for Estimating BTEX Emissions
(Prepublication Draft). Washington, DC. February 1996.
6. Memorandum from Akin, T., EG/R Incorporated, to Smith, M.E.,
EPA/CPB. July 30, 1993. Revised preliminary estimate of the
number and size ranges of tank batteries on a national
basis.
7. Reference 3.
8. Memorandum from Viconovic, G., EC/R Incorporated, to Smith,
M.E., EPA/CPB. April 8, 1993. Summary of meeting with the
Gas Research Institute.
9. Gas Research Institute. Technical Reference Manual for GRI-
GLYCalc™: A Program for Estimating Emissions from Glycol
Dehydration of'Natural Gas, Version 3.0 (GRI-96/0091).
Chicago, IL. March 1996.
10. GRID: Gas Research Institute Digest (Summer 1993). Gas
Research Institute, Chicago, IL.
11. Chemical Engineering. December 1993. McGraw Hill Publishing
Company, Hightstown, NJ.
12. Gas Research Institute. Natural Gas Dehydration: Status and
Trends. Final Report (GRI-94/0099). Chicago, IL. January
1994.
13. Memorandum from Akin, T., and G. Viconovic, EC/R
Incorporated, to Smith, M.E., EPA/CPB. June 23, 1994.
Summary of the meeting with the American Petroleum
Institute's Clean Air Issues Group on May 17th, 1994.
14. Reference 8.
15. Reference 13.
16. Memorandum and attachments from Viconovic, G., EC/R
Incorporated, to Smith, M.E., EPA/WCPG. June 26, 1995.
Summary of the April 26th, 1995,. teleconference with
representatives of the American Petroleum Institute.
17. Reference 5.
4-13
-------
18. Reference 12.
19. Reference 1.
20. Reference 1.
21. Oil and Gas Journal. July 12, 1993. PennWell Publishing
Company, Tulsa, OK.
22 U.S. Environmental Protection Agency/Office of Water.
Development Document for Effluent Limitations Guidelines and
New Source Performance Standards for the Offshore
Subcategory of the Oil and Gas Extraction Point Source
Category: Final (EPA 821-R-93-003). Washington, DC. January
1993.
23. Memorandum from Akin, T., and G. Viconovic, EC/R
Incorporated, to Smith, M.E., EPA/CPB. February 14, 1994.
Summary of Meeting with the American Petroleum Institute's
Clean Air Issues Group.
24 US Department of the Interior/Minerals Management Service.
Federal Offshore Statistics: 1993 (OCS Report. MMS 94-0060).
Herndon, VA. 1994.
25. Memorandum from Viconovic, G. , EC/R Incorporated, to Smith,
M E., EPA/WCPG. July 10, 1996. Site visit report -
Transcontinental Gas Pipe Line Corporation, Compressor
Station, District 160, Reidsville, North Carolina.
26. Reference 25.
27. Memorandum from Viconovic, G., EC/R Incorporated, to Smith,
M.E., EPA/WCPG. December 7, 1995. Summary of November 9
1995, meeting with representatives of the natural gas
transmission industry.
4-14
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5.0 ENVIRONMENTAL AND ENERGY IMPACTS OF CONTROL OPTIONS
5.1 INTRODUCTION
This chapter provides a discussion of the environmental and
energy impacts associated with the control options that have been
identified as applicable to the identified hazardous air
pollutant (HAP) emission points in the oil and natural gas
production and natural gas transmission and storage source
categories. The control options under evaluation for HAP
emission points identified in these source categories are listed
in Table 3-1 of Chapter 3.0 of this background information
document (BID).
The control options applicable to the identified HAP
emission points include a variety of emission reduction
techniques. The control options include (1) the.use of emissions
control equipment (e.g., installation of a cover or fixed-roof
for tanks) and (2) work standards (e.g., system optimization for
glycol dehydration units and leak detection and repair (LDAR)
programs for fugitive emission points).
Two control options being evaluated for HAP emission points
in these source categories may have secondary environmental
impacts or energy-use impacts. These control options include the
use of (1) a combustion system (flare) for remotely located
facilities and (2) a vapor collection and redirect system for
fixed-roof storage tanks.
The impact analyses consider a facility's ability to handle
collected vapors. Some remotely located facilities may not be
able to use collected vapor for fuel or recycle it back into the
5-1
-------
process. In addition, it may not be technically feasible for
some facilities to utilize the non-condensable vapor streams from
condenser systems as an alternative fuel source safely. An
option for these facilities is to combust these vapors by
flaring.
These concerns are reflected in the analyses conducted by
the EPA. In its analyses, the EPA estimated that (1) 45 percent
of all impacted facilities will be able to use collected vapors
as an alternative fuel source for an on-site combustion device
such as a process heater or the glycol dehydration unit firebox,
(2) 45 percent will be able recycle collected vapors into a low
pressure header system for combination with other hydrocarbon
streams handled at the facility, and (3) 10 percent will direct
all collected vapor to an on-site flare.
5.2 AIR POLLUTANT IMPACTS
5.2.1 Primary Air Pollutant Impacts
The primary air pollutant impacts are based on the estimated
control efficiency of the control options listed in Table 5-1.
Emission reductions for control of the glycol dehydration unit
reboiler vent are based on the application of (1) a condenser
with a flash tank in the design of the glycol dehydration system
or (2) an equivalent HAP control system.
The control options that are being evaluated for HAP
emission points in these source categories are also effective in
the control of volatile organic compound (VOC) and methane
emissions from the same identified emission points. Thus, the
primary air pollutant impacts associated with control of HAP
emission points include reductions in associated VOC and methane
emissions. The primary nationwide air pollutant impacts, which
are reductions in HAP, VOC, and methane air emissions associated
with major HAP emission points in these source categories, are
presented in Tables 5-1 and 5-2. The primary nationwide air
pollutant impacts associated with area source glycol dehydration
units are presented in Table 5-3.
5-2
-------
TABLE 5-1. EXAMPLE NATIONAL PRIMARY AIR POLLUTANT IMPACTS FOR
MAJOR SOURCES IN THE
OIL AND NATURAL GAS PRODUCTION SOURCE CATEGORY
Emission point
Baseline
Process vents
Storage vessels
Equipment leaks
Total baseline
Reduction
Process vents
Storage vessels
Equipment leaks
Total reduction
Controlled3
Process vents
Storage vessels
Equipment leaks
Total controlled
HAP
36,000
2,100
470
39,000
28,000
1,500
230
30,000
8,000
640
240
8,900
Emissions (Megagrams per year)
VOC
85,000
6,900
1,500
94,000
55,000
4,800
730
61,000
30,000
2,100
770
33,000
Methane
6,200
3,900
1,100
11,000
3,800
2,700
540
7,000
2,400
1,200
560
4,200
a - Based on following control options:
Glycol dehydration unit - Condenser with flash tank in design
Storage tanks - Vent to 95% control device
Equipment leaks - 70% level of control
5-3
-------
TABLE 5-2. EXAMPLE NATIONAL PRIMARY AIR POLLUTANT IMPACTS FOR
MAJOR SOURCES IN THE
NATURAL GAS TRANSMISSION AND STORAGE SOURCE CATEGORY
Emission point
Baseline
Process vents
Reduction
Process vents
Controlled3
Process vents
Emissions (Megagrams per y«ar)
VOC Methane
120
110
10
1,500
1,400
100
59
54
a - Based on following control options:
Glycol dehydration unit - Condenser with flash tank in design
5-4
-------
TABLE 5-3. EXAMPLE NATIONAL PRIMARY AIR POLLUTANT IMPACTS FOR
AREA SOURCE GLYCOL DEHYDRATION UNITS IN THE
OIL AND NATURAL GAS PRODUCTION SOURCE CATEGORY
Emission point
Emissions (Megagrams per year)
HAP VOC Methane
Baseline
Process vents
Reduction
Process vents
Controlled3
Process vents
19,000
3,300
16,000
43,000
7,200
36,000
9,600
1,500
8,100
a -
Based on the application of a condenser with flash tank in design to
area source glycol dehydration units. Of the estimated total population
of approximately 37,000 area source glycol dehydration units,
approximately 520 units would be required to install controls.
