Unrt»dSt«t«
Environmental Protection
AQWWV
Office of Air Quality
Planning and Standards
Research Triangle Park NC 27711
MAY 1982
Air
Draft
EIS
VOC Fugitive
Emissions in
On-Shore
Natural Gas
Production Industry
Background Information
for Proposed Standards
Preliminary Draft
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NOTICE
This document has not been formally released by EPAand should not now be construed to represent Agency policy.
It is being circulated for comment on its technical accuracy and policy implications.
VOC Fugitive Emissions in On-Shore
Natural Gas Production Industry
Background Information
for Proposed Standards
Emission Standards and Engineering Division
MAY 1982
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air, Noise, and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
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This report has been reviewed by the Emission Standards and Engineering Division of the Office of Air
Quality Planning 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, N.C. 27711, or from the National Technical Information Services, 5285 Port Royal Road,
Springfield, Virginia 22161.
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TABLE OF CONTENTS
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 1-2
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 2-10
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
iii
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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 4-11
4.4 References 4-18
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 7-9
7.4 Solid Waste Impact 7-9
7.5 Energy Impacts 7-9
7.6 Other Environmental Concerns 7-10
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 8-27
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TABLE OF CONTENTS (Concluded)
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
A.I Literature Review A-2
A.2 Plant Visits A-4
A.3 Emission Source Testing A-5
A.4 Meetings with Industry A-5
A.5 Review Process A-6
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 References for Appendix C C-7
D Emission Measurement and Continuous Monitoring. . . . D-l
D.I Emission Measurement Methods D-2
D.2 Continuous Monitoring Systems and Devices D-6
D.3 Performance Test Method D-7
D.4 References D-9
E Model for Evaluating the Effects of Leak
Detection and Repair on Fugitive Emissions from
Pumps and Valves E-l
E.I Introduction E-l
E.2 Description of Model E-l
E.3 Model Outputs E-3
E.4 References E-32
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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
Model Gas Plant 3-11
4-1 Percentage of Components Predicted to be Leaking In An
Individual Component Survey 4-4
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 Regulatory Alternatives for Fugitive VOC Emission
Sources at Gas Processing Plants. 6-8
7-1 Controlled Emission Factors for Various Inspection
Intervals . 7-2
7-2 Emissions for Regulatory Alternatives 7-4
7-3 Annual Model Plant Emissions and Percent Emission
Reduction From Regulatory Alternative I and From
Previous Regulatory Alternative 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 7-11
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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 8-6
8-3 Leak Detection and Repair Labor-Hour Requirements .... 8-10
8-4 Leak Detection and Repair Costs 8-11
8-5 Derivation of Annualized Labor, Administrative,
Maintenance, and Capital Costs 8-12
8-6 Labor-Hour Requirements for Initial Leak Repair 8-13
8-7 Initial Leak Repair Costs 8-15
8-8 Recovery Credits 8-16
8-9 Annual Cost Estimates 8-17
8-10 Cost Effectiveness of Regulatory Alternatives 8-20
8-11 Cost Effectiveness by Component Type of Alternative
Techniques for Control of Fugitive VOC Emissions From
Natural Gas Plants (Model Plant B) 8-23
8-12 Fifth-Year Nationwide Costs of the
Regulatory Alternatives 8-25
8-13 Statutes That May Be Applicable to the Natural Gas
Processing Industry 8-26
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
vii
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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-5
C-3 Soap Screening Data for API-Tested and
EPA-Tested Gas Plants C-6
E-l Results of the Modeled Leak Detection and
Repair (LDR) Programs ..... E-4
E-2 Statistical Analysis (SAS) Program to Evaluate the Impact
of a Maintenance Program on Fugitive Emissions
From Valves and Pumps E-5
E-3 Input Data for Examining the Reduction in Average Leak
Rate Due to a Maintenance Program (Valves) E-18
E-4 Input Data for Examining the Reduction in Average Leak
Rate Due to a Maintenance Program (Pumps) E-19
E-5 Estimated Emission Factors and
Mass Emission Reductions (Valves) E-20
E-6 Estimated Emission Factors and
Mass Emission Reductions (Pumps) ....... E-21
E-7 Fraction of Sources Screened and Operated on by Year
(Valves) E-22
E-8 Fraction of Sources Screened and Operated on by Year
(Pumps) E-23
E-9 Fraction of Sources Screened and Operated on by Month
(Valves) E-24
E-10 Fraction of Sources Screened and Operated on by Month
(Pumps) E-25
E-ll Estimated Emission Factors and Mass Emission
Reduction by Quarter (Valves) E-26
E-12 Estimated Emission Factors and Mass Emission
Reduction by Quarter (Pumps) E-27
E-13 Fractional Distribution of Sources by Period (Valves) . . E-28
E-14 Fractional Distribution of Sources by Period (Pumps) . . E-30
VTM
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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 3-7
3-5 Diagram of a spring-loaded relief valve 3-7
4-1 Rupture disk intallation upstream of a relief valve . . . 4-14
4-2 Diagram of two closed-loop sampling systems 4-17
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-2
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1. 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 from valves, relief valves, open-ended lines, compressor
seals, pump seals, and sampling connections.
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:
Quarterly instrument monitoring for leaks from valves, relief
valves, and compressor seals;
Quarterly instrument and weekly visual monitoring for leaks
from pump seals; and
Installation of caps (including plugs, flanges, or second
valves) on open-ended lines.
Regulatory Alternative III is more restrictive than Alternative II.
The requirements are as follows:
Monthly monitoring of valves (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);
Monthly monitoring of relief valves and pump seals, and weekly
visual inspection of pump seals;
Installation of a vent control system to control compressor
seal emissions;
Installation of closed purge sampling systems on sampling
connections; and
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t 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
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
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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.
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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
Air
Impact
0
+2**
+2**
+2**
Water
Impact
0
+1**
+1**
+1**
Solid
Waste Energy Noise
Impact Impact Impact
000
0 +1* 0
0 +1* 0
0 +1* 0
Economic
Impact
0
+1*
-i.
-I*
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. 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 technolo-
gies 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, herein-
after 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 construc-
tion 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 list the categories of major stationary sources
that have not already been listed and regulated under standards of perfor-
mance. Regulations must be promulgated for these new categories on the
following schedule:
a. 25 percent of the listed categories by August 7, 1980.
b. 75 percent of the listed categories by August 7, 1981.
c. 100 percent of the listed categories by August 7, 1982.
A governor of a State may apply to the Administrator to add a category not
on the list or may apply to the Administrator to have a standard of perfor-
mance revised.
2. EPA is required to review the standards of performance every
4 years and, if appropriate, revise them.
3. EPA is authorized to promulgate a standard based on design, equip-
ment, work practice, or operational procedures when a standard based on
emission levels is not feasible.
4. 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.
5. 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
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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. Con-
gress does not intend that new source performance standards contribute to
these problems. Fifth, the standard-setting process should create incen-
tives for improved technology.
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 signi-
ficant 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))
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Although standards of performance are normally structured in terms of
numerical emission limits where feasible, alternative approaches are some-
times 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 stan-
dard 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 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 Admini-
strator must find: (1) a substantial likelihood that the technology will
produce greater emission reductions than the standards require or an equi-
valent 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
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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 implementing
the Clean Air Act. Often, these "areas" are actually pollutants 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) esti-
mated 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 endan-
ger 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
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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.
After the source category has been chosen, the types of facilities
within the source category to which the standard will apply must be deter-
mined. A source category may have several facilities that cause air pollu-
tion, 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 demon-
strated control practice; (2) adequately consider the cost, the nonair-
quality 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.
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During the information-gathering phase, industries are queried through
a telephone survey, letters of inquiry, and plant visits by EPA representa-
tives. 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 data, and existing
State regulations governing emissions from the source category are then
used in establishing "regulatory alternatives." These regulatory alterna-
tives are essentially different levels of emission control.
EPA conducts studies to determine the impact of each regulatory alterna-
tive 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 represen-
tatives 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.
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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 regula-
tion, 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 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.
2-8
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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 cap-
tured potential air pollutants may pose a solid waste disposal problem. The
total environmental impact of an emission source must, therefore, be ana-
lyzed 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-
2-9
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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)).
Nevertheless, the Agency has concluded that the preparation of environ-
mental 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 environ-
mental 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 asso-
ciated 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
2-10
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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, 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/gasoline processing plants are a part of the oil and
gas industry. Natural 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/gasoline
processing plants are defined as facilities engaged in the separation of
natural gas liquids from field gas and 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
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
Methane
to Sales
Sales Products
(ethane, propane, iso-butane, butane, natural gasoline, etc.)
Figure 3-1. General Schematic of Natural Gas-Gasoline Processing,
3-2
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types, such as the positive-displacement, reciprocating and rotary
action, and special canned and diaphragm pumps, may also be used.
Natural gas liquids 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
2
by a lubricant that flows between the packing and the shaft.
Packing
Gland
Atmosphere
End
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
3-3
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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 to remove frictional heat. However, because of its
construction, much less lubricant is needed.
PUMP
STUFFING
BOX
GLAND
'RING
FLUID
END
STATIONARY
ELEMENT
POSSIBLE
LEAK AREA
SHAFT
»ROTATING
SEAL RING
Figure 3-3. Diagram of a basic single mechanical seal.2
3.2.2 Compressors
Gas compressors used in process units are similar to pumps in that
they can be driven by rotary or reciprocating shafts. They are also
similar to pumps in their need for shaft seals to isolate the process
gas from the atmosphere. As with pumps, these seals can be the source
of fugitive emissions 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
3-4
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lubricant is supplied to the seal faces. Mechanical seals can achieve
the lowest leak rates of the tyes identified above, but they are not
3
suitable for all processing 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,
compressor seals are normally enclosed and vented outside of the compressor
building. If hydrogen sulfide is present in the gas, then the vented
vapors are normally flared.
