United States Office of Air Quality EPA-450/3-82-024a
Environmental Protection Planning and Standards December 1983
Agency Research Triangle Park NC 27711
—
«>EPA Equipment Leaks Draft
ofVOCin EIS
Natural Gas
Production Industry -
Background Information
for Proposed Standards
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EPA-450/3-82-024a
Equipment Leaks of VOC
in Natural Gas Production Industry
Background Information
for Proposed Standards
Emission Standards and Engineering Division
U.S ENVIRONMENTAL PROTECTION AGENCY
Office of Air, Noise, and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
December 1983
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This report has been reviewed by the Emission Standards and Engineering Division of the Off ice of Air Quality P!^nr ing
and Standards, EPA, 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, for a fee, fron
the National Technical Information Services, 5285 Port Royal Road, Springfield, Virginia 22161.
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ENVIRONMENTAL PROTECTION AGENCY
Background Information
and Draft
Environmental Impact Statement
for Equipment Leaks of VOC in Natural
Gas Production Industry
Prepared by:
ick R. Farmer
)irector. Emission Standards and Engineering Division
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
1. The proposed standards of performance would limit emissions of VOC
from equipment leaks at new, modified, and reconstructed affected
facilities at natural gas plants. Section 111 of the Clean Air Act
(42 U.S.C. 7411), as amended, directs the Administrator to establish
standards.of performance for any category of new stationary source of
air pollution that "... causes or contributes significantly to air
pollution which may reasonably be anticipated to endanger public health
or welfare."
2. Copies of this doucment have been sent to the following Federal
Departments: Labor, Health and Human Services, Defense, Transpor-
tation, Agriculture, Commerce, Interior, and Energy; the National
Science Foundation; the Council on Environmental Qualtiy; members of
the State and Territorial Air Pollution Program Administrators; the
Association of Local Air Pollution Control Officials; EPA Regional
Administrators; and other interested parties.
3. For additional information contact:
Mr. Gilbert H. Wood
Standards Development Branch (MD-13)
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
Telephone: (919) 541-5578
4. Copies of this document may be obtained from:
U.S. EPA Library (MD-35)
Research Triangle Park, North Carolina 27711
National Technical Information Service
5285 Port Royal Road
Springfield, Virginia 22161
111
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METRIC CONVERSION TABLE
EPA policy is to express all -neasurements in Agency documents in
metric units. Listed below are metric units used in this report with
conversion factors to obtain equivalent English units. A list of
prefixes to metric units is also presented.
To Convert
Metric Uni t
centimeter (cm)
meter (m)
liter (1)
cubic meter (m )
cubic ^neter (m )
3
cubic meter (m )
kilogram (kg)
megagram (Mg)
gigagram (Gg)
gigagram (Gg)
joule (J)
Multiply 3y
Conversion Factor
0.39
3.28
0.26
254.2
6.29
35
2.2
1.1
2.2
1102
9.48 x 10
-4
To Obtain
English Unit
inch (in.)
feet (ft.)
U.S. gallon (gal)
U.S. gal Ion (gal )
barrel (oil) (bbl)
cubic feet (ft3)
pound (Ib)
ton
million pounds (10 Ibs)
ton
British thermal unit (3tL
PREFIXES
Prefix
tera
giga
mega
kilo
centi
mi Hi
micro
Symbol
T
G
M
k
c
m
Multip!ication
Factor
10
10-
10
10
10
12
9
6
3
-2
-3
-6
IV
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TABLE OF CONTENTS
Page
METRIC CONVERSION TABLE iv
TABLE OF CONTENTS v
LIST OF TABLES viii
LIST OF FIGURES xi
1.0 SUMMARY 1-1
1.1 Regulatory Alternatives 1-1
1.2 Environmental Impact " 1-2
1.3 Economic Impact 1-3
2.0 INTRODUCTION 2-1
2.1 Background and Authority for Standards 2-1
2.2 Selection of Categories of Stationary Sources .... 2-4
2.3 Procedure for Development of Standards of
Performance 2-6
2.4 Consideration of Costs 2-8
2.5 Consideration of Environmental Impacts 2-9
2.6 Impact on Existing Sources , ?-10
2.7 Revision of Standards of Performance 2-11
3.0 SOURCES OF VOC EMISSIONS 3-1
3.1 General 3-1
3.2 Description of Fugitive Emission Sources. ...,'.. 3-1
3.3 Baseline Fugitive VOC Emissions 3-8
3.4 References 3-12
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TABLE OF CONTENTS (Continued)
4.0 EMISSION CONTROL TECHNIQUES 4-1
4.1 Introduction 4-1
4.2 Leak Detection and Repair Methods 4-1
4.3 Preventive Programs 4-13
4.4 References 4-20
5.0 MODIFICATION AND RECONSTRUCTION 5-1
5.1 General Discussion of Modification and Reconstruction
Provisions 5-1
5.2 Applicability of Modification and Reconstruction
Provisions to Natural Gas/Gasoline Processing
Plants 5-3
6.0 MODEL PLANTS AND REGULATORY ALTERNATIVES 6-1
6.1 Introduction 6-1
6.2 Model Plants 6-1
6.3 Regulatory Alternatives 6-2
6.4 References 6-10
7.0 ENVIRONMENTAL IMPACTS 7-1
7.1 Introduction 7-1
7.2 Emissions Impact 7-1
7.3 Water Quality Impact 7-3
7.4 Solid Waste Impact 7-3
7.5 Energy Impacts 7-9
7.6 Other Environmental Concerns 7-9
7.7 References 7-12
8.0 COST ANALYSIS 8-1
8.1 Cost Analysis of Regulatory Alternatives 8-1
8.2 Other Cost Considerations 8-24
8.3 References 8-26
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TABLE OF CONTENTS (Concluded)
Page
9.0 ECONOMIC ANALYSIS 9-1
9.1 Industry Profile 9-1
9.2 Economic Impact Analysis 9-21
9.3 Potential socioeconomic and Inflationary Impacts. 9-30
9.4 References 9-32
APPENDICES
A Evolution of the Background Information Document. A-l
B Index to Environmental Considerations B-l
C Emission Source Test Data C-l
C.I Plant Description and Test Results C-2
C.2 Industry Valve Maintenance Study C-4
C.3 References for Appendix C C-8
D Emission Measurement and Continuous Monitoring. . D-l
D.I Emission Measurement Methods D-l
D.2 Continuous Monitoring Systems and Devices .... D-4
D.3 Performance Test Method D-4
D.4 References D-7
E Model for Evaluating the Effects of Leak
Detection and Repair on Fugitive Emissions from
Pumps and Valves E-l
E.I Introduction E-2
E.2 LDAR Model E-2
E.3 Model Outputs E-4
E.4 References E-6
F Docket Entries on Correlation Between
Cost-effectiveness and Throughput for
Small Gas Plants F-l
G Revised Compressor Seal Emission Factors and Seal
Vent System Control Costs G-l
H Calculation of Emission Reductions and Cost
Effectiveness for the Proposed Standards by
Source Type H-l
I Revised Pump Seal Leak Detection and Repair
Emission Reduction 1-1
vii
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LIST OF TABLES
Number Page
1-1 Environmental and Economic Impacts of Regulatory
Alternatives 1-4
3-1 Baseline Fugitive Emission Factors for Gas Plants .... 3-9
3-2 Estimated Baseline Fugitive VOC Emissions From a
Typical Gas Plant 3-11
4-1 Percentage of Components Predicted to be Leaking In An
Individual Component Survey 4-3
4-2 Percent of Total VOC Emissions Affected at Various
Leak Definitions 4-8
4-3 VOC Emission Correction Factors for Various Inspection
Intervals, Allowable Repair Times, and Leak
Definitions 4-12
6-1 Example Types of Equipment Included and Excluded in
Vessel Inventories for Model Plant Development 6-3
6-2 Number of Components in Hydrocarbon Service and Number
of Vessels at Four Gas Plants 6-4
6-3 Ratios of Numbers of Components to Numbers of Vessels . . 6-5
6-4 Fugitive VOC Emission Sources for Three Model Gas
Processing Plants 6-6
6-5 Fugitive VOC Regulatory Alternative Control
Specifications 6-8
7-1 Controlled Emission Factors for Various Inspection
Intervals 7-2
7-2 Emissions for Regulatory Alternatives 7-4
7-3 Total and Incremental Emission Reductions
of the Regulatory Alternatives on a Model Plant
Basis 7-7
7-4 Projected Fugitive Emissions From Affected Model
Plants for Regulatory Alternatives for 1983-1987 7-8
7-5 Energy Impacts of Emission Reductions for
Regulatory Alternatives for 1983-1987 7-10
vm
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LIST OF TABLES (Continued)
Number Page
8-1 Capital Cost Data 8-2
8-2 Capital Cost Estimates for Model Plants 8-7
8-3 Leak Detection and Repair Labor-Hour Requirements .... 8-11
8-4 Annual Leak Detection and Repair Labor Costs 8-12
8-5 Derivation of Annualized Labor, Administrative,
Maintenance, and Capital Costs 8-14
8-6 Labor-Hour Requirements for Initial Leak Repair 8-15
8-7 Initial Leak Repair Costs 8-16
8-8 Recovery Credits 8-17
8-9 Annual Cost Estimates for Model Plant A 8-18
8-10 Annual Cost Estimates for Model Plant B 8-19
8-11 Annual Cost Estimates for Model Plant C 8-20
8-12 Cost Effectiveness of Regulatory Alternatives 8-21
8-13 Fifth-Year Nationwide Costs of the
Regulatory Alternatives 8-23
8-14 Statutes That May Be Applicable to the Natural Gas
Processing Industry 8-25
9-1 Distribution of Gas Plants by Capacity (1980) 9-3
9-2 Distribution of Gas Plants by Process Method (1980) ... 9-5
9-3 Distribution of Gas Plants by Ownership (1980) 9-6
9-4 Distribution of Gas Plants by State (1980) 9-7
9-5 Production of Energy by Type, United States 9-8
9-6 Aggregate Retail Price Elasticities of Demand, U.S. . . . 9-9
9-7 Natural Gas Gross Withdrawals and Marketed Onshore and
Offshore Production 9-11
9-8 Composite Financial Data for the Natural Gas Industry
1976-1981 and 1983-1985 Estimates 9-14
9-9 Projected Lower-48 States Conventional Natural Gas
Production 9-16
9-10 Projections of Natural Gas Supply: Comparison of 1980
Forecasts 9-18
9-11 Estimated Number of New Gas Plants, 1983-1987 9-20
9-12 Natural Gas Prices: History and Projections for
1965-1995 9-22
ix
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LIST OF TABLES (Concluded)
Number Page
9-13 Onshore Natural Gas Processing, Total and Cumulative
Before-Tax Net Annualized Cost of VOC NSPS Regulatory
Alternatives 1983-1987 9-27
9-14 Onshore Natural Gas Processing Model Plants' Before-Tax
Net Annualized Cost of VOC NSPS Regulatory Alternatives
Per Plant 9-28
9-15 Onshore Natural Gas Processing Model Plants' After-Tax
Net Annualized Cost of VOC NSPS Regulatory Alternatives
Per Plant 9-29
C-l Gas Plants Tested for Fugitive Emissions C-3
C-2 Instrument Screening Data for EPA-Tested Gas Plants . . . C-6
C-3 Soap Screening Data for API-Tested and
EPA-Tested Gas Plants C-7
E-l Results of the LDAR Model Leak Detection and
Repair Programs E-5
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LIST OF FIGURES
Number Page
3-1 General schematic of natural gas-gasoline processing. . . 3-2
3-2 Diagram of a simple packed seal 3-3
3-3 Diagram of a basic single mechanical seal 3-4
3-4 Diagram of a gate valve 3-6
3-5 Diagram of a spring-loaded relief valve 3-6
4-1 Rupture disk intallation upstream of a relief valve . . . 4-14
4-2 Diagram of two closed-loop sampling systems 4-18
9-1 Selected natural gas prices - three categories for the
period 1955-1979 9-13
9-2 Projected new discovery onshore natural gas production. . 9-17
E-l Schematic diagram of the modeled leak detection
and repair program E-3
XI
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1.0 SUMMARY
1.1 REGULATORY ALTERNATIVES
Standards of performance for new stationary sources of volatile
organic compounds (VOC) from fugitive emission sources in the onshore
natural gas production industry are being developed under, the authority
of Section 111 of the Clean Air Act. These standards would reduce
emissions caused by leaks from valves, relief valves, open-ended
lines, compressor seals, pump seals, and sampling connections. Because
VOC is emitted as a result of equipment leaks, the,emissions are
referred to as fugitive emissions, and the process equipment are
referred to as fugitive emission sources in this document. However,
the title of this document has been changed from the title used for
previous drafts (VOC Fugitive Emissions in On-Shore Natural Gas Production
Industry - Background Information for Proposed Standards) to "Equipment
Leaks of VOC in Natural Gas Production Industry - Background Information
for Proposed Standards" to^-clarify that the fugitive emissions are the
result of equipment leaks.
Four regulatory alternatives were considered. Regulatory Alternative I
is the baseline alternative and represents the level of control that
would exist in the absence of any standards of performance. Requirements
of Alternative II are:
o Quarterly instrument monitoring for leaks from valves,
relief valves, and compressor seals;
o Quarterly instrument and weekly visual monitoring for leaks
from pump seals; and
o Installation of caps (including plugs, flanges, or second
valves) on open-ended lines.
Regulatory Alternative III is more restrictive than Alternative II.
1-1
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The requirements are as follows:
o Monthly monitoring of valves (if a particular valve is founa
not to be leaking for 3 successive months, then 2 months may
be skipped before the next time it is monitored with an
instrument);
o Monthly monitoring of relief valves and pump seals, and
weekly visual inspection of pump seals;
o Installation of a vent control system to control compressor
seal emissions;
o Installation of closed purge sampling systems on sampling
connections; and
o Installation of caps (including plugs, flanges, or second
valves) on open-ended lines.
Regulatory Alternative IV is the most stringent of the alternatives.
Monthly instrument monitoring would be required for valves, relief
valves would be equipped with a rupture disc, and pumps would be
required to have dual mechanical seals. Other requirements would be
the same as Alternative III.
1.2 ENVIRONMENTAL IMPACT
Fugitive emissions of VOC from affected gas production facilities
under Regulatory Alternative I would be approximately 22,000 Mg/yr in
1987, the fifth year of implementation. This is compared to 6,900,
6,200, and 5,000 Mg/yr under Alternatives II, III, and IV, respectively.
In addition to reducing emissions to the atmosphere, Alternatives II,
III, and IV would reduce liquid leaks, thereby reducing wastewater
treatment needs. Some solid waste would be generated by the replacement
of existing equipment (e.g., replaced seal packing, rupture discs).
However, this amount of solid waste would be very small in comparison
to existing levels of solid waste generated by gas plants.
Energy savings from VOC and non-VOC hydrocarbons would result
under Regulatory Alternatives II-IV. Under Alternative II, hydrocarbons
recovered during the fifth year of implementation would have an energy
content of approximately 6,400 terajoules. This is equivalent to the
heating valve of approximately 1,050 barrels of crude oil. Hydrocarbons
recovered under Alternative III would result in slightly less energy
savings than Alternative II, because emissions are not recovered from
1-2
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compressor seal leaks. Alternative IV would result in energy savings
of approximately 6,900 terajoules, which is approximately equivalent
to the heating value of 1,120 barrels of crude oil.
A more detailed analysis of environmental and energy impacts is
presented in Chapter 7. A summary of the environmental impacts
associated with the four regulatory alternatives is shown in Table 1-1.
1.3 ECONOMIC IMPACT
Costs incurred by the onshore natural gas production industry
under Regulatory Alternative II would actually be a credit due to the
value of the recovered hydrocarbons. In the fifth year of implementation
of Alternative II, a net annual credit of $160,000 would result. Net
annual costs incurred during the fifth year under Alternative III
would be approximately $510,000; under Regulatory Alternative IV net
annual costs of over $7 million are incurred. A more detailed analysis
of costs is included in Chapter 8. Price impacts of the regulatory
alternatives are expected to be slight regardless of the regulatory
alternative. No plant closures or curtailments are expected, and
effects on industry profitability, output, growth, and other factors
would be negligible or zero. A more detailed economic analysis is
presented in Chapter 9. A summary of environmental, energy, and
economic impacts associated with the alternatives is shown in Table 1-1.
1-3
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Table 1-1. ENVIRONMENTAL, ENERGY, AND ECONOMIC IMPACTS OF REGULATORY ALTERNATIVES
Administrative
Action
Regulatory
Alternative I
(No action)
Regulatory
Alternative II
Regulatory
Alternative III
Regulatory
Alternative IV
Sol id
Air Water Waste Energy
Impact Impact Impact Impact
00 00
+2** +1** 0 +1*
+2** +1** 0 +1*
+2** +1** 0 +1*
Noise Economic
Impact Impact
0 0
0 +1*
0 -1*
0 -1*
KEY: + Beneficial impact
- Adverse impact
0 No impact
1 Negligible impact
2 Small impact
3 Moderate impact
4 Large impact
* Short-term impact
** Long-term impact
*** Irreversible impact
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2.0 INTRODUCTION
2.1 BACKGROUND AND AUTHORITY FOR STANDARDS
Before standards of performance are proposed as a Federal regulation,
air pollution control methods available to the affected industry and
the associated costs of installing and maintaining the control equipment
are examined in detail. Various levels of control based on different
technologies and degrees of efficiency are expressed as regulatory
alternatives. Each of these alternatives is studied by EPA as a
prospective basis for a standard. The alternatives are investigated
in terms of their impacts on the economics and well-being of the
industry, the impacts on the national economy, and the impacts on the
environment. This document summarizes the information obtained through
these studies so that interested persons will be privy to the information
considered by EPA in the development of the proposed standard.
Standards of performance for new stationary sources are established
under Section 111 of the Clean Air Act (42 U.S.C. 7411) as amended,
hereinafter referred to as the Act. Section 111 directs the Administrator
to establish standards of performance for any category of new stationary
source of air pollution which ". . . causes, or contributes significantly
to air pollution which may reasonably be anticipated to endanger
public health or welfare."
The Act requires that standards of performance for stationary
sources reflect, ". . . the degree of emission reduction achievable
which (taking into consideration the cost of achieving such emission
reduction, and any nonair quality health and environmental impact and
energy requirements) the Administrator determines has been adequately
demonstrated for that category of sources." The standards apply only
to stationary sources, the construction or modification of which
commences after regulations are proposed by publication in the Federal
Register.
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The 1977 amendments to the Act altered or added numerous provisions
that apply to the process of establishing standards of performance.
1. EPA is required to review the standards of performance every
4 years and, if appropriate, revise them.
2. EPA is authorized to promulgate a standard based on design,
equipment, work practice, or operational procedures when a standard
based on emission levels is not feasible.
3. The term "standards of performance" is redefined, and a new
term "technological system of continuous emission reduction" is defined.
The new definitions clarify that the control system must be continuous
and may include a low- or non-polluting process or operation.
4. The time between the proposal and promulgation of a standard
under section 111 of the Act may be extended to 6 months.
. Standards of performance, by themselves, do not guarantee protection
of health or welfare because they are not designed to achieve any
specific air quality levels. Rather, they are designed to reflect the
degree of emission limitation achievable through application of the
best adequately demonstrated technological system of continuous emission
reduction, taking into consideration the cost of achieving such emission
reduction, any nonair-quality health and environmental impacts, and
energy requirements.
Congress had several reasons for including these requirements.
First, standards with a degree of uniformity are needed to avoid
situations where some States may attract industries by relaxing standards
relative to other States. Second, stringent standards enhance the
potential for long-term growth. Third, stringent standards may help
achieve long-term cost savings by avoiding the need for more expensive
retrofitting when pollution ceilings may be reduced in the future.
Fourth, certain types of standards for coal-burning sources can adversely
affect the coal market by driving up the price of low-sulfur coal or
effectively excluding certain coals from the reserve base because
their untreated pollution potentials are high. Congress does not
intend that new source performance standards contribute to these
problems. Fifth, the standard-setting process should create incen-
tives for improved technology.
2-2
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Promulgation of standards of performance does not prevent State
or local agencies from adopting more stringent emission limitations
for the same sources. States are free under Section 116 of the Act to
establish even more stringent emission limits than those established
under Section 111 or those necessary to attain or maintain the National
Ambient Air Quality Standards (NAAQS) under Section 110. Thus, new
sources may in some cases be subject to limitations more stringent
than standards of performance under Section 111, and prospective
owners and operators of new sources should be aware of this possibility
in planning for such facilities.
A similar situation may arise when a major emitting facility is
to be constructed in a geographic area that falls under the prevention
of significant deterioration of air quality provisions of Part C of
the Act. These provisions require, among other things, that major
emitting facilities to be constructed in such areas are to be subject
to best available control technology. The term Best Available Control
Technology (BACT), as defined in the Act, means
... an emission limitation based on the maximum degree of
reduction of each pollutant subject to regulation under
this Act emitted from, or which results from, any major
emitting facility, which the permitting authority, on a
case-by-case basis, taking into account energy, environ-
mental, and economic impacts and other costs, determines is
achievable for such facility through application of produc-
tion processes and available methods, systems, and techniques,
including fuel cleaning or treatment or innovative fuel
combustion techniques for control of each such pollutant.
In no event shall application of 'best available control
technology' result in emissions of any pollutants which
will exceed the emissions allowed by any applicable standard
established pursuant to Sections 111 or 112 of this Act.
(Section 169(3))
Although standards of performance are normally structured in
terms of numerical emission limits where feasible, alternative approaches
are sometimes necessary. In some cases physical measurement of emissions
from a new source may be impractical or exorbitantly expensive.
Section lll(h) provides that the Administrator may promulgate a design
or equipment standard in those cases where it is not feasible to
prescribe or enforce a standard of performance. For example, emissions
of hydrocarbons from storage vessels for petroleum liquids are greatest
2-3
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during tank filling. The nature of the emissions, high concentrations
for short periods during filling and low concentrations for longer
periods during storage, and the configuration of storage tanks make
direct emission measurement impractical. Therefore, a more practical
approach to standards of performance for storage vessels has been
equipment specification.
In addition, Section lll(j) authorizes the Administrator to grant
waivers of compliance to permit a source to use innovative continuous
emission control technology. In order to grant the waiver, the Admin-
istrator must find: (1) a substantial likelihood that the technology
will produce greater emission reductions than the standards require or
an equivalent reduction at lower economic energy or environmental
cost; (2) the proposed system has not been adequately demonstrated;
(3) the technology will not cause or contribute to an unreasonable
risk to the public health, welfare, or safety; (4) the governor of the
State where the source is located consents; and (5) the waiver will
not prevent the attainment or maintenance of any ambient standard. A
waiver may have conditions attached to assure the source will not
prevent attainment of any NAAQS. Any such condition will have the
force of a performance standard. Finally, waivers have definite end
dates and may be terminated earlier if the conditions are not met or
if the system fails to perform as expected. In such a case, the
source may be given up to 3 years to meet the standards with a mandatory
progress schedule.
2.2 SELECTION OF CATEGORIES OF STATIONARY SOURCES
Section 111 of the Act directs the Adminstrator to list categories
of stationary sources. The Administrator ". . . shall include a
category of sources in such list if in his judgement it causes, or
contributes significantly to, air pollution which may reasonably be
anticipated to endanger public health or welfare." Proposal and
promulgation of standards of performance are to follow.
Since passage of the Clean Air Amendments of 1970, considerable
attention has been given to the development of a system for assigning
priorities to various source categories. The approach specifies areas
of interest by considering the broad strategy of the Agency for imple-
menting the Clean Air Act. Often, these "areas" are actually pollutants
2-4
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emitted by stationary sources. Source categories that emit these
pollutants are evaluated and ranked by a process involving such factors
as: (1) the level of emission control (if any) already required by
State regulations, (2) estimated levels of control that might be
required from standards of performance for the source category,
(3) projections of growth and replacement of existing facilities for
the source category, and (4) the estimated incremental amount of air
pollution that could be prevented in a preselected future year by
standards of performance for the source category. Sources for which
new source performance standards were promulgated or under development
during 1977, or earlier, were selected on these criteria.
The Act amendments of August 1977 establish specific criteria to
be used in determining priorities for all major source categories not
yet listed by EPA. These are: (1) the quantity of air pollutant
emissions that each such category will emit, or will be designed to
emit; (2) the extent to which each such pollutant may reasonably be
anticipated to endanger public health or welfare; and (3) the mobility
and competitive nature of each such category of sources and the consequent
need for nationally applicable new source standards of performance.
The Administrator is to promulgate standards for these categories
according to the schedule referred to earlier.
In some cases it may not be feasible immediately to develop a
standard for a source category with a high priority. This might
happen when a program of research is needed to develop control techniques
or because techniques for sampling and measuring emissions may require
refinement. In the developing of standards, differences in the time
required to complete the necessary investigation for different source
categories must also be considered. For example, substantially more
time may be necessary if numerous pollutants must be investigated from
a single source category. Further, even late in the development
process the schedule for completion of a standard may change. For
example, inablility to obtain emission data from well-controlled
sources in time to pursue the development process in a systematic
fashion may force a change in scheduling. Nevertheless, priority
ranking is, and will continue to be, used to establish the order in
which projects are initiated and resources assigned.
2-5
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After the source category has been chosen, the types of facilities
within the source category to which the standard will apply must be
determined. A source category may have several facilities that cause
air pollution, and emissions from some of these facilities may vary
from insignificant to very expensive to control. Economic studies of
the source category and of applicable control technology may show that
air pollution control is better served by applying standards to the
more severe pollution sources. For this reason, and because there is
no adequately demonstrated system for controlling emissions from
certain facilities, standards often do not apply to all facilities at
a source. For the same reasons, the standards may not apply to all air
pollutants emitted. Thus, although a source category may be selected
to be covered by a standard of performance, not all pollutants or
facilities within that source category may be covered by the standards.
2.3 PROCEDURE FOR DEVELOPMENT OF STANDARDS OF PERFORMANCE
Standards of performance must (1) realistically reflect best
demonstrated control practice; (2) adequately consider the cost, the
nonairquality health and environmental impacts, and the energy requirements
of such control; (3) be applicable to existing sources that are modified
or reconstructed as well as new installations; and (4) meet these
conditions for all variations of operating conditions being considered
anywhere in the country.
The objective of a program for developing standards is to identify
the best technological system of continuous emission reduction that
has been adequately demonstrated. The standard-setting process involves
three principal phases of activity: (1) information gathering, (2) analysis
of the information, and (3) development of the standard of performance.
During the information-gathering phase, industries are queried
through a telephone survey, letters of inquiry, and plant visits by
EPA representatives. Information is also gathered from many other
sources to provide reliable data that characterize the pollutant
emissions from well-controlled existing facilities.
In the second phase of a project, the information about the
industry and the pollutants emitted is used in analytical studies.
Hypothetical "model plants" are defined to provide a common basis for
analysis. The model plant definitions, national pollutant emission
2-6
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data, and existing State regulations governing emissions from the
source category are then used in establishing "regulatory alternatives."
These regulatory alternatives are essentially different levels of
emission control.
EPA conducts studies to determine the impact of each regulatory
alternative on the economics of the industry and on the national
economy, on the environment, and on energy consumption. From several
possibly applicable alternatives, EPA selects the single most plausible
regulatory alternative as the basis for a standard of performance for
the source category under study.
In the third phase of a project, the selected regulatory alternative
is translated into a standard of performance, which, in turn, is
written in the form of a Federal regulation. The Federal regulation,
when applied to newly constructed plants, will limit emissions to the
levels indicated in the selected regulatory alternative.
As early as is practical in each standard-setting project, EPA
representatives discuss the possibilities of a standard and the form
it might take with members of the National Air Pollution Control
Techniques Advisory Committee. Industry representatives and other
interested parties also participate in these meetings.
The information acquired in the project is summarized in the
Background Information Document (BID). The BID, the standard, and a
preamble explaining the standard are widely circulated to the industry
being considered for control, environmental groups, other government
agencies, and offices within EPA. Through this extensive review
process, the points of view of expert reviewers are taken into consideration
as changes are made to the documentation.
A "proposal package" is assembled and sent through the offices of
EPA Assistant Administrators for concurrence before the proposed
standard is officially endorsed by the EPA Administrator. After being
approved by the EPA Administrator, the preamble and the proposed
regulation are published in the Federal Register.
As a part of the Federal Register announcement of the proposed
regulation, the public is invited to participate in the standard-setting
process. EPA invites written comments on the proposal and also holds
a public hearing to discuss the proposed standard with interested
2-7
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parties. All public comments are summarized and incorporated into a
second volume of the BID. All information reviewed and generated in
studies in support of the standard of performance is available to the
public in a "docket" on file in Washington, D. C.
Comments from the public are evaluated, and the standard of
performance may be altered in response to the comments.
The significant comments and EPA's position on the issues raised
are included in the "preamble" of a "promulgation package," which also
contains the draft of the final regulation. The regulation is then
subjected to another round of review and refinement until it is approved
by the EPA Administrator. After the Administrator signs the regulation,
it is published as a "final rule" in the Federal Register.
2.4 CONSIDERATION OF COSTS
Section 317 of the Act requires an economic impact assessment
with respect to any standard of performance established under Section 111
of the Act. The assessment is required to contain an analysis of:
(1) the costs of compliance with the regulation, including the extent
to which the cost of compliance varies depending on the effective date
of the regulation and the development of less expensive or more efficient
methods of compliance; (2) the potential inflationary or recessionary
effects of the regulation; (3) the effects the regulation might have
on small business with respect to competition; (4) the effects of the
regulation on consumer costs; and (5) the effects of the regulation on
energy use. Section 317 also requires that the economic impact assessment
be as extensive as practicable.
The economic impact of a proposed standard upon an industry is
usually addressed both in absolute terms and in terms of the control
costs that would be incurred as a result of compliance with typical,
existing State control regulations. An incremental approach is necessary
because both new and existing plants would be required to comply with
State regulations in the absence of a Federal standard of performance.
This approach requires a detailed analysis of the economic impact from
the cost differential that would exist between a proposed standard of
performance and the typical State standard.
Air pollutant emissions may cause water pollution problems, and
captured potential air pollutants may pose a solid waste disposal
2-8
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problem. The total environmental impact of an emission source must,
therefore, be analyzed and the costs determined whenever possible.
A thorough study of the profitability and price-setting mechanisms
of the industry is essential to the analysis so that an accurate
estimate of potential adverse economic impacts can be made for proposed
standards. It is also essential to know the capital requirements for
pollution control systems already placed on plants so that the additional
capital requirements necessitated by these Federal standards can be
placed in proper perspective. Finally, it is necessary to assess the
availability of capital to provide the additional control equipment
needed to meet the standards of performance.
2.5 CONSIDERATION OF ENVIRONMENTAL IMPACTS
Section 102(2)(C) of the National Environmental Policy Act (NEPA)
of 1969 requires Federal agencies to prepare detailed environmental
impact statements on proposals for legislation and other major Federal
actions significantly affecting the quality of the human environment.
The objective of NEPA is to build into the decisionmaking process of
Federal agencies a careful consideration of all environmental aspects
of proposed actions.
In a number of legal challenges to standards of performance for
various industries, the United States Court of Appeals for the District
of Columbia Circuit has held that environmental impact statements need
not be prepared by the Agency for proposed actions under Section 111
of the Clean Air Act. Essentially, the Court of Appeals has determined
that the best system of emission reduction requires the Administrator
to take into account counter-productive environmental effects of a
proposed standard, as well as economic costs to the industry. On this
basis, therefore, the Court established a narrow exemption from NEPA
for EPA determination under Section 111.
In addition to these judicial determinations, the Energy Supply
and Environmental Coordination Act (ESECA) of 1974 (PL-93-319) specifically
exempted proposed actions under the Clean Air Act from NEPA requirements.
According to Section 7(c)(l), "No action taken under the Clean Air Act
shall be deemed a major Federal action significantly affecting the
quality of the human environment within the meaning of the National
Environmental Policy Act of 1969" (15 U.S.C. 793(c)(l)).
2-9
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Nevertheless, the Agency has concluded that the preparation of
environmental impact statements could have beneficial effects on
certain regulatory actions. Consequently, although not legally required
to do so by Section 102(2)(C) of NEPA, EPA has adopted a policy requiring
that environmental impact statements be prepared for various regulatory
actions, including standards of performance developed under Section 111
of the Act. This voluntary preparation of environmental impact statements,
however, in no way legally subjects the Agency to NEPA requirements.
To implement this policy, a separate section in this document is
devoted solely to an analysis of the potential environmental impacts
associated with the proposed standards. Both adverse and beneficial
impacts in such areas as air and water pollution, increased solid
waste disposal, and increased energy consumption are discussed.
2.6 IMPACT ON EXISTING SOURCES
Section 111 of the Act defines a new source as ". . . any stationary
source, the construction or modification of which is commenced ..."
after the proposed standards are published. An existing source is
redefined as a new source if "modified" or "reconstructed" as defined
in amendments to the general provisions of Subpart A of 40 CFR Part
60, which were promulgated in the Federal Register on December 16,
1975 (40 FR 58416).
Promulgation of a standard of performance requires States to
establish standards of performance for existing sources in the same
industry under Section 111 (d) of the Act if the standard for new
sources limits emissions of a designated pollutant (i.e., a pollutant
for which air quality criteria have not been issued under Section 108
or which has not been listed as a hazardous pollutant under Section 112).
If a State does not act, EPA must establish such standards. General
provisions outlining procedures for control of existing sources under
Section lll(d) were promulgated on November 17, 1975, as Subpart B of
40 CFR Part 60 (40 FR 53340).
2.7 REVISION OF STANDARDS OF PERFORMANCE
Congress was aware that the level of air pollution control achievable
by any industry may improve with technological advances. Accordingly,
section 111 of the Act provides that the Administrator ". . . shall,
2-10
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at least every 4 years, review and, if appropriate, revise . . ." the
standards. Revisions are made to assure that the standards continue
to reflect the best systems that become available in the future. Such
revisions will not be retroactive, but will apply to stationary sources
constructed or modified after the proposal of the revised standards.
2-11
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3.0 SOURCES OF VOC EMISSIONS
3.1 GENERAL
Natural gas processing plants are a part of the oil and gas industry.
Field gas is first gathered in the field directly from gas wells or from
oil/gas separation equipment (see Figure 3-1). The gas may be compressed
at field stations for the purpose of transporting it to treating or
processing facilities. Treating is necessary in certain instances for
removal of water, sulfur compounds, or carbon dioxide. Gas gathering,
compression, and treating may or may not occur at a gas plant. For the
purposes of this document, natural gas processing plants are defined as
facilities engaged in the separation of natural gas liquids from field
gas and/or fractionation of the liquids into natural gas products, such
as ethane, propane, butane, and natural gasoline. Types of gas 'plants
are: absorption, refrigerated absorption, refrigeration, compression,
adsorption, cryogenic — Joule-Thomson, and cryogenic-expander.
3.2 DESCRIPTION OF FUGITIVE EMISSION SOURCES
In this document, fugitive emissions from gas plants are considered
to be those volatile organic compound (VOC) emissions that result when
process fluid (either gaseous or liquid) leaks from plant equipment. VOC
emissions are defined as nonmethane-nonethane hydrocarbon emissions.
There are many potential sources of fugitive emissions in a gas plant.
The following sources are considered in this chapter: pumps, compressors,
valves, relief valves, open-ended lines, sampling connections, flanges
and connections, and gas-operated control valves. These source types are
described below.
3.2.1 Pumps
Pumps are used in gas plants for the movement of natural gas liquids.
The centrifugal pump is the most widely used pump. However, other types,
such as the positive-displacement, reciprocating and rotary action, and
special canned and diaphragm pumps, may also be used. Natural gas liquids
3-1
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Sulfur
Recovery
Field Gas Gathering Systems
Field Compression
Gas Treating
Sweetening and Dehydration
(H2S, C02, and H20 Removal)
Separation of Natural Gas
Liquids from Field Gas
Fractionation of
Natural Gas Liquids
Dry Gas
to Sales
Sales Products
(ethane, propane, 1so-butane; butane, natural gasoline, etc.)
Figure 3-1. General Schematic of Natural Gas-Gasoline Processi
ng.
3-2
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transferred by pumps can leak at the point of contact between the moving
shaft and stationary casing. Consequently, all pumps except the canned-motor
and diaphragm type require a seal at the point where the shaft penetrates
the housing in order to isolate the pump's interior from the atmosphere.
Two generic types of seals, packed and mechanical, are currently in
use on pumps. Packed seals can be used on both reciprocating and rotary
action types of pumps. As Figure 3-2 shows, a packed seal consists of a
cavity ("stuffing box") in the pump casing filled with special packing
material that is compressed with a packing gland to form a seal around
the shaft. Lubrication is required to prevent the buildup of frictional
heat between the seal and shaft. The necessary lubrication is provided
o
by a lubricant that flows between the packing and the shaft.
Packing
Gland
Figure 3-2. Diagram of a simple packed seal.
Mechanical seals are limited in application to pumps with rotating shafts
and can further be categorized as single and dual mechanical seals.
There are many variations to the basic design of mechanical seals, but
all have a lapped seal face between a stationary element and a rotating
seal ring. In a single mechanical seal application (Figure 3-3), the
rotating-seal ring and stationary element faces are lapped to a very high
degree of flatness to maintain contact throughout their entire mutual
surface area. As with a packed seal, the seal faces must be lubricated
3-3
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to remove frictional heat.
less lubricant is needed.
PUMP
STUFFING
BOX
However, because of its construction, much
GLAND
'RING
STATIONARY
ELEMENT
POSSIBLE
LEAK AREA
SHAFT
ROTATING
S£AL RING
Figure 3-3. Diagram of a basic single mechanical seal.2
3.2.2 Compressors
Three types of compressors can be used in the natural gas production
industry: centrifugal, reciprocating, and rotary. The centrifugal
compressor utilizes a rotating element or series of elements containing
curved blades to increase the pressure of a gas by centrifugal force.
Reciprocating and rotary compressors increase pressure by confining the
gas in a cavity and progressively decreasing the volume of the cavity.