5-5
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5.2.2 Secondary Air Pollutant Impacts
Secondary emissions of air pollutants result from the
operation of certain control devices (such as a flare) that may
be used to comply with a standard. For condenser systems, it is
estimated that 45 percent of impacted glycol dehydration units
will use the non-condensable portion of the emission stream as a
supplemental fuel source for the glycol reboiler. Thus, there is
no net change in energy use associated with the application of
this control option for those facilities that incorporate this
design and no net change in combustion-related emissions.
A portion of impacted facilities (10 percent) are judged to
be remotely located or technically unable to utilize collected
vapors. These facilities flare collected emission streams.
Thus, there will be an increase in sulfur dioxide (SOX), nitrogen
oxide (NOX), and carbon monoxide (CO) emissions from this
combustion. Table 5-4 presents the secondary air pollutant
impacts on a national basis. The estimated national annual
increase in secondary air emissions from flaring will be <1
megagram (Mg) of SOX, 7 Mg of NOX, and 1 Mg of CO.
5.3 WATER AND SOLID WASTE IMPACTS
The condensed water collected with the hydrocarbon
condensate can be directed back into the system for reprocessing
with the hydrocarbon condensate or, if separated, combined with
produced water for disposal by reinjection. Thus, the water
impact associated with installation of a condenser system for a
glycol dehydration unit reboiler vent would be minimal.
Water vapor may be collected along with hydrocarbon vapors
in the vapor collection and redirect system for fixed-roof
storage tanks. The water vapor may condense in the control
systems. A knockout designed into the system will collect any
condensable product (water and hydrocarbons). As with the
condenser system, this water can be directed back into the system
for reprocessing with the hydrocarbon condensate or, if
separated, combined with produced water for disposal by
5-6
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TABLE 5-4. EXAMPLE NATIONAL SECONDARY AIR POLLUTANT IMPACTS DUE
TO FLARING FOR MAJOR AND AREA SOURCES IN THE
OIL AND NATURAL GAS PRODUCTION SOURCE CATEGORY3
Model plant and
emission point
Stand alone
glycol units
A
B
C
D
Tank battery
F
G
H
Natural gas
processing plants
A
Total
Estimated number
installing flare
52
34
4
2
6
4
2
1
Estimated
emissions per
flare*3 (Kilograms
per year)
SOX NOX CO
<1 48 10
<1 48 10
<1 48 10
<1 52 11
<1 48 10
<1 48 10
<1 52 11
<1 48 10
Total (Megagrams
per year)
SOX NOX CO
<1 2 <1
<1 2 <1
<1 <1 <1
<1 <1 <1
<1 <1 <1
<1 <1 . <1
<1 <1 . <1
<1 <1 <1
<1 7 1
a - No major sources in the natural gas transmission and storage source
category are anticipated to use flares.
b - SOX - Sulfur dioxide
NOX - Nitrogen oxides
CO - Carbon monoxide
5-7
-------
reinjaction. Thus, the water impact associated with installation
of vapor control systems would be minimal.
There are no identified solid wastes that would be generated
by installation of (1) a condenser system for the glycol
dehydration unit reboiler vent or (2) a vapor collection and
redirect system for fixed-roof storage tanks. Thus, no solid
waste impacts are anticipated with the installation of these
systems.
5.4 ENERGY IMPACTS
If vapor collection and redirect systems is used for the
control of emissions from a fixed-roof storage tank, it would
require electricity for operation of the primary components of
the vapor collection/recovery system. These components include
fans and blowers for proper operation of the system.
The annual estimated energy requirements for each vapor
collection/recovery system is 300 kilowatt hours per year (kw-
hr/yr). It is estimated that approximately 125 facilities would
install one or more of these control options.
The national energy demand impact is presented in Table 5-5.
The estimated national electrical demand that would result from
the operation of all control options is 38,000 kw-hr/yr.
5-8
-------
TABLE 5-5. EXAMPLE NATIONAL ENERGY REQUIREMENTSE
Emission point
and model plant
Estimated number
installing
control option
Energy
requirement
(kw-hr/yr)
Total
(kw-hr/yr)
Storage tanks
Condensate tank
batteries
Natural gas
processing
plants
Total
100
25
300
300
30,000
7,500
38,000
kw-hr/yr - Kilowatt hours per year
5-9
-------
-------
6.0 COSTS OF CONTROL OPTIONS
6.1 INTRODUCTION
This chapter presents the approach used to estimate the cost
impacts of the control options presented in Chapter 3.0 to
identified hazardous air pollutant (HAP) emission points in the
oil and natural gas production and natural gas transmission and
storage source categories. Cost impacts are based on the model
plants presented in Chapter 4.0.
The model plant cost impacts were extrapolated to estimate
the cost and cost-effectiveness of the control options on a
national basis. The methodology used to estimate the cost
impacts of applying control options1 to identified HAP emission
points in these source categories is described in Appendix B.
A detailed example is provided in this BID to demonstrate
the methodology as applied on a model plant basis. The costs of
the control options used in this example case are presented in
Reference 1.
6.2 SUMMARY OF COST METHODOLOGY
6.2.1 General Approach
Cost estimates were developed for the following control
options (1) condenser systems, with and without the installation
of a gas condensate glycol separator (GCG separator or flash
tank) in glycol dehydration system design, (2) vapor collection
systems for fixed-roof storage tanks, and (3) a leak detection
and repair (LDAR) program for fugitive emissions.
All costs were updated to July 1993 dollars using cost
indices obtained from Chemical Engineering.2 In selected cases,
6-1
-------
separate costs were estimated for applying control options to
existing and new facilities.
The difference in costs between an existing facility and a
new facility for the same control option is a retrofit factor
that accounts for space limitations and additional engineering
requirements. The retrofit factor is applied to the capital cost
of control options installed at existing facilities. The
retrofit cost adjustment factor is estimated to be 1.15, meaning
that it was judged that it will cost (on average) 15 percent more
to install a control option at an existing facility as compared
with installation of the same control option at a similar size
new facility.
6.2.2 Monitoring Equipment
Cost estimates for monitoring equipment associated with
condenser systems and vapor collection devices were included in
the capital cost estimates. In addition, the annualized capital
costs of the monitoring equipment were included in the annual
costs of these control options.