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 configurator 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.
3-5
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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
o
reattained, the valve reseats, and a seal is again formed. 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
2
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. Examples are purge valves,
drain valves, and vent valves. A faulty valve seat or incompletely
closed valve would result in leakage through the open-end of the line
and fugitive 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 non-welded
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.
3-6
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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.
3-7
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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 some services undergo; this results in the deformation of the
q
seal between the flange faces. 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 or vapor is sometimes drained onto the ground or into a
drain, where it can evaporate and release VOC emissions 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
-i y
four plants were tested by Radian Corporation under contract to EPA.
Baseline fugitive emission factors for six of the seven component types
12
were developed from these data. The baseline emission factor for one
component type, sampling connections, was developed from refinery 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.
3-8
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Table 3-1. BASELINE FUGITIVE EMISSION FACTORS FOR
GAS PLANTS, kg/day
Component
Valves3
Relief valves9
Open-ended lines3
Compressor seals3
Pump seals3
Sampling connections
Flanges and3
connections
Emission factor
0.18
0.33
0.34
1.0
1.2
0.36
0.011
(0.48)
(4.5)
(0.53)
(4.9)
(1.5)
(0.36)
(0.026)
95% Confidence interval
0.1-0.3
0.007-8
0.1-0.7
0.1-5
0.5-3
0.006-0.02
(0.2-1)
(0.1-100)
(0.2-1)
(0.7-30)
(0.5-4)
(0.01-0.05)
xx = VOC emission values.
(xx)= Total hydrocarbon emission values.
Reference 12.
Sufficient data are not available to estimate the amount of methane-
ethane present. Therefore, the total hydrocarbon emission value is
assumed to be equal to the VOC emission value. Confidence intervals
are not available. Reference 13.
3-9
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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 MODEL GAS PLANT
Component Number of
type components
Valves
Relief valves
Open-ended lines
Compressor seals
Pump seals
Sampling connections
Flanges and 3
connections
750
12
150
6
6
21
,000
Total baseline emissions
Baseline
emissions,
kg/day
140
4.0
51
6.0
7.2
7.6
33
249
(360)
( 54)
( 80)
( 29)
( 9.0)
( 7.6)
( 78)
(618)
Percentage of
total emissions
56
2
20
2
3
3
13
(58)
( 9)
(13)
( 5)
( 1)
( 1)
(13)
xx = VOC emission values.
(xx) = Total hydrocarbon emissions values.
aFrom Table 3-1.
3-11
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3.4 REFERENCES
1. Cantrell, A. Worldwide Gas Processing. Oil and Gas Journal,
July 14, 1980. p. 88.
2. Erikson, D.G., and V. Kalcevic. Emissions Control Options for the
Synthetic Organic Chemicals Manufacturing Industry, Fugitive Emissions
Report, Draft Final. Hydroscience, Inc., 1979.
3. Nelson, W.E. Compressor Seal Fundamentals. Hydrocarbon Processing,
56(12):91-95. 1977.
4. Telecon. R.A. McAllister, TRW, to G.H. Holliday, Shell Oil, Houston,
Texas. March 10, 1981. Compressors and seals at gas plants.
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.
6. Lyons, J.D., and C.L. Ashland, Jr. Lyons' Encyclopedia of Valves.
New York, Van Nostrand Reinhold Co., 1975. 290 p.
7. Templeton, H.C. Valve Installation, Operation and Maintenance.
Chem. E., 78(23)141-149, 1971.
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.
9. McFarland, I. Preventing Flange Fires. Chemical Engineering
Progress, 65(8):59-61. 1969.
10. Letter from Hennings, T.J., TRW to K.C. Hustvedt, EPA. June 30, 1981.
Results of a telephone survey concerning control of fugitive emissions
from gas plant compressor seals.
11. Eaton, W.S., et al. Fugitive Hydrocarbon Emissions from Petroleum
Production Operations. API Publication No. 4322. March 1980.
12. DuBose, D.A., J.I. Steinmetz, and G.E. Harris. Emission Factors
and Leak Frequencies for Fittings in Gas Plants, Draft Final Report.
Radian Corp. September 8, 1981.
13. Memo from Hustvedt, K. C. , EPA to J. F. Durham, EPA. Development
of a sampling connection purge emission factor. October 13, 1981.
3-12
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4. 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.
This chapter (Section 4.4) 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.
4-1
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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)
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 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 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 equip-
ment 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.
4-2
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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 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 on ground levels 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
available 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 con-
centration 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 indica-
tions; 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. Elevated hydrocarbon
4-3
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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
Pump seals3
>100,000 ppmv
9
8
20
10
Predicted
> 50, 000 ppmv
11
11
27
22
percent of sources leaking
> 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.
-------
concentrations 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
A
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 units may be required;
and the portable instrument is also 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 for
, . 5
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
4-5
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material to be positioned improperly in the valve and allow leakage.
Valves that are not often used can build up a "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 Relief valves. In general, 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 relief valve without shutting down the process, a
block valve should be attached while the faulty valve is repaired and
tested. As an alternative to the potential hazard introduced by the
change of a block valve being mistakenly closed when a vessel is over-
pressured, it may be preferable to install a second block valve and
relief valve for use when the first relief valve is under repair. An
even safer alternative is to install a three-way valve with parallel
7 8
relief systems so that one of the two relief systems is always open. '
Some relief valves may be difficult to monitor. It may be appropriate
to require less frequent monitoring for relief valves that are difficult
to access because of location or hazardous operating conditions.
4.2.2.3 Compressor seals. Leaks from reciprocating compressor
seals may be reduced by the same repair procedures that were described
for pumps. If the leak is small, temporary emissions resulting from a
shutdown may be greater than the emissions from the leaking seal. It is
4-6
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anticipated that for many reciprocating compressor seals it will not be
possible to bring leaks under the designated action level. In these
instances i't 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 would have
no effect or possible 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
4-7
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oo
Table 4-2. PERCENT OF TOTAL EMISSIONS AFFECTED AT VARIOUS
LEAK DEFINITIONS
Percent of mass emissions affected at this leak definition
Component type
Valvesb
Relief valvesc
Compressor seals
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
67
87
72
(83)
(69)
(88)
(71)
10,000 ppmv
86
77
92
79
(87)
(77)
(93)
(79)
1,000 ppmv
97
96
99
94
(98)
(96)
(99)
(94)
xx = VOC emission values.
(xx) = Total hydrocarbon emission valves.
These 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.
-------
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
than 10,000 ppm. Maintenance programs on valves have shown that emission
reductions are possible through on-line repair for essentially all
valves with non-zero 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. ' ' Therefore, 10,000 ppm seems to be the most reasonable
leak definition to direct maintenance effort at the bulk of the valve
emissions 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 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
4-9
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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 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 to estimation
of emission reduction presented here is to reduce this theoretical
maximum control efficiency by accounting quantitatively for those factors
outlined above.
4-10
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There are two models available for estimation of reduction efficiency
from leak detection and repair. Both models are used in this BID. The
first 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
for relief valves and compressors. Therefore, a second model is applied
to these sources. The 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
repaired.
C = Non-Instantaneous 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 model
presented in Appendix E.
4.3 PREVENTIVE PROGRAMS
An alternative approach to controlling fugitive VOC emissions from
gas plant operations is to replace components with leakless equipment.
4-11
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Table 4-3. VOC EMISSION CORRECTION FACTORS FOR VARIOUS INSPECTION INTERVALS,
ALLOWABLE REPAIR TIMES, AND LEAK DEFINITIONS
Component type
Leak occurence and
recurrence correction
factor
Non-i nstantaneous
repair correction
factor
Imperfect repair correction factor
Inspection interval
Allowable repair
time (days)
Leak definition (ppmv)
Quarterly Monthly
15
100,000
50,000 10,000
1,000
Relief valves
Compressor seals
0.90 0.95 0.98 0.99 0.92
(0.99)
0.90 0.95 0.98 0.99 0.98
(0.97)
0.91
(0.99)
0.98
(0.96)
0.89
(0.99)
0.97
(0.95)
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.
Factor accounts for emissions that occur between detection of a leak and subsequent repair. Reference 11.
Factors 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.
-------
-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 Relief Valves
A rupture disk can be used upstream of a safety/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 safety/relief valve
will relieve the pressure. Figure 4-1 is a diagram of a rupture disk
and safety/relief valve installation. The installation is arranged to
prevent disk fragments from lodging in the valve and prevent 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
safety/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 is also necessary to
install a block valve upstream of the rupture disk so that the disk can
be isolated and repaired on-line without shutting down the unit. Alter-
nately, to prevent possible overpressure while using a block valve, a
parallel system of relief valves and rupture disks can be installed so
that one rupture disk/relief valve is in operation while the other is
being repaired.
Use of a rupture disk upstream of a safety/relief valve would
eliminate leaks due to improper seating of the relief valve. Also, the
disk can extend the life of a safety/relief valve by protecting it
against system materials that could be corrosive and thereby cause seal
degradation.
4.3.2 Compressor Seals
Leaks from compressor seals can be controlled by enclosing the seal
area or distance piece and installing piping to vent the emissions to a
suitable combustion device. Installation of check valves in the piping
will prevent back pressure in the line, will serve to maintain a positive
pressure to prevent air intake to the system, and will allow release of
vapors to the combustion device only when the pressure reaches a suffi-
cient level. Obtaining a good seal at the distance piece door and at
4-13
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Tension-adjustment
thimble
Spring
To
atmospheric
vent
BLIND FLANGE
CONNECTION FOR
PRESSURE GAUGE
& BLEED VALVE
FROM SYSTEM
Figure 4-1. Rupture disk installation upstream of a relief valve.