Reciprocating compressors usually employ a piston and cylinder arrangement
while rotary compressors utilize rotating elements such as lobed impellers
or sliding vanes. About half of the compressors installed in new plants
are likely to be centrifugal and half reciprocating.
As with pumps, sealing devices are required to prevent leakage from
compressors. Rotary shaft seals for compressors may be chosen from
several different types: labyrinth, restrictive carbon rings, mechanical
contact, and liquid film. All of these seal types are leak restriction
devices; none of them completely eliminate leakage. Many compressors may
be equipped with ports in the seal area to evacuate collected gases.
Mechanical contact seals are a common type of seal for rotary compressor
shafts, and are similar to the mechanical seals described for pumps. In
this type of seal the clearance between the rotating and stationary
elements is reduced to zero. Oil or another suitable lubricant is supplied
to the seal faces. Mechanical seals can achieve the lowest leak rates of
3-4
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the types identified above, but they are not suitable for all processing
3
conditions.
Packed seals are used for reciprocating compressor shafts. As with
pumps, the packing in the stuffing box is compressed with a gland to form
a seal. Packing used on reciprocating compressor shafts is often of the
"chevron" or nested V type. Because of safety considerations, the area
between the compressor seals and the compressor motor (distance piece) is
normally enclosed and vented outside of the compressor building. If
hydrogen sulfide is present in the gas, then the vented vapors are normally
flared.10
Reciprocating compressors may employ a metallic packing plate and
R R
nonmetallic partially compressible (i.e, GRAFFOIL, TEFLON ) material or
oil wiper rings to seal shaft leakage to the distance piece. Nevertheless,
some leakage into the distance piece may occur.
3.2.3 Process Valves
One of the most common pieces of equipment in gas plants is the
valve. The types of valves commonly used are globe, gate, plug, ball,
butterfly, relief, and check valves. All except the relief valve (to be
discussed below) and check valve are activated through a valve stem,
which may have a rotational or linear motion, depending on the specific
design. This stem requires a seal to isolate the process fluid inside
the valve from the atmosphere as illustrated by the diagram of a gate
valve in Figure 3-4. The possibility of a leak through this seal makes
it a potential source of fugitive emissions. Since a check valve has no
stem or subsequent packing gland, it is not considered to be a potential
source of fugitive emissions.
Sealing of the stem to prevent leakage can be achieved by packing
inside a packing gland or 0-ring seals. Valves that require the stem to
move in and out with or without rotation must utilize a packing gland.
Conventional packing glands are suited for a wide variety of packing
materials. The most common are various types of braided asbestos that
contain lubricants. Other packing materials include graphite, graphite-
impregnated fibers, and tetrafluoroethylene polymer. The packing material
used depends on the valve application and configuraton. These conventional
packing glands can be used over a wide range of operating temperatures.
At high pressures these glands must be quite tight to attain a good
seal.7
3-5
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PACKING
GLAND
POSSIBLE
LEAK AREAS
PACKING
Figure 3-4. Diagram of a gate valve.'
Possible
Leak Area
Process Side
Figure 3-5. Diagram of a spring-loaded relief valve.
3-6
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3.2.4 Pressure Relief Devices
Engineering codes require that pressure-relieving devices or systems
be used in applications where the process pressure may exceed the maximum
allowable working pressure of the vessel. The most common type of pressure-
relieving device used in process units is the pressure relief valve
(Figure 3-5). Typically, relief valves are spring-loaded and designed to
open when the process pressure exceeds a set pressure, allowing the
release of vapors or liquids until the system pressure is reduced to its
normal operating level. When the normal pressure is reattained, the
valve reseats, and a seal is again formed.8 The seal is a disk on a
seat, and the possibility of a leak through this seal makes the pressure
relief valve a potential source of VOC fugitive emissions. A seal leak
can result from corrosion or from improper reseating of the valve after a
relieving operation.
Rupture disks may also be used in process units. These disks are
made of a material that ruptures when a set pressure is exceeded, thus
allowing the system to depressurize. The advantage of a rupture disk is
that the disk seals tightly and does not allow any VOC to escape from the
system under normal operation. However, when the disk does rupture, the
system depressurizes until atmospheric conditions are obtained, unless
the disk is used in series with a pressure relief valve.
3.2.5 Open-Ended Lines
Some valves are installed in a system so that they function with the
downstream line open to the atmosphere. Open-ended lines are used mainly
in intermittent service for sampling and venting. Examples are purge,
drain, and sampling lines. Some open-ended lines are needed to preserve
product purity. These are normally installed between multi-use product
lines to prevent products from collecting in cross-tie lines due to valve
seat leakage. In addition to valve seat leakage, an incompletely closed
valve could result in VOC emissions to the atmosphere.
3.2.6 Flanges and Connections
Flanges are bolted, gasket-sealed junctions used wherever pipe or
other equipment such as vessels, pumps, valves, and heat exchangers may
require isolation or removal. Connections are all other nonwelded fittings
that serve a similar purpose to flanges, that also allow bends in pipes
(ells), joining two pipes (couplings), or joining three or four pipes
(tees or crosses). The connections are typically threaded
3-7
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Flanges may become fugitive emission sources when leakage occurs due
to improperly chosen gaskets or poorly assembled flanges. The primary
cause of flange leakage is due to thermal stress that piping or flanges
in sorie services undergo; this results in the deformation of the seal
between the flange faces.9 Threaded connections may leak if the threads
become damaged or corroded, or if tightened without sufficient lubrication
or torque.
3.2.7 Gas-Operated Control Valves
Pneumatic control valves are used widely in process control at gas
plants. Typically, compressed air is used as the operating medium for
these control valves. In certain instances, however, field gas or flash
gas is used to supply pressure. Since gas is either continuously bled
to the atmosphere or is bled each time the valve is activated, this can
potentially be a large source of fugitive emissions. There are also some
instances where highly pressurized field gas is used as the operating
medium for emergency control valves. However, these valves are seldom
activated and, therefore, have a much lower emissions potential than
control valves in routine service.
3.2.8 Sampling Connections
The operation of a gas plant is checked periodically by routine
analyses of process fluids. To obtain representative samples for these
analyses, sampling lines must first be purged prior to sampling. The
purged liquid is sometimes drained onto the ground or into a drain, where
it can evaporate and release VOC emissions to the atmosphere.
Purged vapor is typically released directly to the atmosphere.
3.3 BASELINE FUGITIVE VOC EMISSIONS
Baseline fugitive emission data have been obtained at six natural
gas/gasoline processing plants. Two of the plants were tested by Rockwell
International under contract to the American Petroleum Institute, and
12
four plants were tested by Radian Corporation under contract to EPA.
Baseline fugitive emission factors for six of the seven component types
1 O
were developed from these data. The emission factors are presented in
Table 3-1. The factors represent the average baseline emission rate from
each of the components of a specific type in a gas plant. Baseline
emissions for sampling connections were determined based on purge volume
calculations for both gas and liquid streams.13'14 The compressor seal
3-8
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Table 3-1. BASELINE FUGITIVE EMISSION FACTORS FOR
GAS PLANTS, kg/day
Component
Valves9
Relief valves3
Open-ended lines3
Compressor seals3'0
Pump seals3
Emission factor
0.18
0.33
0.34
1.0
1.2
(0.48)
(4.5)
(0.53)
(4.9)
(1.5)
95% Confidence interval
0.1-0.3
0.007-8
0.1-0.7
0.1-5
0.5-3
(0.2-1)
(0.1-100)
(0.2-1)
(0.7-30)
(0.5-4)
Sampling connections
Gas
Liquid
Flanges and3
connections
0.016 (0.32)
0.085 (0.085)
0.011 (0.026)
0.006-0.02 (0.01-0.05)
xx = VOC emission values.
(xx)= Total hydrocarbon emission values.
3Reference 12.
References 13 and 14. Liquid streams are assumed to be 100 percent
VOC, sampled twice per month with a 1.96 liter purge. Gas streams
are assumed to be sampled twice per shift with a 1 sec purge through
a 6.4 mm ID sample tube 15 cm long; 80% methane, 15% ethane, 5% VOC.
GEmission factors for compressors are based on EPA and API testing of emissions
into the distance piece area from open frame compressors. The factors
do not include emissions into the seal packing vent or into enclosed
distance pieces. Therefore- the emission factors given are probably
understated substantially.
3-9
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emissions factor represents only the emissions measured in the distance
piece area from open frame compressors. Therefore, the emissions from
the seal packing vent and from enclosed distance pieces are not included.
This probably results in a significant understatement of total compressor
emissions because the majority of the compressor emissions will come from
the seal vents. The total daily and annual emissions from fugitive
sources at a model gas plant are shown in Table 3-2. Total daily emissions
are calculated by multiplying the number of pieces of each type of equipment
by the corresponding daily emission factor. The average percent of total
emissions attributed to each component type is also presented in Table 3-2.
3-10
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Table 3-2. ESTIMATED BASELINE FUGITIVE VOC EMISSIONS FROM
A TYPICAL GAS PLANT
Component Number of
type components
Valves
Relief valves
Open-ended lines
Compressor seals
Pump seals
Sampling connections
Inlet Gas
Liquids
Flanges and 3
connections
750
12
150
6
6
6
6
,000
Total baseline emissions
Baseline
emissions,
kg/day
140
4.0
51
6.0
7.2
0.1
0.5
33
242
(360)
( 54)
( 80)
( 29)
( 9.0)
(1.9)
(0.5)
( 78)
(612)
Percentage of
total emissions
58
2
21
2
3
1
1
14
(59)
( 9)
(13)
( 5)
( 1)
( 1)
( 1)
(13)
xx = VOC emission values.
(xx) = Total hydrocarbon emissions values.
aFrom Table 3-1.
As discussed in Table 3-1, the compressor seal emission factor and thus
the percentage of total emissions from compressors may be substantially
understated.
3-11
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3.4 REFERENCES
1. Cantrell, A. Worldwide Gas Processing. Oil and Gas Journal,
July 14, 1980. p. 88. Docket Reference Number II-I-23.*
2. Organic Chemical Manufacturing, Volume 3: Storage, Fugitive, and
Secondary Sources. Report 2, Fugitive Emissions. U.S. Environmental
Protection Agency. Office of Air Quality Planning and Standards.
Emission Standards and Engineering Division. Research Triangle
Park, North Carolina. EPA-450/3-80-025. December 1980. Docket
Reference Number II-A-22.*
3. Nelson, W.E. Compressor Seal Fundamentals. Hydrocarbon Processing,
56_(12):91-95. 1977. Docket Reference Number II-I-12.*
4. Telecon. R.A. McAllister, TRW, to G.H. Holliday, Shell Oil, Houston,
Texas. March 10, 1981. Compressors and seals at gas plants.
Docket Reference Number II-E-7.*
5. Letter from Hennings, T.J., TRW to K.C. Hustvedt, EPA. May 13, 1981.
Results of a telephone survey concerning the use of pneumatic
control valves at gas plants. Docket Reference Number II-B-6.*
6. Lyons, J.D., and C.L. Ashland, Jr. Lyons' Encyclopedia of Valves.
New York, Van Nostrand Reinhold Co., 1975. 290 p. Docket Reference
Number II-I-9.*
7. Templeton, H.C. Valve Installation, Operation and Maintenance.
Chem. E., 78(23)141-149, 1971. Docket Reference Number II-I-4.*
8. Steigerwald, B.J. Emissions of Hydrocarbons to the Atmosphere from
Seals on Pumps and Compressors. Report No. 6, PB 216 582, Joint
District, Federal and State Project for the Evaluation of Refinery
Emissions. Air Pollution Control District, County of Los Angeles,
California. April 1958. 37 p. Docket Reference Number II-I-l.*
9. McFarland, I. Preventing Flange Fires. Chemical Engineering
Progress, ^5(8):59-61. 1969. Docket Reference Number II-I-3.*
10. Letter from Hennings, T.J., TRW to K.C. Hustvedt, EPA. July 7, 1981.
Results of a telephone survey concerning control of fugitive emissions
from gas plant compressor seals. Docket Reference Number II-B-7.*
11. Eaton, W.S., et al. Fugitive Hydrocarbon Emissions from Petroleum
Production Operations. API Publication No. 4322. March 1980. Docket
Reference Number II-I-20.*
12. DuBose, D.A., J.I. Steinmetz, and G.E. Harris. Frequency of Leak
Occurrence and Emission Factors for Natural Gas Liquid Plants.
Final Report. Radian Corp., Austin, Texas. Prepared for U.S.
Environmental Protection Agency, Emissions Measurement Branch,
Research Triangle Park, North Carolina. EMB Report No. 80-FOL-l.
July 1982. Docket Reference Number II-A-36.*
3-12
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13. Memo from Norwood, T.L., PES to Docket. Gas sampling connection
purge emission factor and control cost effectiveness. October 28,
1982. Docket Reference Number II-B-15.*
14. Memo from Norwood, T.L., PES to Docket, Liquid sampling connection
purge emission factor and control cost effectiveness. October 27,
1982. Docket Reference Number II-B-14.*
15. Letter and Attachments. Norwood, Tom, Pacific Environmental Services,
Inc. to Gibson, Jim, Seagull Products Company. Draft Trip Report
to Palacios Gas Plant. December 9, 1982. Docket Reference Number
II-C-18.*
16. "National Air Pollution Control Techniques Advisory Committee
Minutes of Meeting July 21 and 22, 1982," U.S. EPA:OAQPS, RTP, NC.
August 23, 1982. Page 111-43. Docket Reference Number II-A-24.*
*References can be located in Docket Number A-80-20-B at U.S. Environmental
Protection Agency Library, Waterside Mall, Washington, D.C.
3-13
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4.0 EMISSION CONTROL TECHNIQUES
4.1 INTRODUCTION
Sources of fugitive VOC emissions from gas plant equipment were
identified in Chapter 3 of this document. This chapter discusses the
emission control techniques that can be applied to reduce fugitive VOC
emissions from these sources. These techniques include leak detection
and repair programs and equipment specifications. The estimated
control effectiveness of the techniques is also presented. In some
cases, the techniques for reducing gas plant fugitive emissions are
based on transfer of control technology as applied to related industries.
This approach is possible because the related industries (e.g., refineries)
use similar types of equipment, such as valves, pumps, and compressors.
There may be differences between gas plants and related industries in
average line temperatures, product composition, or other parameters.
However, these differences do not influence the applicability of the
techniques used in controlling fugitive emissions.
Chapter 4 also presents other control strategies applicable to
control of fugitive emissions from gas plants. However, the control
effectiveness of these alternative strategies has not been estimated.
4.2 LEAK DETECTION AND REPAIR METHODS
Leak detection and repair methods can be applied in order to
reduce fugitive emissions from gas plant sources. Leak detection
methods are used to identify equipment components that are emitting
significant amounts of VOC. Emissions from leaking sources may be
reduced by three general methods: repair, modification, or replacement
of the source.
4.2.1 Leak Detection Techniques
Various monitoring techniques that can be used in a leak detection
program include individual component surveys, unit area (walk-through)
4-1
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surveys, and fixed-point monitoring systems. These emission detection
methods would yield qualitative indications of leaks.
4.2.1.1 Individual Component Survey. Each fugitive emission
source (pump, valve, compressor, etc.) is checked for VOC leakage in
an individual component survey. The source may be checked for leakage
by visual, audible, olfactory, soap solution, or instrument techniques.
Visual methods are good for locating liquid leaks, especially pump
seal failures. High pressure vapor leaks may be detected by hearing
the escaping vapors, and leaks of odorous materials may be detected by
smell. Predominant industry practices are leak detection by visual,
audible, and olfactory methods. However, in many instances, even very
large VOC leaks are not detected by these methods.
Applying a soap solution on equipment components is one individual
survey method. If bubbles are seen in the soap solution, a leak from
the component is indicated. The method requires that the observer
subjectively determine the rate of leakage based on the rate of formation
of soap bubbles over a specified time period. The method is not
appropriate for very hot sources, although ethylene glycol can be
added to the soap solution to extend the temperature range. This
method is also not suited for moving shafts on pumps or compressors,
since the motion of the shaft may cause entrainment of air in the soap
solution and indicate a leak when none is present. In addition, the
method cannot generally be applied to open sources such as relief
valves or vents without additional equipment.
The use of portable hydrocarbon detection instruments is the best
known individual survey method for identifying leaks of VOC from
equipment components because it is applicable to all types of sources.
The instrument is used to sample and analyze the air in close proximity
to the potential leak surface by traversing the sampling probe tip
over the entire area where leaks may occur. This sampling traverse is
called "monitoring" in subsequent descriptions. A measure of the
hydrocarbon concentration of the sampled air is displayed in the
instrument meter. The performance criteria for monitoring instruments
and a description of instrument survey methods are included in Appendix D.
Table 4-1 presents data on the percentage of components that are
4-2
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Table 4-1. PERCENTAGE OF COMPONENTS PREDICTED TO BE LEAKING
IN AN INDIVIDUAL COMPONENT SURVEY
Component
type
Valves3
Relief valves
Compressor seals3
Punp seals3
Predicted percent of sources leaking
100,000 ppmv
9
8
20
10
50,000 ppmv
11
11
27
22
20,000 ppmv
14
15
35
26
10,000 ppmv
18
19
43
33
1,000 ppmv
28
34
60
53
Reference 1.
'Reference 2.
-------
predicted to have instrument readings greater than or equal to various
concentrations during an individual component survey.
4.2.1.2 Unit Area Survey. A unit area or walk-through survey
entails measuring the ambient VOC concentration within a given distance,
for example, one meter, of all equipment located at ground level and
other accessible levels within a processing area. These measurements
are performed with a portable VOC detection instrument utilizing a
strip chart recorder.
The instrument operator walks a predetermined path to assure
total coverage of a unit on both the upwind and downwind sides of the
equipment, noting on the chart record the location in a unit where any
elevated VOC concentrations are detected. If an elevated VOC concentration
is recorded, the components in that area can be screened individually
to locate the specific leaking equipment.
It is estimated that 50 percent of all significant leaks in a
unit are detected by the walk-through survey, provided that there are
only a few pieces of leaking equipment, thus reducing the VOC background
concentration sufficiently to allow for reliable detection.
The major advantages of the unit area survey are that leaks from
accessible leak sources near the ground can be located quickly and
that the leak detection manpower requirements can be lower than those
for the individual component survey. Some of the shortcomings of this
method are that VOC emissions from adjacent units can cause false leak
indications; high or intermittent winds (local meteorological conditions)
can increase dispersion of VOC, causing leaks to be undetected; elevated
equipment leaks may not be detected; and additional effort is necessary
to locate the specific leaking equipment, i.e., individual checks in
areas where high concentrations are found.
4.2.1.3 Fixed-Point Monitors. This method consists of placing
several automatic hydrocarbon sampling and analysis instruments at
various locations in the process unit. The instruments may sample the
ambient air intermittently or continuously. Hydrocarbon concentrations
above a background level indicate a leaking component. As in the
walk-through method, an individual component survey is required to
identify the specific leaking component in the area. Leaks from
-------
adjacent units and meteorological conditions may affect the results
obtained. The efficiency of this method is not well established, but
it has been estimated that 33 percent of the number of leaks identified
by a complete individual component survey could be located by fixed-point
monitors. These leaks would be detected sooner by fixed-point monitors
than by use of portable monitors, because the fixed-point monitors
operate semi continuously. Fixed-point monitors are more expensive;
multiple fixed point monitors may be required; and use of the portable
instrument is still required to locate the specific leaking component.
Calibration and maintenance costs may be higher. Fixed-point monitors
have been used to detect emissions of hazardous or toxic substances
(such as vinyl chloride) as well as potentially explosive conditions.
Fixed-point monitors have an advantage in these cases, since a particular
compound can be selected as the sampling criterion.
4.2.1.4 Visual Inspections. Visual inspections can be performed
for any of the leak detection techniques discussed above to detect
evidence of liquid leakage from plant equipment. When such evidence
is observed, the operator can use a portable VOC detection instrument
to measure the VOC concentration of the source. In a specific application,
visual inspections can be used to detect the failure of the outer seal
of a pump's dual mechanical seal system. Observation of liquid leaking
along the shaft indicates an outer seal failure and signals the need
5
for seal repair.
4.2.2 Repair Methods
The following descriptions of repair methods include only those
features of each fugitive emission source (pump, valve, etc.) that
should be considered in assessing the applicability and effectiveness
of each method.
4.2.2.1 Valves. Most valves have a packing gland that can be
tightened while in service. Although this procedure should decrease
the emissions from the valve, in some cases it may actually increase
the emission rate if the packing is old and brittle or has been
overtightened. Unbalanced tightening of the packing gland may also
cause the packing material to be positioned improperly in the valve
and allow leakage. Valves that are not often used can build up a
4-5
-------
"static" seal of paint or hardened lubricant that could be broken by
tightening the packing gland. Plug-type valves can be lubricated with
grease to reduce emissions around the plug.
Some types of valves have no means of in-service repair and must
be isolated from the process and removed for repair or replacement.
Other valves, such as control valves, may be excluded from in-service
repair by operating procedures or safety procedures. In many cases,
valves cannot be isolated from the process for removal. If a line
must be shut down in order to isolate a leaking valve, the emissions
resulting from the shutdown may possibly be greater than the emissions
from the valve if it were allowed to leak until the next process
change that permits isolation for repair. Depending on site-specific
factors, it may also be possible to repair leaking process valves by
injection of a sealing fluid into the source of the leak.
4.2.2.2 Pressure Relief Valves. In general, pressure relief
valves that leak must be removed in order to repair the leak. In some
cases of improper reseating, manual release of the valve may improve
the seat seal. In order to remove the pressure relief valve for
repair without shutting down the process, the process must be kept
isolated from atmosphere. The safest way to isolate the process is to
install a three-way valve with parallel relief systems so that one of
7 8
the two relief systems is always open. '
4.2.2.3 Compressor Seals. Leaks from centrifugal and reciprocating
compressor seals may be reduced by replacing the seal or tightening or
replacing the packing. If the leak is small, temporary emissions
resulting from a shutdown may be greater than the emissions from the
leaking seal. It is anticipated that for many reciprocating compressor
seals it will not be possible to bring leaks under the designated
action level. In addition, there will not often be a spare compressor
to allow shutdown for repair of the leaking compressor seal. In these
instances it would be more appropriate to vent leaks from compressor
seals to a control device. This approach is described in Section 4.3.2.
4.2.2.4 Pumps. In some cases, it is possible to operate a spare
pump while the leaking pump is being repaired. Leaks from packed
seals may be reduced by tightening the packing gland. At some point,
the packing may deteriorate to the point where further tightening
4-6
-------
would have no effect or possibly even increase fugitive emissions from
the seal. The packing can be replaced with the pump out of service.
When mechanical seals are utilized, the pump must be dismantled so the
leaking seal can be repaired or replaced. Dismantling pumps may
result in spillage of some process fluid causing emissions of VOC.
These temporary emissions have the potential of being greater than the
continued leak from the seal. Therefore, the pump should be isolated
from the process and flushed of VOC as much as possible prior to
repacking or seal replacement.
4.2.2.5 Flanges and Connections. In some cases, leaks from
flanges can be reduced by replacing the flange gaskets. Leaks from
small threaded connections can be reduced by placing synthetic (e.g.,
Teflon) tape or "pipe dope" on the male threads before the connection
is made. Most flanges and connections cannot be isolated to permit
repair of leaks. Data show that flanges and connections emit relatively
small amounts of VOC (Table 3-1).
4.2.3 Emission Control Effectiveness of Leak Detection and Repair
The control efficiency achieved by a leak detection and repair
program is dependent on several factors, including the leak definition,
inspection interval, and the allowable repair time.
4.2.3.1 Definition of a Leak. The first step in developing a
monitoring plan for fugitive VOC emissions is to define an instrument
meter reading that is indicative of an equipment leak. The choice of
the meter reading for defining a leak is influenced by several consi-
derations. The percent of total mass emissions that can potentially
be controlled by the leak detection and repair program can be affected
by varying the leak definition. Table 4-2 gives the percent of total
mass emissions affected at various leak definitions for a number of
component types. From the table, it can be seen that, in general, a
low leak definition results in larger potential emission reductions.
Other considerations are more source specific. For valves, the
selection of an action level for defining a leak is a tradeoff between
the desire to locate all significant leaks and to ensure that emission
reductions are possible through maintenance. Although test data show
that some valves with meter readings less than 10,000 ppm have significant
emission rates, most of the major emitters have meter readings greater
4-7
-------
Table 4-2. PERCENT OF TOTAL EMISSIONS AFFECTED AT VARIOUS
LEAK DEFINITIONS
00
Percent of mass emissions affected at this leak definition9
Component type
b
Valves
Relief valves0
Compressor seals
-, b
Pump seals
100,000 ppmv
54
41
63
46
(59)
(42)
(64)
(47)
50,000 ppmv
64
53
75
63
(70)
(56)
(76)
(63)
20,000 ppmv
78 (83)
67 (69)
87 (88)
72 (71)
10,000 ppmv
86 (87)
77 (77)
92 (93)
79 (79)
1,000 ppmv
97
96
99
94
(98)
(96)
(99)
(94)
xx = VOC emission values.
(xx) = Total hydrocarbon emission values.
aThese figures relate the leak definition to the percentage of total mass emissions that can
be expected from sources with concentrations at the source greater than the leak definition.
If these sources were instantaneously repaired to a zero leak rate and no new leaks occurred,
then emissions could be expected to be reduced by this maximum theoretical efficiency.
Reference 1.
°Reference 2.
-------
than 10,000 ppm. Maintenance programs on valves have shown that
emission reductions are possible through on-line repair for essentially
all valves with nonzero meter readings. There are, however, cases
where on-line repair attempts result in an increased emission rate.
The increased emissions from such a source could be greater than the
emission reduction if maintenance is attempted on low leak valves.
These valves should, however, be able to achieve essentially 100 percent
emission reduction through off-line repair. Generally, the emission
rates from valves with meter readings greater than or equal to 10,000 ppm
are significant enough so that an overall emission reduction is likely
for a leak detection and repair program with a 10,000 ppm leak definition.
In addition, testing by EPA and industry has shown that meter readings
will generally be either much less than 10,000 ppm or much greater
than 10,000 ppm.1'9'10 Therefore, 10,000 ppm was determined to be the
most reasonable leak definition to initiate valve maintenance efforts
while still having confidence that an overall emission reduction will
result.
For pump and compressor seals, the rationale for selection of an
action level is different because the cause of leakage is different.
As opposed to valves, which generally have zero leakage, most pump and
compressor seals leak to a certain extent while operating normally.
These seals would tend to have low instrument meter readings. With
time, however, as the seal begins to wear, the concentration and
emission rate are likely to increase. At any time, catastrophic seal
failure can occur with a large increase in the instrument meter reading
and emission rate. As shown in Table 4-2, over 90 percent of the
emissions from compressor seals and 80 percent of the emissions from
pump seals are from sources with instrument meter readings greater
than or equal to 10,000 ppm. Since properly designed, installed, and
operated seals should have low instrument meter readings, and, since
the bulk of the pump and compressor seal emissions are from seals that
have worn out or failed such that they have a concentration equal to
or greater than 10,000 ppm, this level was chosen as a reasonable
action level.
4.2.3.2 Inspection Interval. The length of time between inspections
should depend on the expected occurrence and recurrence of leaks after
4-9
-------
a piece of equipment has been checked and/or repaired. This interval
can be related to the type of equipment and service conditions, and
different intervals can be specified for different pieces of equipment.
Monitoring may be scheduled on an annual, quarterly, monthly, or
weekly basis. The choice of the interval affects the emission reduction
achievable, since more frequent inspection intervals will result in
earlier detection and repair of leaking sources.
4.2.3.3 Allowable Repair Time. If a leak is detected, the
equipment should be repaired within a certain time period. The allowable
repair time should allow the plant operator sufficient time to obtain
necessary repair parts and maintain some degree of flexibility in
overall plant maintenance scheduling. The determination of this
allowable repair time will affect emission reductions by influencing
the length of time that leaking sources are allowed to continue to
emit VOC.
4.2.3.4 Estimation of Reduction Efficiency. Data are presented
in Table 4-2 that show the expected percent of total emissions from
each type of source contributed by those sources with VOC concentrations
greater than given leak definitions. If a leak detection and repair
program resulted in repair of all such sources to 0 ppmv, elimination
of all sources over the leak definition between inspections, and
instantaneous repair of those sources found at each inspection, then
emissions could be expected to be reduced by the amount reported in
Table 4-2. However, since these conditions are not met in practice,
the fraction of emissions from sources with VOC concentrations over
the leak definition represents the theoretical maximum reduction
efficiency. The approach used to estimate emission reductions
presented here is to reduce this theoretical maximum control efficiency
by accounting quantitatively for those factors outlined above.
There are two models available for estimation of emission reduction
efficiency from leak detection and repair programs. Both models are
used in this BID. The first model (the computer leak detection and
repair (LDAR) model) is described in Appendix E and is applied to
valves and pumps. It is the preferred model, because it incorporates
recently available data on leak occurrence and recurrence and data on
the effectiveness of simple in-line repair. These data are not available
4-10
-------
for relief valves and compressors. Therefore, a second model (the
ABCD model) is applied to these sources. The ABCD model can be expressed
mathematically by the following equation:
Reduction efficiency =AxBxCxD
Where:
A = Theoretical Maximum Control Efficiency = fraction of total
mass emissions from sources with VOC concentrations greater
than the leak definition (from Table 4-2).
B = Leak Occurrence and Recurrence Correction Factor = correction
factor to account for sources which start to leak between
inspections (occurrence), for sources which are found to be
leaking, are repaired and start to leak again before the next
inspection (recurrence), and for known leaks that could not be
repa i red.
C = Noninstantaneous Repair Correction Factor = correction factor
to account for emissions which occur between detection of a
leak and subsequent repair, since repair is not instantaneous.
D = Imperfect Repair Correction Factor = correction factor to
account for the fact that some sources which are repaired are
not reduced to zero. For computational purposes, all sources
which are repaired are assumed to be reduced to an emission
level equivalent to a concentration of 1,000 ppmv.
As an example of this technique, Table 4-3 gives values for the "B,"
"C," and "D" correction factors for various possible inspection intervals,
allowable repair times, and leak definitions. These values are given
only for relief valves and compressors seals, because the reduction
efficiency for valves and pump seals is estimated according to the
LDAR model presented in Appendix E.
The ABCD model control efficiencies for compressors and pressure
relief valves, however, have been modified to correct for the accuracy
of the engineering judgment employed to derive one of the model inputs.
The accuracy of the judgment was approximated by the comparison of the
LDAR model and ABCD model control efficiencies for valves. The control
efficiency for compressors and pressure relief valves was derived by
18
weighting the ABCD model results by this relationship. This technique
is used to determine emission reductions for control alternatives in
Table 7-1.
4-11
-------
Table 4-3. VOC EMISSION CORRECTION FACTORS FOR VARIOUS INSPECTION INTERVALS,
ALLOWABLE REPAIR TIMES, AND LEAK DEFINITIONS FOR ABCD MODEL
I
t—'
ro
Leak occurence and
recurrence correction
factor
Non-instantaneous
repair correction
factor0
Imperfect repair correction factor
Inspection interval
Allowable repair
time (days)
Leak definition (ppmv)
Component type
Relief valves
Compressor seals
Quarterly
0.90
0.90
Monthly 15 5
0.95 0.98 0.99
0.95 0.98 0.99
100,000
0.92
(0.99)
0.98
(0.97)
50,000
0.91
(0.99)
0.98
(0.96)
10,000
0.89
(0.99)
0.97
(0.95)
1,000
0.85
(0.99)
0.97
(0.94)
xx = VOC emission values.
(xx) = Total hydrocarbon emission values.
aFactor accounts for sources that start to leak between inspections (occurrence), for sources that are found
to be leaking, are repaired, and start to leak again before the next inspection (recurrence), and for
leaking sources that cannot be repaired. Reference 11.
bFactor accounts for emissions that occur between detection of a leak and subsequent repair. Reference 11.
cFactors accounts for the fact that some sources that are repaired are not reduced to zero. Repaired
sources are assumed to be reduced to a 1,000 ppmv concentration level. From Tables 3-1, 4-1, 4-2, and
References 1 and 2.
-------
4.3 PREVENTIVE PROGRAMS
An alternative approach to controlling fugitive VOC emissions
from gas plant operations is to replace components with leakless
equipment. This approach is referred to as a preventive program.
This section will discuss the kinds of equipment that could be applied
in such a program and the advantages and disadvantages of this equipment.
4.3.1 Pressure Relief Valves
As discussed in Chapter 3, pressure relief valves can be sources
of fugitive VOC emissions because of leakage through the valve seat.
This type of leakage can be prevented by installing a rupture disk
upstream of the valve, by connecting the discharge port of the valve
to a closed-vent system, or by use of soft seat technology such as
elastomer "0-rings." A rupture disk can be used upstream of a pressure
relief valve so that under normal conditions it seals the system
tightly but will break when its set pressure is exceeded, at which
time the pressure relief valve will relieve the pressure. Figure 4-1
is a diagram of a rupture disk and pressure relief valve installation.
The installation is arranged to prevent disk fragments from lodging in
the valve and preventing the valve from being reseated if the disk
ruptures. It is important that no pressure be allowed to build in the
pocket between the disk and the pressure relief valve; otherwise, the
disk will not function properly. A pressure gauge and bleed valve can
be used to prevent pressure buildup. With the use of a pressure
gauge, it can be determined whether the disk is properly sealing the
system against leaks.
It may be necessary to install a 2-port valve and parallel relief
valve when using a rupture disk upstream of a relief valve. Such a
system may be required to isolate the relief valve/rupture disk system
for repair in case of an overpressure discharge. The parallel system
would provide a backup relief valve during repair. However, a block
valve upstream of the rupture disk/relief valve system will accomplish
the same purpose where safety codes allow the use of a block valve for
this purpose.
An alternative method for controlling pressure relief valve
emissions due to improper reseating is the use of a soft elastomer
seat in the valve. An elastomer "0-ring" can be installed so that the
4-13
-------
•—-Tension-adjustment
thimble
To
atmospheric
vent
CONNECTION FOR
PRESSURE GAUGE
& BLEED VALVE
FROM SYSTEM
Figure 4-1. Rupture disk installation upstream of a relief valve.'
-------
valve always forms a tight seal after an overpressure discharge.
However, this approach will not prevent leakage due to "simmering," a
condition due to the system pressure being too close to the set pressure
of the valve.
4.3.2 Compressor Seals
As discussed in Chapter 3, there are three types of compressors
used in natural gas plants: centrifugal, rotary, and reciprocating.
Centrifugal and rotary compressors are driven by rotating shafts while
reciprocating compressors are driven by shafts having a linear recipro-
cating motion. In either case, fugitive emissions occur at the junction
of the moving shafts and the stationary casing, but the kinds of
controls that can be effectively applied depend on the type of shaft
motion involved.
4.3.2.1 Centrifugal and Rotary Compressors. Centrifugal and
rotary compressors are both driven by rotating shafts. Emissions fron
these types of compressors can be controlled by the use of mechanical
seals with barrier fluid (liquid or gas) systems or by the use of
liquid film seals. In both of these types of seals, a fluid is injected
into the seal at a pressure higher than the internal pressure of the
compressor. In this way, leakage of the process gas to atmosphere is
prevented except when there is a seal failure. As in the case of
pumps, seal fluid degassing vents must be controlled with a closed
vent system to prevent process gas from escaping from the vent.
4.3.2.2 Reciprocating Compressors. This type of compressor
usually involves a piston, cylinder, and drive-shaft arrangement.
Since the shaft motion is linear, a packing gland arrangement is
normally employed to prevent leakage around the moving shaft. This
type of seal can be improved by inserting one or more spacer rings
into the packing and connecting the void area or areas thus produced
to a collection system through vents in the housing. This is referred
to as a "scavenger" system. As with other fugitive emission collection
systems, these vents must be controlled to prevent fugitive emissions
from entering the atmosphere. However, venting the seal does not
eliminate emissions from reciprocating compressors entirely, because
emissions can still occur into the distance piece area. These leaks
4-15
-------
can be controlled by enclosing the distance piece area and installing
suitable piping to vent the emissions either to a flare, a plant
process heater, or back into a low pressure point in the process. For
the latter two cases, an auxilliary compressor may be required to
compress the vent stream to a usable pressure. Purging the distance
piece with natural gas could be performed to keep the enclosure above
the upper explosive limit and to ensure a nonexplosive atmosphere
(Figure 4-2).
As shown in Figure 4-2, the distance piece enclosure could be
maintained slightly above atmospheric pressure by purging the enclosure
with residue or sales gas through a regulator. To ensure safety,
13
either double distance pieces or more sophisticated piston rod
12
seals should be employed. Additionally, a high pressure sensor in
the purge gas line should be used to shut off the gas supply in the
event of regulator failure. In order to provide for draining of seal
oil leaks, the atmospheric pressure oil drain line should be connected
through a "U" tube trap as shown to prevent loss of the purge gas
while allowing uninterrupted oil flow. A second water filled trap in'
the outlet serves to maintain the pressure in the enclosure, while
allowing free flow of emissions (or seal failure gases) to the control
device by displacement of the water into the knockout drum when the
pressure in the system exceeds the water column height set pressure.
Obtaining a good seal at the distance piece door and at the point
where emissions are vented from the distance piece or seal area is
necessary for maintaining a sufficient pressure (e.g., 2 to 5 psig).
Block valves should also be installed in order to close vent lines
during compressor shutdown periods. This will prevent hydrocarbon
vapors from entering the work place and air from entering the vent
14
system during compressor maintenance. There may be instances where
retrofitting of such a vent control system to a compressor distance
piece may be infeasible for safety reasons. Therefore, the application
of this preventive program as a retrofit will have to be evaluated on
a case-by-case basis.
4.3.3 Pump Seals
Pumps can be potential fugitive VOC emission sources because of
leakage through the drive-shaft sealing mechanism. This kind of
4-16
-------
I
I—»
^-J
Waste Oil
Drain Line
to Tank or
Recovery
2" (5cm) Header
To Flare or
^Process Heater
due or
Sales Gas Line
Figure 4-2. COMPRESSOR DISTANCE PIECE PURGE SYSTEM
-------
leakage can be reduced to a negligible level through the installation
of improved shaft sealing mechanisms, such as dual mechanical seals.