The cost of monitoring equipment consists of the
installation of instrumentation to monitor the operation of the
control device. For purposes of this analysis, the cost of
monitoring was estimated to be equal to the capital cost
instrumentation factor for each control option.
6.2.3 Product Recovery
Product recovery is presented as an annual credit in each
cost table, where applicable. Product recovery credits were
calculated by multiplying the mass of product recovered by the
product value for each control option.
Recovered condensate and other liquid hydrocarbons were
assigned a value of $18.00 per barrel, the average current price
for crude oil.3 For recovered gaseous products, different values
were assigned depending on how the recovered gas are used.
Recovered gaseous hydrocarbons recycled for processing were
assigned a value of $2.00 per thousand standard cubic feet
(mscf).4 By assigning a value of 1,000 British thermal units
6-2
-------
(BTUs)/mscf, recovered gaseous hydrocarbons used as supplemental
fuel were valued at $1.30/mscf.5 Gaseous hydrocarbons directed
to an incinerator or flare have no value for product recovery.
.6.2.4 Monitoring. Inspection. Recordkeepina. and Reporting
The annual costs associated with monitoring, inspection,
recordkeeping, and reporting (MIRR) were included in the total
annual costs, but are presented separately from the control
option costs. Appendix C presents the methodology and estimated
example MIRR costs for each major HAP emission point. Estimated
example MIRR costs are also presented in Appendix C for glycol
dehydration units that are classified as area sources.
6.2.5 Costs of HAP Emission Control Options
6.2.5.1 Process Vents. The glycol dehydration unit
reboiler vent has been identified in this BID as the primary HAP
emission process vent in the oil and natural gas production and
natural gas transmission and storage source categories. The most
effective control option identified for.reducing the level of HAP
emissions from the glycol dehydration unit reboiler vent is a
condenser operated in conjunction with a flash tank in a glycol
dehydration unit's system design.
Additional control can be achieved by recycling the non-
condensable gas stream into the incoming natural gas line. The
non-condensable gas stream may also be directed to a flare or
incinerator or used as a supplemental fuel source. A condenser
may be operated at a high enough efficiency such that the
residual non-condensable gas stream may be vented to the
atmosphere. Cost estimates were developed for a condenser system
with a 95 percent HAP emission reduction efficiency. The
necessary equipment for a condenser system includes a condenser,
condensate storage vessel, and piping.
System optimization is another control option that may be
applicable to this HAP emission point. Costs for system
optimization are not presented due to the variability of effort
associated with implementing this option. In addition, the HAP
6-3
-------
reduction and the costs of implementing this option may vary
substantially among facilities based on site-specific factors.
6.2.5.2 Storage Tanks. Crude oil and condensate are
typically stored in fixed-roof storage tanks. Since most of
these tanks are too small to install an internal floating roof,
the control options evaluated for fixed-roof storage tanks
require collecting the vapor emitted with a closed-vent system.
The vapor collected by the closed-vent system may be
processed for sale, used for fuel, or be directed to a control
device. For this analysis, it was estimated that 45 percent of
all facilities implementing controls for storage tanks will
process the recovered gas for sale, 45 percent will use the
recovered gas for fuel or fuel substitute, and 10 percent will
install flares to destroy the collected gas stream.
The capital cost for each closed-vent system includes the
cost of a fan, flame arrester, and piping. The equipment was
designed to recover vapor from four storage tanks. Total capital
cost was estimated to be the same for all model plant
configurations utilizing this control option.
Costs were also estimated for flares. Based on the
recovered volumes of gas from the storage tanks, costs estimates
were developed for two size flares. Capital costs for flares
include the costs for a knockout drum, a flare, and piping.
6.2.5.3 ttrpHpment Leaks. Control option costs for
equipment leaks at natural gas processing plants are based on the
model plant component counts for the facilities that are
presented in Chapter 4.0 and the use of a LDAR program. Cost
estimates were tabulated for a monthly LDAR program based on the
New Source Performance Standards (NSPS) for Equipment Leaks of
VOC from Onshore Natural Gas Processing Plants (40 CFR, Part 60,
Subpart KKK) . 6
6.3 MODEL PLANT BASED CONTROL COSTS
This section provides a general . discussion of how control
option costs were estimated for the model plants,, More detailed
6-4
-------
information on the methodology and the algorithms used may be
found in Reference 1.
6.3.1 Glycol Dehydration Units
The costs of applying a condenser to the reboiler vent of
each model glycol dehydration unit described in Chapter 4.0 were
estimated. For this analysis, it was estimated that all. existing
model triethylene glycol (TEG)-D and TEG-E dehydration units have
flash tanks in their system designs (see Chapter 2.0 for
discussion of flash tank use). It was also estimated that 90
percent of the model TEG-A dehydration units, 60 percent of model
TEG-B dehydration units, and 45 percent of model TEG-C
dehydration units do not have flash tanks in their system
designs. Therefore, costs for flash tanks were added to the
condenser cost estimates for those existing model glycol
dehydration units not having flash tanks in the system design.
6.3.2 Condensate Tank Batteries
For condensate model tank batteries, control option costs
were estimated for VRUs for fixed-roof storage tanks.
6.3.3 Natural Gas Processing Plants
Control option costs for model natural gas processing plants
were developed for VRUs for fixed-roof storage tanks and a
monthly LDAR program for control of equipment leaks.
6.4 EXAMPLE
The following example illustrates the approach used to
estimate the cost impacts of control options on a model plant.
The model plant selected for this example is model condensate
tank battery G that has a model TEG-C unit co-located at the tank
battery. The model plant characteristics of these facilities are
presented in Tables 4-1 and 4-3 of Chapter 4.0.
The applicable control options for this model plant
combination include (1) a condenser for the glycol dehydration
unit reboiler vent and (2) a closed-vent system for the storage
tanks. This example model plant combination has an on-site
combustion device, so installation of a control device is not
required for the vapor collected from storage tanks.
6-5
-------
The size of the condenser is dependent on the flow rate of
the glycol dehydration unit reboiler vent, which is the inlet
stream to the condenser. The flow rate and HAP concentration of
the glycol dehydration unit reboiler vent was estimated using the
parameters presented in Table 4-1 in Chapter 4.0 of this BID and
GRI-GLYCalc™ (Version 3.0).7 The reduction of HAP achieved by
the condenser is based on a HAP emission reduction efficiency of
95 percent and an average inlet concentration of 200 parts per
million by volume (ppmv) benzene, toluene, ethyl benzene, and
mixed xylenes (collectively referred to as BTEX) in the wet
natural gas entering the glycol dehydration process.
The design criteria and cost of the condenser system are
presented in Table 6-1 and Table 6-2. As shown, the estimated
total capital investment of the condenser is $11,000, while the
total net annual cost is ($940).
A closed-vent system is the control option applied to the
fixed-roof storage tanks at this facility. Emissions from the
storage tanks are based on standing and working losses. For
purposes of this example, flash emissions were not calculated.
As shown in Table 6-3, the total capital investment is estimated
as $3,600. The vapor collected is directed to the on-site
combustion device (flare). Therefore, no product recovery credit
is claimed in the total net annual cost shown in Table 6-4.