4-14
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the point where emissions are vented from the distance piece or seal
area is necessary for maintaining a sufficient pressure (e.g., 15 to
20 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 during compressor maintenance. It
should not be necessary to install an auxiliary compressor to vent
I y
emissions to the combustion device. There may be instances where
retrofitting of such a vent control system to a compressor distance
13
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 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 environment, 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 degassing emissions to a control
device, such as a process heater, or vapor recovery system. Control
4-15
-------
-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 to detect failure
3
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
Fugitive emissions from open-ended lines are caused by leakage
through the seat of a valve upstream of the open end of the line.
Fugitive emissions from open-ended lines can be controlled by installing
a cap, plug, flange, or second valve to the open end of the line. In
the case of a second valve, the upstream valve should always be closed
first after the use of the valves. Each time the cap, plug, flange, or
second valve is opened, any VOC that has leaked through the first valve
seat will be released. These emissions have not been quantified. The
control efficiency will be dependent on the frequency of removal of the
cap or plug. Caps, plugs, etc. for open-ended lines do not affect
emissions that may occur during use of an upstream valve. These emissions
may be caused by line purging for sampling, draining, or venting.
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
14
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.
4-16
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Process Line
Process Line
I
I"
^1
LJ
Sample
Container
Sample
Container
Figure 4-2. Diagram of Two Closed-Loop Sampling Systems.
-------
4.3.6 Gas-OperateoSCpntrol 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.
4-18
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4.4 REFERENCES
1. DuBose, D.A., J.I. Steinmetz, and G.E. Harris. Emission Factors
and Leak Frequencies for Fittings in Gas Plants, Draft Final Report.
Radian Corporation. September, 1981.
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.
3. Erikson, D.G. and V. Kalcevic. Emissions Control Options for the
Synthetic Organic Chemicals Manufacturing Industry, Fugitive Emissions
Report. Hydroscience, Inc. Knoxville, TN. For U.S. Environmental
Protection Agency. Research Triangle Park, NC. Draft Report for
EPA Contract Number 68-02-2577. February 1979.
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.
5. Hustvedt, K.C. , R.A. Quaney, andW.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.
6. Teller, James H. Advantages Found in On-Line Leak Sealing. Oil
and Gas Journal, 77(29):54-59, 1979.
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.
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.
9. Letter with attachments from H. H. McClure, Texas Chemical Council,
to W. Barber, EPA. June 30, 1980. Appendix B, page 11.
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.
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.
4-19
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12. Letter and attachment from Hennings> T.J., TRW to K.C. Hustvedt,
EPA. June 30, 1981. Results of a telephone survey concerning
control of fugitive emissions from gas plant compressor seals.
13. 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.
14. Letter and attachments from McClure, H.H., Texas Chemical Council,
to Patrick, D.R., EPA. May 17, 1979.
4-20
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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. 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-Thompson, 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
2
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
4
under contract to the American Petroleum Institute. The number of
sampling connections is based on the ratio of sampling connections to
open-ended lines as determined at refineries.
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, number of vessels appears to be best suited to this
need. Example types of equipment included and excluded in vessel inven-
tories 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, 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 model
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
-------
Table 6-1. EXAMPLE TYPES OF EQUIPMENT INCLUDED AND EXCLUDED IN
VESSEL INVENTORIES FOR MODEL PLANT DEVELOPMENT
Included
Excluded
1. Absorption/Desorption 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
EPA tested plants3
Vessels
Valves
Relief valves
Open-ended lines
Compressor seals
Pump seals
Flanges and connections
A
31
508C
16C
62C
0
1C
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.
"Only 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 VESSELS0
I
01
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
C
37.0
0.2
7.4
0.4
0.4
170.8
tested 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
Number of components
Component type
Valves3
Relief valves3
Open-ended lines3
Compressor seals3
Pump seals3
Sampling connections
Flanges and connections3
Model plant
A
(10 vessels)
250
4
50
2
2
7
1,000
Model plant Model plant
B C
(30 vessels) (100 vessels)
750 2
12
150
6
6
21
3,000 10
,500
40
500
20
20
70
,000
Number of components based on average ratios presented in Table 6-3.
'Number of components based on ratio of sampling connections to open-ended
lines at refineries (Reference 5).
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.
The 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 tn
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
-------
Table 6-5. REGULATORY ALTERNATIVES FOR FUGITIVE VOC EMISSION SOURCES AT GAS PROCESSING PLANTS
cr>
co
Component type
Valves
Relief valves
Open-ended lines
Sampling connections
Compressor seals
Pump seals
I II
Monitoring Equipment
interval specification
baseline quarterly
control
(no NSPS)
quarterly
cap
none
quarterly
quarterly,
weekly visual
Regulatory
Monitoring
interval
monthly/
quarterly
monthly
monthly,
weekly visual
Alternative
III
Equipment
specification
cap
closed purge
sampling
compressor vent
control
IV
Monitoring Equipment
interval specification
monthly
rupture disc
cap
closed purge
sampling
compressor vent
control
dual seals
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
-------
6.4 REFERENCES
1. Cantrell, A. Worldwide Gas Processing. Oil and Gas Journal, July
14, 1980. p. 88.
2. Assessment of Atmospheric Emissions from Petroleum Refining, Volume
3, Appendix B. EPA 600/2-80-075c, April 1980. Pages 266 and 280.
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.
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.
5. VOC Fugitive Emissions in Petroleum Refining Industry - Background
Information for Proposed Standards. U.S. EPA, OAQPS. April 1981.
6. Eaton, W.S., et al. Fugitive Hydrocarbon Emissions from Petroleum
Production Operations. API Publication No. 4322. March 1980.
6-10
-------
7. 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. For relief
valves and compressor seals, these factors were calculated by multiplying
the baseline emission factor for each component type by a control efficiency
factor. Derivation of these factors is explained in Chapter 4 and
Appendix E.
-------
Table 7-1. CONTROLLED EMISSION FACTORS FOR VARIOUS INSPECTION INTERVALS
--J
I
ro
Source
type
Valves
Relief
valves
Compressor
seals
Pump
seals
Inspection
interval
quarterly
monthly/quarterly
monthly
quarterly
monthly
quarterly
quarterly
monthly
Baseline
emission factor
(kg/day)
0.
0.
0.
0.
0.
1.
1.
1.
18
18
18
33
33
0
2
2
(0.
(0.
(0.
(4.
(4.
(4.
(1.
(1.
48)
48)
48)
5)
5)
9)
5)
5)
Correction factors
Ab Bc Cd D* e
0.
0.
0.
0.78 0.90 0.98 0.89 (0.99) 0.
0.78 0.95 0.98 0.89 (0.99) 0.
0.92 0.90 0.98 0.97 (0.95) 0.
0.
o.
Control ,
ifficiency
77
78
84
61
65
79
58
65
(0.
(0.
(0.
(0.
(0.
(0.
(0.
(0.
77)
78)
84)
68)
72)
77)
58)
65)
Controlled
emission factor^
(kg/day)
0.041
0.041
0.029
0.13
0.12
0.21
0.50
0.42
(0.11)
(0.11)
(0.079)
(1.4)
(1.3)
(1.1)
(0.63)
(0.53)
xx = VOC emission values.
(xx) = Total hydrocarbon emission values.
aFrom Table 3-1.
Theoretical maximum control efficiency at a leak definition of 10,000 ppmv. From Table 4-2.
Lead occurrence and recurrence correction factor. Assumed to be 0.90 for quarterly inspection and 0.95 for monthly inspection.
Non-instantaneous repair correction factor. For a 15-day maximum allowable repair time, assuming a 7.5 day average repair time yields
a 0.98 yearly correction factor: [365 - (15/2)]/365 = 0.98.
elmperfect repair correction factor. Calculated as 1 - (f/F), where f = average emission rate for sources at 1000 ppm and F = average
emission rate for sources greater than 10,000 ppm. From Table 4-3.
Control efficiencies for valves and pump seals are developed on the basis of the model described in Appendix E. Control efficiencies
for relief valves and compressor seals are equal to AxBxCxD.
Controlled emission factor = baseline emission factor x [1 - control efficiency]. Values for valves and pump seals are provided
in Appendix E, Tables E-5 and E-6.
-------
The impacts of the regulatory alternatives on valves and pump seals
were determined through use of a mathematical model described in Appendix E.
This model was used in place of the approach "described in Chapter 4
because of the options that are included to evaluate alternative leak
detection and repair programs and because of recently available maintenance
data. In the case of valves, a "monthly/quarterly" (rather than a
"monthly" or "quarterly") leak detection and repair program (outlined in
Chapter 6) is included in Regulatory Alternative III. Because this
program cannot be satisfactorily evaluated by means of the Chapter 4
approach, the model described in Appendix E was used to evaluate each of
the regulatory alternatives with respect to valves. Also, the model has
incorporated actual data on leak occurrence, recurrence, and repair
collected at refineries. It is recognized that the" data collected at
refineries may not be entirely representative of similar information
that could be collected at gas plants. However, use of the data in
estimating potential emission reductions is considered more appropriate
than disregarding it in favor of the approach taken in Chapter 4 which
relies heavily on engineering judgement.
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 relative control effectiveness of Regulatory Alternatives II through
IV over Alternative I (baseline emissions) and also each regulatory
alternative over 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
7-3
-------
Table 7-2. EMISSIONS FOR REGULATORY ALTERNATIVES (MODEL PLANT A)
Component
type
Valves
Relief valves
Open-ended
lines
Compressor
seals
Pump seals
Sampling
connections
Flanges and
connections
Total
I
Baseline
emissions,
kg/day
45
1.
17
2.
2.
2.