Dual mechanical seals consist of two mechnical sealing elements
usually arranged in either a back-to-back or a tandem configuration.
In both configurations a barrier fluid circulates between the seals.
The barrier fluid system may be circulating system, or it may rely on
convection to circulate fluid within the system. While the barrier
fluid's main function is to keep the pumped fluid away from the environ-
ment, it can serve other functions as well. A barrier fluid can
provide temperature control in the stuffing box. It can also protect
the pump seals from the atmosphere, as in the case of pumping easily
oxidizable materials that form abrasive oxides or polymers upon exposure
to air. A wide variety of fluids can be used as barrier fluids. Some
of the more common ones that have been used are water (or steam),
glycols, methanol, oil, and heat transfer fluid. In cases in which
product contamination cannot be tolerated, it may also be possible to
use clean product, a product additive, or a product diluent.
Emissions of VOC from barrier fluid degassing vents can be controlled
by a closed vent system, which consists of piping and, if necessary,
flow inducing devices to transport the degaussing emissions to a control
device, such as a process heater, or vapor recovery system. Control
effectiveness of a dual mechanical seal and closed vent system is
dependent on the effectiveness of the control device used and the
frequency of seal failure. Failure of both the inner and outer seals
can result in relatively large VOC emissions at the seal area of the
pump. Pressure monitoring of the barrier fluid may be used in order
o
to detect failure of the seals. In addition, visual inspection of
the seal area also can be effective for detecting failure of the outer
seals. Upon seal failure, the leaking pump would have to be shut down
for repair.
4.3.4 Open-Ended Lines
Caps, plugs, and double block and bleed valve are devices for
closing off open-ended lines. When installed downstream of an open-ended
line, they are effective in preventing leaks through the seat of the
valve from reaching atmosphere. In the double block and bleed system,
it is important that the upstream valve be closed first. Otherwise,
4-18
-------
product will remain in the line between the valves, and expansion of
this product can cause leakage through the valve stem seals.
The control efficiency will depend on such factors as frequency
of valve use, valve seat leakage, and material that may be trapped in
the cap or plug. Annual VOC emissions from a leaking open-ended valve
are approximately 100 kg. Assuming that open-ended lines are used
an average of 10 times per year, that 0.1 kg of trapped organic material
is released when the valve is used, and that all of the trapped organics
released are emitted to atmosphere, the annual emissions from closed
off open-ended lines would be 1 kg. This would be a 99 percent reduction
in emissions. Due to the conservative nature of these assumptions, a
100 percent control efficiency has been used to estimate the emission
reductions of closing off open-ended lines.
4.3.5 Closed-Purge Sampling
VOC emissions from purging sampling lines can be controlled by a
closed-purge sampling system, which is designed so that the purged VOC
is returned to the system or sent to a closed disposal system so that
the handling losses are minimized. Figure 4-2 gives two examples of
closed-purge sampling systems where the purged VOC is flushed from a
point of higher pressure to one of lower pressure in the system and
where sample-line dead space is minimized. Other sampling systems are
available that utilize partially evacuated sampling containers and
require no line pressure drop.
Reduction of emissions for closed-purge sampling is dependent on
many highly variable factors, such as frequency of sampling and amount
of purge required. For emission calculations, it has been assumed
that closed-purge sampling systems will provide 100 percent control
efficiency for the sample purge.
4.3.6 Gas-Operated Control Valves
VOC emissions from pneumatic control valves result when field gas
or flash gas is used as the operating medium. These emissions can be
eliminated by the use of compressed air. This will require installation
of an air compression system and connection of the appropriate pressure
supply lines.
4-19
-------
4.4 REFERENCES
1. DuBose, D.A., J.I. Steinmetz, and G.E. Harris. Frequency of Leak
Occurrence and Emission Factors for Natural Gas Liquid Plants.
Final Report. Radian Corporation. Austin, Texas. Prepared for
U.S. Environmental Protection Agency. Emissions Measurement Branch.
Research Triangle Park, North Carolina. EMB Report No. 80-FOL-l.
July 1982. Docket Reference Number II-A-36.*
2. Hennings, T. J., TRW to VOC/Onshore Production Docket. April 2,
1982. Cumulative distribution of mass emissions and percent sources
with respect to screening value for relief valves. Docket Reference
Number II-B-12.*
3. Erikson, D.G. and V. Kalcevic. Organic Chemical Manufacturing,
Volume 3: Storage, Fugitive, and Secondary Sources. Report 2.
Fugitive Emissions. U.S. Environmental Protection Agency. Research
Triangle Park, NC. Report Number EPA-450/3-80-025. December 1980.
Docket Reference Number II-I-15.*
4. Hustvedt, K.C. and R.C. Weber. Detection of Volatile Organic
Compound Emissions from Equipment Leaks. Paper presented at 71st
Annual Air Pollution Control Association Meeting. Houston, TX.
June 25-30, 1978. Docket Reference Number II-A-2.*
5. Hustvedt, K.C., R.A. Quaney, and W.E. Kelly. Control of Volatile
Organic Compound Leaks from Petroleum Refinery Equipment. U.S.
Environmental Protection Agency. Research Triangle Park, NC.
Report Number EPA-450/2-78-036. June 1978. Docket Reference
Number II-A-3.*
6. Teller, James H. Advantages Found in On-Line Leak Sealing. Oil
and Gas Journal, 77J29):54-59, 1979. Docket Reference Number II-I-16.*
7. Letter from Naughton, D. A., Hartford Steam Boiler Inspection and
Insurance Company, to M. Cappers, Allied Chemical. May 28, 1981.
Proposed EPA regulations requiring isolation valve upstream of
relief valves and rupture discs. Docket Reference Number II-I-29.*
8. Letter from Lambert, J. A., Jr., Industrial Risk Insurers, to
M. A. Cappers, Allied Chemical. May 28, 1981. Proposed EPA regulations
requiring isolation valve upstream of relief valves and rupture
discs. Docket Reference Number II-I-28.*
9. Letter with attachments from H. H. McClure, Texas Chemical Council,
to W. Barber, EPA. June 30, 1980. Appendix B, page 11. Docket
Reference Number II-D-4.*
10. "A Fugitive Emissions Study in Petrochemical Manufacturing Unit"
Kun-Chieh Lee, et. al., Union Carbide Corporation, South Charleston,
West Virginia, presented to annual meeting of the Air Pollution
Control Association, Montreal, Quebec, June 22-27, 1980. page 2.
Docket Reference Number II-D-4.*
4-20
-------
11. Tichenor, B.A., K.C. Hustvedt, and R.C. Weber. Controlling Petroleum
Refinery Fugitive Emissions Via Leak Detection and Repair. Symposium
on Atmospheric Emissions from Petroleum Refineries. Austin, TX.
Report Number EPA-600/9-80-013. November 6, 1979. Docket Reference
Number II-A-7.*
12. Letter from Sheppard, R.W., Ingersoll Rand to Ajax, R.L., EPA.
October 29, 1982. Docket Reference Number II-D-43.*
13. "Reciprocating Compressors for General Refinery Service," American
Petroleum Institute, API Standard 618, July 1974, pp. 6-8.
Docket Reference Number II-I-35.*
14. Letter and attachment from Hennings, T.J., TRW to K.C. Hustvedt,
EPA. July 7, 1981. Results of a telephone survey concerning
control of fugitive emissions from gas plant compressor seals.
Docket Reference Number II-B-7.*
15. Letter and attachment from Hennings, T. J., TRW to K. C. Hustvedt,
EPA. February 22, 1982. Results of a telephone survey on safety
issues concerning compressor vent control systems. Docket Reference
Number II-B-16.*
16. Fugitive Emission Sources of Organic Compounds. Additional Information
on Emissions, Emission Reduction, and Costs. U.S. Environmental
Protection Agency. EPA-450/3-82-010. April 1982. Docket Reference
Number II-A-25.*
17. Letter and attachments from McClure, H.H., Texas Chemical Council,
to Patrick, D.R., EPA. May 17, 1979. Docket Reference Number II-D-3.*
18. Memorandum from Rhoads, T.W., PES, Inc., to Docket Number A-80-20.
Calculation of Controlled Emission Factors for Pressure Relief
Valves and Compressor Seals. November 1, 1982. Docket Reference
Number II-B-17.*
*References can be located in Docket Number A-80-20-B at U.S. Environmental
Protection Agency Library, Waterside Mall, Washington, D.C.
4-21
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5. MODIFICATION AND RECONSTRUCTION
In accordance with the provisions of Title 40 of the Code of Federal
Regulation (CFR), Sections 60.14 and 60.15, an existing facility can
become an affected facility and, consequently, subject to the standards
of performance if it is modified or reconstructed. An "existing facility,"
defined in 40 CFR 60.2, is a facility of the type for which a standard
of performance is promulgated and the construction or modification of
which was commenced prior to the proposal date of the applicable standards.
The following discussion examines the applicability of modification/
reconstruction provisions to natural gas/gasoline processing plants that
involve fugitive VOC emissions.
5.1 GENERAL DISCUSSION OF MODIFICATION AND RECONSTRUCTION PROVISIONS
5.1.1 Modification
Modification is defined in Section 60.14 as any physical or operational
change to an existing facility that results in an increase in the emission
rate of the pollutant(s) to which the standard applies. Paragraph (e)
of Section 60.14 lists exceptions to this definition which are not
considered modifications, irrespective of any changes in the emission
rate. These changes include:
1. Routine maintenance, repair, and replacement;
2. An increase in the production rate not requiring a capital
expenditure as defined in Section 60.2(bb);
3. An increase in the hours of operation;
4. Use of an alternative fuel or raw material if, prior to the
standard, the existing facility was designed to accommodate that alternative
fuel or raw material;
5. The addition or use of any system or device whose primary
function is the reduction of air pollutants, except when an emission
5-1
-------
control system is removed or replaced by a system considered to be less
environmentally beneficial.
As stated in paragraph (b), emission factors, material balances,
continuous monitoring systems, and manual emission tests are to be used
to determine emission rates expressed as kg/day of pollutant. Paragraph
(c) affirms that the addition of an affected facility to a stationary
source through any mechanism — new construction, modification, or
reconstruction -- does not make any other facility within the stationary
source subject to standards of performance. Paragraph (f) provides for
superseding any conflicting provisions. And, (g) stipulates that
compliance be achieved within 180 days of the completion of any
modification.
5.1.2 Reconstruction
Under the provisions of Section 60.15, an existing facility becomes
an affected facility upon reconstruction, irrespective of any change in
emission rate. A source is identified for consideration as a reconstructed
source when: (1) the fixed capital costs of the new components exceed
50 percent of the fixed capital costs that would be required to construct
a comparable entirely new facility, and (2) it is technologically and
economically feasible to meet the applicable standards set forth in this
part. The final judgment on whether a replacement constitutes
reconstruction will be made by the Administrator's determination of
reconstruction will be based on:
(1) The fixed capital cost that would be required to construct
a comparable new facility; (2) the estimated life of the
facility after the replacements compared to the life of a
comparable entirely new facility; (3) the extent to which the
components being replaced cause or contribute to the emissions
from the facility; and (4) any economic or technical limita-
tions in compliance with applicable standards of performance
which are inherent in the proposed replacements.
The purpose of the reconstruction provision is to ensure that an
owner or operator does not perpetuate an existing facility by replacing
all but minor components, support structures, frames, housing, etc.,
rather than totally replacing it in order to avoid being subject to
applicable performance standards. In accordance with Section 60.5, EPA
5-2
-------
will, upon request, determine if an action taken constitutes construction
(including reconstruction).
5.2 APPLICABILITY OF MODIFICATION AND RECONSTRUCTION PROVISIONS TO
NATURAL GAS/GASOLINE PROCESSING PLANTS
As a result of cost and energy considerations, as well as changes
in product demand and feedstock supply, there are expected to be a
number of modernization projects at existing gas plants in the near
future. Some of these projects could result in existing gas plants
becoming subject to the provisions of Sections 60.14 and 60.15.
For example, a company may decide to add process trains at an
existing facility in order to increase the plant capacity or efficiency.
The additional process equipment would include additional sources of
potential fugitive emissions, such as valves or compressors. Routine
changes are also made to gas plants, such as those made to increase ease
of maintenance, to increase productivity, to improve plant safety, or
correct minor design flaws. These types of changes may also result in
an increase of fugitive emissions. However, measures could be taken to
reduce fugitive emissions from other sources to compensate for the
increase. The capital expenditure for any of the above additions,
replacements, or changes may exceed the level of capital expenditure as
defined in Section 60.2(bb). Some changes may involve only the replace-
ment of a potential fugitive emission source such as a valve. If the
source is replaced with an equivalent source the level of fugitive
emissions would be expected to remain unchanged.
It may be advantageous for certain plants to convert to an entirely
different processing method. Most new gas plants use the cryogenic
processing method because it is less costly to operate and because it is
more efficient. For the same reasons, owners of existing plants may
decide to convert to the cryogenic method. Depending on the process
method that is presently being used, this may involve a substantial
amount of new equipment. It is possible that the cost of the conversion
would exceed 50 percent of the cost of a new plant.
5-3
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6.0. MODEL PLANTS AND REGULATORY ALTERNATIVES
6.1 INTRODUCTION
This chapter presents model plants and regulatory alternatives for
reducing fugitive VOC emissions from natural gas/gasoline processing
plants. The model plants were selected to represent the range of pro-
cessing complexity in the industry. They provide a basis for determining
environmental and cost impacts of the regulatory alternatives. The
regulatory alternatives consist of various combinations of the available
control techniques and provide incremental levels of emission control.
6.2 MODEL PLANTS
There are a number of different process methods used at gas plants:
absorption, refrigerated absorption, refrigeration, compression, adsorp-
tion, cryogenic - Joule-Thomson, and cryogenic-expander. Process
conditions are expected to vary widely between plants using these different
methods. However, available data show that fugitive emissions are
proportional to the number of potential sources, and are not related to
o
capacity, throughput, age, temperature, or pressure. Therefore, model
plants defined for this analysis represent different levels of process
complexity (number of fugitive emission sources), rather than different
process methods.
In order to estimate emissions, control costs, and environmental
impacts on a plant specific basis, three model plants were developed.
With the exception of sampling connections, the number of components for
each model plant is derived from actual component inventories performed
at four gas plants. Two of the plants were inventoried during EPA
testing, and two were inventoried during testing by Rockwell International
under contract to the American Petroleum Institute.4 The number of
sampling connections is based on one liquid sampling connection at
each pump and one gas sampling connection at each compressor.
6-1
-------
Complexity of gas plants can be indexed by means of calculating
ratios of component populations to a more easily counted population.
For gas plants, the number of vessels appears to be best suited to this
need. Equipment included and excluded in vessel inventories are listed
in Table 6-1. The vessel inventories for the industry-tested gas plants
are taken from the site diagrams and descriptions provided in the
API/Rockwell report,6 and the vessel inventories from the EPA-tested
plants were performed during the testing. These vessel inventories and
the component inventories are shown in Table 6-2. Table 6-3 shows the
ratios of numbers of components to numbers of vessels at the four gas
plants. The mean and standard deviation of the four ratios are also
shown in Table 6-3.
Three model plants have been developed using the average ratios of
components to vessels. The number of vessels in the model gas plants
are 10, 30, and 100. This range in number of vessels is based on the
vessel inventories shown in Table 6-2. The low end of the range, 10
vessels, is approximately equivalent to the number of vessels that are
accounted for in one of the three process trains at the EPA-tested
plant A. It is assumed that there are existing gas plants with a similar
configuration to the EPA-tested plant A, that have only one process
train. The high end of the range, 100 vessels, is slightly larger than
the number of vessels at the industry-tested plant C. Since this was
the largest of the plants tested, it appears reasonable to use this as a
guide in calculating the number of components at the largest node!
plant. The middle-sized model plant has 30 vessels. This is approximately
the same number of vessels as at three of the four plants tested and may
be representative of a common gas plant size. The three model plants
and their respective number of components are shown in Table 6-4.
6.3 REGULATORY ALTERNATIVES
This section presents four regulatory alternatives for controlling
fugitive VOC emissions from natural gas/gasoline processing plants. The
alternatives define feasible programs for achieving varying levels of
6-2
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Table 6-1. EXAMPLE TYPES OF EQUIPMENT INCLUDED AND EXCLUDED IN
VESSEL INVENTORIES FOR MODEL PLANT DEVELOPMENT
Included
Excluded
i
co
1. Absorption/Desorptlon Units
a. Absorbers
b. Scrubbers
c. Dehydrators
d. Stabilizer
e. Stripper
2. Adsorption Units
3. Distillation/Fractionation Units
a. Demethanizer
b. Deethanizer
c. Depropanizer
d. Splitter
e. Flash Drum/Tank
f. Stills
4. Heating/Cooling Units
a. Heaters
b. Chillers
c. Heat Exchangers
d. Reboilers
e. Condensers
f. Coolers
5. Drums/Tanks
a. Separator
b. Surge
c. Gas
d. Oil
e. Accumulator
f. Knockout
1. Compressors, Pumps
2. Piping Systems
a. Manifold/header systems
b. Valves, flanges, connections, etc.
c. Meters, gauges, control equipment
3. Glycol, lube oil, water storage
4. Any equipment associated with sweetening
-------
Table 6-2. NUMBER OF COMPONENTS IN HYDROCARBON SERVICE AND NUMBER OF
VESSELS AT FOUR GAS PLANTS
cr>
EPA tested plants3
Vessels
Valves
Relief valves
Open-ended lines
Compressor seals
Pump seals
Flanges and connections
A
31
508C
16C
62C
0
lc
1,530C
B
30
541
11
64
8
12
1,440
Industry tested plants
C
90
3,330
20
669
35
32
15,370
D
25
762
7
173
0
3
3,030
Reference 3.
Reference 4.
C0nly two of the three adsorption units at the plant were tested and inventoried. Estimated total
number of components is therefore based on the sum of the number of components counted in the
larger unit plus twice the number of components counted in the smaller unit.
-------
Table 6-3. RATIOS OF NUMBERS OF COMPONENTS TO NUMBERS OF VESSELS^
cr>
i
en
Valves
Relief valves
Open-ended lines
Compressor seals
Pump seals
Flanges and
connections
EPA tested
A
16.4
0.5
2.0
0.0
0.0
49.4
plants
B
18.0
0.4
2.1
0.3
0.4
48.0
Industry tested
C
37.0
0.2
7.4
0.4
0.4
170.8
plants
D
30.5
0.3
6.9
0.0
0.1
121.2
Average
ratio
25.5
0.4
4.6
0.2
0.2
97.4
Standard
deviation
of ratio
9.9
0.1
3.0
0.2
0.2
59.7
Based on data presented in Table 6-2.
-------
Table 6-4. FUGITIVE VOC EMISSION SOURCES FOR THREE MODEL
GAS PROCESSING PLANTS
Component type
Valves3
Relief valves3
Open-ended lines3
Compressor seals3
Pump seals3
Sampling connections
Liquid
Gas
Flanges and connections
Number of components
Model plant Model plant Model plant
ABC
(10 vessels) (30 vessels) (100 vessels)
250
4
50
2
2
2
2
1,000
750 2,
12
150
6
6
6
6
3,000 10,
500
40
500
20
20
20
20
000
Number of components based on average ratios presented in Table 6-3.
""Based on one liquid connection at each pump and one gas connection at
each compressor.
6-6
-------
emission reduction. The first alternative represents a baseline level
of fugitive emissions in which case the impact analysis is based on no
additional controls. The remaining regulatory alternatives require
increasingly restrictive controls comprised of the techniques discussed
in Chapter 4. Table 6-5 summarizes the requirements of the regulatory
alternatives.
6.3.1 Regulatory Alternative I
Regulatory Alternative I reflects normal existing gas plant operations
with no additional regulatory requirements. This baseline regulatory
alternative provides the basis for incremental comparison of the impacts
of the other regulatory alternatives.
6.3.2 Regulatory Alternative II
Regulatory Alternative II provides a higher level of emission
control than the baseline alternative through leak detection and repair
methods as well as equipment specifications.
This regulatory alternative requires quarterly instrument monitoring
of valves, relief valves, compressor seals, and pump seals for leaks.
Leaks that are found to be in excess of a prescribed hydrocarbon concen-
tration (as indicated by a hydrocarbon detection instrument) would be
repaired within a prescribed time period. Pump seals would additionally
receive weekly visual inspections for leaks. Leaks found to be in
excess of the prescribed concentration would be repaired within the
prescribed time period.
The regulatory alternative also requires that caps (including
plugs, flanges, or second valves) be installed on open-ended lines.
6.3.3 Regulatory Alternative III
Regulatory Alternative III achieves a greater emission reduction
than Alternative II by requiring monthly instrument monitoring of valves,
relief valves, and pump seals. If a particular valve is found not to be
leaking for 3 successive months, then 2 months may be skipped before the
next time it is monitored with an instrument. A compressor vent control
system would be installed to control compressor seal emissions. Sampling
connections would be equipped with a closed purge sampling system.
Other requirements (caps on open-ended lines, weekly inspection of
pumps) remain the same as Alternative II.
6-7
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Table 6-5. FUGITIVE VOC REGULATORY ALTERNATIVE CONTROL SPECIFICATIONS
Regulatory Alternative
II
III
IV
Component type
Valves
basel ine
control
(no NSPS)
Monitoring
interval
quarterly
Equipment
specification
Monitoring
interval
monthly/
quarterly
Equipment
specification
Monitoring
interval
monthly
Equipment
specification
Rel ief valves
quarterly
monthly
rupture disc
Open-ended lines
cap
cap
cap
i
00
Sampling connections
Compressor seals
Pump seals
quarterly3
quarterly, .
weekly visual
none
monthly, .
weekly visual
closed purge
sampling
compressor vent
control
closed purge
sampling
compressor vent
control
dual seals
Quarterly monitoring and repair is not an effective control technique for all compressors. In some instances, reduction in emissions
from compressors through seal repair may necessitate a process unit turnaround because compressors generally are not spared. In addition,
it may not be possible to repair a compressor seal to below a prescribed leak definition because the seals can normally operate with
concentrations above the action level. In these instances a compressor vent control system should be substituted for monitoring.
Instrument monitoring of pumps would be supplemented with weekly visual inspections for liquid leakage. If liquid is noted to be leaking
from the pump seal, the seal would be repaired.
-------
6.3.4 Regulatory Alternative IV
Regulatory Alternative IV increases emission control by requiring
monthly instrument monitoring of valves. Relief valves should be equipped
with a rupture disc, and pumps are required to have dual mechanical
seals. Other requirements are the same as Alternative III.
6-9
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6.4 REFERENCES
1. Cantrell, A. Worldwide Gas Processing. Oil and Gas Journal, July
14, 1980. p. 88. Docket Reference Number II-I-23.*
2. Assessment of Atmospheric Emissions from Petroleum Refining, Volume
3, Appendix B. EPA 600/2-80-075C, April 1980. Pages 266 and 280.
Docket Reference Number II-A-8.*
3. Hustvedt, K.C., memo to James F. Durham, Chief, Petroleum Section,
OAQPS, U.S. EPA. Preliminary Test Data Summaries of EPA testing at
Houston Oil and Minerals Smith Point gas plant and Amoco Production
Hastings gas plant. March 19, 1981. Docket Reference Number
II-B-19*.
4. Eaton, W.S., Rockwell International, letter to D. Markwordt, OAQPS,
U.S. EPA. Component Inventory Data from Two API-Tested Gas Plants.
September 11, 1980. Docket Reference Number II-D-5.*
5. VOC Fugitive Emissions in Petroleum Refining Industry - Background
Information for Proposed Standards. U.S. EPA, OAQPS. April 1981.
Docket Reference Number II-A-10.*
6. Eaton, W.S., et al. Fugitive Hydrocarbon Emissions from Petroleum
Production Operations. API Publication No. 4322. March 1980. Docket
Reference Number II-I-20, Vol. 1.1* and Docket Reference
Number II-I-21, Vol. 1.2*
*References can be located in Docket Number A-80-20-B at the U.S.
Environmental Protection Agency Library, Waterside Mall, Washington, D.C.
6-10
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7.0 ENVIRONMENTAL IMPACTS
7.1 INTRODUCTION
This chapter discusses the environmental impacts from implementing
the regulatory alternatives presented in Chapter 6. The primary emphasis
is a quantitative assessment of the fugitive emissions that would result
from each of the alternatives. The impacts on water quality, solid
waste, energy and other environmental concerns are also addressed.
7.2 EMISSIONS IMPACT
7.2.1 Emission Source Characterization
As discussed in Chapter 6, the model plants consist of several
types of components (e.g., valves, pumps) that comprise the major fugitive
emission sources within natural gas/gasoline processing plants. The
emission factors presented in Table 3-1 are characteristic of existing
gas plant components. These emissions are referred to as "baseline" and
represent emissions under Regulatory Alternative I. The control techno-
logy discussed in Chapter 4 is applied in progressive increments in
Alternatives II, III, and IV in reducing emissions below baseline levels.
7.2.2 Development of Emission Levels
In order to estimate the impacts of the regulatory alternatives on
fugitive VOC emission levels, emission factors for the model plants were
determined for each regulatory alternative. Controlled emission factors
were developed for those component types that would be controlled by the
implementation of a leak detection and repair program and are given in
Table 7-1. Controlled emission factors for pressure relief valves and
compressor seals were derived based upon the ABCD model correction
factors and the leak detection and repair (LDAR) model as discussed in
Chapter 4. Controlled emission factors for valves and pump seals were
derived directly from the LDAR model as described in Chapter 4 and
Appendix E.
7-1
-------
Table 7-1. CONTROLLED EMISSION FACTORS FOR VARIOUS
INSPECTION INTERVALS
Source
Type
Valves
Relief
valves
Compressor
seals
Pump
seals
Inspection
Interval
Quarterly
Monthly/
Quarterly
Monthly
Quarterly
Monthly
Quarterly
Quarterly
Monthly
Baseline Controlled ,
Emission Factor Control Emission Factor
(kg/day)
0.18 (0.48)
0.33 (4.5)
1.0 (4.9)
1.2 (1.5)
Efficiency
0.77 (0.77)c
0.78 (0.78)
0.84 (0.84)
0.63 (0.69)d
0.70 (0.76)
0.82 (0.78)d
0.58 (0.58)C
0.65 (0.65)
(kg/day)
0.041 (0.11)
0.041 (0.11)
0.029 (0.077)
0.12 (1.4)
0.10 (1.1)
0.18 (1.1)
0.50 (0.63)
0.42 (0.53)
xx = VOC emission values
(xx) = THC emission values
aFrom Table 3-1.
Controlled emission factor = baseline emission factor x (1-control efficiency)
cFrom Table E-l.
References 4, 5.
7-2
-------
Where the regulatory alternatives require an equipment specification,
it is assumed that there are no subsequent emissions from the controlled
source. Table 7-2 presents the total fugitive VOC emissions from Model
Plants A, B, and C under each regulatory alternative by component type
and the component percent of the total emissions. Table 7-3 compares
the control effectiveness of Regulatory Alternatives II through IV over
Alternative I (baseline emissions) and the incremental cost effectiveness
between each regulatory alternative and the previous alternative.
7.2.3 Future Impact on Fugitive VOC Emissions
Future impacts of the regulatory alternatives were estimated for
the 5-year period, 1983 to 1987 as shown in Table 7-4. The number of
affected model plants (detailed in Section 9.1.2.2) projected for each
year was multiplied by the estimated total fugitive emissions per model
plant for each of the alternatives (from Table 7-3).
Over the 5-year period, the total fugitive VOC emissions for new
plants under baseline control (Regulatory Alternative I) are projected
at 52 gigagrams. These baseline emissions may reach an additional
19 gigagrams from existing plants through modification/reconstruction.
Implementation of Regulatory Alternatives II through IV would reduce the
total new plant emissions to 16, 14, and 11 gigagrams, respectively.
Modification/reconstruction may add up to 5.6, 5.0, and 4.1 gigagrams,
respectively, to the new plant projections.
7.3 WATER QUALITY IMPACT
Although fugitive emissions from gas plant equipment primarily
impact air quality, they also adversely impact water quality. In particular,
leaking components handling liquid hydrocarbon streams increase the
waste load entering wastewater treatment systems. Leaks from equipment
contribute to the waste load by entering drains via run-off. Implementation
of Regulatory Alternatives II through IV would reduce the waste load on
wastewater treatment systems by preventing leakage from process equipment
from entering the wastewater system.
7.4 SOLID WASTE IMPACT
Solid wastes that are generated by the natural gas/gasoline processing
industry and that are associated with the regulatory alternatives include
replaced mechanical seals, seal packing, rupture disks, and valves.
7-3
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Table 7-2. EMISSIONS FOR REGULATORY ALTERNATIVES (MODEL PLANT A)
Regulatory Alternative*
Component
type
Valves
Rel ief valves
Open-ended
lines
Compressor
seals
Pump seals
Sampling
connections
Flanges and
connections
Total
I
Baseline
emissions,
kg/day
45 (120)
1.3 (18)
17 (27)
2.0 (9.8)
2.4 (3.0)
G .03 (.64)
L .17 (.17)
11 (26)
79 (205)
Percent
total
emissions
57 (59)
2 (9)
22 (13)
3 (5)
3 (1)
<1 (<1)
14 (13)
II
Controlled
emissions,
kg/day
10 (28)
0.48 (5.6)
0.0 (0.0)
0.36 (2.2)
1.0 (1.3)
0.3 (.64)
.17 (.17)
11 (26)
23 (64)
III
Percent
total
emissions
43 (44)
2 (9)
0 (0)
2 (3)
4 (2)
<1 (<1)
<1 (<1)
48 (41)
Controlled
emissions,
kg/day
10 (28)
0.40 (4.4)
0.0 (0.0)
0.0 (0.0)
0.84 (1.1)
0.0 (0.0)
0.0 (0.0)
11 (26)
22 (60)
Percent
total
emissions
45 (47)
2 (7)
0 (0)
0 (0)
4 (2)
0 (0)
0 (0)
49 (44)
IV
Controlled
emissions,
kg/day
7.3 (20)
0.0 (0.0)
0.0 (0.0)
0.0 (0.0)
0.0 (0.0)
0.0 (0.0)
0.0 (0.0)
11 (26)
18 (46)
Percent
total
emissions
40 (43)
0 (0)
0 (0)
0 (0)
0 (0)
0 (0)
0 (0)
60 (57)
* From Chapter 6
xx = VOC emission values
(xx) = THC emission values
aG = Gas Service
L = Liquid Service
-------
Table 7-2. EMISSIONS FOR REGULATORY ALTERNATIVES (MODEL PLANT B) Continued
en
Regulatory Alternative*
-Component
type
Valves
Relief valves
Open-ended
lines
Compressor
seals
Pump seals
Sampl i nga
connections
Flanges and
connections
Total
I
Baseline
emissions,
kg/day
140 (360)
4.0 (54)
51 (80)
6.0 (29)
7.2 (9.0)
G. .09 (1.9)
L. .51 .51
33 (78)
242 (612)
II
Percent
total
emissions
57 (59)
2 0)
22 (13)
3 (5)
3 (1)
<1 (<1)
<1 (<1)
14 (13)
Controlled
emissions,
kg/day
31 (83)
1.4 (17)
0.0 (0.0)
1.1 (6.6)
3.0 (3.8)
0.9 (1.9)
.51 .51
33 (78)
71 (191)
Percent
total
emissions
43 (44)
2 (9)
0 (0)
2 (3)
4 (2)
<1 (
-------
Table 7-2. EMISSIONS FOR REGULATORY ALTERNATIVES (MODEL PLANT C) Concluded
Regulatory Alternative
Component
type
Valves
Relief valves
Open-ended
lines
Compressor
seals
Pump seals
Sampling3
connections
Flanges and
connections
Total
I
Baseline
emissions,
kg/day
450 (1,200)
13 (180)
170 (265)
20 (98)
24 (30)
G. 0.3 (6.4)
L. 1.7 (1.7)
110 (260)
789 (2,041)
Percent
total
emissions
57 (59)
2 (9)
22 (13)
3 (5)
3 (1)
14 (13)
,11
Controlled
emissions,
kg/day
100 (280)
4.8 (56)
0.0 (0.0)
0.36 (22)
10 (13)
0.3 (6.4)
1.7 1.7
110 (260)
227 (643)
III
Percent
total
emissions
39 (43)
2 (9)
0 (0)
1 (3)
4 (2)
43 (40)
Controlled
emissions,
kg/day
100 (280)
4.0 (44)
0.0 (0.0)
0.0 (0.0)
8.4 (11)
0.0 (0.0)
0.0 (0.0)
110 (260)
220 (600)
Percent
total
emissions
45 (47)
2 (7)
0 (0)
0 (0)
4 (2)
0 (0)
0 (0)
49 (44)
IV
Controlled
emissions,
kg/day
73 (200)
0.0 (0.0)
0.0 (0.0)
0.0 (0.0)
0.0 (0.0)
0.0 (0.0)
0.0 (0.0)
110 (260)
180 (460)
Percent
total
emissions
40 (43)
0 (0)
0 (0)
0 (0)
0 (0)
0 (0)
0 (0)
60 (57)
xx = VOC emission values.
(xx) = Total hydrocarbon emission values.
aG = Gas Service
L = Liquid Service
-------
Table 7-3. TOTAL AND INCREMENTAL EMISSION REDUCTIONS OF THE
REGULATORY ALTERNATIVES ON A MODEL PLANT BASIS
Model plant emissions, Mg/yr
Regulatory
alternative A
I 29 (75)
II 8.4 (23)
III 8.0 (22)
IV 6.6 (17)
B
88 (223)
26 (70)
25 (65)
20 (51)
C
288 (745)
83 (235)
80 (220)
66 (170)
Percent emission reduction
Total b
—
70 (68)
73 (71)
78 (77)
Incremental
--
70 (68)
3 (3)
5 (6)
xx = VOC emission values.
(xx) = Total hydrocarbon emission values.
From Table 7-2. Assume 365 days per year operation.
Emissions reduction from Regulatory Alternative I.
cEmissions reduction from previous Regulatory Alternative.
-------
Table 7-4. PROJECTED FUGITIVE EMISSIONS FROM AFFECTED MODEL PBANTS AND
REGULATORY ALTERNATIVES FOR 1983-1987
03
Cumulative number of
affected model plants
Total fugitive emissions projected under
regulatory alternative (1000 Mg/yr)
New
plants
Year
1983
1984
1985
1986
1987
5th -
A
0
0
0
0
0
year
reduction
Modified/
reconstructed
plants
1983
1984
1985
1986
1987
5th -
2
4
6
8
10
year
reduction
B
40
80
120
150
180
emission
from baseline
3
6
9
12
15
emission
from baseline
C
0
0
0
0
0
3
6
9
12
15
3.5
7.0
11
13
16
_
1.2
2.5
3.7
4.9
6.2
I
(8.9)
(18)
(27)
(33)
(40)
(-)
(3.1)
(6.1)
(9.2)
(12)
(15)
II
1.0 2.
2.2 5.
3.1 8.
3.9 (11)
4.7 (13)
11.3 (27)
8 1.
6 2.
4 3.
3.
4.
11.
0.34 (0.96) 0.
0.69 (1.
1.0 (2.
1.4 (3.
J 0.
3 1.
B 1.
1.7 (4.8) 1.
- ( - ) 4.5 (10.2) 4.
Ill
0 2
0 5.
0 7.
8 9.
IV
6) 0.80
2) 1.6
8 2.4
8 3.0
2.0)
4.1)
6.1)
7.7)
5 (12) 3.6 (9.2)
5 (28) 12.4 (30.8)
33 (0.
67 (1.
0 (2.
3 (3.
7 (4.
5 (10.
90) 0.27 (0.70)
8 0.54
7 0.81
6 1.1
1.4)
2.1)
2.8
5) 1.4 (3.5)
5) 4.8 (11.5)
xx = VOC emission values.
(xx) = Total hydrocarbon emission values.
aThe number of affected model plants projected through 1987 distinguish between new plant construction and
modification/reconstruction. Plants in existence prior to 1983 are otherwise excluded. A discussion of
the growth projections is in Section 9.1.2.2.
The total fugitive emissions from Model Plants A, B, and C are derived from the emissions per model plant
in Table 7-3. The sum of emissions in any one year is the sum of the products of the number of affected
facilities per model plant times the emissions per model plant.
-------
Implementation of Regulatory Alternatives II through IV would increase
solid waste whenever equipment specifications require the replacement of
existing equipment.
Implementation of Alternatives II through IV, however, would have
an insignificant impact beyond existing levels (Regulatory Alternative I).
This is because most gas plant solid waste is unrelated to the regulatory
alternatives. These sources of solid waste include separator and tank
sludges, filter cakes, and slop oil. Also, metal solid wastes (e.g.,
mechanical seals, rupture disks, caps, plugs, and valve parts) could be
recycled and thus minimize any impact on solid waste.
7.5 ENERGY IMPACTS
Implementation of Regulatory Alternatives II through IV results in
a net positive energy impact. The energy savings from the "recovered"
emissions far outweigh the energy requirements of the alternatives. The
regulatory alternatives would require a minimal increase in energy
consumption due to: operation of monitoring instruments; installation
of dual mechanical seals, which require a minimal increase in energy
over single mechanical seals because of seal/shaft friction and operation
of fluid flush system; operation of the compressor vent control system;
closed loop sampling; and operation of combustion devices.
The energy savings over a 5-year period from new plants alone is
estimated at 4,600 terajoules (Regulatory Alternative II) up to 4,900
terajoules (Regulatory Alternative IV) as shown in Table 7-5. Modified/
reconstructed units may represent an additional 1,600 and 1,8.00 tera-
joules, respectively. Table 7-5 also shows the energy savings in crude
oil equivalents.