The total estimated annual costs for MIRR are approximately
$5,700 for this model plant. The costs are added to the annual
costs for the control options for this model plant. The
summation of these annual costs divided by the annual HAP
emission reduction is equal to the cost effectiveness for
controlling the combination of HAP emission points at this model
plant.
The cost impacts of implementing these control options to
this model plant combination are summarized in Table 6-5. As
shown, the total capital investment for this model plant
combination is $14,600. Total net annual cost incurred by the
6-6
-------
TABLE 6-1. EXAMPLE CONDENSER CAPITAL COSTSa FOR
MODEL GLYCOL DEHYDRATION UNIT TEG-C
Equipment Description Size
Condenser" Condenser and All
piping
Condensate 50 gallons
storage tank
Flash tank Low pressure 125 psig
separator
Purchased equipment costs (PEC)
Enhanced monitoring equipment (EM)
Total capital cost (TCC) for existing unitc
Factor/
Reference
Ref . 8
2. 72 (V) +1,960
Ref. 9
Ref. 10
0.10*PEC
1.15*(PEC+EM)
Cost
$6,800
2,100
N.A.
$8,900
890
$11,000
a - July 1993 dollars.
b - Includes direct and indirect costs.
c - Retrofit factor of 1.15x for existing units.
N.A. - Not applicable to units with flash tank in existing system design.
Note: Numbers may vary due to rounding.
6-7
-------
TABLE 6-2.
MODEL
EXAMPLE CONDENSER ANNUAL COSTSa FOR
GLYCOL DEHYDRATION UNIT TEG-C
Cost category
Factor
Direct annual cost
Operating labor
Supervising labor
Operating materials
Maintenance
Labor
Material
Utilities
Indirect annual costs
Overhead
Administrative
Property taxes
Insurance
Capital recovery13
Recovery credit0/
condensate
Total annual cost
(0.5 hr/8 hr)*(2,080
hr/yr)*($13.20/hr)
0.15*(Operating labor)
None required
(0.5 hr/8 hr)*(2,080
hr/yr)*($14.50/hr)
0.5*(Maintenance labor)
None required
0.60*(Maintenance total)
0.02*(TCC)
0.01*(TCC)
0.01*(TCC)
0.1098*(TCC)
(555 bbl/yr)*($18.00/bbl)
July 1993 dollars.
Cost
$1,700
260
0
1,900
950
0
2,300
230
110
110
1,500
(10,000)
($940)
a -
b - Based on an equipment life of 15 years and an interest rate of 7 percent
over the life of the equipment.
c - Number in parentheses indicate a savings.
Note; Numbers may vary due to rounding.
6-8
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TABLE 6-3. EXAMPLE CLOSED VENT SYSTEM CAPITAL COSTSa
MODEL CONDENSATE TANK BATTERY TB-G
FOR
Equipment Description Size
Pan FRP, centrifugal 10.5" dia.
Motor w/Belt & starter 7 . 5 hp
Piping 2" Galv. steel 200 ft
Flame 2" dia.
arrestor
Equipment costs (EC)
Enhanced monitoring equipment (EM)
Purchased equipment cost (PEC)
Direct installation cost (DC)
Indirect installation cost (1C)
Total capital cost (TCC)
Factor/
Reference
42.3*(D)1-2
Ref . 11
235* (hp)0-256
Ref . 11
Ref . 12
Ref . 12
0.10* (EC)
1.08* (EC+EM)
Ref. 12
0.20*(PEC)
(PEC+DC+IC)
Cost
$750
410
830
110
$2,100
210
2,500
580
500
$3,600
a - July 1993 dollars.
Note; Numbers may vary due to rounding.
6-9
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TABLE 6-4 EXAMPLE CLOSED VENT SYSTEM ANNUAL COSTS3 FOR
MODEL CONDENSATE TANK BATTERY TB-G
Cost category
Direct annual cost
Maintenance
Labor13
Material
Utilities
Indirect annual costs
Overhead
Administrative
Property taxes
Insurance
Capital recovery13'0
Total annual cost
(1 hr/yr)*($14.50/hr)
1.0*(Maintenance labor)
$0.0509/kW-hr
0.60*(Maintenance total)
0.02*(TCC)
0.01*(TCC)
0.01*(TCC)
0.1098*(TCC)
Cost
$15
15
20
18
72
36
36
400
$610
c -
July 1993 dollars.
Reference 12.
Based on an equipment life of 15 years and an interest rate of 7 percent
over the life of the equipment.
N.A. - Not applicable.
Note: Numbers may vary due to rounding.
6-10
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TABLE 6-5. EXAMPLE MODEL PLANT COST IMPACTS3
HAP emission point
Glycol reboiler vent
Storage tanks
MIRR costsc
Total
Control
option
Condenser
Closed vent
system
HAP
reduction
(Megagrams
per year)
60
0.2
60
Total
capital cost
$11,000
3,600
$14,600
Total
net
annual
cost
($940)i>
610
5,700
$5,370
a -
These cost impacts apply to an existing facility represented by model
condensate tank battery G and model glycol dehydration unit TEG-C.
Parentheses represent a cost savings due to product recovery.
Monitoring, inspection, recordkeeping, and reporting (MIRR) costs
includes $3,400 for glycol dehydration unit and $2,300 for storage
tanks.
6-11
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model plant combination is $5,370, which includes the cost of
MIRR. Total annual reduction of hazardous air pollutants is 60
megagrams per year (Mg/yr). Therefore, the cost effectiveness of
these control options on this model plant combination is $90 per
megagram (Mg) of HAP reduced.
References used in the development of the tables in this
chapter8'9'10'11'12'13 are listed in Section 6.5 of this chapter.
6.5 REFERENCES
l US Environmental Protection Agency. .Economic Impact
Analysis of the Proposed Oil and Natural Gas NESHAPs. Final
Report (EPA-453/R-96-016). Research Triangle Park, NC.
November 1996.
2 Chemical Engineering. Equipment Indices. McGraw-Hill
Publishing. New York, NY. Various Issues.
3. Oil and Gas Journal. Statistics. June 21, 1993. PennWell
Publishing Company. Tulsa, OK.
4.
5.
6.
7.
8.
9.
10.
Reference 3.
Gas Research Institute. Proceedings of the 1992 Gas Research
Institute Glycol Dehydrator Air Emissions Conference.
Chicago, IL. September 1992.
Standards of Performance for Equipment Leaks of VOC from
Onshore Natural Gas Processing Plants. Code of- Federal
Regulations, Title 40, Part 60, Subpart KKK. July 1, 1992.
U.S. Government Printing Office, Washington, DC.
Gas Research Institute. Technical Reference Manual for GRI-
GLYCalc™: A Program for Estimating Emissions from Glycol
Dehydration of Natural Gas, Version 3.0 (GRI-96/0091).
Chicago, IL. March 1996
Ventura County Air Pollution Control District (California).
Rule 71.5, Glycol Dehydrators (Draft Staff Report).
Executive Summary. Ventura, CA. August 8, 1994.
U S. Environmental Protection Agency. OAQPS Control Cost
Manual (Fourth Edition, EPA 450/3-90-006). Research Triangle
Park, NC. January 1990.