11
81
(120)
3 (18)
(27)
0 (9.8)
4 (3.0)
5 (2.5)
(26)
(206)
Percent
total
emissions
56 (58)
2 (9)
21 (13)
2 (5)
3 (1)
3 (1)
14 (13)
II
Controlled
emissions,
kg/day
10
0.52
0.0
0.42
1.0
2.5
11
25
(28)
(5.6)
(0.0)
(2.2)
(1.3)
(2.5)
(26)
(66)
Regulatory Alternative
III
Percent
total
emissions
39 (43)
2 (9)
0 (0)
2 (3)
4 (2)
10 (4)
43 (40)
Controlled
emissions,
kg/day
10
0.48
0.0
0.0
0.84
0.0
11
22
(28)
(5.2)
(0.0)
(0.0)
(1.1)
(0.0)
(26)
(60)
Percent
total
emissions
45 (46)
2 (9)"
0 (0)
0 (0)
4 (2)
0 (0)
49 (43)
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)
11 (26)
18 (46)
Percent
total
emissions
40 (43)
0 (0)
0 (0)
0 (0)
0 (0)
0 (0)
60 (57)
-------
Table 7-2. CONTINUED (MODEL PLANT B)
Regulatory Alternative
Component
type
Valves
Relief valves
Open-ended
lines
Compressor
seals
Pump seals
Sampling
connections
Flanges and
connections
Total
I
Baseline
emissions,
kg/day
140 (360)
4.0 (54)
51 (80)
6.0 (29)
7.2 (9.0)
7.6 (7.6)
33 (78)
249 (618)
II
Percent
total
emissions
56 (58)
2 (9)
20 (13)
2 (5)
3 (1)
3 (1)
13 (13)
Controlled
emissions,
kg/day
31 (83)
1.6 (17)
0.0 (0.0)
1.3 (6.6)
3.0 (3.8)
7.6 (7.6)
33 (78)
78 (200)
Percent
total
emissions
40 (42)
2 (9)
0 (0)
2 (3)
4 (2)
10 (4)
43 (40)
III
Controlled
emissions,
kg/day
31 (83)
1.4 (16)
0.0 (0.0)
0.0 (0.0)
2.5 (3.2)
0.0 (0.0)
33 (78)
68 (180)
Percent
total
emissions
46 (46)
2 (9)
0 (0)
0 (0)
4 (2)
0 (0)
49 (43)
IV
Controlled
emissions,
kg/day
22 (59)
0.0 (0.0)
0.0 (0.0)
0.0 (0.0)
0.0 (0.0)
0.0 (0.0)
33 (78)
55 (140)
Percent
total
emissions
40 (43)
0 (0)
0 (0)
0 (0)
0 (0)
0 (0)
60 (57)
-------
Table 7-2. CONCLUDED (MODEL PLANT C)
I
Ol
Component
type
Valves
Relief valves
Open-ended
lines
Compressor
seals
Pump seals
Sampl i ng
connections
Flanges a,,d
connections
Total
I
Baseline
emissions,
kg/day
450
13
170
20
24
25
110
812
(1,200)
(180)
(265)
(98)
(30)
(25)
(260)
(2,058)
Percent
total
emissions
55 (58)
2 (9)
21 (13)
2 (5)
3 (1)
3 (1)
14 (13)
II
Controlled
emissions,
kg/day
100
5.2
0.0
4.2
10
25
110
250
(280)
(56)
(0.0)
(22)
(13)
(25)
(260)
(660)
Regulatory Alternative
III
Percent
total
emissions
39 (43)
2 (9)
0 (0)
2 (3)
4 (2)
10 (4)
43 (40)
Controlled
emissions,
kg/day
100
4.8
0.0
0.0
8.4
0.0
110
220
(280)
(52)
(0.0)
(0.0)
(ID
(0.0)
(260)
(600)
Percent
total
emissions
45 (46)
2 (9)
0 (0)
0 (0)
4 (2)
0 (0)
49 (43)
IV
Controlled
emissions,
kg/day
73
0.0
0.0
0.0
0.0
0.0
110
180
(200)
(0.0)
(0.0)
(0.0)
(0.0)
(0.0)
(260)
(460)
Percent
total
emissions
40 (43)
0 (0)
0 (0)
0 (0)
0 (0)
0 (0)
60 (57)
xx = VOC emission values.
(xx) = Total hydrocarbon emission values.
-------
Table 7-3. ANNUAL MODEL PLANT EMISSIONS AND PERCENT EMISSION REDUCTION FROM
REGULATORY ALTERNATIVE I AND FROM PREVIOUS REGULATORY ALTERNATIVE
Model plant emissions,3 Mg/yr
Regulatory
alternative A
I 30 (75)
II 9.1 (24)
III 8.0 (22)
IV 6.6 (17)
91
28
25
20
B
(230)
(73)
(66)
(51)
C
300 (750)
91 (240)
80 (220)
66 (170)
Percent emission reduction
Total b
70
73
78
-
(68)
(71)
(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 PLANTS FOR
REGULATORY ALTERNATIVES FOR 1983-1987
Cumulative number of
affected model plants
Total fugitive emissions projected under
regulatory alternative (103 Mg/yr)
Year
II
III
IV
1983
1984
New 1985
plants 1986
1987
5-year
5-year
0
0
0
0
0
total
emission
40
80
120
150
180
0
0
0
0
0
3.6
7.3
11
14
16
52
-
(9.2)
(18)
(28)
(35)
(41)
(130)
( - )
1.1
2.2
3.4
4.2
5.0
16
36
(2.9)
(5.8)
(8.8)
(11)
(13)
(42)
(88)
1.0
2.0
3.0
3.8
4.5
14
38
(2.6)
(5.3)
(7.9)
(9.9)
(12)
(38)
(92)
0.80
1.6
2.4
3.0
3.6
11
41
(2.0)
(4.1)
(6.1)
(7.7)
(9.2)
(29)
(100)
reduction from baseline
Modified/
reconstructed
plants
1983
1984
1985
1986
1987
5-year
5-year
2
4
6
8
10
total
emission
3
6
9
12
15
3
6
9
12
15
1.2
2.5
3.7
4.9
6.2
19
-
(3.1)
(6.2)
(9.3)
(12)
(15)
(46)
( - )
0.38
0.75
1.1
1.5
1.9
5.6
13
(0.99)
(2.0)
(3.0)
(3.9)
(4.9)
(15)
(31)
0.33 (0.90)
0.67 (1.8)
1.0 (2.7)
1.3 (3.6)
1.7 (4.5)
5.0 (14)
14 (32)
0.27
0.54
0.81
1.1
1.4
4.1
15
(0.70)
(1.4)
(2.1)
(2.8)
(3.5)
(11)
(35)
reduction from baseline
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.
7-f
-------
19 gigagrams from existing plants through modification/reconstruct!'on.
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.
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
7-9
-------
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
1,800 terajoules, 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.
7.6.2 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.
7-10
-------
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 (103 Mg) (terajoules) '
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
(103 bbl)d
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 incinerators
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.
Calculated 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.
-------
7.7 REFERENCES
1. Nelson, W. L. Petroleum Refinery Engineering. McGraw-Hill Book
Company, Inc. New York, 1958. p. 32.
2. Perry, R. H., and C. H. Chilton, eds. Chemical Engineers' Handbook,
Fifth Edition. McGraw-Hill Book Company, New York. 1973. p. 9-16.
3. DOE Monthly Energy Review. January 1981. DOE/EIA-0035 (81/01).
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 regulatory
alternative discussed in Chapter 6. These estimates will then be used
in Chapter 9 to estimate the economic impact of the regulatory alterna-
tives 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. Alternative IV
includes all the costs of Alternative III plus the costs of a rupture
disk system and dual mechanical seals. The costs of Regulatory Alterna-
tive IV are different for new installation of equipment and for retrofit
installations.
-------
Table 8-1. CAPITAL COST DATA (June 1980 dollars)
1. Monitoring Instruments
2 instruments (Century Systems 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 ,
(250 psi) water, oil, gas (w.o.gfc) 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 Vent Control System
Model
Parts6
Model plant A
e
10 m 2.5 cm pipe = $ 28.20
120 m 5.1 cm pipe = 780.00
four 2.5 cm check valves
@ $80.40 = 321.60
2 elbows @ $6.22 = 12.44
3 T's @ $8.16 = 24.48
2 gate type block valves
(21 kg/cm2-w.o.g.) @ $61.77 123.54
Total Parts $1,290.00 x ^30.6 _ $1>192.oo
Laborf
on m/hm/wQ7r = 4.3 hr for installation by crew
30 m/hr/crew 2-Q hr for set.up/breakdown
2.0 hr for fabrication
8.3 hours/crew
8.3 crew hrs X 2-J§!i = 25 man hrs X $18.00/hrd = Total Labor $450.00
crew
Total Dollars $1,642.00
Model plant B
Parts6
30 m 2.5 cm pipe =
160 m 5.1 cm pipe =
twelve 2.5 cm check valves
@ $80.40 =
2 elbow @ $6.22 =
11 T's @ $8.16 =
6 gate type block valves
(21 kg/cm2-w.o.g.) @ $61.