7.6 OTHER ENVIRONMENTAL CONCERNS
7.6.1 Irreversible and Irretrievable Commitment of Resources
Implementation of any of the regulatory alternatives is not expected
to result in any irreversible or irretrievable commitment of resources^
Rather, implementation of Alternatives II through IV would save resources
due to the energy savings associated with the reductions in emissions.
As previously noted, the generation of solid waste used in the control
equipment will not be significant.
7-9
-------
Table 7-5. ENERGY IMPACTS OF EMISSION REDUCTIONS FOR
REGULATORY ALTERNATIVES FOR 1983-1987
New
plants
Modified/
reconstructed
plants
Regulatory
alternative
II
III
IV
II
III
IV
Five-year total Energy value of
recovered emissions recovered emissions
from baseline (1000 Mg)a (terajoules)D'c
36 (88)
37 (85)
40 (94)
13 (31)
13 (31)
14 (34)
4,600
4,400
4,900
1,600
1,600
1,800
Crude oil equivalent
of recovered emissions
(1000 bbl)a
750
720
800
260
260
290
xx = VOC emission values.
(xx) = Total hydrocarbon emission values.
Estimated total fugitive emission reduction from Model Plants A, B, and C, from Table 7-4. Numbers are
corrected to account for emissions not recovered due to venting of compressors to flares or heater fuel
line in Regulatory Alternatives III and IV.
Calculated on the basis of 47 terajoules per gigagram of VOC. Heating value is assumed to be equal to
that of natural gas plant liquid production for 1978-1980 of 3,925,000 Btu/bbl (4.14 gigajoules/bbl),
Reference 3. Specific gravity assumed to be 0.55, Reference 1.
Calculated on the basis of 55 terajoules per gigagram of methane-ethane. Composition is assumed to be
80 percent methane and 20 percent ethane. The heats of combustion are assumed to be 23,000 Btu/lb and
22,300 Btu/lb for methane and ethane, respectively, Reference 2.
dCalculated on the basis of 163 bbl crude per terajoule. Heating value is assumed to be equal to that of
crude petroleum production for 1978-1980 of 5,800,000 Btu/bbl, Reference 3.
-------
7.6.2 Environmental Impact of Delayed Regulatory Action
As discussed in the above sections, implementation of the regulatory
alternatives will not significantly impact water quality or solid waste.
However, a delay in regulatory action would adversely impact air quality
at the rate shown in Table 7-4.
7-11
-------
7.7 REFERENCES
1. Nelson, W. L. Petroleum Refinery Engineering. McGraw-Hill Book
Company, Inc. New York, 1958. p. 32. Docket Reference
Number II-I-l.*
2. Perry, R. H., and C. H. Chilton, eds. Chemical Engineers' Handbook,
Fifth Edition. McGraw-Hill Book Company, New York. 1973.
p. 9-16. Docket Reference Number II-I-7.*
3. DOE Monthly Energy Review. January 1981. DOE/EIA-0035 (81/01).
Docket Reference Number II-I-26.*
4. Memorandum, T.W. Rhoads, PES to Docket A-80-20-B. Evaluation of
the Effects of Leak Detection and Repair on Fugitive Emissions in
the Onshore Natural Gas Processing Industry Using the LDAR Model,
November 1, 1982. Docket Reference Number II-B-18.*
5. Memorandum T.W. Rhoads, PES to Docket A-80-20-B. Calculation of
Controlled Emission Factors for Pressure Relief Valves and
Compressor Seals. November 1, 1982. Docket Reference
Number II-B-17.*
*References can be located in Docket Number A-80-20-B at U.S. Environmental
Protection Agency Library, Waterside Mall, Washington, D.C.
7-12
-------
8. COST ANALYSIS
8.1 COST ANALYSIS OF REGULATORY ALTERNATIVES
8.1.1 Introduction
The following sections present estimates of the capital costs,
annual costs, and cost effectiveness for each model plant and regula-
tory alternative discussed in Chapter 6. These estimates will then be
used in Chapter 9 to estimate the economic impact of the regulatory
alternatives upon the natural gas/gasoline processing industry. To
ensure a common cost basis, Chemical Engineering cost indices were
used to adjust control equipment to June 1980 dollars.
8.1.2 New Facilities
8.1.2.1 Capital Costs. The bases for the capital costs for
monitoring instruments and control equipment are presented in Table 8-1.
These data are used to tabulate the capital costs for each model plant
under the regulatory alternatives as given in Table 8-2.
Regulatory Alternative I requires no additional controls and
therefore incurs no capital costs. Under Regulatory Alternatives II
through IV, caps for open-ended lines and two monitoring instruments
would be purchased. Although only one instrument is required, it is
assumed that plant operators will purchase a spare in the event that
the first becomes inoperable. There are no other capital costs associated
with Alternative II.
Regulatory Alternative III also includes the cost of a compressor
vent control system and closed-loop sampling connections. As shown in
Figure 4-2, the compressor vent control system capital costs for
reciprocating seals include venting the seal and distance piece emissions
to either a flare or the plant heater as fuel gas. For centrifugal
seals, the compressor vent control system capital costs include capturing
the seal emissions from the seal degassing vent and similarly destroying
8-1
-------
Table 8-1. CAPITAL COST DATA (June 1980 dollars)
1. Monitoring Instruments
2 instruments (Foxboro OVA-108)
@ $4,600/instrument
Total cost is $9,200/plant
2. Caps for Open-Ended Lines
Based on cost for 5.1 cm screw-on gate valve, rated at 17.6 kg/cm2 L
(250 psi) water, oil, gas (w.o.g.) pressure. June 1981 cost is $46.50 ,
June 1980 cost is 8 percent less at $43. Retrofit installation =
1 hour at $18/hour . Total cost is $61/1ine.
3. Compressor Seal Vent Control System
A. Vent Manifold Piping6
2m 30cm pipe @ $108.00/m $ 216.00
100m 5.1cm pipe @ $6.50/m 650.00
2 30 cm blind flanges @ $50 100.00
Total vent manifold and trap piping $ 966
Laborf
102m of pipe = 3.4 hr for installation
30m/hr/crew 2.5 hr for set-up/breakdown
5.0 hr for fabrication
10.9 hours/crew
10.9 crew hrs. x j^6" x $18.00/hr =
total labor $ 589
total dollars $ 1.555
B. Reciprocating Compressor Seal Piping6
1 double distance piece $ 2,000.00j
15m 2.5cm pipe @ $2.82/m 42.30
5m 5.1cm pipe @ $6.50/m 32.50
1 2.5cm tee 0 $7.30 7.30
2 5.1cm x 2.5cm tees @ $8.16 16.32
3 2.5cm block valves @ $24.63 73.89
1 2.5cm check valve @ $80.40 80.40
3 2.5cm elbows @ $6.22 . 18.66
1 pressure alarm @ $9.901 9.90
Total manifold piping $ 2,281
8-2
-------
Table 8-1. CAPITAL COST DATA (June 1980 dollars)
(continued)
Labor'
20m of pipe
30m/hr/crew
3.25 crew hrs. x
1 hr for installation
0.75 hr for set-up/breakdown
1.5 hr for fabrication
3. 25 hr/crew
x $18.00/hr =
total labor $
total dollars
176
$ 2.456
C. Centrifugal Compressor Seal Piping
5m 2.5cm pipe @$2.82/ni
5m 5.1cm pipe § $6.50/tn
1 5.1cm x 2.5cm tees Q $8.16
1 2.5cm block valves @ $24.63
1 2.5cm elbows @ $6.22 .
1 pressure alarm @ 9.901
Total manifold piping
14.10
32.50
8.16
24.63
6.22
9.90
Labor1
10m of pipe
30m/hr/crew
1.08 crew hrs. x
0.33 hr for installation
0.25 hr for set-up/breakdown
0.5 hr for fabrication
1.08 hours/crew
3 men
crew
x $18.00/hr =
96
D. Gas Supply System Costs
Parts
5m 2.5 cm pipe @ $2.82/m
2 2.5 cm back valves @ $24.
1 pressure alarm @ $9.90 .
1 gas shutoff valve @ $23.891
Total Parts
Labor @ 100% Parts Price
58
total dollars
$ 154
$ 14.10
63 49.26
9.90
23.89
97.15
97.15
total dollars
194
8-3
-------
Table 8-1. CAPITAL COST DATA (June 1980 dollars)
(continued)
4. Closed-purge Sampling Connections9
Based on 6 m length of 2.5 crn schedule 40 carbon steel pipe, and three
2.5 cm ball valves. Retrofit or new installation = 18 hours at $18/hour,
Total cost is $530/sampling connection.
5. Rupture Disk System with Block Valve9
New Installation
Rupture Disk Assembly
7.6 cm rupture disk (stainless) = $ 230
7.6 cm rupture disk holder
(carbon steel) = 384
0.6 on pressure gauge = 18
0.6 cm bleed gate valve = 30
Subtotal $ 662
Upstream Block Valve
7.6 cm gate valve = $ 700
Offset Mounting
10.2 cm tee, elbow = $ 21
Installation
rupture disk assembly, 16 hrs @ $18/hr = $248
upstream block valve, 10 hrs Q $18/hr = 180
offset mounting, 8 hrs @ $18/hr = 144
Subtotal $ 612
Total $ 1,995
8-4
-------
Table 8-1. CAPITAL COST DATA (June 1980 dollars)
(continued)
Retrofit Installation
Relief Valve Replacement
7.6 cm relief valve (stainless)
Installation, 10 hrs (? $18/hr
Rupture Disk Assembly
Total
$1,456
180
$ 1,636
1,995
$3.631
6. Rupture Disk System with 3-Way Valve
New Installation
Rupture Disk with 3-wayValve
rupture disk assembly
One 3-way valve .(7.6 cm, 2-port)
One 7.6 cm pressure relief valve
(stainless)
Two 7.6 cm elbows
Subtotal
Installation. 36 hrs @ $18/hr
Total
$ 662
1,320
1,456
30
$ 3,468
648
$4.116
Retrofit Installation
Rupture Disk with 3-way Valve
Installation. 72 hrs @ $18/hr
$ 3,468
$ 1.296
$4,764
7. Dual Mechanical Seals9
New Installation
Seal cost
Seal credit
Installation, 16 hrs @ $18/hr
Total
Retrofit Installation
Seal cost
Installation, 19 hrs @ $18/hr
Total
Barrier Fluid Systan for
TJual Mechanical Seals (new or
retrofit)
$1,250
-278
288
$ 1,250
342
$ 1,260
$ 1,592
1,850
8-5
-------
Table 8-1. CAPITAL COST DATA (June 1980 dollars)
(concluded)
Pump Seal Barrier Fluid $ 4,000
Degassing Reservoir Vent
(new or retrbfitj
Total - new installation $ 7,100
Total - retrofit installation $ 7.388
a
One instrument used as a spare. Cost is based on Reference 1.
Reference 2.
GCost adjustment based on the economic indicators for pipe, valves, and
fittings in April 1980 (final) vs. April 1981 (preliminary). Reference 3.
Reference 4.
Reference 5.
Reference 18.
^Reference 7.
Reference 8.
Reference 6.
JReference 16.
L.
Engineering estimate.
8-6
-------
Table 8-2. CAPITAL COST ESTIMATES FOR MODEL PLANTS
(thousands of June 1980 dollars)
Capital cost item
ir
Regulatory Alternative
III'
IV1
Model Plant A
1. Monitoring instrument
2. Caps for open-ended
lines
3. Compressor vent control
system
4. Closed-loop sampling
connections
5. Rupture disk system
6. Dual mechanical seals
9.2 9.2
3.1 3.1
5.9
2.1
9.2 9.2
3.1 3.1
5.9 5.9
2.1 2.1
12 17
14 15
Total
12
20
46
52
aCosts are the same for new or retrofit installation.
New installation costs.
cRetrofit installation costs.
dCosts based on installed compressor seal vent control system for
50 percent reciprocating and 50 percent centrifugal compressors.
eCosts based on 50% rupture disk systems with block valve and
50% rupture disk systems with 3-way valve.
8-7
-------
Table 8-2. CAPITAL COST ESTIMATES FOR MODEL PLANTS
(thousands of June 1980 dollars)
(Continued)
Capital
Model PI
1. Mom"
2. Caps
cost item
ant B
tor ing instrument
for open-ended
Regulatory
A a
na ina
9.2 9.2
9.2 9.2
Alternati
h
IVD
9.2
9.2
ve
r
IVC
9.2
9.2
lines
3. Compressor vent control
system
4. Closed-loop sampling
connections
11.1 11.1 11.1
6.4
6.4 6.4
5.
6.
Rupture disk system
Dual mechanical seals
Total
37
43
18 36 116
51
44
131
iCosts are the same for new or retrofit installation.
3New installation costs.
Retrofit installation costs.
^Costs based on installed compressor seal vent control system for
50 percent reciprocating and 50 percent centrifugal compressors.
eCosts based on 50% rupture disk systems with block valve and
50% rupture disk systems with 3-way valve.
8-8
-------
Table 8-2. CAPITAL COST ESTIMATES FOR MODEL PLANTS
(thousands of June 1980 dollars)
(Concluded)
Regulatory Alternative
Capital cost item Ha IHa IVb IVC
Model Plant C
1.
2.
3.
4.
5.
6.
Monitoring instrument
Caps for open-ended
lines
Compressor vent control
system
Closed-loop sampling
connections
Rupture disk system
Dual mechanical seals
9.2 9.2 9.2
31 31 31
29 29
21 21
120
140
9.2
31
29
21
170
150
Total 40 90 350 410
aCosts are the same for new or retrofit installation.
New installation costs.
GRetrofit installation costs.
dCosts based on installed compressor seal vent control system for
50 percent reciprocating and 50 percent centrifugal compressors.
eCosts based on 50 percent rupture disk systems with block valve and
50 percent rupture disk systems with 3-way -valve.
8-9
-------
the emissions. Table 8-1 shows the installed capital costs for the
vent system piping arrangements. The model plant capital costs reported
in Table 8-2 are based on the model unit number of compressors with
50 percent reciprocating and 50 percent centrifugal compressor seals.
The costs given in Table 8-2 reflect two vent manifold systems and
one gas supply system for each plant, in addition to the required
number of centrifugal and reciprocating seal piping systems.
Alternative IV includes all the costs of Alternative III plus the
costs of a rupture disk for pressure system relief valves and dual
mechanical seals for pumps. The costs of Regulatory Alternative IV
are different for new installation of equipment and for retrofit
installations.
8.1.2.2 Annual Costs. Implementation of Regulatory Alternatives II
through IV would require visual and/or instrument monitoring of potential
VOC emissions. The inspection requirements are given in Chapter 6.
Table 8-3 summarizes the leak detection and repair labor-hour requirements,
and Table 8-4 shows the annual costs for the alternatives by model
plant. These repair costs cover the expense of repairing those components
in which leaks develop after initial repair. The cost for leak detection
and repair labor was assumed to be $18.00 per hour.
Administrative and support costs were estimated at 40 percent of
the sum of leak detection and repair labor costs. Leak detection
labor, leak repair labor, and administrative/support costs are recurring
annual costs for each regulatory alternative.
8.1.2.3 Annual i zed Costs. The bases for the annual ized control
costs are presented in Table 8-5. The annualized capital, maintenance,
and miscellaneous costs were calculated by taking the appropriate
factor from Table 8-5 and applying it to the corresponding capital
cost from Table 8-2. The capital recovery factors were calculated
using the equation:
(1 + i)"- 1
Where i = interest rate, expressed as a decimal,
n = economic life of the component, years.
The interest rate used was 10 percent. The expected life of the
monitoring instrument was 6 years. Dual mechanical seals and rupture
8-10
-------
TABLE 8-3. LEAK DETECTION AND REPAIR LABOR-HOUR REQUIREMENTS
00
I
• Leak detection
Monltori no
Component
type
Valves
Relief valves
Monitoring
interval
quarterly
monthly/
quarterly
monthly
quarterly
monthly
Compressor seals
quarterly
Pump seals
quarterly
monthly
weekly
Components per
model plant Type of
ABC monitoring
250 750 2,500 Instrument
instrument
Instrument
4 12 40 instrument
instrument
2 6 20 instrument
2 6 20 instrument
instrument
visual
Times
monitored
per year
4.0h'9
4.3h'9
11. 9h'9
4
12
4
49
129
52
labor-hours Fraction of
required * sources
ABC maintained
33
36
99
4.3
13
1.3
1
1.3
4.0
0.9
100
108
298
13
38
4.0
4.0
12
2.6
333
358
992
43
130
13
13
40
8.7
0.1859
0.1879
0.1919
0.08e
O.lle
0.17e
0.3949
0.4089
Leak repair
Estimated
number of Repair time Maintenance^
leaks per year per source labor-hours
ABC (hours) ABC
46
47
48
0.
0.
0.
0.
0.
139
140
143
3 1.3
4 1.3
3 1.0
79 2.4
82 2.5
464
467
478
3.2
4.4
3.4
7.9
8.2
1.131 52
53
54
0J 0
0
40k 12
16k 12.6
13.1
157 524
158 528
162 540
0 0
0 0
40 136
38 126
40 131
aAssumes that instrument monitoring requires a two-person team, and visual monitoring, one person.
Monitoring time per person: pumps-instrument 5 min., visual 1/2 min.; compressors 5 mln.; valves 1 min., and safety/relief valves 8 m1n. Reference 10.
cMonitoring labor-hours = number of workers x number of components x time to monitor x times monitored per year.
Based on the number of sources leaking at 10,000 ppmv. From Table 4-1.
eAnnual percent recurrence factors have been applied for monthly and quarterly instrument inspections for relief valves and compressor seals to
determine the percentage of sources maintained. It is assumed that 5 percent of leaks Initially detected are found with monthly monitoring (0.05 x 12
= 0.6) and that 10 percent of leaks Initially detected are found with quarterly monitoring (0.1 x 4 = 0.4). Fraction of sources initially leaking from
Table 4-1. Number of leaks - number of components x fraction of sources initially leaking x annual fraction of recurrence factor. Reference 7.
fLeak repair labor-hours = number of leaks x repair time.
9The values used in calculating- labor-hour requirements for valves and pump seals were developed on the basis of the model and data presented 1n
Appendix E.
fractional numbers accounted for by recognizing that it is not necessary to monitor valves that have previously been identified as leakers
and have not yet been repaired.
Weighted average based on 75 percent of the leaks repaired on-Hne, requiring 0.17 hours per repair, and on 25 percent of the leaks, repaired offline,
requiring 4 hours per repair. Reference 9.
•'it is assumed that these leaks are corrected by routine maintenance at no additional labor requirements. Reference 10.
References 10 and 17.
-------
Table 8-4. ANNUAL LEAK DETECTION AND REPAIR LABOR COSTS3
(June 1980 dollars)
Regulatory.
alternative
IIC
IIId
IVe
Leak
A
730
970
1,800
detection cost
model plant
B
2,200 7
2,900 9
5,400 18
C A
,400 1,400
,700 1,200
,000 970
Repair cost
model plant
B C
4,300 14,000
3,600 12,000
2,900 9,700
Costs = labor-hours (Table 8-3) x $18/hour (Table 8-5).
Regulatory Alternative I (baseline control) has zero costs.
Calculated on the basis of quarterly instrument monitoring for
valves, relief valves, compressor seals, and pump seals, and
weekly visual monitoring for pump seals.
Calculated on the basis of monthly/quarterly instrument
monitoring for valves, monthly instrument monitoring for
relief valves and pump seals, and weekly visual monitoring
for pump seals.
Calculated on the basis of monthly monitoring of valves.
8-12
-------
disks were assumed to have a 2-year life. All other control equipment
is assumed to have a 10-year life.
For the purposes of determining recovery credits, the value of
VOC is assumed to be $192/Mg, and the value of methane-ethane is
assumed to be $61/Mg. The derivation of these values is described in
Table 8-5. Although compressor emissions can be routed to the process
heater, resulting in a fuel savings, no credit is taken because most
plants are likely to combust these organics in a flare.
Implementation of Regulatory Alternatives II, III, and IV involves
initial detection and repair of leaking components. As shown in
Table 8-6, the repair labor-hour requirements of the initial survey
are derived by multiplying the fraction of sources leaking and repair
time per source by the model plant component counts. The cost of
repairing initial leaks was amortized over a 10-year period, since
this is a one-time cost. Administrative and support costs to implement
the regulatory alternatives were assumed to be 40 percent of the leak
detection and repair labor costs. Table 8-7 shows the initial leak
repair costs. These costs include the labor costs from Table 8-6, and
replacement mechanical pump seals. The initial leak repair cost in
Table 8-7 shows Alternative II to be the most costly. Costs decrease
for the other alternatives as equipment specifications replace the
labor intensive equipment repairs.
8.1.2.4 Recovery Credits. The annual emissions, total emissions
recovered, and annual recovered product credits for each model plant
and regulatory alternative appear in Table 8-8. Regulatory Alternative I
represents "baseline emissions" and therefore receives no recovery
credits.
8.1.2.5 Net Annual Costs. The net annual model plant costs
shown in Tables 8-9, 8-10, and 8-11 were determined by subtracting the
annual recovered product credit from the total cost before credit.
For example, Model Plant A under Regulatory Alternative II has a net
annual cost of $3,800, as a result of $9,700 in costs and $5,900 in
recovery credits.
8.1.2.6 Cost Effectiveness. The cost effectiveness of the
regulatory alternatives for each model plant is shown in Table 8-12.
Regulatory Alternatives II and III for all model plants entail
8-13
-------
Table 8-5. DERIVATION OF ANNUALIZED LABOR,
ADMINISTRATIVE, MAINTENANCE, AND CAPITAL COSTS
1. Capital recovery factor for capital costs
o Dual mechanical seals and rupture disks
o Other control equipment
o Monitoring instruments
2. Annual maintenance costs
o Control equipment
o Monitoring instruments
o Replacement pump seals
3. Annual miscellaneous costs
4. Labor costs
5. Administrative and support costs to
implement regulatory alterative
6. Annualized charge for initial leak repairs
7. Recovery credits
o Nonmethane-nonethane hydrocarbons (VOC)
o Methane-ethane
0.58 x capital*
0.163 x capital6
0.23 x capital0
0.05 x capital0
$3,000e
$HOm
0.04 x capital
$18/hr9
0.40 x (monitoringJabor +
maintenance labor)
(estimated number of leaking
components per model unit x
repair time) x $18/hrn x 1.4
x 0.163
$ 61/Mg
aApplies to cost of seals ($972-incremental cost due to specification of dual
seals instead of single seals) and disk ($230) only. Two year life, ten
percent interest. Reference 7.
Ten year life, ten percent interest. Reference 11.
cSix year life, ten percent interest. Reference 11.
From Reference 11.
elncludes materials and labor for maintenance and calibration.
Reference 11.
^Includes wages plus 40 percent for labor-related administrative and overhead
costs. Reference 11.
From Reference 4.
1 Shown in Table 8-3.
•^Initial leak repair amortized for ten years at ten percent interest.
kBased on LPG price of 40
-------
TABLE 8-6. LABOR-HOUR REQUIREMENTS FOR INITIAL LEAK REPAIR
0*
I
Component type
Valves
Relief valves
Compressor seals
Punp seals
Number of components
per model plant
A
250
4
2
2
b
750
12
6
6
C
2,500
40
20
20
Percent of
sources
leaking in .
Initial survey'
18
19
43
33
Estimated
Number of leaks
1 A
45
0.76
0.86
0.66
. B C
135 450
2.3 7.6
2.6 8.6
2.0 6.6
Repair time
per source
(hours)
1.13
0
40
16
Repair lahnr-hnur<;
A
51
0
34
11
B
153
0
104
32
C
509
0
344
106
uSee Table 8-3.
-------
Table 8-7. INITIAL LEAK REPAIR COSTS (JUNE 1980 DOLLARS)
Initial repair costs Annualized initial repair
for model plants costs for model plants0
Regulatory
alternative
II
III
IV
2,400
1,600
1,300
7,300
4,700
3,900
24,000
16,000
13,000
390
260
210
1,200
770
640
4,000
2,500
2,100
Regulatory Alternative I (baseline control) has zero costs.
bCosts = labor-hours (Table 8-6) x $18/hour (Table 8-5) x 1.4 (Administrative
costs, Table 8-5) + new seal costs for pumps.
°Annualized cost = Initial Repair Costs x 0.163 (capital
recovery factor, Table 8-5).
8-16
-------
Table 8-8. RECOVERY CREDITS
CO
Model Plant A
Regulatory
alternative
II
III
IV
Recovered
emissions,
Mg/yr
20.6 (52)
20.3 (49)
22 (54)
Recovered
product
value, b
$/yr
5,870
5,650
6,180
Model Plant B
Recovered
emissions,
Mg/yr
62 (113)
61 (147)
66 (161)
Recovered
product
value, b
$/yr
15,000
17,000
18,500
Model Plant C
Recovered
emissions,
Mg/yr
205 (510)
201 (489)
215 (539)
Recovered
product
value, b
$/yr
58,000
56,200
61,000
xx = VOC emission values.
(xx) = Total hydrocarbon emission values.
aBased on emission reductions presented in Table 7-2 and 7-3.
Based on recovered VOC value of $192/Mg, and recovered non-VOC hydrocarbon (methane-ethane) value of
$61/Mg from Table 8-5. No recovery credits are given for compressors. Compressor seal vent emissions could
be used as process heater fuel resulting in recovery of these emissions at their fuel value.
Example Calculation for Model Plant A, Regulatory Alternative IV:
Recovered Product Value ($/yr) = (22 Mg/yr VOC) ($192/Mg VOC) + (54 Mg/yr THC - 22 Mg/yr VOC) ($61/Mg
Op C2) = $6,180
-------
Table 8-9. ANNUAL COST ESTIMATES FOR MODEL PLANT A
(Thousands of Jane 1980 Dollars)
Regulatory Alternative
Cost Item II4
Annual! zed Capital Costs
A. Control equipment
1. Monitoring instruments 2.1
2. Caps for open-ended lines 0.51
3. Compressor vent control system
4. Closed-loop sampling connections
5. Rupture disk system
6. Dual mechanical seal system
B. Initial leak repair8 0.39
Operating Costs
A. Maintenance costs
1. Monitoring Instruments 3.0
2. Caps for open-ended lines 0.16
3. Compressor vent control system
4. Closed-loop sampling connections
5. Rupture disk system
6. Dual mechanical seals
7. Replacement seal system 0.11
B. Miscellaneous costs
1. Monitoring instruments 0.37
2. Caps for open-ended lines 0.12
3. Compressor vent control system
4. Closed-loop sampling connections
5. Rupture disk system
6. Dual mechanical seal system
C. Labor charges
1. Monitoring labor9 0.73
2. Leak repair labor9 1.4
3. Administrative and supportf 0.85
Total Before Credit 9.7
Recovery Credits'1 (5.9)
Net Annual Cost 3.8
4Costs are the same for new or modified/reconstructed facilities (
IIId
2.1
0.51
0.96
0.34
0.26
3.0
0.16
0.30
0.10
0.11
0.37
0.12
' 0.24
0.08
0.97
1.2
0.87
12
(5.7)
6.3
) » cost savings.
IVb
2.1
0.51
0.96
0.34
2.4
3.1
0.21
3.0
0.16
0.30
0.10
0.60
0.71
0.37
0.12
0.24
0.08
0.48
0.57
1.8
0.97
1.1
20
(6.2)
14
IVC
2.1
0.51
0.96
0.-34
3.1
3.5
0.21
3.0
0.16
0.30
0.10
0.85
0.74
0.37
0.12
0.24
0.08
0.68
0.60
1.8
0.97
1.1
22
(6.2)
16
Costs for new facilities.
cCosts for modified/reconstructed facilities.
dCapital costs from Table 8-2. Capital recovery factor from Table 8-5.
eFrom Table 8-7. ~"~
fFrom Table 8-5
9From Table 8-4.
hFrom Table 8-8.
8-18
-------
Table 8-10. ANNUAL COST ESTIMATES FOR MODEL PLANT B
(Thousaads of June 1980 Dollars)
Regulatory Alternative
Cost Item II4
Annual 1 zed Capital Costs
A. Control equipment
1. Monitoring instruments 2.1
2. Caps for open-ended lines 1.5
3. Compressor vent control system
4. Closed-loop sampling connections
5. Rupture disk system
6. Dual mechanical seals
B. Initial leak repair6 1.2
Operating Costs
A. Maintenance costs
1. Monitoring instruments 3.0
2. Caps for open-ended lines 0.46
3. Compressor vent control system
4. Closed-loop sampling connections
5. Rupture disk system
6. Dual mechanical seals
7. Replacement pump seals 0.34
B. Miscellaneous costs
1. Monitoring instruments 0.37
2. Caps for open-ended lines 0.37
3. Compressor vent control system
4. Closed-loop sampling connections
5. Rupture disk system
6. Dual mechanical seals
C. Labor charges
1. Monitoring labor9 2.2
2. Leak repair labor9 4.3
3. Administrative and support 2.6
Total Before Credit 19
Recovery Credits'1 (15)
Net Annual Cost . 4
*Costs are the same for new or modified/reconstructed facilities.
bCosts for new facilities.
°Costs for modified/reconstructed facilities.
dCap1tal costs from Table 8-2. Capital recovery factor from Table 8-5.
eFrom Table 8-7.
fFrom Table 8-5
9From Table 8-4.
From Table 8-8.
Ill3
2.1
1.5
1.8
1.0
0.77
3.0
0.46
0.55
0.32
0.35
0.37
0.37
0.44
0.26
2.9
3.6
2.6
22
(17)
5
Ivb
2.1
1.5
1.8
1.0
7.1
9.4
0.64
3.0
0.46
0.55
0.32
1.9
2.1
0.37
0.37
0.44
0.26
1.5
1.7
5.4
2.9
3.3
48
(19)
29
IVC
2.1
1.5
1.8
1.0
9.4
10
0.64
3.0
0.46
0.55
0.32
2.6
2.2
0.37
0.37
0.44
0.26
2.0
1.8
5.4
2.9
3.3
52
(19)
33
8-19
-------
Table 8-11. ANNUAL COST ESTIMATES FOR MODEL PLANT C
(Thousands of June 1980 Dollars)
Cost Item
Annual 1 zed Capital Costs
A. Control equipment
1. Monitoring Instruments
2. Caps for open-ended lines
3. Compressor vent control system
4. Closed-loop sampling connections
5. Rupture disk system
6. Dual mechanical seals
B. Initial leak repair6
Operating Costs
A. Maintenance costs
1. Monitoring instruments
2. Caps for open-ended lines
3. Compressor vent control system
4. Closed-loop sampling connections
5. Rupture disk system
6. Dual mechanical seals
7. Replacement pump seals
B. Miscellaneous costs
1. Monitoring instruments
2. Caps for open-ended lines
3. Compressor vent control system
4. Closed-loop sampling connections
5. Rupture disk system
6. Dual mechanical seals
C. Labor charges
1. Monitoring labor**
2. Leak repair labor"
3. Administrative and support
Total Before Credit
Recovery Credits
Net Annual Cost
Regulatory
II" III8
2.1 2.1
5.0 5.0
4.7
3.4
4.0 2.5
3.0 3.0
1.5 1.5
1.4
1.0
1.1 1.1
0.37 0.37
1.2 1.2
1.2
0.84
7.4 9.7
14 12
8.6 8.7
48 59
(58) (56)
.(10) 3
Alternative
Ivb
2.1
5.0
4.7
3.4
24
31
2.1
3.0
1.5
1.4
1.0
6.1
7.1
0.37
1.2
1.2
0.84
4.8
5.7
18
9.7
11
145
(61)
84
IVC
2.1
5.0
4.7
3.4
31
35
2.1
3.0
1.5
1.4
1.0
8.4
7.4
0.37
1.2
1.2
0.84
6.8
6.0
18
9.7
11
161
(61)
100
*Costs are the same for new or modified/reconstructed facilities.
bCosts for new facilities.
°Costs for modified/reconstructed facilities.
dCap1tal costs from Table 8-2. Capital recovery factor from Table 8-5.
eFroin Table 8-7.
fFrom Table 8-5
9From Table 8-4.
hFrom Table 8-8.
8-20
-------
Table 8-12. COST EFFECTIVENESS OF REGULATORY ALTERNATIVES
Regulatory Alternative
Model Plant A
Capital Cost ($)d
Net annual cost ($/yr) f
Total VOC reduction (Mg/yr)
Cost effectiveness ($/Mg VOC)9
Model Plant B
Capital Cost ($)d ,
Net annual cost ($/yr) f
Total VOC reduction (Mg/yr)
Cost effectiveness ($/Mg VOC)9
Model Plant C
Capital Cost ($)d .
Net annual cost ($/yr) f
Total VOC reduction (Mg/yr)
Cost effectiveness ($/Mg VOC)9
I
0
0
0
0
0
0
0
0
0
0
0
0
IIa
12,000
3,800
20.6
180
18,000
4,000
62
65
40,000
(10,000)
200
(50)
III3
20,000
6,300
21.0
300
36,000
5,000
63
79
90,000
3,000
210
14
IVb
46,000
14,000
22.4
630
116,000
29,000
68
430
350,000
84,000
220
380
IVC
52,000
16,000
22.
710
131,000
33,000
68
490
410,000
100,000
220
450
Costs are the same for new or modified/reconstructed facilities.
Costs for new facilities.
Costs for modified/reconstructed facilities.
dFrom Table 8-1.
eFrom Table 8-9.
From Table 7-3.
9Cost effectiveness = total VOC emission reduction divided by the net annual
cost.
hFrom Table 8-10.
""From Table 8-11.
8-21
-------
relatively low costs per Mg of VOC emission reduction when compared to
Alternative IV. Model Plant B Regulatory Alternative II and Model
Plant C Regulatory Alternatives II and III have a net annual credit.
8.1.3 Modified/Reconstructed Facilities
8.1.3.1 Capital Costs. The bases for determining the capital
costs for modified/reconstructed facilities are presented in Table 8-1.
The capital cost for Alternatives I, II, and III are the same as for
new plants. However, the capital cost for Regulatory Alternative IV
is higher than for new plants. This is because of the additional
costs incurred through replacement of relief valves, and retrofit
installation of dual mechanical seals.
8.1.3.2 Annual Costs. The annual control costs for modified/
reconstructed plants are derived from the same basis as new plants
(see Table 8-5). The net annual costs for modified/reconstructed
facilities are higher than for new facilities under Regulatory
Alternative IV (I, II, and III are the same as new facilities), as
shown in Tables 8-9, 8-10, and 8-11. The recovery credits remain the
same as for new plants.
8.1.3.3 Cost Effectiveness. The cost effectiveness of Regulatory
Alternative IV for modified/reconstructed facilities is also shown in
Table 8-12. The cost effectiveness of this Alternative is substantially
higher than for new facilities.
8.1.4 Projected Cost Impacts
The projected fifth year industry wide costs of implementing the
regulatory alternatives are presented in Table 8-13. The cost estimates
were obtained by multiplying the costs per model plant by the model
plant growth estimates given in Table 7-4 for 1983 to 1987. The cost
impacts for new plants and modified/reconstructed plants are reported
separately in order to differentiate between expected impacts, represented
by new plants, and maximum impacts, represented by new plants with the
addition of modified/ reconstructed plant impacts. A maximum impact
would result if all changes to existing plants constitute modification/
reconstruction. The total capital costs reflect the cumulative costs
of implementing the regulatory alternatives in a given year. All
other costs shown are for plants subject to new source performance
standards in the indicated year.
8-22
-------
Table 8-13. FIFTH-YEAR NATIONWIDE COSTS OF THE REGULATORY ALTERNATIVES
(thousands of June 1980 dollars)
CD
r>>
CO
Cost item
New plants3
Cumulative capital costs by 1987
Total annual costs
Total recovery credit
Net annual costs
Modi f i ed/recons tructed f aci 1 i ti es
Cumulative capital costs by 1987
Total annual costs
Total recovery credits
Net annual costs
II
3,200
3,400
2,700
700
990
1,100
1,200
(100)
III
6,500
4,000
3,100
900
2,100
1,300
1,200
100
IV
21,000
9,700
3,400
6,300
8,600
4,200
1,300
2,900
( ) = cost savings
aA schedule of projected new and modified/reconstructed model plants is presented
in Table 7-4.
-------
0.2 OTHER COST CONSIDERATIONS
Environmental, safety, and health statutes that may cause an
outlay of funds by the gas processing industry are listed in Table 8-14.
Specific costs to the industry to comply with the provisions, requirements,
and regulations of the statutes are unavailable.
8-24
-------
Table 8-14 STATUTES THAT MAY BE APPLICABLE TO THE NATURAL GAS PROCESSING INDUSTRY
CO
I
ro
tn
Statute
Applicable provision, regulation or
requirement of statute
Statute
Applicable provision, regulation or
requirement of statute
Clean Air Act and Admendments
Clean Water Act (Federal
Water Pollution Act)
Resource Conservation and
Recovery Act
Toxic Substances Control
Act
o State Implementation plans
o National emission standards for
hazardous air pollutants
o New source performance standards
o PSO construction permits
o Nonattainment construction permits
o Discharge permits
o Effluent limitations guidelines
o New source performance standards,
o Control of oil spills and discharges
o Pretreatment requirements
o Monitoring and reporting
o Permitting of industrial projects
that impinge on wetlands or
public*waters
o Environmental impact statements
o Permits for treatment, storage, and
disposal of hazardous wastes
o Establishes system to track
hazardous wastes
o Establishes recordkeeping, reporting,
labeling, and monitoring system
for hazardous waste
o Superfund
o Premanufacture notification
o Labeling, recordkeeping
o Reporting requirements
o Toxicity testing
Occupational Safety S Health
Act
Coastal Zone Management Act
National Environmental Policy
Act
Safe Drinking Water Act
Marine Sanctuary Act
i,
o Walking-working surface standards
o Means of egress standards
o Occupational health and environ-
mental control standards
o Hazardous material standards
o Personal protective equipment
standards
o General environmental control
standards
o Medical and first aid standards
o Fire protection standards
o Compressed gas and compressed air
equipment
o Welding, brazing, and cutting
standards
o States may veto Federal permits for
plants to be sited 1n coastl zone
o Requires environmental Impact
statements
o Requires undergrond Injection
control permits
o Ocean dumping permits
o Recordkeeping and reporting
-------
8.3 REFERENCES
1. Telephone conversation. Michael Alexander, TRW, with Ms. M. Fecci
of Analabs/Foxboro. March 23, 1982. Price of Century Systems
OVA-108 in July 1980. Docket Reference Number II-E-14.*
2. Telephone conversation. Michael Alexander, TRW, with Mr. Harris of
Dillon Supply, Durham, N.C. June 17, 1981. Price of gate valves.