Owens, A.S. BTEX Emissions from Gas/Glycol Dehydrators: Air
•Quality Case Histories. Proceedings of the 1994 GRI Glycol
Dehydrator/Gas Processing Air Toxics Conference (June 1994).
Gas Research Institute, Chicago, IL.
.6-12
-------
11. U.S. Environmental Protection Agency. Control Technologies.
for Hazardous Air Pollutants (EPA 625/6-91/014). Washington,
DC. June 1991.
12. U.S. Environmental Protection Agency. Hazardous Waste TSDF -
Background Information for Proposed RCRA Air Emission
Standards - Volume III (EPA 450/3-89-023c). Research
Triangle Park, NC. June 1991.
13. National Emissions Standards for Hazardous Air Pollutants;
Announcement of Negotiated Regulations for Equipment Leaks,.
Federal Register, Vol. 56, No. 44, pp. 9315-9339. March 6,
1991. Office of the Federal Register, Washington, DC.
6-13
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APPENDIX A.
EVOLUTION OF THE BACKGROUND INFORMATION DOCUMENT
The primary objective of this project is to develop a basis
for supporting proposed national emissions standards for
hazardous air pollutants (NESHAP) for the oil and natural gas
production and natural gas transmission and storage source
categories. To accomplish this objective, technical data were
acquired on the following aspects of these two source categories
(1) process operations and equipment, (2) the characteristics of
extracted and recovered products, (3) identified potential
emission points where hazardous air pollutants (HAP) are released
(including the magnitude and composition of HAP emissions), and
(4) the types and costs of control options that may be applied to
identified potential HAP emissions.
The bulk of the information was gathered from the following
sources '
1. Technical literature,
2. Federal, Regional, State, and local regulatory
agencies,
3. Site visits,
4. Industry representatives, and
5. Equipment vendors.
Significant events relating to the evolution of the
background information document (BID) for the oil and natural gas
production and natural gas transmission and storage NESHAPs are
itemized in Table A-l.
A-l
-------
TABLE A-l. EVOLUTION OF THE BACKGROUND INFORMATION DOCUMENT
Date Company, consultant, or agency/location Nature of action
06/22/92
10/07/92
U.S. Environmental Protection Agency and Industry meeting
industry representatives/RTF, NC
Amoco Production Co.
ARCO Oil & Gas Co.
Chevron U.S.A. Inc.
Exxon Company, U.S.A.
Conoco, Inc.
Texaco Exploration and Producing Inc.
Mobil Exploration & Producing U.S. Inc,
10/12/92 Amoco Production Co., Zachary, LA
10/12/92 ARCO Oil & Gas Co., Lafayette, LA
10/13/92 Chevron, U.S.A. Inc., Thompson, TX
10/13/92 Exxon Company, U.S.A., Katy, TX
10/14/92 Conoco, Inc., Benavides, TX
Section 114
information request
letter for plant
visits
Plant visit to gather
background
information on the
methods used to
produce oil and
natural gas
Plant: visit to gather
background
information on the
methods used to
produce oil and
natural gas
Plant visit to gather
background
information on the
methods used to
produce oil and
natural gas
Plant visit to gather
background
information on the
methods used to
produce oil and
natural gas
Plant visit to gather
background
information on the
methods used to
produce oil and
natural gas
A-2
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TABLE A-l.
EVOLUTION OF THE BACKGROUND INFORMATION DOCUMENT
(Continued)
Date
Company, consultant, or agency/location
Nature of action
10/15/92 Texaco Exploration and Producing Inc., Plant visit to gather
Midland, TX background
information on the
methods used to
produce oil and
natural gas
03/17/93
04/06/93
&
04/07/93
04/29/93
05/27/93
U.S. Environmental Protection Agency and Industry meeting
Gas Research Institute/RTP, NC
U.S. Environmental Protection Agency and Industry meeting
industry representatives/RTP, NC
U.S. Environmental Protection
Agency/RTP, NC and Washington, DC
Marathon Oil Co.
Oxy USA Inc.
Shell Oil Co.
Lomack Petroleum, Inc.
Maxus Energy Corp.
Mitchell Energy Co.
Phillips Petroleum Co.
Amerada Hess Corp.
Amoco Production Co.
Conoco, Inc.
Oryx Energy Co.
Texaco, Inc.
Unocal
Mesa Petroleum
Union Pacific Environmental Services
Enron Corp.
Atlantic Richfield Co.
BP Exploration Alaska, Inc.
Chevron USA Production Co.
Exxon USA Production Dept.
Mobil Oil Corp.
Kerr McGee
Pogo Production Co.
Arch Petroleum
Work group meeting
Air emissions survey
questionnaires
mailout
A-3
-------
TABLE A-l.
EVOLUTION OF THE BACKGROUND INFORMATION DOCUMENT
(Continued)
Date
Company, consultant, or agency/location
Nature of action
07/27/93
08/03/93
Exxon Company U.S.A.
Chevron U.S.A., Inc.
Shell Western E&P Inc.
Texaco USA
Texaco Exploration and Production Inc.
Offshore of Santa Barbara County, CA
08/04/93
Mobil Exploration and Producing U.S.
Inc., Goleta, CA
08/04/93
Exxon Company, U.S.A., Offshore of Santa
Barbara County, CA
08/03/93
Sc
08/05/93
08/09/93
through
08/11/93
Chevron U.S.A. Inc., Offshore of Santa
Barbara County and Ventura County, CA
State of Kansas, Various sites
Section 114
information request
letter for plant
visits
Plant visit to gather
background
information on the
methods used to
produce oil and
natural gas
Plant visit to gather
background
information on the
methods used to
produce oil and
natural gas
Plant visit to gather
background
information on the
methods used to
produce oil and
natural gas
Plant visits to
gather background
information on the
methods used to
produce oil and
natxiral gas
Plant visits to
gather background
information on the
methods used to
produce oil and
natural gas
A-4
-------
TABLE A-l. EVOLUTION OF THE BACKGROUND INFORMATION DOCUMENT
(Continued)
Date
Company, consultant, or agency/location
Nature of action
08/10/93 Wallace Energy, Inc., Plainville, KS
08/10/93 Oil Reclaiming Company, Limited, Seward,
KS
08/10/93 H&W Oil Company, Hays, KS
08/11/93 Trident NGL, Inc., Cheney, KS
09/15/93 CNG Transmission Corp.