Total Parts
$ 84.60
1,040.00
964.80
12.44
89.76
77 370.62 c
$2,562.00 x HS'T = $2,367.00
O^ / . O
(continued)
8-2
-------
Table 8-1. Continued
Laborf
30 m/hr/crew = 6'3 hr for installat1on bV crew
JU m/hr/crew 3>Q hr for set-up/breakdown
6.0 hr fabrication
15.3 hours/crew
15.3 crew hrs X - = 45 man hrs X $18.00/hrd = Total Labor $ 830.00
^
Total Dollars $3.197.00
Model plant C
Parts6
50 m 2.5 cm pipe = $ 141.00
200 m 5.1 cm pipe = 1,300.00
forty 2.5 cm check valves
@ $80.42 = 3,216.80
6 elbows @ $6.22 = 74.64
19 T's @ $8.16 = 318.24
20 gate type block valves
(21 kg/cm2-w.o.g.) @ $61.77 1.235.40 c
Total Parts $6,286.00 x 33P/Q = $5.808.00
Laborf
nmyhryr = 8-3 hr for installation
30 m/hr/crew set-Up/breakdown
18.0 hr for fabrication
32.3 hours/crew
32.3 crew hrs X |~-^ = 97 man hrs X $18.00/hrd = Total Labor $1.750.00
i^^^^^^^. «.^^
Total Dollars $7.558.00
4. Closed-loop Sampling Connections^
Based on 6 m length of 2.5 cm 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 Valve^
New Installation
Rupture Disk Assembly
7.6 cm rupture disk (stainless) = $ 230
7.6 cm rupture disk holder
(carbon steel) = 384
0.6 cm pressure gauge = 18
0.6 cm bleed gate valve = 30
Installation, 16 hrs @ $18/hr = 288
(continued)~'
8-3
-------
Table 8-1. Continued
Upstream Block Valve
7.6 cm gate valve = 700
Installation, 10 hrs @ $18/hr = 180
Offset Mounting
10.2 cm tee, elbow =
Installation, 8 hrs @ $18/hr =
Retrofit Installation
Relief Valve Replacement
7.6 cm relief valve (stainless)
Installation, 10 hrs @ $18/hr
$3,631
Rupture Disk System with 3-Way Valve
New Installation
Costs for rupture disk assembly are the same as for new rupture disk
disk system (above), except replace block valve with
One 3-way valve (7.6 cm, 2-port) = $1,320
Additional cost for
One 7.6 cm pressure relief valve
stainless = $1,456
Two 7.6 cm elbows = 30
Installation, 36 hrs @ $18/hr = 648
$4,100
Retrofit Installation
Costs for rupture disk assembly and 3-way valve costs are the same as
for new applications except
Installation, 72 hrs @ $18/hr = $1,296
$4,800
(continued)
8-4
-------
Table 8-1. Concluded
7. Dual Mechanical
New Installation
Seal cost = $1,250
Seal credit = -278
Installation, 16 hrs @ $18/hr = 288
$1,260
Retrofit Installation
Seal cost = $1,250
Installation, 19 hrs @ $18/hr = 342
$1,592
One instrument used as a spare. Cost is based on Reference 1.
Reference 2.
Cost 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 6.
^Reference 7.
hReference 8.
8-5
-------
Table 8-2. CAPITAL COST ESTIMATES FOR MODEL PLANTS
(thousands of June 1980 dollars)
Regulatory
Capital cost item IIa III3
Model Plant A
1. Monitoring instrument 9.2 9.2
2. Caps for open-ended 3.1 3.1
lines
3. Compressor vent control 1.6
system
4. Closed-loop sampling 3.7
connections
5. Rupture disk system
6. Dual mechanical seals
Total 12 18
Alternative
IVb IVC
9.2 9.2
3.1 3.1
1.6 1.6
3.7 3.7
12 17
2.5 3.2
32 38
(continued)
8-6
-------
Table 8-2. Continued
Regulatory
Capital cost item IIa III8
Model Plant B
1. Monitoring instrument 9.2 9.2
2. Caps for open-ended 9.2 9.2
lines
3. Compressor vent control 3.2
system
4. Closed- loop sampling 11
connections
5. Rupture disk system
6. Dual mechanical seals
Total 18 33
Alternative
IVb
9.2
9.2
3.2
11
37
7.6
77
IVC
9.2
9.2
3.2
11
51
9.6
93
(continued)
8-7
-------
Table 8-2. Concluded
Regulatory Alternative
Capital cost item
IIs IIIa 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
7.6 7.6
37 37
120
25
9.2
31
7.6
37
170
32
Total 40 85 230 290
aCosts are the same for new or retrofit installation.
New installation costs.
cRetrofit installation costs.
Costs based on 50% rupture disk systems with block valve and
50% rupture disk systems with 3-way valve.
8-8
-------
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)n- 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 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.
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
8-9
-------
Table 8-3. LEAK DETECTION AND REPAIR LABOR-HOUR REQUIREMENTS
Leak detection
Component type
Valves9
Relief valves
Compressor seals
Pump seals9
Monitoring
interval
quarterly
monthly/
quarterly
monthly
quarterly
monthly
quarterly
quarterly
monthly
weekly
Components per
model plant Type of
ABC monitoring3
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
4.3h
11. 9h
4
12
4
4
12
52
Leak repair
Monitoring Percent of Estimated
labor-hours sources number of Repair time
required ' initially leaks per year per source
ABC leaking0 ABC (hours)
33
36
99
4.3
13
1.3
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
18 46 139
47 140
48 143
11 0.2 0.5
0.3 0.8
43 0.3 1.0
33 0.79 2.4
0.82 2.5
464 1.131
467
478
1.8 Oj
2.6
3.4 40k
7.9 II1
8.2
Maintenance-
labor- hours
ABC
52
53
54
0
0
12
8.7
9.0
157
158
162
0
0
40
26
28
524
528
540
0
0
136
87
90
Assumes that instrument monitoring requires a two-person team, and visual monitoring, one person.
Monitoring time per person: pumps-instrument 5 min., visual 1/2 rain.; compressors 5 min.; valves 1 min., and safety/relief valves 8 min. Reference 7.
Monitoring 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.
g
Annual percent recurrence factors have been applied for monthly and quarterly instrument inspections for relief valves and compressor seals.
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). Number of leaks = number of components x fraction of sources initially
leaking x annual fraction of recurrence factor. Reference 7.
Leak repair labor-hours = number of leaks x repair time.
The values used in calculating labor-hour requirements for valves and pump seals were developed on the basis of the model and data presented in 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-line, 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.
'Reference 10.
Based on 50 percent of pumps using mechanical seals, requiring 16 hours per repair, and 50 percent of pumps using packed seals, requiring 6 hours per
repair (including the labor-hour equivalent cost of materials). References 11 and 12.
-------
Table 8-4. LEAK DETECTION AND REPAIR COSTS3
(June 1980 dollars)
Regulatory.
Leak detection cost Repair cost
model plant model plant
alternative ABC A B
IIC
IIId
IVe
730
970
1,800
2,200
2,900
5,400
7,400
9,700
18,000
1,300
1,100
970
4,000
3,300
2,900
13,000
11,000
9,700
aCosts = labor-hours (Table 8-3) x $18/hour (Table 8-5).
Regulatory Alternative I (baseline control) has zero costs.
cCalculated 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.
8-11
-------
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
3. Annual miscellaneous costs
4. Labor costs
5. Administrative and support costs to
implement regulatory alternative
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 capital
0.23 x capital0
0.05 x capital
$3,000e
0.04 x capitalf
$18/hrg
0.40 x (monitoring, labor +
maintenance labor)
(estimated number of leaking
components per model unit x
repair time) x $18/hr x 1.4
x 0.163
$192/Mg!f
$ 61/Mg1
Applies 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 9.
°Six year life, ten percent interest. Reference 9.
From Reference 9.
p
Includes materials and labor for maintenance and calibration.
Reference 9.
^Includes wages plus 40 percent for labor-related administrative and overhead
costs.
From Reference 9.
Shown in Table 8-3.
'initial leak repair amortized for ten years at ten percent interest.
i,
Based on LPG price of 40
-------
Table 8-6. LABOR-HOUR REQUIREMENTS FOR INITIAL LEAK REPAIR
00
i»
CO
Number of components
per model plant
Component type
Valves
Relief valves
Compressor seals
Pump seals
A
250
4
2
2
B
750
12
6
6
C
2,500
40
20
20
Percent of
sources
leaking in
Initial survey
18
11
43
33
Estimated
Number of leaks
A
45
0.44
0.86
0.66
B
135
1.3
2.6
2.0
C
450
4.4
8.6
6.6
Repair time
per source
(hours)
1.13
0
40
11
Repair labor-hours
A
51
0
34
7.3
B
153
0
104
22
C
509
0
344
73
Based on the number of sources leaking at >10,000 ppm from Table 4-1.
bSee Table 8-3.
-------
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. 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. In Alternatives III and IV, there is no recovery credit for
the venting of compressors to flares or incinerators.
8.1.2.5 Net Annual Costs. The net annual costs shown in Table 8-9
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 $4,000, as a result of $9,500 in
costs and $5,500 in recovery credits.
8.1.2.6 Cost Effectiveness. The cost effectiveness of the regulatory
alternatives for each model plant is shown in Table 8-10. Regulatory
Alternatives II and III for all model plants entail 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. Table 8-11 presents
the cost effectiveness by component type of the alternative techniques
for control of fugitive VOC emissions at new plants.
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.
8-14
-------
Table 8-7. INITIAL LEAK REPAIR COSTS (JUNE 1980 DOLLARS)
Initial repair costs Annualized initial repair
for model plants costs for model plants
Regulatory
alternative
II
III
IV
A
1,700
1,000
920
B
5,000
3,200
2,800
C
17,000
10,000
9,200
A
390
230
210
B
1,100
730
640
C
3,900
2,300
2,100
aRegulatory Alternative I (baseline control) has zero costs.
bCosts = labor-hours (Table 8-6) x $18/hour (Table 8-5).
cAnnualized cost = Costs x 0.163 (capital recovery factor, Table 8-5) x
1.4 (administrative costs, Table 8-5).
8-15
-------
Table 8-8. RECOVERY CREDITS
Model Plant A
Regulatory
alternative
II
III
IV
Recovered
emissions,3
Mg/yr
20 (48)
21 (50)
22 (55)
Recovered
product
value, b
$/yr
5,500
5,800
6,200
Model Plant B
Recovered
emissions,
Mg/yr
61 (140)
64 (140)
69 (160)
Recovered
product
value, b
$/yr
17,000
17,000
19,000
Model Plant C
Recovered
emissions,
Mg/yr
200 (480)
210 (500)
220 (550)
Recovered
product
value, b
$/yr
55,000
58,000
62,000
xx = VOC emission values.
CO
(xx) = Total hydrocarbon emission values.
Based on numbers presented in Table 7-3.
due to venting of compressors to flares or incinerators in Alternatives III and IV.
Based on recovered VOC
$61/Mg from Table 8-5.