Docket Reference Number II-E-11.*
3. Economic Indicators. Chemical Engineering. Vol. 88 #12. June 15,
1981. p. 7. Docket Reference Number II-I-30.*
4. Letter with attachments from Texas Chemical Council to Walt Barber,
U.S. EPA. June 30, 1980. Docket Reference Number II-D-4.*
5. Telephone conversation. Michael Alexander, TRW, with Danny Keith,
Dillon Supply Co., Raleigh, N.C. June 15, 1981. Costs of valves,
pipes, and fittings. Docket Reference Number II-E-10.*
6. Telephone conversation. Tom Norwood, Pacific Environmental Services,
Inc., with W.W. Grainger, Inc., Raleigh, NC. December 17, 1981.
Costs of pressure switches and gas shutoff valves. Docket Reference
Number II-E-18.*
7. VOC Fugitive Emissions in Petroleum Refining Industry - Background
Information for Proposed Standards. EPA-450/3-81-015a. U.S. EPA,
OAQPS. November 1982. Docket Reference Number II-A-36.*
8. Memorandum from Cole, D. G., PES, Inc., to K. C. Hustvedt, U.S.
Environmental Protection Agency. Estimated Costs for Rupture Disk
System with a 3-way valve. July 29, 1981. Docket Reference Number
II-B-8.*
9. Erikson, D. G. and V. Kalcevic. Organic Chemical Manufacturing
Volume 3: Storage, Fugitive, and Secondary Sources. EPA-450/3-80-025.
U.S. EPA, OAQPS. December 1980. Docket Reference Number II-A-22.*
10. Letter with attachments from J. M. Johnson, Exxon Company, U.S.A.,
to Robert T. Walsh, U.S. EPA. July 28, 1977. Docket Reference
Number II-D-2.*
11. Environmental Protection Agency. Control of Volatile Organic
Compounds Leaks from Petroleum Refinery Equipment. EPA-450/2-78-036,
OAQPS No. 1.2-111. June 1978. Docket Reference Number II-A-3.*
12. Letter with attachments from R. E. Van Ingen, Shell Oil Company, to
D. R. Goodwin, OAQPS, U.S. EPA. January 10, 1977. Response to 114
letter on hydrocarbon sources from petroleum refineries. Docket
Reference Number II-D-1.*
8-26
-------
13. Telephone conversation. T. Hennings, TRW, with Editor, Oilgram
News. February 25, 1981. Price of LPG on June 16, 1980. Docket
Reference Number II-E-6.*
14. Nelson, W. L., Petroleum Refinery Engineering. McGraw-Hill Book
Co., Inc. New York. 1958. p. 32. Docket Reference Number II-I-2.*
15. DOE Monthly Energy Review. January 1981. DOE/EIA-0035(81/01).
p. 88. Docket Reference Number II-I-26.*
16. Telephone conversation. T. Norwood, Pacific Environmental Services,
Inc., with P. Marthinetti, Ingersoll Rand. Distance Piece Price,
December 8, 1982. Docket Reference Number II-E-16.*
17. Fugitive Emission Sources of Organic Compounds - Additional Information
on Emissions, Emission Reductions, and Costs. EPA 450/3-82-010, April
1982. Docket Reference Number II-A-25.*
18. McMahon, Leonard A., 1981 Dodge Guide. Annual Edition No. 13,
McGraw-Hill Publishing Co. Docket Reference Number II-I-125.*
*References can be located in Docket Number A-80-20-B at the U.S. Environmental
Protection Agency Library, Waterside Mall, Washington, D.C.
8-27
-------
9. ECONOMIC ANALYSIS OF THE REGULATORY ALTERNATIVES
9.1 INDUSTRY PROFILE
This section describes the general business and economic conditions of
the onshore natural gas production industry. The primary focus of the
discussion is on the natural gas processing segment of the industry for
which alternative emission regulations are being considered.
Projections for the year 1987, five years after a proposal date of
1982 for the regulatory alternatives for new, modified or reconstructed
sources, were developed for the industry. The growth-projections are
presented to illustrate the future trend of the industry. The profile and
the projections, including significant factors and trends in the industry,
are presented to aid in the determination of economic impacts of the
proposed standards. The energy and environmental impact analyses also were
conducted based upon these projections. The economic impacts are described
in subsequent sections.
9.1.1 Onshore Natural Gas Production Industry
The natural gas system in the United States consists of producers,
processors, dealers, interstate and intrastate pipelines, distributors and
consumers. The production industry includes hundreds of firms engaged in
the exploration, drilling, producing and processing of natural gas. A
relatively small number of companies dominate the industry. The American
Association of Petroleum Geologists (AAPG) states that the 16 largest firms
in the industry found 53.7 percent of 2.8 billion barrels of crude oil and
40.3 percent of 41.3 trillion cubic feet of natural gas discovered during
the period from 1969 to 1978. Also, the AAPG states that the 16 largest
companies accounted for about 60 percent of industry expenditures for
geological and geophysical information and lease acquisition. However,
9-1
-------
these large companies spend almost twice as much money as smaller firms on
predrilling exploration and one-half as much as the others on wildcat
drilling.
Approximately two-thirds of all processed gas is transmitted in
pipelines across state lines to be sold in various metropolitan areas. The
remainder is sold in intrastate markets. Approximately 100 pipeline
companies operate the interstate pipeline network. The pipeline sector of
the industry tends to be dominated by large companies more than the
production sector. In 1971, the four largest pipeline companies accounted
for 35 percent of the total interstate pipeline volume, while the 20
largest companies transported over 93 percent of the gas.
Companies involved in the final distribution of the gas constitute the
least concentrated sector of the industry. Over 1,600 companies buy gas
from pipelines and distribute it to various communities. Because they
operate in different service areas, these companies rarely compete with one
another, except in input markets, and are often regulated by state or local
agencies.
There is some vertical integration in the industry with pipeline
companies often owning producing wells. However, few companies engage in
production, transmission and distribution of the gas. In contrast,
horizontal integration is quite extensive. In the production sector,
almost all companies produce crude oil and natural gas liquids in addition
to natural gas although no one company predominates. In addition, many
also have investments in coal, oil shale, synfuels and mineral industries.
9.1.1.1 Natural Gas Processing Facilities. In 1980, there were 772
gas processing plants in the United States, with a combined total capacity
of approximately 71.2 billion cubic feet per day. As of January 1, 1980,
these plants were utilizing about 63 percent of their combined capacity.
Table 9-1 presents a distribution of the gas plants based on their
capacity. As this table indicates, at least 60 percent of the plants have
capacities of 50 million cubic feet per day (MMcfd) or less. Another 16.8
percent of the plants have capacities between 50 MMcfd and 100 MMcfd. The
remainder of the gas plants have capacities greater than 100 MMcfd, ranging
as high as 2,650 MMcfd.
9-2
-------
Table 9-1. DISTRIBUTION OF GAS PLANTS BY CAPACITY9 (1980)
Plant Capacity Number of Plants
(MMcfd)
50 460
51 - 100 130
100 - 200 70
201 - 300 34
301 - 400 9
401 - 500 3
501 - 600 7
601 - 700 0
701 - 800 2
801 - 900 6
901 - 1,000 6
> 1,000 6
No Response 39
TOTAL 772
a Based on data presented in Oil and Gas Journal, July 14, 1980.
9-3
-------
There are a number of different process methods currently being used
at natural gas processing plants: adsorption, refrigerated absorption,
refrigeration, compression, adsorption, cryogenic—Joule-Thomson and
cryogenic-expander. The distribution of gas plants by these process
methods and combinations of these methods is presented in Table 9-2.
In 1980, there were 138 different companies operating gas processing
plants in the United States. Table 9-3, which shows the distribution of
gas plants by ownership, lists the companies that own more than 20 plants.
This table indicates that over 55 percent of the gas plants are owned by
these "larger" companies. Also, Table 9-3 indicates that almost 85 percent
of the 138 companies own less than ten gas plants.
All the gas plants in the United States in 1980 were located in
twenty-two states, including two plants in Alaska. Table 9-4 shows a
distribution of gas plants based on location and ranked in order of gas
plant capacity. As the table indicates, over 46 percent of the plants are
located in Texas. States not listed in Table 9-4 have less than ten gas
plants.
9.1.1.2 Markets. Although the natural gas component of total energy
production has decreased from 40 percent in 1973 to 34 percent in 1980 as
indicated in Table 9-5, the natural gas production industry is expected to
continue to supply a significant fraction of total domestic energy
requirements. Exploration and production activities for natural gas are
anticipated to continue to increase as a result of phased natural gas price
deregulation and expected price increases.
Imports of natural gas have remained fairly constant since 1973,
ranging from 953 billion cubic feet in 1975 to 1,253 billion cubic feet in
1979. Imports were 984 billion cubic feet in 1980 representing 4 percent
of domestic consumption. Exports of natural gas declined from 77 billion
cubic feet in 1973 to 49 billion cubic feet in 1980. Exports are primarily
to Japan and Mexico. Imports are primarily from Canada, Mexico, and
Algeria.
Domestic aggregate retail price elasticities of demand for solid
fuels, natural gas, electricity and petroleum are shown in Table 9-6.
These elasticities represent the change in final demand for each fuel with
9-4
-------
Table 9-2. DISTRIBUTION OF GAS PLANTS BY PROCESS METHOD3 (1980)
Process Method Number of Plants
Absorption 77
Refrigerated Absorption 280
Refrigeration 161
Compression 7
Adsorption 40
Cryogenic-Joule-Thomson 19
Cryogenic-Expander 147
Absorption & Refrigerated Absorption 2
Absorption & Compression 1
Refrigerated Absorption & Refrigeration 2
Refrigerated Absorption & Adsorption 1
Refrigerated Absorption & Cryogenic-Joule-Thomson 2
Refrigerated Absorption & Cryogenic-Expander 13
Refrigeration & Compression 1
Refrigeration & Cryogenic-Joule-Thomson 1
Cryogenic-Joule-Thomson & Expander 10
No Response 8
TOTAL 772
Based on data presented in Oil and Gas Journal. July 14, 1980.
9-5
-------
Table 9-3. DISTRIBUTION OF GAS PLANTS BY OWNERSHIP3 (1980)
Company Owner Number of Plants
Amoco Production Company 47
Cities Service Company 41
Phillips Petroleum Company 37
Warren Petroleum Company 35
Exxon Company 33
Shell Oil Company 33
Sun Gas Company 33
Getty Oil Company 26
Mobil Oil Corporation 26
Texaco, Inc. 25
ARCO Oil and Gas Company 24
Chevron USA, Inc. 23
Union Oil Company of California 23
Mitchell Energy & Development Corporation 22
Number of companies that own between 10 and 20 plants 7
Number of companies that own less than 10 plants 117
Total number of companies that own gas plants 138
TOTAL 772
a Based on data presented in Oil and Gas Journal, July 14, 1980.
9-6
-------
Table 9-4 DISTRIBUTION OF GAS PLANTS BY STATE3 (1980)
State
Texas
Louisiana
Kansas
Oklahoma
New Mexico
Wyomi ng
California
Colorado
All other states
TOTAL
a Based on data presented
Number of plants
356
103
26
86
34
40
37
27
63
772
in Oil and Gas Journal, July 14,
Plant
capacity
(MMcfd)
24,646.9
24,566.7
5,320.9
4,267.7
3,632.1
1,357.7
1,254.5
799.6
5,346.5
71,192.6
1980.
9-7
-------
Table 9-5. PRODUCTION OF ENERGY BY TYPE, UNITED STATES (Quadrillion Btu)
00
1973
1974
1975
1976
1977
1978
1979
1980
Coal1
14.366
14.468
15.189
15.853
15.829
15.037
17.651
18.877
Crude
oil2
19.493
18.575
17.729
17.262
17.454
18.434
18.104
18.250
NGPL3
2.569
2.471
2.374
2.327
2.327
2.245
2.286
2.263
Natural
gas
(dry)
22.187
21.210
19.640
19.480
19.565
19.485
20.076
19.754
Hydro-
electric
power
2.861
3.177
3.155
2.976
2.333
2.958
2.954
2.913
Nuclear
electric
power
0.910
1.272
1.900
2.111
2.702
2.977
2.748
2.704
Other5
0.046
0.056
0.072
0.081
0.082
0.068
0.089
0.114
Total
energy
produced
62.433
61.229
60.059
60.091
60.293
61.204
63.907
64.876
% NG
of
total
40
39
37
36
36
.36
35
34
Totals may not equal sum of components due to independent rounding.
\ Includes bituminous coal, lignite and anthracite.
i Includes lease condensate.
. Natural gas plant liquids.
? Includes industrial and utility production of hydropower.
Includes geothermal power and electricity produced from wood and waste.
R = Revised data
Source: U.S. Department of Energy, Energy Information Administration calculations.
July 1981.
Monthly Energy Review,
-------
Table 9-6. AGGREGATE RETAIL PRICE ELASTICITIES OF DEMAND, U.S.
(Estimate for 1985)
With respect to
Sol id fuels
Natural gas
Electricity
Petroleum
Source: The Global
Solid
fuels
-.215
.005
.011
.002
2000 Report
Price
Natura
gas
.030
-.426
.052
.013
to the
elasticity of demand
1
Electricity
.131
.228
-.376
.077
President, (Volume III:
Petroleum
.031
.062
.111
-.263
Documentation), A report prepared by the Council on Environmental
Quality and the Department of State. April 1981. p. 301.
9-9
-------
respect to a change in the price of all four aggregate fuel types.
Therefore, the diagonal corresponding to direct price elasticity should
have a negative sign. For example, the domestic retail price elasticity
for natural gas is -.426, indicating an inelastic aggregate retail demand.
Electricity has the highest cross price elasticity with respect to natural
gas with a value of .228, indicating that a one percent increase in the
retail natural gas price causes a .228 percent increase in the aggregate
quantity demanded of electricity. All of the cross price elasticities are
positive, representing interfuel substitution.
9.1.2 Onshore Natural Gas Production Industry—Growth and Projections
This section discusses the historical production and price of natural
gas. Natural gas production is projected for the years 1985, 1990 and 2000
and distributed in the categories of onshore, offshore, discoveries from
existing fields and discoveries from new fields.
9.1.2.1 Historical Data. Marketed production of natural gas
increased from 5.42 trillion cubic feet in 1949 to a peak of 22.65 trillion
cubic feet in 1973. Increases in marketed production from 1949 through
1973 averaged 6.0 percent annually. In 1974 and 1975, marketed production
decreased 4.6 percent and 6.9 percent, respectively. After 1976, marketed
production declined slightly to 19.67 trillion cubic feet in 1979.
Total gross withdrawals of natural gas from both gas wells and oil
wells generally follow the same trend as marketed production. However, the
volume of natural gas withdrawn from oil wells has remained relatively
constant at about three to five trillion cubic feet per year from 1949 to
the present. Table 9-7 presents total natural gas production distributed
2
between onshore and offshore production for the years 1949 through 1979.
Onshore production declined from 99.1 percent of the total in 1954 to 72.4
percent of the total in 1979. The difference between gross withdrawals and
marketed production represents quantities from gas wells and oil wells that
3
were either vented, flared or used for reservoir repressuring. In 1980,
there were approximately 175,000 producing gas wells in the United States.
Although most natural gas is produced from natural gas wells, about 18
percent is produced from crude oil wells.
9-10
-------
Table 9-7. NATURAL GAS GROSS WITHDRAWALS AND MARKETED ONSHORE AND OFFSHORE PRODUCTION
Production in Trillion Cubic Feet
Year
1949
1950
1951
1952
1953
1954
1955
1956
1957
1958
1959
1960
1961
1962
1963
196'4
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
1977
1978
1979b
From
Gas Wells
4.99
5.60
6.48
6.84
7.10
7.47
7.84
8.31
8.72
9.15
10.10
10.85
11.20
11.70
12.61
13.11
13.52
13.89
15.35
16.54
17.49
18.59
18.93
19.04
19.37
18.67
17.38
17.19
17.42
17.39
17.17
From
Oil Wells
2.56
2.88
3.21
3.43
3.55
3.52
3.88
4.07
4.19
3.99
4.13
4.23
4.27
4.34
4.37
4.43
4.44
5.14
4.91
4.79
5.19
5.19
5.16
4.97
4.70
4.18
3.72
3.75
3.68
3.91
3.75
Gross
Withdrawals
7.55
8.48
9.69
10.27
10.65
10.98
11.72
12.37
12.91
13.15
14.23
15.09
15.46
16.04
16.97
17.54
17.96
19.03
20.25
21.33
22.68
23.79
24.09
24.02
24.07
22.85
21.10
20.94
21.10
21.31
20.92
Marketed3
Production
5.42
6.28
7.46
8.01
8.40
8.74
9.41
10.08
10.68
11.03
12.05
12.77
13.25
13.88
14.75
15.55
16.04
17.21
18.17
19.32
20.70
21.92
22.49
22.53
22.65
21.60
20.11
19.95
20.03
19.97
19.67
Onshore
Production
NA
NA
NA
NA
NA
8.66
9.28
9.94
10.51
10.77
11.70
12.33
12.77
13.24
13.99
14.70
15.10
15.84
16.33
17.00
17.86
18.70
18.74
18.77
18.67
17.37
15.85
15.65
15.49
14.87
14.25
Offshore
Production0
NA
NA
NA
NA
NA
0.08
0.13
0.14
0.17
0.26
0.35
0.44
0.48
0.64
0.76
0.85
0.94
1.37
1.84
2.32
2.84
3.22
3.75
3.76
3.98
4.23
4.26
4.30
4.54
5.10
5.42
Percentaoe
Onshore
NA
NA
NA
NA
NA
99.1
98.6
98.6
98.4
97.6
97.1
96.6
96.4
95.4
94.8
94.5
94.1
92.0
89.9
88.0
86.3
85.3
83.2
83.3
82.4
80.4
78.8
78.4
77.3
74,5
72.4
Offshore
NA
NA
NA
NA
NA
0.9
1.4
1.4
1.6
2.4
2.9
3.4
3.6
4.6
5.2
5.5
5.9
8.0
10.1
12.0
13.7
14.7
16.8
16.7
17.6
19.6
21.2
21.6
22.7
2s!s
27.6
MA - Not Available.
Marketed production is derived. It is gross withdrawals from producing reservoirs less gas used for reservoir
representing and quantities vented and flared.
Estimated, based on reported data through November.
Note: Sum of components may not equal total due to independent rounding. Beginning with 1965 data all volumes
are shown on a pressure base of 14.73 psia at 60°F. For prior years, the pressure base is 14.65 psia at
60 F.
Sources:
• 1949 through 1975, U.S. Department of the Interior, Bureau of Mines, Minerals Yearbook, "Natural Gas"
chapter.
• 1976 through 1978, U.S. Department of Energy, Energy Information Administration, Natural Gas Production
and Consumption, annual.
c Data from U.S. Department of the Interior, Geological Survey - Conservation Division, Outer Continental Shelf
Statistics.
9-11
-------
The nominal price of natural gas remained reasonably steady during the
period from 1955 through 1973. Since 1973, the year of the Arab Oil
Embargo, the price has consistently increased in real terms. Figure 9-1
shows selected natural gas prices for three categories for the period from
1955 through 1979. In 1979, the price of natural gas at the wellhead was
$1.13 per million Btu, $1.85 per million Btu at the city gate and $2.50 per
million Btu delivered to ultimate customer. This consistent increase in
the price coupled with the deregulation of the price of natural gas in
almost all categories before the end of 1985 will boost the revenues and
profitability margins for the industry. This will contribute to growth in
capital availability potentially to be used for more drilling, deeper
drilling and increased exploration and production of tight gas formations.
Since the Oil Embargo in 1973, the financial condition of the onshore
crude oil and natural gas production industry has been improving steadily
in both revenues and net profits. Composite financial data shown in Table
9-8 indicate increased revenues from $15,292 million in 1976 to $38,000
million in 1980. During the same period, net profits increased from $1,155
million to $1,925 million.
Composite net profit margins as a percent of sales however have
declined from 7.6 percent in 1976 to 5.1 percent in 1980. This fact
indicates that production costs have risen at a faster pace than prices.
Also, total capital has grown at a slower pace than revenues and profits.
Consequently, return on total assets and return on equity have improved.
According to Value Line Investment Survey, the composite industry will
continue to have a healthy financial future into the 1980's. It is
projected in 1983-85 that the industry will have a composite net profit
margin of 4.6 percent on annual revenues of approximately $70 billion in
current dollars. The long term debt ratio is projected to be 45.5 percent.
Total capital is projected to increase to $35,500 million in current
dollars or 51 percent of revenues in 1983-85.
9.1.2.2 Five-Year Projections. In this subsection, projections for
the number of new and modified and reconstructed gas processing facilities
in the years 1983 through 1987 are developed. The form of the growth in
terms of new facilities, modified facilities and reconstructed facilities
9-12
-------
UD
I
0
1955
1960
1965
1970
1975 78 79
Year
Figure 9-1. Selected natural gas prices - three categories for the period 1955-1979/
-------
Table 9-8. COMPOSITE FINANCIAL DATA FOR THE NATURAL GAS INDUSTRY 1976-1981 and
1983-1985 ESTIMATES (Current dollars)
Item
Revenues ($mill)
Net Profit ($mill)
Income Tax Rate
Net Profit Margin
Long-term Debt Ratio
Common Equity Ratio
Total Capital ($mill)
Net Plant ($mi11)
^ % Earned Total Capital
*• % Earned Net Worth
% Earned Comm. Equity
% Retained to Comm. Equity
% All Dividends to Net Profit
Average Annual P/E Ratio
Average Annual Dividend Yield
Fixed Charge Coverage
1976
15,292
1,155
44.4%
7.6%
54.3%
41.0%
19,538
18,356
8.0%
12.9%
13 . 5%
7.5%
48%
7.1
6.3%
278%
1977
19,430
1,356
43.1%
7.0%
50.8%
44.4%
20,207
19,865
8.8%
13.6%
14.2%
8.0%
47%
7.6
5.8%
281%
1978
22,463
1,399
43.9%
6.2%
48.5%
46.8%
20,611
21,423
8.9%
13.2%
13.7%
7.2%
50%
7.1
6.6%
284%
1979
30,357
1,702
43 . 2%
5.6%
48.0%
47.1%
22,236
23,453
9.8%
14.7%
15.4%
8.9%
45%
6.8
6.3%
287%
1980
38,000
1,925
44.0%
5.1%
48.5%
48.0%
23,750
26,000
10.5%
15.5%
16.0%
9.0%
45%
NA
NA
290%
1981
46,000
2,200
45.0%
4.8%
47.0%
50.0%
26,000
27,000
10.5%
15.5%
16.0%
9.0%
45%
NA
NA
295%
83-85E
70,000
3,200
47.0%
4.6%
45.5%
53.0%
35,500
33,000
11.5%
16.5%
17.0%
9.5%
45%
8.0
6.0%
310%
E = Estimates
NA = Not available
Source: A. Bernhard & Company. "Natural Gas Industry." Value Line Investment Survey, July 18, 1980.
-------
is discussed. The size distribution of new facilities is developed based
upon industry's historical trend. Information on the projection of natural
gas price is presented, and the effect of price deregulation on natural gas
production is discussed.
Production of natural gas by conventional techniques has exceeded the
rate of reserve additions in recent years. Consequently, conventional
reserves are expected to continue declining and production from
conventional reserves will decline as well. Annual production of
conventional natural gas is expected to decline roughly 1.5 to 2.0 trillion
cubic feet every five years through 1995. The production of associated and
dissolved gas is expected to decline less rapidly than the production of
nonassociated gas, due to higher price incentives for crude oil.
Table 9-9 presents the American Gas Association's (AGA) projected
Lower-48 states conventional natural gas production for the period from
1980 through 2000. 5 In 1985, the production is projected to be 19.7
trillion cubic feet, decreasing to 17.7 trillion cubic feet in 1990.
Natural gas produced through enhanced gas recovery (EGR) techniques is
expected to increase rapidly and provide a significant portion of the
production by 1995.
Production from new (past 1977) onshore discoveries according to AGA
is projected to total 3.6 trillion cubic feet in 1985 and to increase
consistently through 1990 when it will reach the maximum of 4.9 trillion
cubic feet. An increasing percentage of total onshore production is
c
projected to come from new discoveries. Table 9-9 includes projected
Lower-48 states onshore conventional natural gas production from new
5
discoveries for the period from 1980 through 2000. Figure 9-2 portrays
the onshore natural gas production from new discoveries through the year
2000.
Natural gas supply projections are conducted by various oil and gas
companies as well as government and independent study groups. Table 9-10
presents a comparison of 1990 projection forecasts presented by the
Department of Energy (DOE), the American Gas Association (AGA), Exxon,
Tenneco and other private study groups. AGA's forecast of 16.3
quadrillion Btu per year is 8.4 percent lower than DOE's forecast of 17.8
9-15
-------
Table 9-9. PROJECTED LOWER-48 STATES CONVENTIONAL
NATURAL GAS PRODUCTION
Gas Source
Production. Trillion Cubic Feet
1980
1985
1990
1995
2000
Onshore
Old Inter3
Old Intra3
Old Direct Sale
New
Offshore ,
Old Inter '
New Inter0
Total
Old Inter
Old Intra
Old Direct Sale
New
TOTALd
a Includes gas used
Twi^li!^!1! *•»*•» tr\ f^l.l ~t t4 s\ •
4.9
3.6
4.0
1.5
5.6
0.1
10.5
3.6
4.0
1.6
19.7
as compressor
i 4- ^ s\ m ^* -P v»^\rvi r\ \f*r
3.6
2.4
2.6
3.6
4.1
3.4
7.7
2.4
2.6
7.0
19.7
fuel
.. 1 n~l~
2.0
1.3
1.5
4.9
1.4
6.6
3.4
1.3
1.5
11.5
17.7
and net storage
7 1 f\ -\ ^* ^\ r*
1.1
0.7
0.8
4.8
0.7
6.5
1.5
0.7
0.8
11.3
14.6
injections.
0.7
0.4
0.5
3.8
nil
5.4
0.7
0.4
0.5
9.2
10.8
c Post-1976 leases only.
Totals may not add due to independent rounding.
Source: American Gas Association, Gas Supply and Statistics—Total Energy
Resource Analysis Model (TERA) 80-1, Appendix A.
9-16
-------
5.0 r
1980
2000
Figure 9-2. Projected new discovery onshore natural gas production.5
9-17
-------
Table 9-10. PROJECTIONS OF NATURAL GAS SUPPLY: COMPARISON OF 1990 FORECASTS6 (Quadrillion Btu)
co
Units
Domestic Production
Conventional
North Alaska
Synthetic Gas
Subtotal
Net Imports
Pipe! ine
Liquefied Natural Gas
Subtotal
Total Supply
1978
Actual
19.5
f
0.2
19.7
0.9
9
0.9
20.6
DOE/
EIAa
17.8
0.9
0.3
19.0
0
0.8
0.8
19.8
197
AGAb
15.3-17.3
1.6
1.1
19.9-21.9
2.1
2.0
4.2
24.1-26.1
9 Projections for 1990
DPPC
16.9
0.4
0.6
18.0
2.0
1.0
3.1
21.0
Paced
16.1
1.0
0.8
18.0
1.4
0.8
2.2
20.2
Exxon6
14.9
f
0.6-1.0
15.5-15.9
1.8
0.8
2.7
18.2-18.6
Tenneco
14.8
.0
1.5
17.3
2.0
3.1
5.1
22.4
a DOE/EIA 1979 Annual Report to Congress, middle range forecast.
b American Gas Association, The Future for Gas Energy in the United States, June 1979.
c Data Resources, Inc., Energy Review, Winter 1980.
d The Pace Company Consultants and Engineers, Inc., The Pace Energy and Petrochemical Outlook to 2000, October
1979.
e Exxon Company, U.S.A., Energy Outlook 1980-2101, December 1979.
f Tenneco Oil Company, Energy 1979-2000, June 1979.
9 Included in conventional production.
h Less than 0.5 quadrillion Btu.
Note: Non-EIA projections converted from trillion cubic feet with 1,020 Btu per cubic foot. Numbers may not
add to totals because of rounding.
-------
quadrillion Btu per year, and Exxon's forecast of 14.9 quadrillion Btu is
16.3 percent lower than DOE's forecast. AGA's projections were used for
the purposes of this study because their projections included estimates of
new production. The other forecasters did not.
The natural gas processing industry is projected to add new plants
needed to process new production. The number of new gas processing plants
that are projected to begin operating between 1983 and 1987 are presented
in Table 9-11. This table shows, for each year, the cumulative number of
new plants that are expected to be in operation as a result of "new"
natural gas production. For this analysis, "new" production is considered
to be gas produced onshore after January 1, 1983 from any well located
outside of a given radius and depth of a proven reserve and gas produced
offshore from any tract leased after January 1, 1983. The figures listed
under the "new production" column include the incremental new production
for that particular year plus the gas produced from the new wells of the
previous years, back to 1983. Therefore, the cumulative number of new gas
plants expected to be in operation each of the five years was determined by
dividing the projected annual new natural gas production by the average
capacity of existing cryogenic gas plants. It is assumed that all new gas
plants will employ the cryogenic process method.
In addition to new gas processing plants being constructed, it is
estimated that approximately eight existing gas plants will be modified or
reconstructed during each year during the period 1983-1987. This estimate
approximates the number of expansions reported each year by Oil and Gas
Journal's semi-annual report on plant expansions and equals one percent of
the total number of gas plants in the United States.
Natural gas prices are projected by the Department of Energy to
increase because of the Natural Gas Policy Act and phased deregulation of
prices during the period from 1983 through 1987. By 1985, almost all
categories of natural gas production will be deregulated. Very little new
gas will be subject to controls; most old intrastate gas will be
decontrolled and the quantity of old interstate gas that remains controlled
will decline rapidly over time. Because of this phased deregulation,
natural gas prices are projected to increase during the period from 1983
9-19
-------
Table 9-11. ESTIMATED NUMBER OF NEW GAS PLANTS, 1983-1987
New natural gas production3 Cumulative number.
Year (trillion cubic feet) of new gas plants
1983
1984
1985
1986
1987
1.32
2.62
3.89
4.99
6.07
40
80
120
150
180
a "New" production is considered to be gas which is (1) produced from a new
well beyond a specified distance from an old well; (2) produced from a
reservoir from which gas was not produced in commercial quantities prior
to January 1, 1983, or (3) produced from an offshore tract leased on or
after January 1, 1983. These new production figures were developed
based on American Gas Association's Total Energy Resource Analysis
(TERA) Model 80-1, November 21, 1980. The figures reflect an average
annual decline in production of 6.2 percent, and the source for this
decline rate is the National Petroleum Council's U.S. Energy Outlook -
Oil and Gas Availability, 1974.
It is assumed that all new gas plants will be cryogenic gas plants, with
an average capacity equivalent to the average capacity of existing
cryogenic plants (90 MMcfd). Therefore, the number of new gas plants
is developed by dividing the projected annual new production by the
average capacity of existing cryogenic gas plants.
9-20
-------
through 1987. In turn, deregulated prices are expected to boost
exploration and production activities. The history and projections for
natural gas prices are summarized in Table 9-12.
9.2 ECONOMIC IMPACT ANALYSIS
This section presents the expected economic impacts of alternative
emissions regulations limiting volatile organic compounds (VOC) emissions
from natural gas/gasoline processing plants.
9.2.1 Economic Impact Assessment Methodology
The methodology for economic impact assessment of VOC emissions
regulations on the onshore natural gas processing industry includes the
following steps:
Step 1 - Analyze the absolute magnitude of additional pollution control
costs in terms of before-tax annualized cost and after-tax
annualized costs.
Step 2 - Determine percentage product price increases required for
regulated plants to maintain constant profitability.
Step 3 - Analyze the regulated plants' ability to pass additional emissions
control costs forward to consumers or backward to suppliers.
Step 4 - Determine the financial viability of regulated plants.
Step 5 - Analyze expected impacts of emissions regulations on plant
closings, curtailment of expansion, industry output, industry
prices, employment, wages, productivity, plant location,
international trade, and possible balance of payments effects.
If it is determined in Step 1 and 2 that the emissions control costs are
small in absolute and relative terms, then expected economic impacts on
output, prices, employment, profitability, etc., will be small and further
expenditure of resources for detailed impact analyses justifiably can be
foregone. Such might be the case where annualized pollution control costs
are much less than EPA's trigger criteria for regulatory analysis, i.e.,
$100 million additional (before tax) annualized cost or a price increase of
5 percent required for industry members to maintain pre-control levels of
profitability.
9-21
-------
Table 9-12. NATURAL GAS PRICES: HISTORY AND PROJECTIONS FOR 1965-1995
(1979 Dollars per Thousand Cubic Feet)
History9 Projections
Price
Domestic Wellhead Prices
Old Interstate
New Interstate
Old Intrastate
New Intrastate
North Alaska
Average
Synthetic Gas Prices
High-Btu Coal Gas
Medium-Btu Coal Gas
Imported Gas Prices
Canadian Gas
Mexican Gas
Liquefied Natural Gas
Delivered Prices
Residential
Commercial
Raw Material
Large boilers
Industrial , Other
Refineries
Electric Utilities
Alternative Fuel Cost
a Source for historical data
Congress, 1979, and the fol
Production and Consumption,
1965 1973 1978 1985
NA NA 0.93 1.01
NA NA NA 4.48
NA NA NA 3.29
NA NA NA 4.72
— — — —
0.36 0.35 1.02 3.26
4.76
3.70
NA NA 2.41 6.21
NA NA NA 6.21
1.54 5.91
2.34 2.04 2.77 5.41
1.60 1.46 2.38 4.88
NA NA NA 4.28
NA NA NA 5.24
0.78 0.77 1.61 4.34
NA NA NA 4.55
0.89 0.63 1.72 4.74
6.23
1990
1.18
4.04
3.32
4.28
1.85
3.42
4.19
4.50
6.92
6.92
6.42
5.74
5.22
4.48
4.54
4.51
4.43
4.42
6.94
1995
1.39
4.59
3.78
4.82
1.85
4.17
4.71
5.44
8.51
8.51
7.70
6.45
5.93
5.21
5.26
5.22
5.13
—
8.29
is Volume 2 of the EIA Annual Report to
lowing EIA Energy Data Reports:
1978; United States Imports and
Natural
Exports
Gas
of
Natural Gas, 1978; and, Natural and Synthetic Gas, 1978.
c Major fuel-burning installations.
Notes: NA = Not available.
-- = Not applicable.
b Source: DQE/EIA Annual Report to Congress. 1980, Vol. 13, pg. 90.
9-22
-------
If it is determined in Steps 1 and 2 that the direct emissions control
costs are significant in either absolute or relative cost to the industry,
then the focus of the analysis turns toward analyzing the ability of
regulated plants to pass additional costs forward to consumers or backward
to suppliers. The analysis in Step 3 is explained in the context of the
industry's structure, conduct and performance as described in Section 9.1.
Specifically, the level of competition within the industry and the
elasticity of demand to the regulated plants is important as well as the
elasticity of aggregate product demand.
If it is determined that the industry is able to pass on all
additional costs, then Step 4 can be omitted since the financial viability
of regulated plants would not be jeopardized. Important impacts may occur
in supplier or consumer sectors and these should be analyzed if expected
price impacts are significant to these sectors. If, on the other hand, it
is determined in Step 3 that the industry is unable to pass on all
additional emissions control costs, then Step 4 is needed to determine the
economic viability of regulated and impacted plants.
If needed, a net present value approach is used in Step 4 to determine
the regulated plants' financial viability. Specifically, after-tax net
annualized cost of emissions control is estimated and used to calculate
required percentage price increases needed for regulated plants to maintain
baseline net present values for each regulatory alternative. If the
required price increase for some regulatory alternative exceeds the amount
which can be successfully passed on or absorbed by the plant then it is
determined that the plant is non-viable for that regulatory alternative.
Based on the findings in Steps 1 through 4 and the industry profile in
Section 9.1, additional analyses of expected economic impacts are
completed. Expected industry price and output impacts are estimated
simultaneously. Then related impacts on employment, productivity,
international trade, etc. are brought into focus in Step 5.
Before-tax annualized costs (BTAC) and after-tax annualized costs
(ATAC) of emissions controls are computed in Step 1 using the following
equations:
9-23
-------
BTAC = IQ CRF + 0&MQ (1)
ATAC = I CRF TAXF + (1-t) 0&MQ (2)
where,
I = initial base year investment
OM = annual O&M cost less applicable by-product credits
CRF = ^ ' , the capital recovery factor
(l+r)n-l
r = the real cost of capital
n = economic life of the asset, i.e. the capital recovery period
(variable by asset)
TAXF = 1-itc - t PVDEP
itc = investment tax credit rate
t = corporate income tax rate
PVDEP = present value of annual depreciation factors per $1
of investment, i.e.
Y DEP
PVDEP = E
y = 1 (l+d)y
Y = length of the depreciation period, 3, 5, 10 or 15 years
d = nominal discount rate, and
DEP = annual depreciation factors based on the most advantageous
depreciation methods for the firm, either (1) rapid amortiza-
tion of pollution control investments or (2) accelerated cost
recovery as allowed by the 1981 Economy Recovery Act.
9-24
-------
Required real price increases needed by model gas processing plants to
maintain baseline profitability (net present value) are computed according
to Equation 3.
Required real = ^r - ~ — « — r
price increase!/ Throughput (1-t)
Inflation and the weighted nominal cost of capital are projected to be
8 and 10 percent, respectively. This inflation rate is consistent with
recent estimates of large econometric models of the U.S. economy. 2/ Ten
percent nominal weighted natural gas industry cost of capital was estimated
using forecasted 1981-1985 composite natural gas industry stock price
earnings ratios of 7 to 8, a 45 percent debt ratio, 47 percent marginal
corporate income tax rates from Value Line Investment Survey, and 13
percent nominal pre-tax interest rate on new debt for domestic corporations
based on Value Line Investment Survey estimates for 1981-1985.