02/01/94 U.S. Environmental Protection Agency and
industry representatives/RTF, NC
02/01/94 Distribution of draft BID Chapters 2.0,
3.0, and 4.0 to industry
04/12/94 U.S. Environmental Protection
Agency/RTP, NC and Washington, DC
04/26/94 U.S. Environmental Protection Agency and
industry representatives/RTP, NC
Plant visit to gather
background
information on the
methods used to
produce oil and
natural gas
Plant visit to gather
background
information on the
methods used to
produce oil and
natural gas
Plant visit to gather
background
information on the
methods used to
produce oil and
natural gas
Plant visit to gather
background
information on the
methods used to
produce oil and
natural gas
Air emissions survey
questionnaire mailout
Industry meeting
BID chapter
distribution
Work group meeting
Industry meeting
A-5
-------
TABLE A-l. EVOLUTION OF THE BACKGROUND INFORMATION DOCUMENT
(Continued)
Date
Company, consultant, or agency/location Nature of action
04/26/94
I
05/17/94
05/23/94
08/26/94
10/13/94
12/08/94
04/26/95
05/08/95
05/25/95
11/02/95
11/09/95
1
| 12/14/95
II
03/21/96
Distribution of draft BID Chapters 2.0,
3.0, and 4.0 to industry
U.S. Environmental Protection Agency and
industry representatives/RTF, NC
U.S. Environmental Protection Agency and
industry representatives /RTP, NC
Distribution of complete preliminary
draft BID to interested parties
U.S. Environmental Protection Agency and
industry representatives/RTP, NC
U.S. Environmental Protection Agency and
industry representatives/RTP, NC
U.S. Environmental Protection Agency and
industry representatives/RTP, NC
U.S. Environmental Protection Agency and
industry representatives/RTP, NC
U.S. Environmental Protection Agency and
industry representatives/RTP, NC
U.S. Environmental Protection Agency and
industry representatives/RTP, NC
U.S. Environmental Protection Agency and
industry representatives/RTP, NC
U.S. Environmental Protection Agency and
industry representatives/RTP, NC
U.S. Environmental Protection Agency and
industry representatives/RTP, NC
BID chapter
distribution
Industry meeting
Industry meeting
BID distribution
Industry
teleconference
Industry meeting
Industry
teleconference
Industry meeting
Industry
teleconference
Industry meeting
Industry meeting
Industry meeting
Industry meeting
A-6
-------
TABLE A-l. EVOLUTION OF THE BACKGROUND INFORMATION DOCUMENT
(Continued)
Date
Company, consultant, or agency/location
Nature of action
04/04/96
05/09/96
07/30/96
08/28/96
10/17/96
10/31/96
11/07/96
Transcontinental Gas Pipe Line
Corporation, Reidsville, NC
U.S. Environmental Protection Agency .and
industry representatives/RTP, NC
U.S. Environmental Protection Agency and
industry representatives/RTP, NC
U.S. Environmental Protection
Agency/RTP, NC and Washington, DC
U.S. Environmental Protection
Agency/RTP, NC and Washington, DC
U.S. Environmental Protection
Agency/RTP, NC and Washington, DC
U.S. Environmental Protection Agency and
industry representatives/RTP, NC
Plant visit to gather
background
information on the
methods used in
natural gas
transmission
Industry meeting
Industry
teleconference
Work group meeting
Work group meeting
Work group meeting
Industry meeting and
teleconference
A-7
-------
-------
APPENDIX B.
NATIONAL IMPACTS METHODOLOGY
B.1 INTRODUCTION
This appendix describes the general methodology used to
estimate the nationwide impacts of the proposed national emission
standards for hazardous air pollutants (NESHAP) that are being
developed for the oil and natural gas production and natural gas
transmission and storage source categories. This methodology
results in (1) estimates of baseline (i.e., before the
implementation of NESHAP) and controlled hazardous air pollutant
(HAP) emissions and (2) the impacts of control options. Impacts
estimated include HAP emission reduction, total capital and net
annual costs, and secondary environmental and energy impacts.
B.2 OVERVIEW OF METHODOLOGY
The basic elements of the methodology used in estimating
impacts for the oil and natural gas production and natural gas
transmission and storage NESHAPs are as follows (I) development
of model plants, (2) identification of HAP emission points and
control options, (3) application of HAP emission control options
to identified emission points, (4) estimation of model plant
impacts, and (5) extrapolation from model plant impacts to
national impacts. Each of the above elements is discussed below.
B.3 MODEL PLANT DEVELOPMENT
Due to the large number of facilities in these source
categories and the time and resources that would have been
required, it was not feasible to simulate the impacts of
standards on each actual impacted facility. Instead, a model
plant approach was used.
B-l
-------
First, distinct sectors of the source categories were
identified in terms of operation, equipment, and emissions. Then
a sufficient number of model plants were developed, to represent
each industry sector. The sectors identified include (1) glycol
dehydration units, (2) condensate tank batteries, (3) natural gas
processing plants, (4) offshore production"platforms in State
waters, and (5) natural gas transmission facilities, including
underground storage operations. Since the primary identified HAP
emission point of concern at natural gas transmission facilities
is the co-location of any triethylene glycol (TEG) dehydration
unit at these facilities, separate model plants were not
developed for facilities in this sector of the oil and natural
gas industry.
The primary information sources used to develop the model
plants and model plant parameters included (1) responses to the
U.S. Environmental Protection Agency's (EPA's) Air Emissions
Survey Questionnaires,1 (2) site visits to operating facilities,
(3) discussions and meetings with industry and trade association
representatives, and (4) available literature.
In addition, a data base from the Gas Research Institute
(GRI) containing natural gas analyses2 and a data base provided
by the American Petroleum Institute (API)3 were used, in
conjunction with industry survey responses, to develop natural
gas compositions. Composition of process streams, particularly
HAP constituents, is a key parameter in the model plant analysis.
The concentration of HAP constituents in these streams has a
direct impact on estimated model plant HAP emissions.
The primary HAP constituents of the process streams
associated with the oil and natural gas production and natural
gas transmission and storage source categories include benzene
toluene, ethyl benzene, and mixed xylenes (collectively referred
to as BTEX), and n-hexane. Process stream concentrations of
these HAP are listed in Table 2-1 of Chapter 2.0 of this BID.
As indicated in Table 2-1, the EPA estimated three national
average BTEX concentrations for natural gas of 200, 160, and 13
B-2
-------
parts per million volume (ppmv). These values are reflective of
the three sectors in these source categories of (1) production,
(2) processing, and (3) transmission and underground storage,
which handle natural gas streams. The EPA has analyzed BTEX
values within ranges of either side of these average values in an
effort to better determine the impacts of the proposed NESHAPs.
Initially, the EPA estimated a production BTEX concentration
of 550 ppmv based on the data received in company responses to
the Air Emissions Survey Questionnaires (Reference 1). The EPA
revised this estimate to 440 ppmv by incorporating BTEX data
supplied by GRI (Reference 2). The EPA revised its estimate
again (May 1996) to 200 ppmv after incorporating additional new
BTEX data supplied by API (Reference 3).
The production estimate influences the calculation of HAP
concentrations for the processing sector in the.oil and natural
gas production source category. The revision of the HAP
concentration for the production sector has caused a 75 percent
reduction in the EPA's initial (December 1993) estimate of
nationwide HAP emissions from glycol dehydration units, the
primary identified HAP emission point in these source categories.
Each model plant was characterized based on the specific
parameters necessary to calculate impacts. Parameters include
(1) product and other throughputs, (2) number and type of process
vessels (i.e., storage tanks), and (3) number and type of process
component equipment (i.e., valves). Chapter 4.0 of this BID
provides detailed descriptions of the model plants.
B.4 CONTROL OPTIONS
Control options were identified that reduce HAP emissions
from HAP emission points in the oil and natural gas production
industry. These control options are discussed in detail in
Chapter 3.0 of this BID.
Control options that are applicable to HAP emission points
in the oil and natural gas production industry will also achieve
co-control of volatile organic compound (VOC) and methane
emissions. Due to similarities in the emission characteristics
B-3
-------
of HAP, VOC, and methane from the emission points in this
industry, control options for HAP were judged to be equally
effective/ in terms of emission reduction efficiency, for HAP,
VOC, and methane. The efficiencies used in the analysis for each
control option can be found in Table 3-1 of this BID.