Based on numbers presented in Table 7-3. Numbers are corrected to account for emissions not recovered
c
Based on recovered VOC value of $192/Mg, and recovered non-VOC hydrocarbon (methane-ethane) value of
-------
Table 8-9. ANNUAL COST ESTIMATES (MODEL PLANT A)
(thousands of June 1980 dollars)
Cost Item
Annual i 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 repair
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
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
IIa III3
2.1 2.1
0.51 0.51
0.26
0.60
0.39 0.23
3.0 3.0
0.16 0.16
0.08
0.19
0.37 0.37
0.12 0.12
0.06
0.15
0.73 0.97
1.3 1.1
0.81 0.83
9.5 11
(5.5) (5.8)
4.0 5.2
Alternative
IVb
2.1
0.51
0.26
0.60
7.0
1.5
0.21
3.0
0.16
0.08
0.19
0.60
0.13
0.37
0.12
0.06
0.15
0.48
0.10
1.8
0.97
1.1
21
(6.2)
15
IVC
2.1
0.51
0.26
0.60
9.9
1.9
0.21
3.0
0.16
0.08
0.19
0,85
0.16
0.37
0.12
0.06
0.15
0.68
0.13
1.8
0.97
1.1
25
(6.2)
19
(continued)
8-17
-------
Table 8-9. CONTINUED (MODEL PLANT B)
Cost Item
Annual ized 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 repair
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
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
IIa III3
2.1 2.1
1.5 1.5
0.52
1.8
1.1 0.73
3.0 3.0
0.46 0.46
0.16
0.56
0.37 0.37
0.37 0.37
0.13
0.44
2.2 2.9
4.0 3.3
2.5 2.5
18 21
(17) (17)
1 4
Alternative
IVb
2.1
1.5
0.52
1.8
21
4.4
0.64
3.0
0.46
0.16
0.56
1.9
0.38
0.37
0.37
0.13
0.44
1.5
0.30
5.4
2.9
3.3
53
(19)
34
IVC
2.1
1.5
0.52
1.8
30
5.6
0.64
3.0
0.46
0.16
0.56
2.6
0.48
0.37
0.37
0.13
0.44
2.0
0.38
5.4
2.9
3.3
65
(19)
46
(continued)
8-18
-------
Table 8-9. CONCLUDED (MODEL PLANT C)
Cost Item
Annuali 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 repair
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
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
IIa III3
2.1 2.1
5.0 5.0
1.2
6.1
3.9 2.3
3.0 3.0
1.5 1.5
0.38
1.9
0.37 0.37
1.2 1.2
0.30
1.5
7.4 9.7
13 11
8.2 8.3
46 56
(55) (58)
(9) (2)
Alternative
IVb
2.1
5.0
1.2
6.1
70
15
2.1
3.0
1.5
0.38
1.9
4.0
1.3
0.37
1.2
0.30
1.5
4.8
1.0
18
9.7
11
160
(62)
98
IVC
2.1
5.0
1.2
6.1
99
19
2.1
3.0
1.5
0.38
1.9
7.5
1.6
0.37
1.2
0.30
1.5
6.8
1.3
18
9.7
11
200
(62)
140
"Costs are the same for new or modified/reconstructed facilities.
Costs for new facilities.
cCosts for modified/reconstructed facilities.
3-19
-------
Table 8-10. COST EFFECTIVENESS OF REGULATORY ALTERNATIVES
(Model Plant A)
oo
ro
o
Regulatory Alternative
Parameter
Capital cost ($)
Annual cost before credit ($)
Annual recovery credit ($)
Net annual cost ($)
Total VOC reduction (Mg/yr)
Cost effectivenessd ($/Mg VOC)
Incremental cost effectiveness6
($/Mg VOC)
I
0
0
0
0
0
0
0
n=
12,000
9,500
5,500
4,000
21
190
190
III3
18,000
11,000
5,800
5,200
22
240
1,200
IVb
32,000
21,000
6,200
15,000
23
650
9,800
IVC
38,000
25,000
6,200
19,000
23
830
13,800
(continued)
-------
Table 8-10. Continued (PLANT B)
Regulatory Alternative
00
i
rv>
i
Parameter
Capital cost ($)
Annual cost before credit ($)
Annual recovery credit ($)
Net annual cost ($)
Total VOC reduction (Mg/yr)
Cost effectiveness*1 ($/Mg VOC)
Incremental cost effectiveness6
($/Mg VOC)
I
0
0
0
0
0
0
0
IIa
18,000
18,000
17,000
1,000
63
16
16
III3
33,000
21,000
17,000
4,000
66
61
1,000
IVb
77,000
53,000
19,000
34,000
71
480
6,000
IVC
93,000
65,000
19,000
46,000
71
650
8,400
(continued)
-------
Table 8-10. Concluded (PLANT C)
Regulatory Alternative
Parameter
Capital cost ($)
Annual cost before credit ($)
Annual recovery credit ($)
Net annual cost ($)
oo
rlo Total VOC reduction (Mg/yr)
ro
Cost effectiveness01 ($/Mg VOC)
Incremental cost effectiveness6
I
0
0
0
0
0
0
0
n'
40,000
46,000
55,000
(9,000)
210
(43)
(43)
in'
85,000
56,000
58,000
(2,000)
220
(9.1)
700
IVb
230,000
160,000
62,000
98,000
230
430
10,000
ivc
290,000
200,000
62,000
140,000
230
610
14,000
Costs are the same for new or modified/reconstructed facilities.
Costs for new facilities.
""Costs for modified/reconstructed facilities.
H
Cost effectiveness = total VOC reduction divided by the net annual cost.
"Incremental cost effectiveness = difference between the net annual costs of the given and previous
regulatory alternatives divided by the difference between the total VOC reduction of the given and
previous regulatory alternatives.
-------
Table 8-11. COST EFFECTIVENESS BY COMPONENT TYPE OF ALTERNATIVE TECHNIQUES FOR
CONTROL OF FUGITIVE VOC EMISSIONS FROM NATURAL GAS PLANTS (MODEL PLANT B)
oo
ro
CO
Component type
Valves
Relief valves
Open-ended lines
Sampling connections
Compressor seals
Pump seals
Number of
Control technique components
Quarterly monitoring 750
Monthly/quarterly monitoring
Monthly monitoring
Quarterly monitoring 12
Monthly monitoring
Rupture disk (new)
Rupture disk (retrofit)
Cap 150
Closed purge 21
Quarterly monitoring 6
Vent control
Quarterly monitoring 6
Monthly monitoring
Dual seals (new)
Dual seals (retrofit)
VOC
emission
reduction,
Mg/yr
40
40
43
0.88
0.95
1.5
1.5
19
2.8
1.7
2.2
1.5
1.7
2.6
2.6
Annual
cost,
$103
7.1
7.3
12
0.33
0.96
24
35
2.3
2.8
15
0.81
0.92
1.2
5.1
6.5
Recovery
credits,
$103
11
11
12
0.94
0.97
1.4
1.4
4.2
0.54
0.72
0.0
0.32
0.35
0.54
0.54
Net
annual
cost
$103
(3.9)
(3.7)
0.0
(0.61)
(0.01)
23
34
(1-9)
2.3
14
0.81
0.60
0.85
4.6
6.0
Cost
effectiveness,
$/Mg
(98)
(93)
0
(690)
(ID
15,000
23,000
(100)
820
8,200
370
400
500
1,800
2,300
Incremental
cost
effectiveness,
$/Mg
(98)
a
1,200
(690)
8,600
42,000
62,000
(100)
820
8,200
(26,000)
400
1,300
4,200
5,700
( ) = Net credit.
aNo change in emissions from previous control alternative.
-------
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 Table 8-10.
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 8-10. The cost effectiveness of this Alternative is substantially
higher than for new facilities.
8.1.4 Projected Cost Impacts
The projected costs of implementing the regulatory alternatives are
presented in Table 8-12. 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.
8.2 OTHER COST CONSIDERATIONS
Environmental, safety, and health statutes that may cause an outlay
of funds by the gas processing industry are listed in Table 8-13.
Specific costs to the industry to comply with the provisions, requirements,
and regulations of the statutes are unavailable.
8-24
-------
Table 8-12. FIFTH YEAR NATIONWIDE COSTS OF THE REGULATORY ALTERNATIVES
(thousands of June 1980 dollars)
co
i
Cost item
New plants
Cumulative capital costs by 1987
Total annual costs
Total recovery credit
Net annual costs
Modified/reconstructed facilities
Cumulative capital costs by 1987
Total annual costs
Total recovery credits
Net annual costs
II
3,200
3,200
3,000
200
990
1,100
1,100
0
III
5,900
3,800
3,000
800
2,000
1,300
1,200
100
IV
14,000
9,500
3,400
6,100
6,100
4,200
1,300
900
-------
Table 8-13. STATUTES THAT MAY BE APPLICABLE TO THE NATURAL GAS PROCESSING INDUSTRY
Statute
Applicable provision, regulation or
requirement of statute
Statute
Applicable provision, regulation or
requirement of statute
Clean Air Act and Admendments o State implementation plans
o National emission standards for
hazardous air pollutants
o New source performance standards
Clean Water Act (Federal
Water Pollution Act)
Co
r\>
CTl
Resource Conservation and
Recovery Act
Toxic Substances Control
Act
o PSD 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
Pretreatment requirements
Monitoring and reporting
o
o
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 wastes
o Superfund
o Premanufacture notification
o Labeling, recordkeeping
o Reporting requirements
o Toxicity testing
Occupational Safety & Health
Act
Coastal Zone Management Act
National Environmental Policy
Act
Safe Drinking Water Act
Marine Sanctuary Act
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
States may veto Federal permits for
plants to be sited in coastal zone
o Requires environmental impact
statements
o Requires underground 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.