9 • 2 • 2 Economic Impact of VOC Regulatory Alternatives - Natural
Gas/Gasoline Processing Plants
Additional costs for natural gas processing plants to comply with VOC
regulatory alternatives are expected to be small in both absolute and
relative terms. Economic impacts on individual plants and the industry
will be slight. Total additional before-tax annualized costs of controls
in 1987, the fifth year of controls, are estimated to be as follows:
Total additional before-tax
Reyu i atory alternatives, VOC annualized cost, 1987
(thousand 1980 dollars)
I 0
II 220.5
III 652.9
IV 8,080.2
II The assumption ANPV = 0 requires that (1-t) AP Q - ATAC = 0;
therefore, AP = ATAC/(l-t)Q. P = the real price increase required to
amortize at the cost of capital the additional pollution control
investment and operating costs over constant throughput Q.
2J Data Resources, Inc. Trendlong 2005 Forecasts. September, 1980.
9-25
-------
These estimates are derived at the bottom of Table 9-13 which displays
aggregate or total before-tax annualized costs of regulatory alternatives
II, III, and IV by year. The projected number of new gas plants during the
period 1983-1987 is 180 mid-size plants. The total before-tax annualized
cost for these new plants in 1987, the fifth year of the regulation, is
$361,800 for regulatory alternative II, $585,000 for regulatory alternative
III and $5,482,800 for regulatory alternative IV.
The projected number of modified and reconstructed plants during the
period 1983-1987 is 10 small, 15 mid-size and 15 large plants. The total
before-tax annualized cost for these modified and reconstructed plants in
1987 is -$141,300 for regulatory alternative II, $67,900 for regulatory
alternative III and nearly $2.6 million for regulatory alternative IV. The
combined total of new and modified and reconstructed plants constructed
during the period 1983-1987 is 10 small plants, 195 mid-size plants, and 15
large plants. Total before-tax annualized costs for these plants in 1987
is estimated to be $220,500 for regulatory alternative II, $652,900 for
regulatory alternative III and nearly $8.1 million for regulatory
alternative IV.
Before-tax net annualized costs for individual model gas plants and
regulatory alternatives I through IV are shown in Table 9-14. The new
model plant, producing 90 million cubic feet per day, has before-tax
annualized costs for regulatory alternatives II, III, IV totalling $2,010,
$3,250 and $30,460 respectively. The smallest modified and reconstructed
model plant has before-tax net annualized costs of $3,060, $4,840 and
$17,280 for alternatives II, III and IV, respectively. For the modified
and reconstructed model plant B costs are $2,010, $3,250, and $40,080 while
model plant C has costs of -$13,470, -$1,950 and $121,550 for regulatory
alternatives II, III and IV, respectively. Negative before-tax net
annualized costs stem from situations where recovery credits outweigh the
annualized investment and operating costs for emissions control.
After-tax net annualized costs of regulatory alternatives are shown in
Table 9-15. For the new model plant, the after-tax net annualized cost for
alternatives II, III and IV are $2,390, $2,590 and $16,660, respectively.
9-26
-------
Table 9-13. ONSHORE NATURAL GAS PROCESSING, TOTAL AND CUMULATIVE BEFORE-TAX NET ANNUALIZED
COST OF VOC REGULATORY ALTERNATIVES 1983-1987
ro
Category
of Facility
New
Projected Cumulative
Number of Gas Plants a/
Year
1983
1984
1985
1986
1987
A
0
0
0
0
0
Modified/Reconstructed
Total New, Modified
1983
1984
1985
1986
1987
2
4
6
8
10
B
40
80
120
150
180
3
6
9
12
15
& Reconstructed
1983
1984
1985
1986
1987
2
4
6
8
10
43
86
129
162
195
C
0
0
0
0
0
3
6
9
12
15
3
6
9
12
15
II
80.4
160.8
241.2
301.5
361.8
-28.3
-56.5
-84.8
-113.0
-141.3
52.1
104.3
156.4
188.5
220.5
Regulatory Alternative
III
•Thousands of 1980
130.0
260.0
390.0
487.5
585.0
13.6
27.2
40.7
54.3
67.9
143.6
287.2
430.7
541.8
652.9
IV
Dollars
IO 1 O A
,218.4
2,436.8
3,655.2
4,569.0
5,482.8
r i c\ c
519.5
1,039.0
1,558.5
2,077.9
2,597.4
1,737.9
3,475.8
5,213.7
6,646.9
8,080.2
a/ Plants A, B and C ave. 10, 30 and 100 vessels, respectively.
-------
Table 9-14. ONSHORE NATURAL GAS PROCESSING MODEL PLANTS' BEFORE-TAX NET ANNUALIZED
COST OF VOC REGULATORY ALTERNATIVES PER PLANT
ro
oo
Model
plant
New
Modified and
Reconstructed
A
B
C
Size
No. vessels
30
10
30
100
MMcfd
90
30
90
250
I
Baseline
control
level
0
0
0
0
Regulatory
II
. _ _ _ —Thni i c A nrlc A^
2.01
3.06
2.01
-13.47
alternative
III
P IQfln Hnllar*;
3.25
4.84
3.25
-1.95
IV
30.46
17.28
40.08
121.55
-------
ID
I
ro
Table 9-15. ONSHORE NATURAL GAS PROCESSING MODEL PLANTS' AFTER-TAX NET ANNUALIZED
COST OF VOC REGULATORY ALTERNATIVES PER PLANT
Model Size
plant No. vessels
New 30
Modified and
Reconstructed
A 10
B 30
C 100
MMcfd
90
30
90
250
I
Baseline
control
level
0
0
0
0
Regulatory a
II
Thoiicanrlc nf
2.39
2.06
2.39
-2.86
Iternative
III
2.59
2.88
2.59
1.88
IV
16.66
9.32
21.68
65.82
-------
For modified and reconstructed model plant A, these costs are $2,060,
$2,880, and $9,320, respectively; $2,390, $2,590, and $21,680,
respectively, for model plant B; and -$2,860, $1,880 and $65,820 for model
plant C.
Required price increases for affected gas plants to maintain baseline
profitability (net present value) are very small as estimated below. For
purposes of this order of magnitude calculation, gas throughput was assumed
to be 30, 90, and 250 MMcfd for plants A, B, and C, respectively. Gas
throughput for new cryogenic plants was assumed to be 90 MMcfd as explained
in Table 9-11 footnote b.
Required price increases for VOC Regulatory Alternatives, 1980 $/Mcf
New Modified and Reconstructed
Regulatory Plant BPlant APlant BPlant C
alternative (90 MMcfd) (30 MMcfd) (90 MMcfd) (250 MMcfd)
II .00020 .00052 .00020 -.00009
HI .00022 .00072 .00022 .00006
IV .00140 .00234 .00182 .00199
Given the inelasticity of retail demand for natural gas and gas
liquids products, it is expected that gas processors will pass a large
portion, if not all, of the incremental emissions control costs forward to
pipelines, gas utilities and eventually to the ultimate consumers of
natural gas and natural gas liquids. The price impacts will be slight
relative to current product prices, less than 0.5 percent, regardless of
regulatory alternative. No plant closures or curtailments are expected due
to the VOC regulatory alternatives analyzed. Effects on industry
profitability, output, growth, employment, productivity, and international
trade will be negligible or zero due to the VOC regulatory alternatives
analyzed.
This concludes the analysis of direct economic impacts of VOC
regulatory alternatives on the Natural Gas Processing Industry. Control
costs for VOC regulatory alternatives and associated economic impacts are
" expected to be negligible for individual plants and particularly for the
composite natural gas processing industry.
9-30
-------
9.3 POTENTIAL SOCIOECONOMIC AND INFLATIONARY IMPACTS
This section discusses the potential social disruption and
inflationary impacts associated with the VOC regulatory alternatives.
Data presented in Section 9.2 above indicated that additional costs
for control of VOC emissions from natural gas processing plants are
expected to be small on an absolute and relative basis for all four
regulatory alternatives considered. No impact is expected on plant
location or structure of the natural gas processing industry. No job
losses are expected.
Additional costs for VOC emissions controls on new, remodeled and
reconstructed gas plants are not expected to have significant inflationary
impacts because the annualized control costs per unit of production are
small, i.e., less than 0.5 percent of sales for all model plants and
regulatory alternatives. It is expected, however, that gas processors will
succeed in passing a large share of the added costs forward into product
markets for natural gas liquids. The direct effect on price will be
negligible, especially when compared to total industry sales, including
existing (exempt) plants. No productivity, plant location, or balance of
payments effects are expected due to any of the VOC regulatory
alternatives.
9-31
-------
9.4 REFERENCES FOR CHAPTER 9
1. Oil & Gas Journal, January 28, 1980, p. 81. Docket Reference
Number A-80-20-B (VOC) II-I-39.*
2. U.S. Deparment of Energy, Energy Information Administration.
Annual Report to Congress-1979. Volume Two (of Three): Data,
Docket Reference Number A-80-20-B (VOC) II-I-36,* and, U.S.
Department of the Interior, U.S. Geological Survey-Conservation
Division, Outer Continental Shelf Statistics, June 1980. Docket
Reference Number A-80-20-B (VOC) II-I-40.*
3. U.S. Department of Energy, Energy Information Administration.
Annual Report to Congress-1979. Volume Two (of Three): Data.
Docket Reference Number A-80-20-B (VOC) II-I-36.*
4. American Gas Association, Department of Statistics, Gas Facts - 1979
Data. Docket Reference Number A-80-20-B (VOC) II-I-38.*
5. American Gas Association, Gas Supply and Statistics - Total
Energy Resource Analysis Model (TERA) 80-1, Appendix A, Figure A-2,
p. 21. Docket Reference Number A-80-20-B (VOC) II-I-41.*
6. U.S. Department of Energy, Energy Information Administration.
Annual Report to Congress-1979. Volume Three (of Three): Projects.
Docket Reference Number A-80-20-B (VOC) II-I-37.*
7. U.S. Department of Energy, Energy Information Administration.
Annual Report to Congress-1979. Volume Three (of Three): Projections,
Docket Reference Number A-80-20-B (VOC) II-I-37.*
*References can be located in Docket Number A-80-20-B at U.S. Environmental
Protection Agency Library, Waterside Mall, Washington, D.C.
9-32
-------
APPENDIX A - EVOLUTION OF THE BACKGROUND INFORMATION DOCUMENT
-------
APPENDIX A - Evolution of the
Background Information Document
Date
November 30, 1979
December 7, 1979
December 18, 1979
December 19, 1979
January 1980
March 19, 1980
July 14, 1980
July 16, 1980
July 18, 1980
Nature of Action
Meeting to discuss onshore
production and to solicit the
aid of API in gathering field
data.
Introductory meeting with
API.
Visit to Exxon Company,
U.S.A., Blackjack Creek facility,
Jay Field, Florida to gain
familiarity with process
equipment and operating conditions.
Visit to Phillips Petroleum,
Chatham facility, Chatham,
Mississippi, to gain familarity
with process equipment and
operating conditions.
Plant visits to various tank
battery sites in the West
Texas oil and gas field to
gain knowledge of processing
equipment.
Source Category Survey
Report.
Visit to Exxon Company tank
battery in Kingsville, Texas,
to gain familarity with gas
and oil production processes
and facilities.
Visit to Phillips Petroleum
Company, Roosevelt County, New
Mexico, to acquire familiarity
with gas and oil product in
processes and facilities.
Visit to Shell Oil Company
Stateline Production Unit in
Sidney, Montana, to acquire
familiarity with gas and oil
production.
A-2
-------
July 21 & 22, 1980
Meeting with API concerning
NSPS development for the
onshore production industry.
July 24, 1980
October 6-9, 1980
October 14-16, 1980
February 9-27, 1981
March 2-13, 1981
March 1981
April 29 & 30, 1981
April 1981
May 1, 1981
Visit to Phillips Petroleum
Company, Canadian County,
Oklahoma, to gain information
on gas processing facilities.
Emission source testing at
Houston Oil and Minerals,
Smith Point gas plant, Chambers
County, Texas.
Emission source testing at
Amoco Production Company,
Hastings gas plant, Brazoria
County, Texas.
Emission source testing
at Texas, Inc., Paradis gas
plant, Paradis, Louisiana.
at
Emission source testing <
Gulf Oil Company, Venice
Plant, Venice, Louisiana.
Preliminary draft CTG document,
Control of Volatile Organic
Compound Equipment leaks from
National gas/gasoline processing
plants.
Meeting of the National Air
Pollution Control Techniques
Advisory Committee to review
the gas/gasoline processing
plants standard.
Model plant package mailed
to industry representatives
for comment.
Meeting with API concerning
Model plants.
A-3
-------
September 1981
December 1981
January 28, 1982
July 21, 1982
August 18, 1982
November 11, 1982
November 12, 1982
January 25, 1983
Drafts of Chapters 3 through 6
sent out for industry review
and comments.
Draft CTG Document, Control of
Volatile Organic Compound
Equipment Leaks from Natural
Gas/Gasoline Processing Plants.
Meeting with API concerning
fugitive VOC emission factor
development for gas plants.
NAPCTAC Meeting
Meeting with industry representatives
to discuss comments on the
draft NSPS for natural gas
processing plants.
Visits to Phillips Petroleum
Co., Alvin, Texas, plant and
Amoco Production Co., Old
Ocean, Texas, Plant.
Visits to Texaco U.S.A.;
Blessing, Texas, Plant and
Seagull Products Co., Pelacious
Texas, Plant.
Meeting with Union Texas
Petroleum Co. to discuss
comments on the draft NSPS
for natural gas processing
plants.
A-4
-------
APPENDIX B ~ INDEX TO ENVIRONMENTAL IMPACT CONSIDERATIONS
-------
Table B-l. INDEX TO ENVIRONMENTAL IMPACT CONSIDERATIONS
Agency Guidelines for Preparing
Regulatory Action Environmental
Impact Statements (39 FR 37419)
Location Within the Background Information Document (BID)
oo
PO
1. Background, description, and
purpose of the regulatory
alternatives and the statutory
authority.
The relationship to other
actions and proposals signi-
ficantly affected by the regu-
latory alternatives.
Industry affected by the
regulatory alternatives.
Specific sources affected
by the regulatory alternatives.
Applicable control techniques.
2. Alternatives to the action.
The regulatory alternatives from which standards will be chosen
are summarized in Chapter 1, Section 1.1, as is the statutory
authority for proposing standards.
To the extent possible, other regulations that apply to the
affected industries are detailed in Chapter 8, Section 8.2
and are considered in the economic impact study in Chapter 9.
The industry and emission sources within the Indus-try affected
by the regulatory alternatives are listed in Chapter 3.
The specific sources affected by the regulatory
alternatives are summarized in Chapter 3, Section 3.2.
A discussion of available emission control techniques
is presented in Chapter 4, Sections 4.2 and 4.3.
The various categories of alternatives to the actions which
were considered are listed below.
a. Alternative regulatory approaches. The alternative
approaches for regulating VOC emissions under Section 111 of
the Clean Air Act are outlined in Chapter 6.
b. Alternative control techniques. The alternative control
techniques that could be utilized by the regulatory
alternatives are outlined In Chapter 4.
(continued)
-------
Table B-l. CONTINUED
Agency Guidelines for Preparing
Regulatory Action Environmental
Impact Statements (39 FR 37419)
Location Within the Background Infonnation Document (BID)
oo
Agency's comparative evaluation
of the beneficial and adverse
environmental, health, social,
and economic effects of each
reasonable alternative.
3. Environmental impact of the
regulatory alternatives.
a. Primary impact.
Primary impacts are those that
can be attributed directly to
the action, such as reduced
levels of specific pollutants
brought about by a new standard
and the physical changes that
occur in the various media with
this reduction.
a. A discussion of the Agency's comparative evaluation of the
various alternative regulatory approaches for VOC emissions
from onshore natural gas production facilities can be
found in Chapter 6, Section 6.3.
b. A summary of the beneficial and adverse environmental
effects of the regulatory alternatives can be found in
Chapter 7. A detailed description of the economic impacts
of each alternative control level, including the capital
and annual costs to the industry, can be found in
Chapter 8. The socioeconomic impacts of the regulatory
alternatives can be found in Chapter 9.
The primary air impacts of the alternative control
levels are quantified in Chapter 7, Section 7.2.
(continued)
-------
Table B-l. CONCLUDED
Agency Guidelines for Preparing
Regulatory Action Environmental
Impact Statements (39 FR 37419)
Location Within the Background Information Document (BID)
co
b. Secondary impact.
Secondary Impacts are indirect
or induced impacts. For example,
mandatory reduction of specific
pollutants brought about by a
new standard could resalt in the
adoption of control technology
that exacerbates another pollution
problem and would be a secondary
impact.
4. Other considerations.
a. Adverse impacts which cannot
be avoided should a regulatory
alternative be implemented.
b. Irreversible and irretrievable
commitments of resources that
would be involved with the
regulatory alternatives, should
one be implemented.
Other environmental impacts (i.e., solid waste, water
quality) of the individual controls that can be used to
meet the regulatory alternatives are identified
qualitatively in Chapter 7, Sections 7.3, and 7.4.
The energy impacts of the alternative control levels are
quantified in Chapter 7, Section 7.5.
A summary of the potential adverse environmental impacts
of the regulatory alternatives and a discussion of the
significance of each impact can be found in Chapter 7.
A discussion of irreversible and irretrievable
committment of resources is in Section 7.6.1.
-------
APPENDIX C. EMISSION SOURCE TEST DATA
-------
APPENDIX C. EMISSION SOURCE TEST DATA
Fugitive emission test data have been collected at six natural
gas/gasoline processing plants (see Table C-l) by EPA and industry. Two
gas plants were tested under contract to the American Petroleum
Institute (API), and four gas plants were tested under contract to EPA.
All six gas plants were screened for fugitive emissions using either
portable hydrocarbon detection instruments, soap solution, or both.
Instrument screening (using EPA's proposed Method 21, described in
Appendix D) was performed at all four of the EPA-tested plants (Plants 3,
4, 5, and 6). The instruments were calibrated with methane. Soap
screening (using the method described in Reference 1) was performed at
the two API-tested plants and at three of the EPA-tested plants. Selected
components were measured for mass emissions at both of the API-tested
plants (Plants 1 and 2) and at two of the EPA-tested plants (Plants 5
and 6). These mass emission measurements were used in development of
emission factors for gas plant fugitives, which are presented in Table 3-1.
A study of maintenance effectiveness at production field tank batteries
was also performed by API. These data are discussed in Section C.2.
C.I PLANT DESCRIPTION AND TEST RESULTS
One API-tested gas plant was of the refrigerated absorption type,
and the other was a cryogenic plant. Descriptions and schematics of the
plants are provided in Reference 1. Of the four EPA-tested plants, the
first tested was a solid bed adsorption type (Reference 2). Natural gas
liquids are removed by adsorption onto silica gel, then stripped from
the bed with hot regeneration gas and condensed out for sales. There
were three adsorption units, of which only one was operating. This unit
had a capacity of 60 MMSCFD (million standard cubic feet per day), and
was operating between 33 and 55 MMSCFD during the testing period. The
second unit was shut down and depressurized, and therefore not tested.
C-2
-------
Table C-l. GAS PLANTS TESTED FOR FUGITIVE EMISSIONS3
Plant
No.
Data
collection
sponsor
Plant process
type
Principal screening
method(s) used
1
2
3
4
5
6
API
API
EPA
EPA
EPA
EPA
Refrigerated Absorption
Cryogenic
Adsorption
Cryogenic
Refrigerated Absorption
Refrigerated Absorption
Soaping
Soaping
Instrument, Soaping
Instrument, Soaping
Instrument, Soaping
Instrument
Reference 6.
Less than 50 components were soap screened at plant No. 6.
C-3
-------
The third unit was also not operating, but it was under natural gas
pressure and was tested.
The second EPA-tested plant was of the cryogenic type (Reference 3).
Feed gas to the plant is compressed and then chilled. Natural gas
liquids are condensed out and split into two streams: ethane/propane
and butane-plus. The cryogenic plant was operating at its rated capacity
of 30 MMSCFD.
The third EPA-tested plant was of the refrigerated absorption type
(Reference 4). There were three absorption systems for removal of
natural gas liquids. The liquids were combined and sent to a single
fractionation train. The fractionation train separated the liquids into
ethane, propane, iso-butane, butane, and debutanized natural gasoline.
Testing was performed on the fractionation train and on the largest
absorption system. The absorption system that was tested was operating
at 450 MMSCFD, near its capacity of 500 MMSCFD.
The fourth EPA-tested plant was also of the refrigerated absorption
type (Reference 5). There were two parallel absorption trains, and one
fractionation train. Natural gas liquids were fractionated into ethane/propane,
propane, iso-butane, butane, and debutanized natural gasoline streams.
The plant was operating at approximately 450 MMSCFD, about half of its
rated capacity of 800 MMSCFD.
A summary of the instrument screening data collected at the four
EPA-tested plants is presented in Table C-2. A summary of the soap
screening data collected at the two API-tested plants and at all of the
EPA-tested plants is presented in Table C-3. (Only a very small amount
of soap screening data were collected at Plant 6). The instrument
screening data are tabulated for each plant, showing the number of each
type of component tested and the percent emitting. The soap screening
data are not tabulated for each plant but are instead summarized by soap
score. A complete tabulation of the soap screening data by plant and by
soap score is provided in Reference 6.
C.2 INDUSTRY VALVE MAINTENANCE STUDY
The API study that developed the gas plant data presented in Section C.I
also included a study of maintenance. Gate valves in gas and condensate
service in oil and gas production field tank batteries were studied.
C-4
-------
The sources were monitored with soap scoring at intervals over a 9-month
period. Maintenance was performed on a portion of the valves studied.
The results of an analysis of this data show that monthly leak occurrence
was 1.3 percent, monthly leak recurrence was 1.6 percent, and leak
repair effectiveness was 100 percent. These results compare favorably
with the 1.3 percent monthly leak occurrence and recurrence and 90 percent
repair effectiveness used to analyze leak detection and repair control
effectiveness in Chapter 4 and 7. The industry study results were not
specifically used here, however, because (1) the data were gathered in
tank batteries which, based on API data, appear to have different leak
characteristics, (2) very few valves were studied (25 total data points),
and (3) a soapscore value of 3 was used to define a leak rather than a
meter reading of 10,000 ppm.
C-5
-------
Table C-2. INSTRUMENT SCREENING DATA FOR ERA-TESTED GAS PLANTS*
—
Valves
Plant No.
N» Tested
J 331
4 506
? !> 1.804
i> 1.038
Total 3.679
Percent
> 10. 000 ppmv
23.6
16.8
12.1
21.5
16.4
Relief valves
No.
Tested
10
7
60
3
80
Percent
> 10, 000 ppmv
90.0
14.3
5.0
33.3
17.5
Open-ended lines
No.
Tested
45
65
472
139
721
Percent
> 10, 000 ppmv
15.6
18.5
11.7
8.6
11.9
Compressor seals
No.
Tested
0
4
30
2
36
Percent
> 10. 000 ppmv
0.0
100
46.7
50.0
52.8
Pump seals
No.
Tested
1
9
51
40
101
Percent
> 10. 000 ppmv
0.0
44.4
33.3
22.5
29.7
Flanges and
connections
No.
Tested
223
281
768
506
1.778
Percent
> 10, 000 ppmv
5.4
2.1
3.6
2.0
3,1
Reference 6.
-------
Table C-3. SOAP SCREENING DATA FOR API-TESTED AND ERA-TESTED GAS PLANTS*
o
I
Valves
<;«ap
Score
0
1
2
3
4
Totat
Number
4,483
322
468
426
274
5.973
X of
Tola)
75.1
5.4
7.8
7.1
4.6
Relief
Number
123
4
2
2
3
134
valves
% of
lota)
91.8
3.0
1.5
1.5
2.2
Open-ended lines
Number
945
63
B3
59
43
1,193
% of
Total
79.2
5.3
7.0
4.9
3.6
Compressor seals
Number
8
1
2
7
10
28
X of
lota)
28.6
3.6
7.1
2b.O
35.7
Pump
Number
14
0
1
0
3
18
seals
% of
Total
77.8
0.0
5.6
0.0
16.7
Flanges and
connections
Number
17,982
706
454
190
65
19,397
X of
Total
92.7
3.6
2.3
1.0
0.3
Includes data from two API-tested plants and four tPA-tested plants. Reference 6
-------
C.3 REFERENCES FOR APPENDIX C
1. Eaton, W. S., et al., Fugitive Hydrocarbon Emissions from Petroleum
Production Operations. API Publication No. 4322. March 1980.
Docket Reference Number II-I-20, II-I-21.*
2. Harris, G. E. Fugitive VOC Testing at Houston Oil and Minerals
Smith Point Plant. U.S. EPA, ESED/EMB Report No. 80-OSP-l.
October 1981. Docket Reference Number II-A-13.*
3. Harris, G. E. Fugitive VOC Testing at the Amoco Hastings Gas
Plant. U.S. EPA, ESED/EMB Report No. 80-OSP-2. July 1981. Docket
Reference Number II-A-12.*
4. Harris, G. E. Fugitive VOC Testing at the Texaco Paradis Gas
Plant, Volume I and II. U.S. EPA, ESED/EMB Report No. 81-OSP-7.
July 1981. Docket Reference Numbers II-A-17, II-A-18.*
5. Harris, G. E. Fugitive Test Report at the Gulf Venice Gas Plant,
Volume I and II. U.S. EPA, ESED/EMB Report No. 80-OSP-8.
September 1981. Docket Reference Number II-A-14, II-A-15.*
6. DuBose, D. A., J. I. Steinmetz, and G. E. Harris. Emission Factors
and Leak Frequencies for Fittings in Gas Plant. Final Report.
U.S. EPA, ESED/EMB Report No. 80-FOL-l. July 1982. Docket Reference
Number II-A-19.*
7. Memorandum, Hustvedt, K.C., EPA to Durham, J.F.., EPA "API/Rockwell
Maintenance Data". December 9, 1982. Docket Reference Number II-B-22.*
*References can be located in Docket Number A-80-20-B at the U.S.
Environmental Protection Agency Library, Waterside Mall, Washington,
D.C.
C-8
-------
APPENDIX D
EMISSION MEASUREMENT AND
CONTINUOUS MONITORING
-------
APPENDIX D. EMISSION MEASUREMENT AND CONTINUOUS MONITORING
D.I EMISSION MEASUREMENT METHODS
D.I.I General Background
A test method was not available when EPA began the development of
control technique guidelines, new source performance standards, and
hazardous pollutant standards for fugitive volatile organic compounds
from industrial categories such as petroleum refineries, synthetic
organic chemical manufacturing, and other types of processes that
handle organic materials.
During development and selection of a test method, EPA reviewed
the available methods for measurement of fugitive leaks with emphasis
on procedures that would provide data on emission rates from each
source. To measure emission rates, each individual piece of equipment
must be enclosed in a temporary cover for emission containment. After
containment, the leak rate can be determined using concentration
change and flow measurements. This procedure has been used in several
studies1'2 and has been demonstrated to be a feasible method for
research purposes. It was not selected for this study because direct
measurement of emission rates from leaks is a time consuming and
expensive procedure, and is not feasible or practical for routine
testing.
Procedures that yield qualitative or semiquantitative indications
of leak rates were then reviewed. There are essentially two alternatives
leak detection by spraying each component leak source with a soap
solution and observing whether or not bubbles were formed; and, the
use of a portable analyzer to survey for the presence of increased
organic compound concentration in the vicinity of a leak source.
Visual, audible, or olefactory inspections are too subjective to be
used as indicators of leakage in these applications. The use of a
portable analyzer was selected as a basis for the method because it
D-2
-------
would have been difficult to establish an enforceable leak definition
based on a subjectve parameter such as bubble formation rates. Also,
the temperature of the component, physical configuration, and relative
movement of parts often interfere with bubble formation.
Once the basic detection principal was selected, it was then
necessary to define the procedures for use of the portable analyzer.
Prior to performance of the first field test, a procedure was reported
q
that conducted surveys at a distance of 5 cm from the components.
This information was used to formulate the test plant for initial
4
testing. In addition, measurements were made at distances of 25 cm
and 40 cm on three perpendicular lines around individual sources. Of
the three distances, the most repeatable indicator of the presence of
a leak was a measurement of 5 cm, with a leak definition concentration
of 100 or 1,000 ppmv. The localized meteorological conditions affected
dispersion significantly at greater distances. Also, it was more
difficult to define a leak at greater distances because of the small
changes from ambient concentrations observed. Surveys were conducted
at 5 cm from the source during the next three facility tests.
The procedure was distributed for comment in a draft control
c
techniques guideline document. Many commenters felt that a measurement
distance of 5 cm could not be accurately repeated during screening
tests. Since the concentration profile is rapidly changing between 0
and 10 cm from the source, a small variance from 5 cm could significantly
affect the concentration measurement. In response to these comments,
the procedures were changed so that measurements were made at the
surface of the interface, or essentially 0 cm. This change required
that the leak definition be increased. Additional testing at two
refineries and three chemical plants was performed by measuring volatile
organic concentrations at the interface surface.
A complication that this change introduces is that a small mass
emission rate leak ("pin-hole leak") can be totally captured by the
instrument and a high concentration result will be obtained. This has
occurred occasionally in EPA tests, and a solution to this problem has
not been found.
D-3
-------
The calibration basis for the analyzer was evaluated. It was
recognized that there are a number of potential vapor stream components
and compositions that can be expected. Since all analyzer types do
not respond equally to different compounds, it was necessary to establish
a reference calibration material. Based on the expected compounds and
the limited information available on instrument response factors,
hexane was chosen as the reference calibration gas for EPA test programs.
At the 5 cm measurement distance, calibrations were conducted at
approximately 100 or 1,000 ppmv levels. After the measurement distance
was changed, calibrations at 10,000 ppmv levels were required. Commenters
pointed out that hexane standards at this concentration were not
readily available commercially. Consequently, modifications were
incorporated to allow alternate standard preparation procedures or
alternate calibration gases in the test method recommended in the
Control Techniques Guideline Document for Petroleum Refinery Fugitive
Emissions.
Since that time, studies have been completed that measured the
ft 7 fi
response factors for several instrument types. ' * The results of
these studies show that the response factors for methane and hexane
are similar enough for the purposes of this method to be used inter-
changeably. Therefore, in later NSPS, the calibration materials were
hexane or methane.
The alternative of specifying a different calibration material
for each type stream and normalization factors for each instrument
type was not intensively investigated. There are at least four
instrument types available that might be used in this procedure, and
there are a large number of potential stream compositions possible.
The amount of prior knowledge necessary to develop and subsequently
use such factors would make the interpretation of results prohibitively
complicated. Additionally, based on EPA test results, the measured
frequency of leak occurrence in a process unit was not significantly
different when the leak definition was based on meter reading using a
reference material and when response factors were used to correct
meter readings to actual concentrations for comparison to the leak
definition.
D-4
-------
An alternative approach to leak detection was evaluated by EPA
9 10
during field testing. The approach used was an area survey, or
walkthrough, using a portable analyzer. The unit area was surveyed by
walking through the unit, positioning the instrument probe within
1 meter of all valves and pumps. The concentration readings were
recorded on a portable strip chart recorder. After completion of the
walkthrough, the local wind conditions were used with the chart data
to locate the approximate source of any increased ambient concentrations.
This procedure was found to yield mixed results. In some cases, the
majority of leaks located by individual component testing could be
located by walkthrough surveys. In other tests, prevailing dispersion
conditions and local elevated ambient concentrations complicated or
prevented the interpretation of the results. Additionally, it was not
possible to develop a general criteria specifying how much of an
ambient increase at a distance of 1 meter is indicative of a 10,000 pptn
concentration at the leak source. Because of the potential variability
in results from site to site, routine walkthrough surveys were not
selected as a reference or alternate test procedure.
D.I.2 Emission Testing Experience
During the data collection phase of this project, tests were
conducted at four natural gas liquids facilities. Each unit was
surveyed using Method 21 and, for portions of two plants, comparative
screening using a soap scoring technique was performed. The purpose
of this comparison was to determine if leak detection by the two
methods could be incorporated into one data set for emission factor
calculation. The result of this comparison was a general correlation
between soap scoring and Method 21 and the combination of the two data
sets for emission factor development. Because soap scoring could
not be used in all cases and because soap scoring requires subjective
observations while an objective concentration measurement procedure is
available, this alternate procedure was not included as a part of the
reference test procedure. However, soaping is being allowed as a
preliminary screening technique. For sources where soaping is possible,
D-5
-------
soap would be applied to the potential leak surfaces and if no bubbles
are observed, the source is presumed not to be leaking.
In addition, source enclosure with measurement was performed at
two plants to develop additional emission rate data. The test procedures
and results are described in Reference 11.
The calibration species used in this study was methane. Flame
ionization type analyzers were used for screening. The analyzers were
tested and could achieve the performance requirements of Method 21.
D.2 CONTINUOUS MONITORING SYSTEMS AND DEVICES
Since the leak determination procedure is not a direct emission
measurement technique, there are no continuous monitoring approaches
that are directly applicable. Continual surveillance is achieved by
repeated monitoring or screening of affected potential leak sources.
A continuous monitoring system or device could serve as an indicator
that a leak has developed between inspection intervals. The EPA
performed a limited evaluation of fixed-point monitoring systems for
Q 1O 1O
their effectiveness in leak detection. ' ' The systems consisted
of both remote sensing devices with a central readout and a central
analyzer system (gas chromatograph) with remotely collected samples.
The results of these tests indicated that fixed point systems were not
capable of sensing all leaks that were found by individual component
testing. This is to be expected since these systems are significantly
affected by local dispersion conditions and would require either many
individual point locations, or very low detection sensitivities in
order to achieve similar results to those obtained using an individual
component survey.
It is recommended that fixed-point monitoring systems not be
required since general specifications cannot be formulated to assure
equivalent results, and each installation would have to be evaluated
individually.
D.3 PERFORMANCE TEST METHOD
The recommended fugitive emission detection procedure is Reference
Method 21. This method incorporates the use of a portable analyzer to
detect the presence of volatile organic vapors at the surface of the
interface where direct leakage to atmosphere could occur. The approach
of this technique assumes that if an organic leak exists, there will
D-6
-------
be an increased vapor concentration in the vicinity of the leak, and
that the measured concentration is generally proportional to the mass
emission rate of the organic compound.
An additional procedure provided in Reference Method 21 is for
the detennination of "no detectable emissions." The portable VOC
analyzer is used to determine the local ambient VOC concentration in
the vicinity of the source to be evaluated, and then a measurement is
made at the surface of the potential leak interface. If a concentration
change of less than 5 percent of the leak definition is observed, then
a "no detectable emissions" condition exists. The definition of
5 percent of the leak definition was selected based on the readability
of a meter scale graduated in 2 percent increments from 0 to 100 percent
of scale, and not necessarily on the performance of emission sources.
Reference Method 21 does not include a specification of the
instrument calibration basis or a definition of a leak in terms of
concentration. Based on the results of EPA field tests and laboratory
studies, methane or hexane is recommended as the reference calibration
basis for fugitive emission sources in the natural gas and crude oil
production industries.
There are at least four types of detection principles currently
available in commercial portable instruments. These are flame ionization,
catalytic oxidation, infrared absorption (NDIR), and photoionization.
Two types (flame ionization and catalytic oxidation) are know to be
available in factory mutual certified versions for use in hazardous
atmospheres.
The recommended test procedure includes a set of design and
operating specifications and evaluation procedures by which an analyzer's
performance can be evaluated. These parameters were selected based on
the allowable tolerances for data collection, and not on EPA evaluations
of the performance of individual instruments. Based on manufacturers'
literature specifications and reported test results, commercially
available analyzers can meet these requirements.
The estimated purchase cost for an analyzer ranges from about
$1,000 to $5,000 depending on the type and optional equipment. The
cost of an annual monitoring program per unit, including semiannual
instrument tests and reporting is estimated to be from $3,000 to
D-7
-------
$4,500. This estimate is based on EPA contractor costs experienced
during previous test programs. Performance of monitoring by plant
personnel may result in lower costs. The above estimates do not
include any costs associated with leak repair after detection.
An alternative preliminary screening procedure has been added for
those sources that can be tested with a soap solution. These sources
are restricted to those with nonmoving seals, moderate surface temperatures,
without large openings to atmosphere, and without evidence of liquid
leakage. The soap solution is sprayed on all applicable sources and
the potential leak sites are observed to determine if bubbles are
formed. If no bubbles are formed, then no detectable emissions or
leaks exist. If any bubbles are formed, then the instrument measurement
techniques must be used to determine if a leak exists, or if no detectable
emissions exist, as applicable.
The alternative soap solution procedure does not apply to pump
seals, sources with surface temperatures greater than the boiling
point or less than the freezing point of the soap solution, sources
such as open-ended lines or valves, pressure relief valve horns, vents
with large openings to atmosphere, and any source where liquid leakage
is present. The instrument technique in the method must be used for
these sources.
The alternative of establishing a soap scoring leak definition
equivalent to a concentration based leak definition is not included in
the method and is not recommended for inclusion in an applicable
regulation because of the difficulty of calibrating and normalizing a
scoring technique based on bubble formation rates. A scoring technique
would be based on estimated ranges of volumetric leak rates. These
estimates depend on the bubble size and formation rates. A scoring
technique would be based on estimated ranges of volumetric leak rates.
These estimates depend on the bubble size and formation rate, which
are subjective judgments of an observer. These subjective judgments
could only be calibrated or normalized by requiring that the observers
correctly identify and score a standard series of test bubbles. It
has been reported that trained observers can correctly and repeatably
classify ranges of volumetric leak rates. However, because soap
scoring requires subjective observations and since an objective
D-8
-------
concentration measurement procedure is available, a soap scoring
equivalent leak definition is not recommended for the applicable
regulation. The alternate procedure that has been included will allow
more rapid identification of potential leaks for more rigorous instrumental
concentration measurement.