B.5 MODEL PLANT IMPACTS
Impacts of the control options were calculated for model
plants using available information. Model plant impacts include
(1) HAP emission reduction per model plant, (2) total capital and
net annual costs and cost -effectiveness per megagram of annual
HAP emission reduction, and (3) secondary environmental impacts
and energy requirements.
B.5.1
Emissions were estimated using emission factors and emission
estimation tools. Emissions from glycol dehydration units were
estimated using GRI-GLYCalc™ (Version 3.0).4 Emissions from
storage tanks resulting from standing and working losses were
estimated using the EPA's TANKS program.5 Flash emissions from
storage tanks were estimated using a separate algorithm
specifically developed by the EPA for estimating flash emissions
from storage tanks in the oil and natural gas production
industry.6 Emissions from components were estimated using
emission factors developed for equipment leaks.7
Emissions based on the model plants were first estimated at
baseline. Baseline was established by assigning an estimated
level of control to each model plant category. Therefore,
baseline estimates have taken into account those emission points
already controlled.
Emissions were then estimated for each model plant with the
application of controls, or after implementation of NESHAP. The
difference of these estimates is the emissions reduction impact
that the NESHAP would have on each model plant.
B.5. 2 Costs
Capital costs and net annual costs were calculated for each
control option. Capital costs include the cost of the control
B-4
-------
equipment and the costs associated with installing the equipment.
Net annual costs account for the operation and maintenance costs
and monitoring, inspection, .recordkeeping, and recording (MIRR)
costs. • . '
Where available, standardized costing methodologies, such as
presented in the OAQPS Control Cost Manual, were used to estimate
capital and annual costs.8 A product recovery credit was
included in the annual costs, where judged appropriate. Example
model plant control option costs are discussed in Chapter 6.0 and
example MIRR costs are discussed in Appendix C of this BID.
The impact analyses consider a facility's ability to handle
collected vapors. Some remotely located facilities may not be
able to use collected vapor for fuel or recycle it back into the
process. In addition, it may not be technically feasible for
some facilities to utilize the non-condensable vapor streams from
condenser systems as an alternative fuel source safely. An
option for these facilities is to combust these vapors by
flaring.
These concerns are reflected in the analyses conducted by
the EPA. In its analyses, the EPA estimated that (1) 45 percent
of all impacted facilities will be able to use collected vapors
as an alternative fuel source for an on-site combustion device
such as a process heater or the glycol dehydration unit firebox,
(2) 45 percent will be able to recycle collected vapors into a
low pressure header system for combination with other hydrocarbon
streams handled at the facility, and (3) 10 percent will direct
all collected vapor to an on-site flare.
B.5.3 Other Impacts
Other impacts associated with the implementation of
standards include secondary environmental impacts and energy
requirements. These impacts were also estimated using the model
plant approach. Chapter 5.0 of this BID provides more discussion
of these impacts.
B-5
-------
B.6 NATIONAL IMPACTS ESTIMATES
To calculate national impacts, estimates were made of the
total number of facilities nationwide corresponding to each model
plant category. These estimates were based primarily on (1)
production statistics, (2) responses to the Air Emissions Survey
Questionnaires, and (3) estimated facility populations.9
Estimated facility populations are at the bottom of each model
plant table (Tables 4-1 to 4-5) in Chapter 4.0 of this BID.
From these distributions and associated model plant HAP
emission estimates, projections were made of the number of
facilities that would be designated as major and area sources of
HAP emissions. The estimated number of major and area sources
were then used as a basis for determining the national impacts of
each control option.
Generally, it was judged that a TEG dehydration unit must be
co-located at a facility in order for the facility to be
designated as a major source. National impacts were calculated
for major sources, area sources, and each source category as a
whole.
B.7 REFERENCES
1. Responses to the U.S. Environmental Protection Agency's Air
Emissions Survey Questionnaires for the Oil and Natural Gas
Production Source Category (EPA Air Docket A-94-04, Items
II-D-1 through II-D-25). 1993.
2. Letter and attachment from Evans, J.M., Gas Research
Institute, to Viconovic, G., EC/R Incorporated. April 19,
1995. Natural gas BTEX content.
3. American Petroleum Institute. Triethylene Glycol Dehydrator
Operating Parameters for Estimating BTEX Emissions
(Prepublication Draft) . Washington, DC.. February 1996.
4. Gas Research Institute. Technical Reference Manual for GRI-
GLYCalc™: A Program for Estimating Emissions from Glycol
Dehydration of Natural Gas, Version 3.0 (GRI-96/0091).
Chicago, IL. March 1996.
5. TANKS (Version 1.1). Downloaded.from the U.S. Environmental
Protection Agency's Technology Transfer Network.
B-6
-------
6.
7.
8.
9.
Memorandum from Akin, T., and W.H. Battye, EC/R
Incorporated, to Smith, M.E., EPA/CPB. October 18, 1994.
Recommendation of an algorithm to estimate flash emissions
from process vessels in the oil and natural gas production
industry.
Standards of Performance for Equipment Leaks of VOC from
Onshore Natural Gas Processing Plants. Code of Federal
Regulations, Title 40, Part 60, Subpart KKK. July 1, 1992.
U.S. Government Printing Office, Washington, DC.
U.S. Environmental Protection Agency. OAQPS Control Cost
Manual (Fourth Edition, EPA 450/3-90-006). Research Triangle
Park, NC. January 1990.
Memorandum from Akin, T., EC/R Incorporated, to Smith, M.E.,
EPA/CPB. July 30, 1993. Revised preliminary estimate of the
number and size ranges of tank batteries on a national
basis.
B-7
-------
-------
APPENDIX C.
MONITORING, INSPECTION, RECORDKEEPING, AND REPORTING
COST METHODOLOGY
C.1 INTRODUCTION
This appendix documents the methodology used to estimate
costs associated with monitoring, inspection, recordkeeping, and
reporting (MIRR) for the control options presented in Chapter 3.0
of this background information document (BID). The primary costs
associated with MIRR are labor costs required to perform MIRR
activities.1 Labor costs are divided into three categories (1)
technical, (2) managerial, and (3) clerical. An estimate of the
number of technical labor hours required was made for each MIRR
activity, and then managerial and clerical labor hours were
estimated as a percentage of technical labor hours (5 and 10
percent of technical labor hours, respectively). Technical labor
was costed at $44.00 per hour ($44/hr), managerial labor at
$60/hr, and clerical labor at $25/hr.
The MIRR costs presented in this appendix should be
considered example costs. Costs projected for the national
emissions standards for hazardous air pollutants (NESHAP) will be
finalized and documented when the specific requirements of the
standards are determined. The capital and annual costs
associated with control option monitoring equipment are included
in the control option costs.
C-l
-------
C.2 COST METHODOLOGY
C.2.1 Example Costs for Manor Source MIRR
MIRR costs are different for each type of control. These
costs are calculated on an emission point basis arid applied to
the model plants. For each emission point, the hours required to
perform an associated MIRR item and the number of times per year
the associated MIRR item is performed are estimated. By
multiplying these two numbers, the estimated number of technical
labor hours is calculated for each associated MIRR item on an
annual basis.