2. Telephone conversation. Michael Alexander, TRW, with Mr. Harris of
Dillon Supply, Durham, N.C. June 17, 1981. Price of gate valves.
3. Economic Indicators. Chemical Engineering. Vol. 88 #12. June 15,
1981. p. 7.
4. Letter with attachments from Texas Chemical Council to Walt Barber,
U.S. EPA. June 30, 1980.
5. Telephone conversation. Michael Alexander, TRW, with Danny Keith,
Dillon Supply Co., Raleigh, N.C. June 15, 1981. Costs of valves,
pipes, and fittings.
6. McMahon, Leonard A., 1981 Dodge Guide. Annual Edition No. 13,
McGraw-Hill Publishing Co.
7. VOC Fugitive Emissions in Petroleum Refining Industry - Background
Information for Proposed Standards. U.S. EPA, OAQPS. April 1981.
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.
9. Erikson, D. G. and V. Kalcevic. Emission Control Options for the
Synthetic Organic Chemicals Manufacturing Industry, Fugitive Emissions
Report, Draft Final. Hydroscience, Inc. 1979.
10. Letter with attachments from J. M. Johnson, Exxon Company, U.S.A.,
to Robert T. Walsh, U.S. EPA. July 28, 1977.
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.
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.
13. Telephone conversation. T. Hennings, TRW, with Editor, Oilgram
News. February 25, 1981. Price of LPG on June 16, 1980.
14. Nelson, W. L. , Petroleum Refinery Engineering. McGraw-Hill Book
Co. , Inc. New York. 1958. p. 32.
15. DOE Monthly Energy Review. January 1981. DOE/EIA-0035(81/01).
p. 88.
8-27
-------
9. ECONOMIC ANALYSIS OF THE ONSHORE NATURAL GAS
PRODUCTION INDUSTRY VOC NSPS
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 NSPS for VOC emissions are being considered.
Projections for the year 1987, five years after a proposal date of
1982 for the NSPS 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 CAPACITY3 (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 C
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, cryogenicJoule-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 METHOD9 (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
a 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
Cities Service Company
Phillips Petroleum Company
Warren Petroleum Company
Exxon Company
Shell Oil Company
Sun Gas Company
Getty Oil Company
Mobil Oil Corporation
Texaco, Inc.
ARCO Oil and Gas Company
Chevron USAS Inc.
Union Oil Company of California
Mitchell Energy & Development Corporation
Number of companies that own between 10 and 20 plants
Number of companies that own less than 10 plants-
Total number of companies that own gas plants
TOTAL
47
41
37
35
33
33
33
26
26
25
24
23
23
22
7
117
138
772
Based on data presented in Qil 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
Wyoming
California
Colorado
All other states
TOTAL
Number of plants
356
103
26
86
34
40
37
27
63
772
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
3 Based on data presented in Oil and Gas Journal, July 14, 1980.
9-7
-------
Table 9-5. PRODUCTION OF ENERGY BY TYPE, UNITED STATES (Quadrillion Btu)
1973
1974
1975'
1976
1977
10 1978
i
00
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.
2 Includes bituminous coal, lignite and anthracite.
~ Includes lease condensate.
. Natural gas plant liquids.
r 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)
Price elasticity of demand
With respect to
Solid fuels
Natural gas
Electricity
Petroleum
Source: The Global
Solid
fuels
-.215
.005
.011
.002
2000 Report
Natural
gas El
.030
-.426
.052
.013
to the President,
ectricity
.131
.228
-.376
.077
(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 IndustryGrowth 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
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
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
195C
1951
1952
1953
1954
1955
1956
1957
1958
1959
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970'
1971
1972
1973
1974
1975
1976
1977
1978
1979b
From
Gas Wells
4.99
5.60
6.48
5.84
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
13.59
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
01 T Wells
2.56
2.88
3.21
3.43
3.55
3.52
3.88
4.07
4.19
3.9'9
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
9.59
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
3.66
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
Production
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
Percentage
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
36.3
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
S.O
10.1
12.0
13.7
14.7
16.8
16.7
17.6
19.6
21.2
21.6
22.7
25.5
27.6
NA 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.
N°te: 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.
Data from U.S. Department of the Interior. Geological Survey - Conservation Division, Outer Continental Shelf
j tStl S tl CS *
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. 4 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 $35,500 million in current
dollars or 51 percent of revenues in 1983-85.
9.1.2.2 Five-Year Projections. In this subsection, projections for
the number of new and modified and reconstructed gas processing facilities
in the years 1983 through 1987 are developed. The form of the growth in
terms of new facilities, modified facilities and reconstructed facilities
9-12
-------
I
I
CO
2.50
rs
4J
CO
c.
o
- 1.50 -
1.00
1955
1960
1965
1970
1975 78 79
Year
Figure 9-1. Selected natural gas prices - three categories for the period 1955-1979.
-------
Table 9-8. COMPOSITE FINANCIAL DATA FOR THE NATURAL GAS INDUSTRY 1976-1981 and
1983-1985 ESTIMATES (Current dollars)
Item
Revenues ($mill)
Net Profit ($mill)
Income Tax Rate
Net Profit Margin
Long-term Debt Ratio
Common Equity Ratio
Total Capital ($mill)
Net Plant ($mill)
% 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. 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
projected to come from new discoveries. Table 9-9 includes projected
Lower-48 states onshore conventional natural gas production from new
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 h
Old Inter3'0
New Inter0
Total
Old Inter
Old Intra
Old Direct Sale
New
TOTALd
4.9
3.6
4.0
1.5
5.6
0.1
10.5
3.6
4.0
1.6
19.7
3.6
2.4
2.6
3.6
4.1
3.4
7.7
2.4
2.6
7.0
19.7
2.0
1.3
1.5
4.9
1.4
6.6
3.4
1.3
1.5
11.5
17.7
1.1
0.7
0.8
4.8
0.7
6.5
1.5
0.7
0.8
11.3
14.6
0.7
0.4
0.5
3.8
nil
5.4
0.7
0.4
0.5
9.2
10.8
a
Including new additions from pre-1977 leases.
c Post-1976 leases only.
Totals may not add due to independent rounding.
Source: American Gas Association, Gas Supply and StatisticsTotal Energy
Resource Analysis Model (TERA) 80-1, Appendix A, Figure A-2,
p. 21.
9-16
-------
1 1 I I I 1 1 I 1
1980
2000
Figure 9-2. Projected new discovery onshore natural gas production
9-17
-------
Table 9-10. PROJECTIONS OF NATURAL GAS SUPPLY: COMPARISON OF 1990 FORECASTS6 (Quadrillion Btu)
1979 Projections for 1990
Units
Domestic Production
Conventional
North Alaska
Synthetic Gas
Subtotal
Net Imports
Pipeline
Liquefied Natural Gas
Subtotal
Total Supply
1978
Actual
19.5
f
0.2
19.7
0.9
g
0.9
20.6
DOE
DOE/
EIA a/
17.8
0.9
0.3
19.0
0
0.8
0.8
19.8
u
AGAb
15.3-17.3
1.6
1.1
19.9-21.9
2.1
2.0
4.2
24.1-26.1
*>
DPPC
16.9
0.4
0.6
18.0
2.0
1.0
3.1
21.0
A
Pace0
16.1
1.0
0.8
18.0
1.4
0.8
2.2
20.2
p
Exxon
14.9
f
0.6-1.0
15.5-15.9
1.8
0.8
2.7
18.2-18.6
f
Tenneco
14.8
1.0
1.5
17.3
2.0
3.1
5.1
22.4
DOE/EIA 1979 Annual Report to Congress, middle range forecast.
American Gas Association, The Future for Gas Energy in the United States, June 1979.
c Data Resources, Inc., Energy Review, Winter 1980.
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.
" Included in conventional production.
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)
History3
Price
1965
1973
1978
Projections
1985
1990
1995
Domestic Wellhead Prices
Old Interstate
New Interstate
Old Intrastate
New Intrastate
North Alaska
Average
NA
NA
NA
NA
__
0.36
NA
NA
NA
NA
__
0.35
0
1
.93
NA
NA
NA
__
.02
1.
4.
3.
4.
3.
01
48
29
72
__
26
1
4
3
4
1
3
.18
.04
.32
.28
.85
.42
1.
4.
3.
4.
1-.
4.
39
59
78
82
85
17
Synthetic Gas Prices
High-Btu Coal Gas
Medium-Btu Coal Gas
--
--
__
--
--
--
4.
3.
76
70
4
4
.19
.50
4.
5.
71
44
Imported Gas Prices
Canadian Gas
Mexican Gas
Liquefied Natural Gas
NA
NA
--
NA
NA
--
2
1
.41
NA
.54
6.
6.
5.
21
21
91
6
6
6
.92
.92
.42
8.
8.
7.
51
51
70
Delivered Prices
Al
a
Residential
Commercial
Raw Material
Large boilers
Industrial , Other
Refineries
Electric Utilities
ternative Fuel Cost
Source for historical data i
Congress, 1979, and the foil
Production and Consumption,
2.34
1.60
NA
NA
0.78
NA
0.89
__
s Volume
owing EIA
1978; Uni
2.04
1.46
NA
NA
0.77
NA
0.63
--
2 of the
Energy
2
2
1
1
.77
.38
NA
NA
.61
NA
.72
--
EIA
Data
ted States
Natural Gas, 1978; and, Natural and Synthetic
5.
4.
4.
5.
4.
4.
4.
6.
Annual
41
88
28
24
34
55
74
23
5
5
4
4
4
4
4
6
Report
Reports:
Imports
Gas,
1978.
and
.74
.22
.48
.54
.51
.43
.42
.94
to
Natural
Exports
6.
5.
5.
5.
5.
5.
8.
Gas
of
45
93
21
26
22
13
--
29
c Major fuel-burning installations.
Notes: NA = Not available.
= Not applicable.
Source: DOE/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 = I CRF + 0&MQ (1)
ATAC = IQ 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
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 = £
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.