D-9
-------
D.4 REFERENCES
1. Joint District, Federal, and State Project for the Evaluation of
Refinery Emissions. Los Angeles County Air Pollution Control
District, Report Six of Nine Reports. 1957-1958.. April 1958.
Docket Reference Number A-80-20-B (VOC) II-I-l.*
2. Wetherold, R. and L. Provost. Emission Factors and Frequency of
Leak Occurrence for Fittings in Refinery Process Units. Radian
Corporation, Austin, TX. For U.S. Environmental Protection
Agency, Research Triangle Park, NC. Report Number EPA-600/2-79-044.
February 1979. Docket Reference Number A-80-20-B (VOC) II-A-27.*
3. Telecon. Harrison, P., Meteorology Research, Inc., with Hustvedt,
K.C., EPA, CPB. December 22, 1977. Docket Reference Number A-80-20-B
(VOC) II-E-17.*
4. Miscellaneous Refinery Equipment VOC Sources at ARCO, Watson
Refinery, and Newhall Refining Company. U.S. Environmental
Protection Agency, Emission Standards and Engineering Division,
Research Triangle Park, NC. EMB Report Number 77-CAT-6. December
1979. Docket Reference Number A-80-20-B (VOC) II-A-28.*
5. Hustvedt, K.C., R.A. Quaney, and W.E. Kelly. Control of Volatile
Organic Compound Leaks from Petroleum Refinery Equipment. U.S.
Environmental Protection Agency, Research Triangle Park, NC.
OAQPS Guideline Series. Report Number EPA-450/2-78-036. June 1978.
Docket Reference Number A-80-20-B (VOC) II-A-3.*
6. DuBose, D.A., and G.E. Harris. Response Factors of VOC Analyzers
at a Meter Reading of 10,000 ppfnv for Selected Organic Compounds.
U.S. Environmental Protection Agency, Research Triangle Park, NC.
Publication No. EPA 600/2-81-051. March 1981. Docket Reference
Number A-80-20-B (VOC) II-A-32.*
7. Brown, G.E., et al. Response Factors of VOC Analyzers Calibrated
with Methane for Selected Organic Compounds. U.S. Environmental
Protection Agency, Research Triangle Park, NC. Publication No.
EPA 600/2-81-002. September 1980. Docket Reference Number A-80-20-B
(VOC) II-A-34.*
8. DuBose, D.A., et al. Response of Portable VOC Analyzers to
Chemical Mixtures. U.S. Environmental Protection Agency, Research
Triangle Park, N.C. Publication No. EPA 600/2-81-110. June 1981.
Docket Reference Number A-80-20-B (VOC) II-A-35.*
9. Emission Test Report: Dow Chemical Company, Plaquemine, La. EMB
Report No. 78-OCM-12-C, December 1979. Docket Reference Number
A-80-20-B (VOC) II-A-31.*
10. Weber, R.C., et al. "Evaluation of the Walkthrough Survey Method
for Detection of Volatile Organic Compound Leaks," EPA Report No.
600/2-81-073, EPA/IERL Cincinnati, Ohio. April 1981. Docket
Reference Number A-80-20-B (VOC) II-A-33.*
D-10
-------
11. "Data Analysis Report: Emission Factors and Leak Frequencies for
Fittings in Gas Plants," EMB Report No. 80-FOL-l. July 1982.
Docket Reference Number A-80-20-B (VOC) II-A-36.*
12. "Emission Test Report: Sun Petroleum Products Co., Toledo, OH,"
EMB Report No. 78-OCM-12B, October 1980. Docket Reference Number
A-80-20-B (VOC) II-A-29.*
13. "Emission Test Report: Union Carbide Corporation, Torrance, CA,"
EMB Report No. 78-OCM-12A, November 1980. Docket Reference
Number A-80-20-B (VOC) II-A-30.*
*References can be located in Docket Number A-80-20-B (VOC) at the
U.S. Environmental Protection Agency Library, Waterside Mall, Washington,
D.C.
D-ll
-------
APPENDIX E - MODEL FOR EVALUATING THE EFFECTS OF LEAK DETECTION
AND REPAIR ON FUGITIVE EMISSIONS FROM PUMPS AND VALVES
-------
E.I INTRODUCTION
The purpose of Appendix E is to present a mathematical model (LDAR
Model) for evaluating the effectiveness of leak detection and repair
programs on controlling fugitive emissions from pumps and valves. In
contrast to the ABCD model presented in Chapter 4 for analysis of leak
detection and repair programs on relief valves and compressor seals, the
LDAR model incorporates recently available data on leak occurrence and
recurrence and data on the effectiveness of simple in-line repair.1 In
the ABCD model, leak detection and repair program impacts are evaluated
through emission correction factors that are based in part upon engineering
judgment.
E.2 LDAR MODEL
The LDAR model is based on the premise that all sources at any
given time are in one of four categories:
1) Non-leaking sources (sources screening at less than the action
level);
2) Leaking sources (sources screening at greater than or equal to
the action level);
3) Leaking sources that cannot be repaired on-line and are awaiting
a shutdown for repair; and
4) Repaired sources with early leak recurrence.
There are four basic components to the LDAR model:
1) Screening of all sources except those in Category 3, above;
2) Maintenance of screened sources in Category 2 and 4 above;
3) Rescreening of repaired sources;
4) Process turnaround during which maintenance is performed for
sources in Categories 2, 3, and 4, above. Figure E-l shows a schematic
diagram of the LDAR model.
Since there are only four categories of sources, there are only
four "leak rates" for all sources. In fact, there are only three distinct
leak rates since the repaired sources experiencing early leak recurrence
are assumed to have the same leak rate as sources that were unsuccessfully
repaired. The LDAR model does not evaluate gradual changes in leak
rates over time but assumes that all sources in a given category have
the same average leak rate.
E-2
-------
I
oo
Quarterly
Screening and
rUlatenaace of
Leaking
Source*'
Leaking Source* '
with Maintenance
'erfoneJ
fc.-L4.kiDt
Sources
Source* not Repaired
Source* Rewired with f
aarly Leak Recurrence
Source* Repaired with Leek
ttcurrcnct During Month
Repaired Source*
- h ..« J «—«••• *mf*ir»A \
Source* with 1
fxM*rcee Scree**4
'•t rir.t Htwtk
Source* Scre«oe4
•evxcet fjat Source* not |
te**ir!3
Eerlr Recurrence Source* Screened
Repaired with Leak ft ****** Hooth
Recurrence During Hontfi
Repaired Source* J
Burlnc Hooth
don-Leaker* ^>urce* Screened fc
at SeconJ Honth
Repaired
Repe^*' wlth
Early Ftilurea
Repaired with Uak
Repaired Source*
During Honth
Hon- Leaker*
«ek Occuireec* Dwiiw Quarter k
Noo-LeakiMi Source* f-
1 at tucvaround ]
Quarterly Screening
Maintenance* o(
Leaking Source*
'Leaking *ource* include all aource* which h*d leak recurrence, had expeclcnced
early failures, or had leak occurrence and regained leeker* at the end of the preceding quarter.
Fiaure E-l. SCHEMATIC DIAGRAM OF THE LDAR MODEL
-------
The LDAR model is implemented by a statistical analysis LDAR system
computer (SAS) computer program enabling investigation of several leak
detection and repair program scenarios. General inputs pertaining to
the leak detection and repair program may vary (for example, frequency
of inspection, repairs, and turnarounds). Further, input characteristics
of the emission sources may vary. Inputs required in the latter group
include:
1) The fraction of sources initially leaking;
2) The fraction of sources that become leakers during a period;
3) The fraction of sources with attempted maintenance for which
repair was successful;
4) The emission reductions from successful and unsuccessful
repair.
Other assumptions associated with the model are:
1) All repairs occur at the end of the repair period; the effects
associated with the time interval during which repairs occur are negligible;
2) Unsuccessfully repaired sources instantaneously fall into the
unrepaired category;
3) Leaks other than unsuccessful maintenance and early recurrences
occur at a linear rate with time during a given inspection period;
4) A turnaround essentially occurs instantaneously at the end of
a turnaround period and before the beginning of the next monitoring
period; and
5) The leak recurrence rate is equal to the leak occurrence rate;
sources that experience leak occurrence or leak recurrence immediately
leak at the rate of the "leaking souses" category.
E.3 MODEL OUTPUTS
The outputs from the LDAR model are summarized in Table E-l for
three leak detection and repair scenarios for valves (quarterly, monthly/
quarterly, and monthly) and two scenarios for pumps (quarterly and
monthly).2 These scenarios enabled estimation of emission reductions
and costs for valves and pumps under Regulatory-Alternatives II, III,
and IV. These estimates are presented in Chapters 7 and 8.
E-4
-------
Table E-l. RESULTS OF THE LDAR MODEL LEAK DETECTION AND REPAIR PROGRAMS
Emission source
and LDR scenario
Valves
Quarterly
Monthly/Quarterly
Monthly
Pumps
Quarterly
Monthly
Emission factor,
kg/day
0.041 (0.11)
0.041 (0.11)
0.029 (0.079)
0.50 (0.63)
0.42 (0.53)
Percent emission
reduction
77
78
84
58
65
Total fraction of
sources screened in
second turnaround -
annual average
4.0
4.3
11.9
4.0
12.0
Fraction of sources
operated on in
second turnaround -
annual average
0.19
0.19
0.19
0.39
0.41
XX = VOC emission values.
(XX) = Total hydrocarbon emission values,
-------
E.4 REFERENCES
1. Wetherold, R. G., G. J. Langley, et. al. Evaluation of Maintenance
for Fugitive VOC Emissions Control. EPA/IERL EPA-600/52-81-080.
May 1981. Docket Reference Number II-A-11.*
2. Memorandum. T.W. Rhoads, Pacific Environmental Services, Inc., to
Docket A-80-20. Evaluation of the Effects of Leak Detection and
Repair on Fugitive Emissions in the Onshore Natural Gas Processing
Industry Using the LDAR Model. November 1, 1982. Docket Reference
Number II-B-18.*
*References can be located in Docket Number A-80-20-B at the U.S.
Environmental Protection Agency Library, Waterside Mall, Washington, D.C.
E-6
-------
APPENDIX F - DOCKET ENTRIES ON CORRELATION BETWEEN COST-EFFECTIVENESS
AND THROUGHPUT FOR SMALL GAS PLANTS
Attached as Appendix F are two docket entries that develop a
correlation between cost-effectiveness and throughput for the recommended
new source performance standard controls for pump seals, valves, and
pressure relief valves. This analysis is only valid for small gas
plants that do not fractionate mixed natural gas liquids into separate
products. Two major assumptions used in this analysis are that throughput
can be related to emissions for small plants and that small non-complex
gas plants would use off-site personnel to implement a leak detection
and repair program. These docket entries are included here to enable
interested parties to review the basis for the recommended small size
cutoff for gas plants without having to obtain copies from the docket.
-------
MEMORANDUM
DATE: November 8, 1982
TO: Docket A-80-20
FROM: Tom Norwood, PES, Inc. ^
SUBJECT: Cost-Effectiveness as a Function of Throughput for Small
Gas Plants
In a meeting with EPA on August 18, 1982, representatives of
Allied Corporation (Union Texas Petroleum Corporation) indicated that
the leak detection and repair programs required by the recommended
NSPS for VOC fugitive emissions for on-shore natural gas processing
plants would have to be performed by corporate staff engineers rather
than plant personnel. Allied indicated in NAPCTAC testimony that to
ensure the program was properly implemented, the cost of such a program
would be $15,000 annually as opposed to the $2,070 indicated by EPA
(Attachment I). It was assumed that Allied's estimates were based on
1982 dollar values.
Given that central office personnel may be required to perform
the program, the cost estimates prepared by Allied were examined for
reasonability and corrected to 1980 dollar values as described in
Attachment II. The Allied estimates seem to be slightly excessive, as
follows:
(1) Inspector Labor: Assuming a plant has 256 valves, relief
valves, and pump seals subject to the leak detection and
repair program (BID Model Plant A), the complete inspection
should take less than 5 hours, as opposed to the two days
predicted by Allied. This time is illustrated in Table 1.
Eight hours should be allowed, however, to cover travel time
and preparation for testing. Four extra hours are allowed
for return air travel. Thus, a total of \h days is considered
realistic.
(2) Travel living expense—since only one day in the field is
required, the living expense should be approximately:
(1980 dollars)
Car $34
Living Expense 57
Total
F-2
-------
In the administrative cost portion, no additional travel expense
is required. As such, the Allied estimates were adjusted as shown in
Table II, and annual costs calculated for monthly inspections. The
cost of replacement pump seals and of amortized initial repairs are
added to the EPA estimate.
As the cost incurred for routine leak detection and repair is
relatively fixed for small plants, the control cost effectiveness is
primarily a function of plant emissions. As such, a limiting plant
size can be determined for a given cost effectiveness. Table III
presents the emissions reductions for a small plant as presented in
BID Table 7-2. Based on the component mixture used in this small
plant, the average emissions reduction for monthly leak detection and
repair was determined to be 82 percent. As the cost effectiveness is
a function of the amount of VOC removed, a graph of cost effectiveness
versus emissions reduction can be nade (Figur° 1).
Based on the source tests performed by EPA for small gas plants,
the VOC emissions can be related to throughput as:
VOC Emissions (Mg/yr) = throughput (MMscfd)1
THC emission reductions can be calculated from Table III as (for model
plant A):
THC reduction = a x VOC reduction
40.2 Mg VOC
or THC = 2.9 x VOC
Cost effectiveness is equal to the annualized cost divided by the
emissions reduction. The annualized cost is reduced by the value of
the products retained in the process. Based on the BID, the VOC value
was established as $192/Mg and the methane-ethane value was $61/Mg.
Since the emissions reduction for monthly monitoring was 82 percent,
the net annual cost =
COST ($/yr) = $15,013 (from Table III) - [$61 x (THC - VOC)
+ $192 x VOC] x 0.82
The cost effectiveness is:
$15.013 - [61 (1.9 x VOC) + 192 x (VOC)] x 0.82
0.82 x VOC
- $18.300 ,nn
" MMscfd " JUU
Memorandum, K.C. Hustvedt, EPA to J. F. Durham, EPA; "Estimation of
VOC Emissions as a Function of Throughput for Small Gas Plants";
November 5, 1982. Docket Reference Number II-B-24.
F-3
-------
Using these relationships, cost effectiveness can be calculated
for any plant throughput. Figure 1 presents a curve of cost effectiveness
of the recommended leak detection and repair program as a function of gas
plant capacity. This curve can be used to select a plant size cutoff.
Table I. LEAK DETECTION TIME REQUIREMENTS
(Model Plant A)
Component
Valves
Relief Valves
Pump Seals
Number in
250
4
2
Plant Min/Componenta
1
8
5
Total
Total Minutes
250
32
10
292 minutes
= 4 hrs 52 min
aBID Chapter 8, 2-man team.
F-4
-------
TABLE II
COMPARISON OF EPA AND ALLIED
LEAK DETECTION AND REPAIR COSTS ESTIMATES FOR RECOMMENDED NSPS
MONITORING WITH OUTSIDE PERSONNEL
Plant Inspection Costs for Each Trip
Allied Estimate (1982 $)
Mechanic
Inspector
Air Travel
Car
Living
Sub Total
8 hrs
16 hrs
2 days
2 days
$200
384
200
80
100
Additional Adninistrative Costs for Each Trip
By Inspector
1 day in office
1/3 day in plant
Travel Expense
Subtotal
Total Cost per
Sample Period
Annual Costs
Instrument Costs
(BID Basis)
Monthly Inspection
$192
64
30_
$286
$1,250
$ 5,500
$15.000
Other Costs Not Considered By Allied
Replacement Seals Pumps
Amortized Initial Repairs
Total Annual Cost
EPA Estimate (1980 $)
8 hrs
12 hrs
1 day
1 day
$144
216
167
34
57
1618
$144
not required
not required
£144
$762
$20,500
$5,500
$9.144
114
255
$15,013
Basis:
Mechanic $25/hr
(With Overhead)
Salary Technical Staff Person $192/day
(With Fringes)
$18/hr
$18/hr
F-5
-------
TABLE III
EMISSIONS REDUCTIONS (MODEL PLANT A)
Component Type Uncontrolled Emissions
kg /day
Valves
Relief Valves
Pump Seals
Total
Emissions Reduction*
45 (120)
1.3 (18)
2.4 (3.0)
48.7 (141)
Monthly LORP Emission Reduction
kg/day kg/day
7.3
0.40
0.84
8.54
82%
(20)
(4.4)
(1.1)
(35.5)
(82%)
37.7 (100)
0.9 (73.6)
1.6 (1.9)
40.2 (116)
XX = VOC
(XX) = THC
Uncontrolled Emissions - Controlled Emissions
Uncontrolled Emissions
F-6
-------
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COST EFFECTIVENESS ($1000/Mg)
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-------
Attachment i
COSTS FOR ROUTINE INSPECTION & REPAIR PROGRAM
FOR ONE SIZE A PLANT
COST BASIS = CONTRACT MECHANIC (WEST TEXAS) = $25/HouR
(WITH OVERHEADS)
SALARY TECHNICAL STAFF MAN = $192/DAY
(WITH FRINGES)
PLANT MONTHLY INSPECTION TRIP- MONTHLY COST
MECHANIC - 3 HOURS 200
INSPECTOR - SALARY - 2 DAYS 384
TRAVEL EXPENSES
AIRLINES 200
CAR go
LIVING EXPENSES 100
SUB TOTAL 954
ADDITIONAL ADMINISTRATIVE TIME
BY INSPECTOR - 1 DAY/MONTH IN OFFICE 192
1 DAY/QUARTER IN PLANT
SALARY ($192 * 3) 64
TRAVEL EXPENSE ($90 * 3) 30
MINIMUM MONTHLY COST 1250
ANNUAL COST - ROUTINE T&I ONLY $15,000
ESTIMATED EPA TOTAL PROGRAM COST $ 2,070 .
F-8
-------
ATTACHMENT II - Derivation of EPA Costs
Assuming Allied costs are 1982 $
Correction Factor: CE Index July 82 314.2,
July 80 263.2^
Ratio = 1.19
I. Air Travel
Allied = $200
Corrected = 2TDO/1.19 = $167
II. Car
Allied 2 days, $80
(1 day = $40)
Corrected = $40/1.19 = $34
III. Living
Allied 2 days $100
for 1 day, will assume Allied estimate is 1 night note! 0 $35.00
and two days expenses @ $32.50/day
Allied for 1 day = 32.50 + 35.00 = $67.50
Corrected = 67.50/1.19 = $57
IV. All labor - will use BID basis of $18/hr
Table 8-5
V. Instrument Costs
will use BID basis of $5,500/yr
(Table 8-9)
References
1 - Chemical Engineering, Vol. 89, No. 21,
October 18, 1982
2 - Chemical Engineering, Vol. 87, No. 20,
October 6, 1980
F-9
-------
s ** \ UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
Q VvT/V I Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
November 5, 1982
MEMORANDUM
SUBJECT: Estimation of VOC Emissions as a Function of Throughput for Small
Gas Plants
FROM: K. C. Hustvedt
Petroleum Section, CPB/ESED
TO: James F. Durham, Chief
Petroleum Section, CPB/ESED
The purpose of this memo is to document the development of a correlation
between VOC emissions and throughput capacity for small gas plants. The
results of the analysis show that the VOC emissions [in megagrams per
year (Mg/yr) ] from small gas plants are approximately equal to plant
throughput capacity in millions of standard cubic feet per day (MM scfd).
This correlation can be used to determine a size cutoff for small gas
plants.
In general, there is no relationship between throughput capacity and
emissions. Emissions are related to number of pieces of equipment, or process
complexity, and process complexity does not consistently relate to throughput
capacity. However, as throughput capacity is reduced to relatively small
quantities, it seems reasonable to assume that emissions would not remain
primarily related to process complexity. If emissions were completely
unrelated to throughput capacity, complex plants (Model Plant C) with very
small throughput capacities such as one million cubic feet per day would
lose a significant portion of their product (almost 10 percent). However, it
is likely that these plants would take action to reduce these losses and
therefore it is likely that emissions would be less for smaller plants.
The basis used for developing this correlation is the results of
the EPA source tests of two relatively small gas plants. Table 1 shows
the development of the leaker and nonleaker emission factors for valves,
relief valves, and pump seals based on the technique described in
EPA-450/3-82-010 (April 1982), "Fugitive Emission Sources of Organic
Compounds - Additional Information on Emissions, Emission Reductions, and
Costs" (AID). Table 2 and 3 present the development of emission estimates
for the two EPA tested small gas plants based on the factors presented
in Table 1. Plant 3 (Table 2) emits 89.2 kilograms per day (kg/day) of
VOC (32.6 Mg/yr) and has a capacity of 60 MM scfd for a ratio of emissions
to throughput of 0.54. Plant 4 (Table 3) emits 120 kg/day (43.9 Mg/yr)
F-10
-------
of VOC and has a capacity of 30 MM scfd for emissions to throughput
ratio of 1.46. The arithmetic average of these two ratios yields the
estimation for small gas plants that the VOC emissions in Mg/yr equals
the throughput in MM scfd (average ratio equals 1.00).
3 Attachments
F-ll
-------
Table 1. DEVELOPMENT OF EMISSION FACTORS FOR LEAKING AND NONLEAKING
SOURCES IN GAS PLANTS3
Source
Valves
(VOC)
(THC)
Relief Valves
(VOC)
(THC)
Pump Seals
(VOC)
(THC)
Overall
Emission*3 Factor
(kg/day)
0.18
0.48
0.33
4.5
1.2
1.5
Leaker
Correction
Factor(b»c)
86
18
87
18
77
19
77
19
79
33
79
33
Leaker
Emission
Factor
(kg/ day)
0.86
2.3
1.3
18
2.9
3.6
Nonleaker
Correction
14
82
13
82
23
.81
23
81
21
67
21
33
Nonleaker
Emission
Factor
(kg/day)
0.031
0.076
0.094
1.3
0.38
0.95
a Technique described in EPA-450/3-82-010 (April 1982) "Fugitive Emission Sources of Organic Compounds -
Additional Information on Emissions, Emission Reduction, and Costs." (AID)
b Emission factors and the inputs to the correction factors are from ESED/EMB Report No. 80-FOL-l (July 1982),
"Frequency of Leak Occurrence and Emission Factors for Natural Gas Liquid Plants."
c As outlined in the AID, the leaker correction factor is the ratio of the percent of overall emissions from
leaking sources divided by the percent of overall sources leaking. This number is multiplied times the
overall emission factor to derive the leaker emission factor.
d As discussed under footnote "c," the nonleaker correction factor is the ratio of the percent of overall
emissions from nonleaking sources divided by the percent of overall sources that are not leaking.
-------
Table 2. ESTIMATED EMISSIONS FOR EPA PLANT. TEST NUMBER 3 (60MM scfd capacity)
i
OJ
Source
Valves
Pressure
Relief Valves
Pump Seals
Total Number
Sources
341
11
1
Percent
Leaking
23.6
90.0
0.0
Number
Leaking
80
9
0
Leaker3
Emissions
(kg/day)
68.8 (184)
11.7 (162)
0 (0)
Number Not
Leaking
261
2
1
Nonleakerb
Emissions
(kg/day)
8.1 (19.8)
0.2 (2.6)
0.4 (1)
Total
Emissions
(kg/day)
76.9 (204)
11.9 (165)
0.4 (1)
Total
80.5 (346)
8.7 (23.4)
89.2 (370)
XX - VOC Emissions
(XX) - Total Hydrocarbon Emissions
Reference: Fugitive VOC Testing at Houston Oil and Minerals Smith Point Plant.
Report No. 80-OSP-l, October 1981.
a Based on leaker emission factor derived in Table 1.
Based on nonleaker emission factor derived in Table 1.
U.S. EPA, ESED/EMB
-------
Table 3. ESTIMATED EMISSIONS FOR EPA PLANT TEST NUMBER 4 (30MM scfd capacity)
Total Number Percent Number Leaker3 1
Source Sources Leaking Leaking Emissions
(kg/day)
Valves 565 16.8 95 81.7 (218)
Pressure
Relief valves 13 14.3 2 2.6 (36)
Pump Seals 14 44.4 6 17.4 (21.6)
Total 102 (276)
Number Not Nonleakerb Total
Leaking Emissions Emissions
(kg/day) (kg/day)
470 14.6 (35.7) 96.3 (254)
11 1.0 (14.3) 3.6 (50.3)
8 3.0 (7.6) 20.4 (29.2)
18.6 (57.6) 120 (334)
XX - VOC Emissions
(XX) - Total Hydrocarbon Emissions
Reference: Fugitive VOC Testing at the AMOCO Hastings Gas Plant.
Report No. 80-OSP-2, July 1981.
U.S. EPA, ESED/EMB
a Based on leaker emission factor derived in Table 1 .
b Based on nonleaker emission factor derived in Table 1.
-------
APPENDIX G
REVISED COMPRESSOR SEAL EMISSION FACTORS AND
SEAL VENT SYSTEM CONTROL COSTS
Appendix G contains three memoranda that document revisions to the
emissions estimates and control cost estimates for compressors. The
compressor seal emission factors presented in Chapters 3, 4, 7 and 8 of
this document were revised. The original emission factors represented the
average emission from all compressors, including those processing dry gas.
Because dry gas compressors are not subject to the proposed standards, the
emission factors were revised to represent average emissions from wet gas
and natural gas liquids compressors, the compressor types that are covered
by the proposed standards. The development of the revised emission factors
is documented in the memorandum dated February 10, 1983, that is included
in this appendix.
After completion of Chapter 8 of this document, the costs for
reciprocating compressor seal controls were also revised in response to
comments received from industry representatives. The revised costs are
presented in the memorandum dated February 23, 1983, that is included in
this Appendix. Finally, the effect of control device costs on compressor
seal vent enclosure cost effectiveness is included in this appendix in a
memorandum dated June 28, 1983.
-------
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
February 10, 1983
MEMORANDUM
SUBJECT: Revised Gas Plant Compressor Seal Emission Factor
FROM: K. C. Hustvedt '
Petroleum Section, Chemicals and Petroleum Branch, ESED (MD-13)
TO: James F. Durham, Chief
Petroleum Section, Chemicals and Petroleum Branch, ESED (MD-13)
Recommendation
In the February 3, 1983, AA review package for the onshore production
new source performance standard (ESED Project No. 80/22A), we included a
recommendation to exempt dry gas equipment from the standards. A review
of the data used in developing our present compressor seal VOC emission
factor (0.36 megagrams per year (Mg/yr) per seal) shows a large portion
of the data are from dry gas compressors; therefore, the overall emission
factors used in the package were not representative of the population
now_being regulated. In developing the basis for compressor seal regu-
lations, I recommend that the refinery hydrocarbon service compressor
seal VOC emission factor (5.5 Mg/year per seal) be used for natural gas
liquids (NGL) service compressor seals and that an estimated emission
factor (0.7 Mg/yr per seal) be used for wet gas service compressor seals.
Weighting these emission factors based on the occurrence of these compres-
sor seal services in the API and EPA testing yields an average gas plant
compressor seal VOC emission factor of 2.3 Mg/yr. Further, using equipment
controls to reduce these emissions will essentially eliminate the emissions
and, where it is technically feasible, quarterly monitoring will reduce
the VOC emissions to 0.4 Mg/yr.
Background
The background information document (BID) for the gas plants NSPS
states that the compressor seal emission factor is probably substantially
understated. This is because both the EPA and API testing of compressors
included only open frame compressor distance piece emissions. No seal
packing vents or enclosed distance pieces were tested. In the past,
industry has stated that most of the compressor seal emissions will 'come
from the seal packing vent if the compressor has one. They have also
stated that enclosing and venting the distance piece is likely to increase
compressor seal emissions because the seal is harder to visually inspect for
failure and because seal maintenance is more difficult (the enclosure
must be removed). These industry comments certainly support our contention
that the compressor seal emisson factor could be substantially understated.
6-2
-------
Based on comments received at the NAPCTAC meeting that certain sources
within gas plants have essentially no VOC emission reduction potential and
a subsequent review of the available data, we have recommended that the
NSPS include an exemption for dry gas service equipment (defined as less
than 1.0 weight percent VOC). Because our data base includes dry gas
compressors and because these are likely to have the lowest VOC emissions
of the compressors studied, the data base should be reviewed to determine
if the emission factors should be corrected to represent only the compressor
seals affected by the recommended NSPS.
Review of Available Data
Table 1 shows a summary of the gas plant compressor seal data used
to develop the gas plant emission factor. As you can see, there were
71 seals screened and 26 measured for mass emissions. Over one-third
of the sources screened and measured were in dry gas service While
deleting the dry gas service data and recalculating a new emission factor
based on the remaining data would be possible, this would not necessarily
result in a better emission factor due to another shortcoming. As shown
in Table 1, 16 of the remaining (non-dry gas) 47 compressor seals or
about one-third are in natural gas liquids (NGL) service and only'one of
these 16 was tested for mass emissions. Simply calculating a new emission
factor based on the existing data base (after removing the dry gas compressors)
would greatly understate the VOC emissions from NGL compressor seals because
the mass emissions data from wet gas compressors (averaging 6.8 percent VOC)
are used to estimate mass emissions from NGL compressors (100 percent YOC
in the one compressor tested) in the development of emission factors
For these reasons, different methods should be used to develop emission
factors for gas plant compressor seals.
Development of Emission Factors
K*+ BeCJr,Se t5erej's a 1ar9e difference in process stream VOC concentration
between NGL and wet gas service compressors as seen in Table 1, emission factors
are developed for both services. NGL service compressors contain mixed
natural gas liquids, LPG, propane refrigerant, etc., and usually contain
greater than 50 percent VOC. In gas plant testing of NGL compressors
16 were screened for leakage, yet only one seal was tested for mass
emissions. Because these limited data are insufficient for direct emission
factor calculation, other methods of developing emission factors were
investigated. The technique based on percent of sources leaking used to
calculate emission factors for chemical plant compressor seals in the
AID (Fugitive Emission Sources of Organic Compounds: Additional Information
on Emissions Emission Reductions, and Costs, EPA 450/3-82-010 April 1982)
could be used, but it was felt that the 83 percent (5 of 6) NGL serv ce
compressor seals leaking found by EPA was not representative of the natural gas
G-3
-------
processing industry. These NGL service compressors are, however, essentially
identical to hydrocarbon service compressors in petroleum refineries and
thus the refinery compressor seal VOC emission factor of 15 kg/day (5.5 Mg/yr)
will be used for gas plant NGL service compressor seals.
For wet gas service compressors, it appears as though sufficient
data are available to use the AID techniques to calculate an emission
factor. Fourteen out of 30, or 46.7 percent, of the wet gas service
compressor seals leaked. Using the procedure outlined in Section 2 of
the AID, this leak frequency translates into an emission factor of 19.2
kg/day (7.0 Mg/yr) as shown in Table 2. This factor, however, is for total
hydrocarbon emissions (THC) and only a portion of the wet gas service
compressor seal THC emissions would be VOC. Based on an estimated average
VOC concentration of 10 weight percent, the wet gas service compressor
seal VOC emission factor would be 1.9 kg/day (0.70 Mg/yr).
To obtain an overall gas plant compressor seal emission factor, the
weighted average of the wet gas and NGL service emission factors are
used. As shown in Table 1, 66 percent (31 of 47) of the seals screened
were in wet gas service and 34 percent (16 of 47) were in NGL service.
Weighting the individual emission factors by these percentages yields an
average emission factor for gas plant compressor seals of 6.4 kg/day
(2.3 Mg/yr) of VOC and 18 kg/day (6.6 Mg/yr) of THC.
Emission Reductions
In the calculation of the emission reduction obtained through control
of gas plant compressor seals, 100 percent control is estimated for
equipment controls. In the CTG, however, quarterly monitoring is allowed
where it is technically feasible. In calculating the ABCD estimated
emission reduction, the B, C, and D values from Table 7-1 of the Refinery
BID (EPA 450/3-81-015a, November 1982) are used because the refinery
compressor seal data form the basis for the new gas plant compressor
seal emission factors. A weighted average A factor for wet gas and NGL
service compressor seals is used. For NGL the A factor is 0.91 (Refinery
BID) and for wet gas compressors the A factor is 0.94 [18026 kg/day per
thousand seals (leaker emissions from Table 2) divided by 19172 kg/day
per thousand seals (total emissions in Table 2)]. Weighting these A
factors as was done for the overall emission factor yields an average A
factor of 0.93. Overall emission reduction is therefore calculated as
follows:
Emission Reduction = AxBxCxD
= 0.93 x 0.90 x 0.98 x 0.98
= 0.80
G-4
-------
This estimated 80 percent emission reduction is then corrected as was
explained in the AID and the Gas Plant BID to lessen the impact of the
estimated B factor on the overall estimate. As was determined in
T. Rhoads (PES) November 1, 1982, memo, "Calculation of Controlled Emission
Factors for Pressure Relief Valves and Compressor Leaks", the VOC correction
factor is 1.04 and the THC correction factor is 1.01. Using these
correction factors, the estimated emission reductions for quarterly
monitoring of gas plant compressor seals is &3 percent for VQC emissions
and 81 percent for THC emissions. This equates to controlled emission
factors of 0.4 Mg/yr VOC and 1.2 Mg/yr THC after implementation of a
quarterly leak detection and repair program.
cc: Dianne Byrne, SD8
Fred Dimmick, SDB
Tom Norwood, PES
Tom Rhoads, PES
Bruce Tichenor, ORD/RTP
6-5
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Table 1. GAS PLANT COMPRESSOR SEAL DATA SUMMARY
Service
--API DATA—
Dry gas'e^
Wet gas(f)
NGL (g)
--EPA DATA--
Dry gas
Wet gas
NGL
--OVERALL--
Number
Screened
24
1
10
0
30
6
71
Number Number Number Percent
Emitting(a) Leaking(b) Measured^) YOC^
18 - 9 0.42
o o
9 0
0 00-
19 14 16 6.8
5 5 ] 100
51 -- 26 6.3
REFERENCE: "Frequency of Leak Occurrence and Emission Factors for Natural Gas
Liquid Plants." - EMB No. 80-FOL-l, July 1982.
(a) Emitting sources are ones that showed any evidence of leakage when screened.
(b) Leaking sources screened greater than 10,000 ppm.
(c) Sources measured for mass emissions.
(d) Total measured VOC emissions divided by total hydrocarbon emissions X 100.
(e) Dry gas is field natural gas after the natural gas liquids are removed.
(f) Wet gas is field natural gas.
(g) NGL is natural gas liquids including raw NGL mix, LPG, propane refrigerant,
etc.
G-6
-------
Table 2. Calculation of Gas Plant Wet bab oervice Compressor Seal
Cmirrinn Fartnvc
Emission Factors
Number of Sources Emission Factor^ Emissions Per
Per 1000 (kg/day) 1000 Sources
(kg/day)
Leaking Sources 467
-------
^"_
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY A-SO-20-B(VOC)
Off ice of Air Quality Planning and Standards ^
Research Triangle Park, North Carolina 27711 II-B-37
February 23, 1983
MEMORANDUM
SUBJECT: Revised Cost Analysis for Reciprocating Compression Seal Vent Controls
FROM: Kent C. Hustvedt
Petroleum Section, CPB (MD-13)
TO: James F. Durham, Chief
Petroleum Section, CPB (MD-13)
Over the past several months many changes have been made in our
configuration and cost basis for controlling gas plant reciprocating
compressor seals. These changes have been made in our continuing effort
to design and cost a safe, realistic system for control of compressor
seal emissions. While the system described and analyzed in the background
information document (BID) is basically adequate, information recently
supplied to us by Union Texas Petroleum (UTP) shows that several oversights
were made in our analysis. Table 1 summarizes revised capital costs for the
reciprocating compressor seal control systems based on our review of UTP's
submittal. A contingency of 10 percent has been added to the capital costs and
they have been annualized as in the BID. These costs will be used to
assess the cost and cost-effectiveness of compressor seal vent control
systems for the gas plant NSPS and CTG.
Table 2 is a detailed listing of the capital costs of the reciprocating
compressor seal control system. Table 2 is a revision of an order of
magnitude cost estimate made by UTP and supplied to us in a letter from
Bill Taylor of UTP to Susan Wyatt dated February 8, 1983, (Docket No. 80-20-B,
II-D-53). I have revised their cost estimates as follows: (1) their costs
were corrected using cost indices to make them consistent with our year
basis (1980), (2) our vendor quote equipment costs were used as documented
in the BID, and (3) reasonable alternative equipment were used. Justifications
for the use of the alternative equipment are provided as references to the table,
Attachment
cc: Dianne Byrne, SDB
Fred Dimmick, SDB
-Tom Norwood, PES
Tom Rhoads, PES
Bruce Tichenor, ORD/RTP
G-8
-------
Table 1 - Summary of Reciprocating Compressor Control System Costs (1980 $)
ItemCapitalCapital CostsAnnual
Cost (a) With Contingency (b) Costs (c)
Double Distance Piece 2500 2750 700
Distance Piece Piping 1000 1100 280
Instrumentation For 1780 1960 500
Purge Gas
Flare 6670 7340 1860
Flare Piping 3380 3700 940
(a) Revised capital costs based on our review of the February 8, 1983,
Union Texas Petroleum submittal (Table 2).
(b) Total capital costs including 10 percent contingency.
(c) Annualized capital costs based on 0.163 capital recovery factor
(10 percent interest rate and 10 year lifetime), 0.05 x capital
costs for maintenance and 0.04 x capital costs for taxes, insurance,
and administration.
G-9
-------
TT>
2.
ORDER OF MAGNITUDE ESTIMATE
FOR COMPRESSOR SEAL LEAK CONTROLS^
Cc
£
Incremental Cost for Double Distance -<
Piece
E-xtontion of Compressor1 Skid & $
jst Per Co**— PO*
binder ftodgl A Plant
»-3 — nnrv t c. /-> /-> f & ) t c_ oon
yo,uuw t •> c» <_> ^/T/ jb ,UUU •
5 — 566- t-t nnn
dation
Distance Piece Piping
1" Piping - 100 ft. @ $2.00/-f
1" Check Valves -X \ @ Qo
1" Block Valves - 2 0 Z5
rBV^a-i Pot ., __
Material
.^OAA Q
VfcWW *
$509-
tonn
Misc. Flanges, Fittings, Etc.