As discussed above, the number of managerial and clerical
labor hours are estimated as a percentage of each technical labor
hour. The number of technical, managerial, and clerical labor
hours are multiplied by the number of impacted facilities and
wage per labor hour to obtain annual MIRR costs.
C.2.2 Number of Manor Sources
After the initial step of estimating the costs associated
with MIRR, the next step is to determine the number of
facilities, on a model plant basis, that will be subject to MIRR
requirements for major sources. Facilities classified as major
sources (those emitting or having the potential-to-emit 10 tons
per year (tpy) or greater of a single hazardous air pollutant
(HAP) or 25 tpy or greater of any combination of HAP) are subject
to the major source MIRR requirements in this section.
The number of facilities impacted within each model plant
category is estimated to calculate annual MIRR costs on a
national basis. The number of impacted facilities was estimated
using model plants and model compositions of process streams
presented in Chapter 4.0 of this BID.
In the oil and natural gas production source category,
approximately 440 triethylene glycol (TEG) dehydration units are
estimated to be major sources or co-located at major sources and,
therefore, would be subject to MIRR requirements., In the natural
gas transmission and storage source category, approximately 5 TEG
dehydration units are estimated to be major sources and,
C-2
-------
therefore, would be subject to MIRR requirements. The estimated
MIRR costs per TEG dehydration unit at major sources are
presented in Table C-l.
It is estimated that approximately 120 facilities have
storage vessels that are located at facilities that are major
sources and would be impacted by the proposed regulation for the
oil and natural gas production source category. Table C-2
presents estimated MIRR costs for these facilities. Storage
tanks include the set of tanks at each facility.
In addition, approximately 12 facilities estimated to be
major sources are projected to be impacted by leak detection and
repair (LDAR) requirements in the proposed regulation for the oil
and natural gas production source category. Except for
additional reporting requirements, all other associated MIRR
items for LDAR programs are accounted for in the net annual
control costs for LDAR. The estimated costs per LDAR program at
major sources for the reporting requirements are presented in
Table C-3.
Total estimated MIRR costs for major sources are calculated
by summing the MIRR costs associated with each emission point,
which are presented in Tables C-l, C-2, and C-3. For the oil and
natural gas production source category, total MIRR costs for
major sources (based on the example cost methodology) is
approximately $1.8 million per year in the third year after
promulgation of the proposed oil and natural gas production
NESHAP. The major source MIRR costs are summarized in Table C-4.
For the natural gas transmission and storage source
category, total MIRR costs for major sources (based on the
example cost methodology) is approximately $17,000 per year in
the third year after promulgation of the proposed natural gas
transmission and storage NESHAP.
C-3
-------
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C-6
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TABLE C-4. TOTAL ESTIMATED EXAMPLE MIRR COSTS FOR
MAJOR HAP EMISSION SOURCES IN THE
OIL AND NATURAL GAS PRODUCTION SOURCE CATEGORY
HAP emission point
category
Estimated
number of
major
sources3-
MIRR per
HAP
emission
point ($)
Total MIRR
($1,000)
Glycol dehydration unit*3
Tank battery
Storage tank
Natural gas processing
plant
Storage tank
Equipment leaks
Total estimated example
MIRR costs over 3 year
compliance period
440
120
3,300
2,300
1,500
280
12
12
2,300
400
28
4.8
1,800°
a - Number of major sources for storage vessels represent the
number of tank batteries and natural gas processing plants
with an average of 4 storage tanks per tank battery.
b - Includes stand alone glycol dehydration units and those
located at condensate tank batteries, and natural gas
processing plants.
c - Rounded to nearest $100,000.
C-7
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C.2.3 Example Costs for Area Source MIRR
If a standard is promulgated for area sources, it is
anticipated that the MIRR requirements and the associated costs
would be less as compared to those for major sources. The same
general method followed for major sources (see Section C.2.1) is
followed for calculating example area source MIRR costs, but with
fewer requirements. As with all other control options, the
capital costs associated with continuous monitoring for area
sources are included as a component to the control option costs.
C.2.4 Number of Area Sources
After the initial step of estimating the costs associated
with area source MIRR, the next step is to determine the number
of facilities, on a model plant basis, that will be area sources
and, thus, subject to area source MIRR. Only those TEG
dehydration units classified as area sources (those not meeting
the designation of major source) and meeting the applicability
thresholds of the proposed area source standard are subject to
area source MIRR requirements.
The number of facilities impacted within each model plant
category is estimated to calculate annual MIRR costs on a
national basis. The number of impacted facilities was estimated
using model plants and model compositions of process streams (see
Chapter 4.0 of this BID). Approximately 520 glycol dehydration
units will be impacted and, thus, subject to MIRR requirements.
The estimated MIRR costs per glycol dehydration unit at area
sources are presented in Table C-5. Total estimated MIRR costs
for area sources (based on the example cost methodology) is
approximately $1.2 million per year in the third year after
promulgation of the proposed oil and natural gas production
NESHAP. The area source MIRR costs are summarized in Table C-6.
C.2.5 Continuous Monitoring
Continuous monitoring requirements are included in standards
for HAP emissions, promulgated under.§112(d) of the Clean Air Act
C-8
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C-9
-------
TABLE C-6.
TOTAL ESTIMATED EXAMPLE MIRR COSTS FOR
GLYCOL DEHYDRATION UNITS
IN THE OIL AND NATURAL GAS PRODUCTION SOURCE CATEGORY
DESIGNATED AS AREA SOURCES
HAP emission point
category
Glycol dehydration units
Total estimated example
MIRR costs over 3 year
compliance period
a - Rounded to nearest $100,000.
Estimated
number of
area
sources
MIRR per
HAP
emission
point ($)
Total MIRR
($l,000)a
520
2,400
1,200
1,200
C-10
-------
as amended in 1990, to ensure continuous compliance. For
standards developed for the oil and natural gas production and
natural gas transmission and storage source categories,
continuous monitoring requirements will be included for control
options used to reduce HAP emissions from glycol dehydration
units and storage vessels. Monitoring of control option
parameters that are indicative of performance, such as
temperature for condensers, will be required.
In developing example costs of control options, the capital
costs of process instrumentation was doubled to account for the
cost of continuous monitoring equipment. In addition, the labor
costs for the operation and maintenance of equipment, recording
monitoring data, and preparing reports associated with continuous
monitoring are included in the example MIRR annual costs.
C.3 BASIS OF METHODOLOGY
The costs associated with MIRR for major sources are based
on emission points. The following judgements were made for the
emission points (1) one control device for all process vents
associated with the glycol dehydration unit, (2) one control
device for each set of storage tanks, (3) one parameter to
monitor continuously for each control device, and (4) one
facility-wide inventory of emission records is included with the
reporting requirements for storage tanks. In addition, only
reporting is required for LDAR programs, since the other MIRR
cost components have been included in the annual control costs
for the LDAR programs.
C.4 REFERENCES
1. U.S. Environmental Protection Agency. BSD Regulatory
Procedures Manual (Continually Updated). Research Triangle
Park, NC.
C-ll
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