Indirects
Sub-Total
Instrumentation For Purae Gas
4296-
fri-et-Control
Material
9 oo
eunLiuii
^M^H
r Slock Valves -
Misc. Flanges, Fittings
Indirects
Sub-Total
-296-
•59- "2-0
-206- I tO
Labor
(18.85/Manhour)
$300
1100
$ 60
$ 50
$210
Labor
50
25
50
195
$~^§5e- 5 Go
J».«°
-^ 3T-T>- 53)
G-10
-------
Cost Per
Cylinder
Model A Plant
Cost of 2-am-SCQ. Flare
Piping To Flare
Material
500'Ft-
Inlet Line from Compressor to
Flare 5-^. - 2" Pipe 9
upture Di
Misc. Flares, Fittings
Indirects
1500
i rnft
ID\J(J
-556-
6670
Labor
1666-
Il6o
Sub-Total
Misc. Costs For Pipe Supports(p«°4)
Total Materials•& Labor
Contingency • 20%-
Total Coot
Adjustment PJI 1J02 v^. 1DQQ CuaLi (
Adjustment Lu EPA CusL for Double Distance-
$49,000
$ 9>500-
50
soc^;
IHSo
-
$25 .OOP
$10.000'
$ 3,000-
•$11.200
SC7.00&-
S55.000
$53 ,800-
G-ll
-------
References for Table 2
A. Telephone conversation report. T. Norwood, Pacific Environmental
Services, Inc., with P. Marthinetti, Ingersoll-Rand. December 8,
1982. Distance piece price verified by Mr. Marthinetti as $2,000
to $3,000 (1980). Average value of $2,500 used. Docket Reference
Number II-E-19.*
B. Single oil seal pot required for all compressors instead of one per
compressor.
C. Telephone conversation. T. Norwood, Pacific Environmental Services,
Inc., with D. Rudolph, Fairchild Industries. Price of natural gas
supply^regulator. Docket Reference Number II-E-22.*
D. These costs are already included in flare cost.
E. Letter, R.W. Kreutzen, Chevron U.S.A. to J.R. Farmer, EPA:CPB,
"Draft CTG for Natural Gas Processing Plants," March 12, 1982.
1982 installed cost of flare given as $8,000. Deflated to 1980
dollars « $6,670.« Docket Reference Number II-D-32.*
F. Pilot gas for flare not needed as compressor vent stream is the
pilot. Flare is auto ignited type.
G. Telephone conversation. T.L. Norwood, Pacific Environmental Services,
Inc., with Continental Disk Co., February 14, 1983. Quote of
$100/holder and $64/disk corrected to June 1980 dollars - $52/disk
and $82/holder. Docket Reference Number II-E-23.*
*References can be located in Docket Number A-80-20-B at the U.S. Environmental
Protection Agency Library, Waterside Mall, Washington, D.C.
G-12
-------
A-30-20-B(VOC)
II-B-44
MEMORANDUM
DATE: June 28, 1983
TO: K.C. Hustvedt
FROM: T.L. Norwood, PES, Inc. 4W
SUBJECT: Effect of Control Device Costs on Compressor Seal
Vent Enclosure Cost Effectiveness
Prior to preparation of the current draft of the new source
performance standard for equipment leaks of YOC from natural gas
processing plants, representatives from Union Texas Petroleum
indicated that not all gas plants have operating flares. They
contended that the cost effectiveness of controlling compressor
seal leaks by using enclosed distance pieces should be adjusted to
include the cost of the control device in the enclosure costs.*•
As some plants do use operating flares, the costs and cost
effectiveness for compressor seal vent controls in plants both with
and without control devices present (Model Plant B) were calculated.
These calculations were performed for two types of compressors
(centrifugal and reciprocating) in either of two types of service
(wet gas or natural gas liquids).
Table 1 presents the cost and cost effectiveness for the eight
resulting cases. As can be seen, the cost effectiveness varies
from $36/Mg for the best «.ase (centrifugal compressors In NGL
service with existing control devices) to $2200/Mg for the worst
case (reciprocating compressors in wet gas service with a new
control device).
Table 2 presents the ",:pita1 cost calculations required to
develop Table 1.
Memo, T.L. Norwood to Oianne Byrne EPA:SOB, January 27, 1983,
"Meeting to Discuss Industry Comments on the Draft NSPS for Natural
Gas Processing Plants." Docket Index No. II-E-24.
G-13
-------
Table 1. COSTS AND COST-EFFECTIVENESS FOR COMPRESSOR VENT CONTROL
SYSTEM FOR MODEL PLANT B
CD
I
Compressor
Typea
Centrifugal
Reciprocating
Control
Device
Presentb
yes
no
yes
no
. Compressor0
Service
wet gas
NGL
wet gas
NGL
wet gas
NGL
wet gas
NGL
Capital
Costd
($1,000)
4.7
12.0
29.0
36.0
Annual
Coste
($l,000/yr)
1.2
3.0
7.3
9.1
Emission
Reduction^
(Mg/yr)
4.2
33
4.2
33
4.2
33
4.2
33
Cost
Effect! veness9
($/Mg)
280
36
710
91
1,700
200
2,200
280
u
Centrifugal compressors are driven by rotating shafts while reciprocating compressors are driven
by shafts having a linear motion.
bi(
"Yes" indicates that a control device is present at the plant. The cost of a control device
(flare) has been added to the compressor vent control system costs for plants without an
existing control device.
c
Wet gas means field gas with an average VOC content of 10 percent by weight NGL (Natural gas
liquids) consists of mixed liquids separated from wet gas (i.e., liquid petroleum gas).
d
Capital costs per Table 2.
B
Annualized cost = CAPITAL RECOVERY + MAINTENANCE COSTS + MISCELLANEOUS COSTS
= [.163 + .05 + .04] x CAPITAL = 0.253 x CAPITAL COST (BID Table 8-5).
f
From BID Appendix G, page G-2, Emission reduction based on six seals in Model Unit B.
Cost Effectiveness = Annual Cost
Emission Reduction
-------
Table 2. COMPRESSOR SEAL VENT SYSTEM CAPITAL COSTS
(Model Plant 8)
Centrifugal
Item
«•«••••••••
Double Distance pieces
Seal Vent Piping
Purge Gas Supply
Flare Piping
Subtotal
Flare
Total e
Compressors
924&.C
3,700*
4,624
7, 340^
11,964
• * ^» W » W 1 ^>\M U V 1 ' 1 M
Compressors3
16.500C
6.60QC
1,960
3,700
28,760
7,340
36,100
From BID Appendix G, page G-10, Table 1.
b
From BID Table 8-1.
c
Costs are for six compressor seals.
d '
Total capital costs for plants with existing control devices.
e
Total capital costs for plants without existing control devices.
G-15
-------
APPENDIX H
CALCULATION OF EMISSION REDUCTIONS AND COST EFFECTIVENESS
FOR THE PROPOSED STANDARDS BY SOURCE TYPE
Chapter 6 of this document presents the model plants and regulatory
alternatives on which the emission reductions and costs impacts in
Chapters 7 and 8 were determined. The proposed standards however, are
not based on a single regulatory alternative; they are based on selected
control strategies from different alternatives for each component.
Consequently, this appendix documents the emission reductions and cost
effectiveness of alternative controls and the proposed standards by
source type for Model Plant B.
-------
MEMORANDUM
TO: Docket A-80-20B DATE: May 26, 1983
FROM: T.L. Norwood and 0.6. Cole {[)*
SUBJECT: Costs and VOC Emission Reduction for
the Recommended Standards of Performance
for Equipment Leaks of VOC in Onshore
Natural Gas Processing Plants (ESED
Project No. 80/22)
The purpose of this memo is to document the costs and VOC emission
reductions for the New Source Performance Standards for onshore natural
gas plants (VOC) recommended for proposal. This is necessary because the
standards for each fugitive emission source are based on the selection of
control techniques rather than regulatory alternatives. Table 1 provides
a summary of the Model Plant B emission reductions and the average and
incremental cost effectiveness of various controls for each fugitive
emission source. The control techniques that are underlined in Table 1
were selected as the basis for the standards because the incremental cost-
effectiveness numbers were judged to be reasonable.
Tables 2 through 7 provide a detailed breakdown of the analyses used
to produce Table 1. All information in the tables is from the BID for
the proposed standards, and footnotes at the end of each table explain
how the numbers were calculated. All of the tables except Table 3 for
compressor seals are based on the control of a single component because
there are no economies of scale. The compressor cost analysis in Table 3
was performed for Model Plant B because there are fjxed costs for the system.
cc: K.C. Hustvedt
Dianne Byrne
H-2
-------
Table 1. EMISSIONS REDUCTIONS AND CONTROL
COST EFFECTIVENESS FOR MODEL PLANT B
Source
Pressure relief
devices
Compressors
Open-ended valves
and lines
Sampling connection
systems
Valves
Pumps
Control
Technique
Quarterly leak
detection and
repai rd
Monthly leak
detection and
repair
Rupture disks6
Closed-vent and
seal system^
Capsd
Closed-purge
sampling
Quarterly leak
detection and
repair
Monthly leak
detection and
repai rd
Quarterly leak
detection and
repai r
Monthly leak
detection and
repai rd
Dual mechanical
seals6
Emission
Reduction^
(Mg/yr)
0.95
1.0
1.5
14*
19
0.22
40
43
1.5
1.7
2.6
Average
Cost
Effectiveness3
($/Mg )
c
0
6,700
460
7,0006
0
830
900
4,900
Incremental
Cost
Effectiveness9
($/Mg)
5,800
22,000
460
7.0006
c
1,400
830
1,500
12,000
aFrom Tables 2 through 7 of this memo.
bFrom BID Table 7-2.
cCost savings occur.
^Control techniques selected as the basis for the recommended standards.
elmpacts shown are weighted averages based on 180 new plants and 40 modified/
reconstructed plants.
'From Reference 2.
H-3
-------
Table 2. ANNUALIZEO CONTROL COSTS PER COMPONENT
FOR PRESSURE RELIEF DEVICES3
(June 1980 Dollars)
Installed Capital Cost
Annualized Capital
A. Control
Equipment
8. Initial Leak
Repair6
Annualized Operating
Costs
A. -Maintenance1"
B. MiscellaneousS
C. Labor
1. Monitoring"
2. Leak Repair6
3. Adminis-
trative and
Support1
Total Annual Cost
Before Credit
Recovery CreditJ
Net Annualized Costs^
Total VOC Emission
Reduction (Mg/yr)1
Cost Effectiveness
($/Mg VOC)m
Incremental Cost
Effecti venessn
($/Mg VOC)
Quarterly
Inspections
0
--C
0
— c
— c
19
0
7.6
27
73
(46)
0.076
(610)
(610)
CONTROL T
Monthly
Inspections
0
— c
0
— c
— c
58
0
23
81
81
0
0.084
0
5,800
ECHNIQUE
Rupture
Disks
(new)
3,100b
600^
0
160
120
0
0
0
880
116
760
0.12
6,300
21,000
Rupture
Disks
(Retrofit)
4,200&
780<*
0
210
170
0
0
0
1,160
116
1,040
0.12
8,700
29,000
H-4
-------
Table 2. ANNUALIZED CONTROL COSTS PER COMPONENT
FOR PRESSURE RELIEF DEVICES3
(June 1980 Dollars) (Concluded)
Footnotes:
aA11 costs and emission reduction estimates are for one piece of
equipment in VOC service.
bSee BID Table 8-1. Assume 1/2 of relief valves controlled by rupture
disks with 3-way valves and 1/2 with rupture disk/block valve.
1995 + 4116 * 3100 (new); 3631 + 4764 = 4200 (retrofit)
2 I
CGost of monitoring instrument is not included in this analysis.
dObtained by multiplying capital recovery factor (2 years, 10 percent
interest = 0.58) by capital cost for rupture disk and capital recovery
factor (10 years, 10 percent interest = 0.163) by capital cost for all
other equipment (rupture disk holder, piping, valves, pressure relief
va 1 ve).
New installation cost = 0.163 (3100 - 230) + 0.58 (230) = 600
Retrofit installation cost = 0.163 (4200 - 230) + 0.58 (230) = 780
eLeaks are corrected by routine maintenance in the absence of the
standards; therefore, no cost is incurred for repair.
f0.05 x capital cost.
90.04 x capital cost.
"Monitoring labor hours (i.e., number of workers X number of components
x time to monitor x times monitored per year) x $18 per hour.
Assumes 2-man monitoring team per relief valve, 8 minutes monitoring
.time per valve, monitored quarterly or monthly.
10.40 x (monitoring cost + leak repair cost).
^Recovery credit based .on uncontrolled VOC emission factor of 0.33
kg/day and total hydrocarbon emission factor of 4.5 kg/day and recovered
VOC value of $192/Mg and recovered non-VOC hydrocarbon (methane-ethane)
value of $61/Mg from Table 8-5. Based on 63 percent control efficiency
for quarterly inspections, 70 percent control efficiency for monthly
inspections, and 100 percent control efficiency for rupture disks.
KTotal annual cost (before credit) minus recovery credit.
'Based on uncontrolled VOC emission factor and control efficiencies for
each control technique in footnote j.
^Obtained by dividing net annualized cost- by total VOC emission reduction.
"Incremental dollars per megagram = (net annual cost of control technique
- net annual cost of next less restrictive control) divided by (annual
reduction of next less restrictive control).
H-5
-------
Table 3. ANNUALIZED CONTROL COSTS FOR
COMPRESSOR SEALS - MODEL PLANT 8a
(June 1980 Dollars)
CONTROL TECHNIQUE
Closed vent and seal system
Installed Capital Costb
Annualized Capital
Control Equipment0
Annualized Operating
Costs
A. Maintenance^
8. Miscellaneous6
Total Annual Cost
Before Credit
Recovery Credit^
Net Annualized Cost9
Total VOC Emission
Reduction (Mg/yr)h
Cost Effectiveness
($/Mg VOC)i
25,100
4,100
1,300
1,000
6,400
0
6,400
14
460
H-6
-------
Table 3. ANNUALIZED CONTRTOl COSTS FOR
COMPRESSOR SEALS - MODEL PLANT
(June 1980 Dollars) (Concluded)
Footnotes:
fCosts and emission reduction are for 6 compressor seals (Model Plant B).
°Capital cost is based on 50 percent reciprocating and 50 percent centrif-
ugal compressors:
1. 3 double distance pieces @ $2750 (Reference 1) = $8250
2. 3 distance pieces piping systems @ $1100 (Reference 1)
, - = 3300
3. 3 centrifugal compressor seal vent piping
systems @ $169 [BID cost of $154 from
Table 8-1 plus 10 percent contingencies ($15)] = 507
4. Instrumentation system for purge gas supply
(Reference 1) = 1959
5. 1 flare (Reference 1) = 7340
6. Piping to flare (Reference 1)* = 3700
Total =$25,057
*It is assumed that centrifugal compressors and reciprocating
compressors are not used in the same plant. If the two types
of compressors are mixed, two flare piping systems might be
necessary. However, this case is considered unlikely because
(1) a new plant would typically use all of one type of com-
pressor, and (2) modified or reconstructed plants would be
unlikely to have both types of compressors fall under NSPS
.requi rements.
CO.163 (capital recovery factor) x capital costs; see BID Table 8-5.
a0.05 x capital cost.
SO.04 x capital cost.
fNo recovery credits are given for compressors because the cost analysis
is based on the captured emissions being flared. Compressor seal
vent emissions could be used for process heater fuel resulting in
recovery of these emissions at their fuel value or recycled to a
process line with a full product credit.
STotal annual cost (before credit) minus recovery credit
"Based on uncontrolled VOC emission factor of 2.3 Mg/yr and 100 percent
control efficiency for a closed vent and seal system. Compressor seal
.emission factor is from Reference 2.
'Obtained by dividing net annualized cost by total VOC emission reduction.
H-7
-------
Table 4. ANNUALIZED CONTROL COSTS PER COMPONENT
FOR OPEN-ENDED LINES*
(June 1980 Dollars)
CONTROL TECHNIQUE
Caps
Installed Capital Costb 61
Annualized Capital
Control Equipment0 9.9
Annualized Operating
Costs
A. Maintenance^ 3.0
B. Miscellaneous6 2.4
Total Annual Cost
Before Credit 15.3
Recovery Credit^ 28.1
Net Annualized Cost9 (12.8)
Total VOC Emission
Reduction (Mg/yr)n 0.124
Cost Effectiveness
($/Mg VOC)i (103)
aAll costs and emission reduction estimates are for one piece of
equipment in VOC service.
bSee BID Table 8-1.
C0.163 (capital recovery factor) x capital cost; see BID Table 8-5.
d0.05 x capital cost.
e0.04 x capital cost.
^Recovery credit based on uncontrolled VOC emission factor of 0.34.
kg/day and total hydrocarbon emission factor of 0.53 kg/day, BID
Table 3-1. Based on 100 percent control efficiency for caps and $192/Mg
(recovered VOC value) and $61/Mg (recovered non-VOC hydrocarbon value)
from BID Table 8-5.
9Total annual cost (before credit) minus recovery credit.
^Based on uncontrolled emission factor of 0.34 kg/day and 100 percent
.control efficiency for caps on open-ended lines.
Obtained by dividing net annualized cost by total VOC emission reduction.
H-8
-------
Table 5. ANNUALIZED CONTROL COSTS PER COMPONENT
FOR SAMPLING CONNECTION SYSTEMS
(June 1980 Dollars)3
CONTROL TECHNIQUE
Closed purge sampling system
Installed Capital Costb 530
Annualized Capital
Control Equipment0 86
Annualized Operating
Costs
A. Maintenance^ 26
B. Miscellaneous6 21
Total Annual Cost
Before Credit 133
Recovery Credit^ 7
Net Annualized Cost9 126
Total VOC Emission
Reduction (Mg/yr)n 0.018
Cost Effecti yeness
($/Mg VOC)1 7,000
aAll costs and emission reduction estimates are for one piece of
equipment in VOC service.
bSee BID Table 8-1.
cCapital recovery factor (10 years, 10 percent interest = 0.163) times
capital cost.
d0.05 x capital cost.
e0.04 x capital cost.
^Recovery credit based on average of inlet gas sampling emission factor
(VOC = 0.016 kg/day, THC = 0.32 kg/day) and product liquids emission
factor (VOC 0.085 kg/day, THC = 0.095 kg/day) from BID Table 3-1 and
recovered VOC value of $192/Mg and recovered non-VOC hydrocarbon
(methane-ethane) value of $61/Mg from BID Table 8-5. Based on 100 percent
control efficiency.
STotal annual cost (before credit) minus recovery credit.
"Based on average of gas and liquid sampling VOC emission factors in
.footnote f above.
Obtained by dividing net annualized cost by total VOC emission reduction.
H-9
-------
9 .
Table 6. ANNUALIZED CONTROL COSTS PER COMPONENT
FOR VALVES3
(June 1980 Dollars)
CONTROL TECHNIQUE
Quarterly Monthly
Inspections Inspections
Annualized Capital
Initial Leak
Repair6 0.84 0.34
Annualized Operating
Costs
LaOor
1. Monitoring^ 2.4 7.1
2. Leak Repair^ 3.3 3.9
3. Adminis-
trative and
support9 2.5 4.4
Total Annual Cost
Before Credit 9.5 IS
Recovery Credit' 15 15
Met Annual!zed Cost9 (5.5) 0
Total VOC Emission
Reduction (Mg/yr)n 0.051 0.055
Cost Effectiveness
(J/Mg VOCJi (110) 0
Incremental Cost
Effectiveness
($/Mg VOC)J (110) 1,400
aA11 costs and emission reduction estimates are for one piece of equipment
in VOC service.
6Annualized initial leak repair costs are obtained by: numoer of leaks
x repair time x labor rate x 1.4 (overnead) x 0.163. (Number of leans
based on 13 percent of valves leaking in initial survey.)
(0.13 x 1.13 hours x $18/hr x 1.4 x 0.163 > 0.34)
cMonitoring labor costs for valves based on the following: numoer of
valves screened (numoer of valves x fractioned screened) x monitoring
time (hours) x labor rate.
Quarterly: 3.34 x 2/60 x $18 - 2.4
Monthly: 11.79 x 2/60 x $18 • 7.1
dleak repair costs are based on the following: fraction of sources
maintained x repair time (hours) x laoor rate *
Quarterly: 0.185 x 1.13 x $18 > 3.8
Monthly: 0.191 x 1.13 x $18 • 3.9
*0.40 x (monitoring cost + leak repair cost).
'Recover/ credit based on uncontrolled VOC emission factor of 0.18 xg/day
and total hydrocarbon emission factor of 0.48 kg/day (BID Table 7-1),
and a recovered VOC value of 3192/Mg and recovered non-VOC hydrocaroon
(methane-ethane) value of $61/Mg from 310 Table 3-5. Based on 77 percent
control efficiency for quarterly Inspections and 34 percent control
efficiency for monthly inspections (BID Taole 7-1).
9Total annual cost (before credit) minus recovery credit.
"Based on uncontrolled VOC emission factor and control efficiencies
presented in footnote f.
'Net annual cost divided by total VOC emission reduction.
JSee Table 2, footnote n.
H-10
-------
10
Table 7. ANNUAL IZED CONTROL COSTS PER COMPONENT
FOR PUMPSa
(June 1980 Dollars)
~~~ CBSITBfll — n/'unnniig
Quarterly
Inspections
" _
Installed Capital
Cost
A. Sea! n
S. Barrier Fluid
System and
Degassing
Vents o
Annualized Capital Cost
A. Control Equipment0
1. Dual
Mechanical
Seal
o Seal o
o tnstal-
ation o
2. Barrier
Fluid
System and
Degassing
Vents o
3. Replacement
Seal 551
8. Initial Leak
Repair 22J
C. Initial Seal
Replacement 7.5Qk
Annualized Operating
Costs
A. Maintenance' 0
8. Miscellaneous"1 0
C. Labor
1. Monitoring" 20
2. Leak Repair0 110
3. Adminis-
tratove and
Support*? 52
total Annual Cost
Before Credit 270
Recovery Credit? 53
Net Annualized Cost 1 217
Total VOC Emission^
Reduction (Mg/yr) 0.26
Cost effect! veness
($/Mg VOCJS 830
Incremental Cost
Effectiveness
(J/Mg VOC)t 330
Liual Mecnanical
Seal System with
3arr1er Fluid
System and
Degassing Vents
Monthly
Inspections New Retrofit
— __
0 I250t> 1590&
0 5350& 5850°
0 560d 72Q6
0 49' 569
0 950" 95Qh
S-71
s/ 0 Q
22J o Q
7.SO<< o Q
0 355 372
0 234 298
44 00
120 n n
* *" ** U \J
66 00
320 2200 2400
59 91 91
261 2109 2309
0.29 Q.44 0.44
900 1800 5200
1500 12,000 14,000
H-n
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11
Table 7. ANNUALIZED CONTROL COSTS PER COMPONENT
FOR PUMPSa
(June 1980 Dollars) (Concluded)
Footnotes:
aAll costs and emission reduction estimates are for one piece of equipment
in VOC service.
bSee BID Table 8-1.
of monitoring instrument is not included in the analysis.
QFor new installation, annualized cost of dual seal = $1,250 (dual seal
cost) x 0.58 (capital recovery factor for 2-year life) less single seal
credit ($278 x 0.58).
eFor retrofit installation, annualized cost of dual seal is same as new
installation, except no single seal credit is given.
"Sixteen hours of installation at $18/hr, annualized over 10 years
(U.163 x $288),
9Nineteen hours of installation at $18/hr, annualized over 10 years
^ U • I 0 O X 4>o4c j ,
h0.163 x capital cost.
Replacement seal cost is 1/2 the cost of a new seal (old seal has
salvage value). Cost corrected to June 1980 dollars ($140/seal) is
based on Reference 3. Multiply replacement cost per seal by number
of leaks per year. For quarterly and monthly inspections, number
of leaks per pump equals 0.39 and 0.41, respectively (number of
.pumps x "fraction of sources operated on" from BID Table E-l).
JAnnualized initial leak repair costs from BID Tables 8-5 and 8-6.
Based on 33 percent of pump seals leaking in initial survey.
KInitial seal replacement cost = percent of pumps initially leaking
x replacement seal cost x capital recovery factor (0.33 x $140 x 0.163
= $ 7 .50 ) .
lo. 05 x capital cost.
m0.04 x capital cost.
"Monitoring labor and leak repair costs for pumps are based on
BID Table 8-3 plus weekly visual inspection cost (based on 0.5 minutes/
source, 52 times/yr, $18/hr) or $7.80 per source.
°0.40 x (monitoring cost + leak repair cost).
PRecovery credit based on uncontrolled VOC emission factor of 1.2 kg/day
and uncontrolled total hydrocarbon emission factor of 1.5 kg/day.
Recovered VOC value of $192/Mg and recovered non-VOC (methane-ethane)
value of $61/Mg are from Table 8-5. Based on 58 percent control efficiency
for quarterly inspections, 65 percent control efficiency for monthly
inspections, and 100 percent control efficiency for dual seal systems
(from BID Table 7-1).
ITotal annual cost (before credit) minus recovery credit.
rBased on uncontrolled VOC emission factors and control efficiencies in
footnote p.
JNet annualized cost divided by total VOC emission reduction.
"-See Table 2, footnote n.
H-12
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12
REFERENCES
1. Memorandum from K.C. Hustvedt to J.F. Durham, EPA:OAQPS. Revised
Cost Analysis for Reciprocating Compressor Seal Vent Controls.
February 23, 1983 (Docket No. A-80-20-B (VOC) II-B-37).
2. Memorandum from K.C. Hustvedt to J.F. Durham, EPA:OAQPS. Revised
Gas Plant Compressor Seal Emission Factor. February 10, 1983
(Docket No. II-B-35).
3. Fugitive Emission Sources of Organic Compounds - Additional Information
on Emissions, Emission Reductions, and Costs. U.S. EPA, OAQPS
EPA-450/3-82-010, April 1982, p. 5-19 (Docket No. II-A-25).
H-13
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APPENDIX I
REVISED PUMP SEAL LEAK DETECTION AND REPAIR
EMISSION REDUCTION
Attached as Appendix I is a memorandum dated December 7, 1983 that
describes the calculation of pump seal control emission reduction. Due to
an error made the inputs to the Leak Detection and Repair (LDAR) model
during the development of the BID, the values used throughout the BID
chapters and previous appendices are incorrect. The memorandum attached
documents the correct emission reduction values for natural gas plant pump
seals, as well as the correct pump seal control cost effectiveness values
for leak detection and repair programs.
-------
,ltos'",
/ ** % UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
I ^M^Z ' Office of Air Quality Planning and Standards
\*' cf Research Triangle Park, North Carolina 27711
MEMORANDUM
SUBJECT: Gas Plants Pump Seals Emission Reduction
FROM: K. C. Hustvedt
Petroleum Section/CPB
TO: James F. Durham, Chief
Petroleum Section/CPB
While I was preparing for our November 29, 1983, meeting with OMB on
the NSPS and CTG for VOC equipment leaks from gas plants, I recalculated
the cost effectiveness of leak detection and repair programs (LDRP) for
pump seals. In checking my results against the numbers developed for
the CTG and NSPS, I found that my new calculations estimated a much
higher emission reduction for all monitoring intervals. I discovered
that in our computer runs for gas plants we had used 87 percent emission
reduction for repair of leaking pump seals (F2 equals 0.13 in the leak
detection -and repair (LDAR) model)1, while in the AID2 we had used an F2
value of 0.028 (97.2 percent emission reduction). As discussed in the
AID, it is likely that repair (replacement) of a leaking pump seal will
result in essentially 100 percent emission reduction or an F2 of 0.00,
so that the AID value is a low estimate of the emission reduction from
repair. Because we feel the LDAR inputs developed in the AID are appropriate
for all of our VOC equipment leak projects, I have recalculated the pump
impacts using 0.028 for F2.
Attached are the LDAR model inputs and outputs for monthly, quarterly,
semiannual and annual LDRP. I have summarized the results of these runs,
including the incremental impacts between alternative LDRP, in Table 1.
The costs and emission reductions shown in Table 1 are based on 100 pump
seals to minimize effects of rounding on the calculated results. To correct
these numbers to model plant numbers, the costs or emission reductions
should be multiplied times the number of pump seals in the model plant divided
by 100. Since there are 6 pumps in model plant B, this means you would
multiply these numbers times 0.06 to get model plant B impacts. The cost
effectiveness numbers are independent of number of pumps so they are already
correct for all the model plants.
1-2
-------
REFERENCES
1.
2.
T. W. Rhoads, PES, Inc. to Docket A-80-20-B. "Evaluation of the Effects
of Leak Detection and Repair on Fugitive Emissions Using the LDAR Model "
November 1, 1982, Docket Reference Number II-B-18.
Fugitive Emission Sources of Organic Compounds—Additional Information
on Emissions, Emission Reductions, and Costs, EPA-450/3-82-010, April 1982,
Attachments
cc: Dianne Byrne, EPA/SDB
Fred Dimmick, EPA/SDB
Tom Norwood, PES~-
Tom Rhoads, PES
Docket A-80-20-B
1-3
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Table 1. LDAR ANALYSIS FOR NATURAL GAS PLANT PUMPS - CTG & NSPSa
Monitoring Emission Change Net Cost Cost Incremental
Interval Reduction E.R. Cost Change Effectiveness C/E
Case_ (Months) TPeTc^hT) WgTyFT IBgTyrT TITyrT TITyrT (l/Mgl U/Mg) Notes^_
M 1 87.2 38.2 23,200 610 .
4.0 3,200 800 M to Q
Q 3 78.0 34.2 20,000 587
5.8 700 121 Q to SA
SA 6 65.0 28.4 19,300 680
10.2 300 ' 29 SA to A
A 12 41.6 18.2 19,000 1,040
16.0 1,000 62 Q to A
a'Based on 100 pump seals.
blncrements between the two monitoring intervals shown.
-------
INPUT DATA
PLANT NATUGAS CTGINSPS
(FOR LIGU LIQUID PUMPS I
FOR EXAMINING EMISSION REDUCTIONS DUE TO LDARl
MONITORING INTERVAL I MONTHS) I
TURNAROUND FREQUENCY (MONTHS) 24
EMISSION FACTOR ( KG/HR/SOURCE ) 0.05
LEAK OCCURRENCE RATE (X PER PERIOD) 3 4
INITIAL '/. LEAKING . 33 0
EMISSIONS REDUCTION FOR UNSUCCESSFUL REPAIR (X) 0.0
EMISSIONS REDUCTION FOR SUCCESSFUL REPAIR (X) 97.2
EARLY LEAK RECURRENCE (X OF REPAIRS) 0 0
UNSUCCESSFUL REPAIR RATE (X) 0.0
UNSUCCESSFUL REPAIR RATE (X) AT TURNAROUND 0.0
i FOR EXAMINING THE COSTS OF LDAR:
en
TOTAL NUMBER OF SOURCES ]QO
MONITORING TIME PER SOURCE INSPECTION (MINUTES) 10.0
VISUAL MONITORING TIME PER SOURCE (MINUTES) 0.50
NUMBER OF VISUAL INSPECTIONS PER YEAR 52
REPAIR TIME PER SOURCE (MINUTES) 950
LABOR RATE (*/HOUR) ts
PARTS COST PER SOURCE (*) 149
ADMINISTRATIVE t SUPPORT OVERHEAD COST FACTOR (X) 40 0
CAPITAL RECOVERY FACTOR (X) 1ft.l
RECOVERY CREDIT FOR EMISSIONS REDUCTION (t/TW) 20?
FOR EXAMINING EMISSION REDUCTIONS DUE TO LDARt
MONITORING .INTERVAL (MONTHS) 3
TURNAROUND FREQUENCY (MONTHS) 24
-------
INPUT DATA
PLANT NATUGAS CTGiNSPS
IFOR LIGtT LIQUID PUMPS)
EMISSION FACTOR (KG/HR/SOURCE) 0.05
LEAK OCCURRENCE RATE (X PER PERIOD) 10.Z
INITIAL 'A LEAKING 33.0
EMISSIONS REDUCTION FOR UNSUCCESSFUL REPAIR (X) 0.0
EMISSIONS REDUCTION FOR SUCCESSFUL REPAIR (X) 97.Z
EARLT LEAK RECURRENCE (X OF REPAIRS) 0.0
UNSUCCESSFUL REPAIR RATE. (X) 0.0
UNSUCCESSFUL REPAIR RATE (X) AT TURNAROUND 0.0
FOR EXAMINING THE COSTS OF LDAR:
TOTAL NUMBER OF SOURCES "0
MONITORING TIME PER SOURCE INSPECTION (MINUTES) 10.0
VISUAL MONITORING TIME PER SOURCE (MINUTES) 0.50
NUMBER OF VISUAL INSPECTIONS PER YEAR 52
REPAIR TIME PER SOURCE (MINUTES) 960
LABOR RATE (J/HOUR ) '*
— PARTS COST PER SOURCE ($) 140
' ADMINISTRATIVE t SUPPORT OVERHEAD COST FACTOR (X) 40.0
CAPITAL RECOVERY FACTOR
-------
INPUT DATA
PLAMT NATUGA5 CTG«NSP3
(FOR LIGLT LIQUID PUMPS)
FOR EXAMINING THE COSTS OF IDARs
TOTAL NUMBER OF SOURCES 100
MONITORING TIME PER SOURCE INSPECTION (MINUTES) 10.0
VISUAL MONITORING TIHE PER SOURCE (MINUTES) 0.50
NUMBER OF VISUAL INSPECTIONS PER YEAR 52
REPAIR TIME PER SOURCE (MINUTES! 960
LABOR RATE (*/HOUR) 1«
PARTS COST PER SOURCE («) 140
ADMINISTRATIVE * SUPPORT OVERHEAD COST FACTOR (X) 40.0
CAPITAL RECOVERY FACTOR
-------
INPUT DATA
PLANT NATUGAS CTGtNSPS
(FOR LICIT LIQUID PUMPS I
LADOR RATE (I/HOUR) 18
PARTS COST PER SOURCE («l 1*0
ADMINISTRATIVE * SUPPORT OVERHEAD COST FACTOR (XI 40.0
CAPITAL RECOVERY FACTOR (XI 16.3
RECOVERY CREDIT FOR EMISSIONS REDUCTION (»/M6l 807
oo
-------
SUMMARY OF ESTIMATED EMISSION FACTORS tKG/MR I AND PERCENT REDUCTION
IN MASS EMISSIONS FOR PUHPS/LIGLT LIQUID SERVICE Bt TURNAROUND - PLANT NATUGAS CTGtNSPS
PERCENT REDUCTION
TURNAROUND
PERIOD
1
2
3
1
2
3
1
2
3
1
2
3
MEAN EMISSION-KG/HR
0.0064
0.0064 M*fl
0.0064
0.0110
0.0110 OM£<
0.0110
0.0175
0.0175 V€*M
0.0175 '
0.0292
0.0292 A.JV
0.0292
COMPARED TO
INITIAL EMISSION
/B7.2
IH.1 *87.2
^87.2
XVe.o
T6U4 2 78.0
\78.0
X65.0
»-«. f "•'
\65.0
/41.6
rA/A*U ? 41.6
/
I 41.6
COMPARED TO EMISSION
FOR WHICH NO MAINTENANCE
MAS DONE DURING PERIOD
92.2
81.3
81.3
86.7
69.8
69.8
78.8
56.5
56.5
65.1
38.3
38.3
'
1
-------
PLANT NATUGAS CTGtNSPS SUMMARYI
AVERAGE ANNUAL COST EFFECTIVENESS
I MONTHLY LDARI
l
o
SOURCE TYPE
PUMPS
LI6LT LIQUID
LIGLT LIQUID
LIGLT LIQUID
LIGLT LIQUID
EMISSION
REDUCTION
tHG/YR)
38.8
34.8
88.4
18.8
RECOVERY
CREDIT
1 7,910
7,070
5,690
3,770
NET
COSTS
* 83.300
80,000
19,300
19,000
GROSS COST
EFFECTIVENESS
IPER MG»
1 817
794
887
1,850
NET COST
EFFECTIVENESS
IPER MB)
i MO r
587 i
680 ?
1,040 /
TOTAL
119
84.600
81.700
893
«86
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TECHNICAL REPORT DATA
(Please read Instructions on the revenf before completing)
1. REPORT NO.
EPA-450/3-82-0243
4. TITLF AND SUBTITLE
Equipment Leaks of VOC in Natural Gas Production
Industry - Background Information for Proposed Standards
3. RECIPIENT'S ACCESSION NO.
5. ''"PORT
December "1983
G. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Office of Air Quality Planning and Standards
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
12. SPONSORING AGENCY NAME AND ADDRESS
Director for Air Quality Planning and Standards
Office of Air, Noise, and Radiation
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
14. SPONSORING AGENCY CODE
EPA/200/04
15. SUPPLEMENTARY NOTES ~ — • —
This report discusses the regulatory alternatives considered during development of the
the environmental and economic impacts
Standards of performance for the control of VOC emissions from equipment leaks
at natural gas processing plants are being proposed under Section ill of the Clean
Air Act. This document contains background information and environmental and
economic impact assessments of the regulatory alternatives considered in developing
the proposed standards. b
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
Air pollution
Pollution control
Standards of performance
Volatile organic compounds
Natural Gas Production
Fugitive emissions
(VOC)
8. DISTRIBUTION STATEMENT
Unlimited
EPA Fo,m 2220-1 (Re». 4-77) PREV.OUS EDITION .s OBSOLETE
b.lDENTIFIERS/OPEN ENDED TERMS
Air Pollution Control
19. SECURITY CLASS (ThisReport)
Unclassified
2O. SECURITY CLASS (Thispage)
Unclassified
c. COSATI Field/Group
T3T
21. NO. OF PAGES
230
22. PRICE
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