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. 2J 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 NSPS Regulatory Alternatives - Natural
Gas/Gasoline Processing Plants
Additional costs for natural gas processing plants to comply with VOC
NSPS 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
Regulatory alternatives, VOC annualized cost, 1987
(thousand 1980 dollars)
I 0
II -1,003
III -424
IV 5,989
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. Trend!onq 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
-$656,000 for regulatory alternative II, -$160,000 for regulatory
alternative III and $3,886,000 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 -$347,000 for regulatory alternative II, -$264,000 for regulatory
alternative III and $2.1 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 -$1.0 million for regulatory alternative II, -$424,000
for regulatory alternative III and nearly $6.0 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 -$3,280,
-$800 and $19,430 respectively. The smallest modified and reconstructed
model plant has before-tax net annualized costs of $2,240, $2,850 and
$13,690 for alternatives II, III and IV, respectively. For the modified
and reconstructed model plant B costs are -$3,280, -$800, and $32,760 while
model plant C has costs of -$21,360, -$17,060 and $98,340 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 -$1,590, -$30 and $10,220, respectively.
9-26
-------
Table 9-13. ONSHORE NATURAL GAS PROCESSING, TOTAL AND CUMULATIVE BEFORE-TAX NET ANNUALIZED
COST OF VOC NSPS REGULATORY ALTERNATIVES 1983-1987
IX)
Category
of Facility Year
New
1983
1984
1985
1986
1987
Projected Cumulative
Number of Gas Plants a/
A
0
0
0
0
0
B
40
80
120
150
180
C
0
0
0
0
0
Regulatory Alternative
II
Thni
-131.2
-262.4
-393.6
-524.8
-656.0
III
isands of 1980 [
-32.0
-64.0
-96.0
-128.0
-160.0
IV
"\f\~\ 1 AV»C ..
777.2
1,554.4
2,331.6
3,108.8
3,886.0
Modified/ Reconstructed
Total
1983
1984
1985
1986
1987
2
4
6
8
10
3
6
9
12
15
3
6
9
12
15
-69.4
-138.8
-208.2
-277.6
-347.0
-52.8
-105.6
-158.4
-211.2
-264.0
420.7
841.4
1,262.1
1,682.8
2,103.5
New, Modified & Reconstructed
1983
1984
1985
1986
1987
2
4
6
8
10
43
86
129
162
195
3
6
9
12
15
-200.6
-401.2
-601.8
-802.4
-1,003.0
-84.8
-169.6
-254.4
-339.2
-424.0
1,197.9
2,395.8
3,593.7
4,791.6
5,989.5
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 NSPS REGULATORY ALTERNATIVES PER PLANT
I
ro
CO
Model Size
plant No. vessels MMcfd
New 30 90
Modified and
Reconstructed
A 10 30
B 30 90
C 100 250
I
Baseline
control
level
0
0
0
0
Regulatory
II
ThniicAnHc f\~i
-3.28
2.24
-3.28
-21.36
alternative
III
F 1 QQPl HA 1 1 A y*c .
-.80
2.85
-0.80
-17.06
IV
19.43
13.69
32.76
98.34
-------
I
IN}
UD
Table 9-15. ONSHORE NATURAL GAS PROCESSING MODEL PLANTS' AFTER-TAX NET ANNUALIZED
COST OF VOC NSPS REGULATORY ALTERNATIVES PER PLANT
Model
plant
New
Modified and
Reconstructed
A
B
C
Size
No. vessels' MMcfd
30 90
10 30
30 90
100 250
I
Baseline
control
level
0
0
0
0
Regulatory
II
~rt~kOiic£knsic t
1 nOUSailUb i
-1.59
1.27
-1.59
-10.86
alternative
III
if IQRfl Hnllavc
)T iyou uuiiaib
-.30
1.56
-.30
-8.64
IV
10.22
7.57
17.32
51.28
-------
For modified and reconstructed model plant A, these costs are $1,270,
$1,560, and $7,570, respectively; -$1,590, -$30, and $17,320, respectively,
for model plant B; and -$10,860, -$8,640 and $51,280 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
throughout for new cryogenic plants was assumed to be 90 MMcfd as explained
in Table 9-11 footnote b.
Required price increases for VOC NSPS, 1980 $/Mcf
New Modified and Reconstructed
Regulatory
alternative
II
III
IV
Plant B
(90 MMcfd)
-.00013
-.00002
-.00085
Plant A
(30 MMcfd)
.00032
.00039
.00190
Plant B
(90 MMcfd)
-.00013
-.00002
.00143
Plant C
(250 MMcfd)
-.00033
-.00026
.00155
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 VOC NSPS. Effects on industry profitability, output, growth,
employment, productivity, and international trade will be negligible or
zero due to VOC NSPS on natural gas plants.
This concludes the analysis of direct economic impacts of VOC NSPS on
the Natural Gas Processing Industry. Control costs for VOC NSPS and
associated economic impacts are expected to be negligible for individual
plants and particularly for the composite natural gas processing industry.
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
9-30
-------
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
2. U.S. Department of Energy, Energy Information Administration. Annual
Report to Congress-1979. Volume Two (of Three): Data, and,
U.S. Department of the Interior, U.S. Geological Survey-Conservation
Division, Outer Continental Shelf Statistics, June 1980.
3. U.S. Department of Energy, Energy Information Administration. Annual
Report to Congress-1979. Volume Two (of Three): Data.
4 American Gas Association, Department of Statistics, Gas Facts - 1979
Data.
5. American Gas Association, Gas Supply and Statistics - Total Energy
Resource Analysis Model (TERA) 80-1, Appendix A, Figure A-2, p. 21.
6. U.S. Department of Energy, Energy Information Administration. Annual
Report to Congress-1979. Volume Three (of Three): Projections.
7. U.S. Department of Energy, Energy Information Administration. Annual
Report to Congress-1979. Volume Three (of Three): Projections.
0-32
-------
APPENDIX A - EVOLUTION OF THE BACKGROUND INFORMATION DOCUMENT
-------
A.I LITERATURE REVIEW
Date
Source
April 1958
1958
August 1969
October 11, 1971
1972
1972
1973
1974
1975
1976
June 1977
December 1977
June 1978
June 25-30, 1978
Joint District, Federal
and State Project for
the Evaluation of
Refinery Emissions,
Report Number 6
McGraw-Hill Co. Inc.
Chemical Engineering
Progress
Chemical Engineering/
Deskbook Issue
E.I. duPont de Nemours
and Co.
University of Texas
at Austin
McGraw-Hill Co.
University of Texas
at Austin
Van Nostrand Reinhold
Company
American Petroleum
Institute
EPA-450/3-77-026
Hydrocarbon Processing
KVB, Inc. KVB 5804-714
EPA (Paper presented
at 71st APCA meeting)
Data or Information
Emissions of Hydrocarbons to
the Atmosphere from Seals on
Pumps and Compressors
Petroleum Refinery Engineering
Preventing Flange Fires
Valve Installation, Operation
and Maintenance
A Tracer Technique for Determining
Efficiency of an Elevated
Flare
Field Handling of Natural Gas,
Third Edition
Chemical Engineers' Handbook,
Fifth Edition
Plant Processing of Natural Gas
Lyons' Encyclopedia of Valves
Primer of Oil and Gas Production,
Book 1 of the Vocational
Training Series
Atmospheric Emissions from
Offshore Oil and Gas Development
and Production
Compressor Seal Fundamentals
Control of Hydrocarbon Emissions
from Stationary Sources in the
California South Coast Air
Basin, Volume I
Detection of Volatile Organic
Compounds from Equipment Leaks
A-2
-------
Date
June 1978
August 1978
February 1979
February 1979
July 16, 1979
October 1979
1979
February 1980
March 1980
March 1980
March 1980
April 1980
June 22-27, 1980
July 14, 1980
Source
EPA-450/2-78-036
EPA-450/3-78-047
EPA-600/2-79-044
Hydroscience
The Oil and Gas Journal
API Publication 4311
University of Texas
at Austin
K. D. Siege!, Ph.D.
Dissertation, Univ. of
Karlsruhe (German)
American Petroleum
Institute
American Petroleum
Institute
EPA-340/1-80-010
EPA-600/2-80-075
Air Pollution Control
Association Proceedings
Oil and Gas Journal
Data or Information
Control of Volatile Organic
Compound Leaks from Petroleum
Refinery Equipment
Evaluation of Emissions from
Onshore Drilling, Producing,
and Storing of Oil and Gas
Emission Factors and Frequency
of Leak Occurrence for Fittings
in Refinery Process Units
Emissions Control Options for
the Synthetic Organic Chemicals
Manufacturing Industry, Fugitive
Emissions Report
Advantages Found in On-Line
Leak Sealing
NO Emissions from Petroleum
Inaustry Operations
A Primer of Oil-Well Drilling,
Fourth Edition
Degree of Conversion of Flare
Gas in Refinery High Flares
Volume I - Fugitive Hydrocarbon
Emissions from Petroleum
Production Operations
Volume II - Fugitive Hydrocarbon
Emissions from Petroleum
Production Operations
Summary of Available Portable
VOC Detection Instruments
Assessment of Atmospheric
Emissions from Petroleum
Refining
A Fugitive Emission Study in a
Petrochemical Manufacturing
Unit
Worldwide Gas Processing
-------
Date
Source
Data or Information
February 17, 1981 EPA:IERL (Report)
February 1981
April 1981
December 1981
1981
(no date)
EPA Report, Contract
No. 68-02-3542
Preliminary Draft
EPA:ESED
EPA:ESED
EPA Contract No.
68-02-2682
State of New Mexico,
Environmental
Improvement Division
Evaluation of Maintenance for
Fugitive VOC Emissions Control
Assessment of API/Rockwell
Plant Fugitive Emissions
Gas
VOC Fugitive Emissions in
Petroleum Refining Industry -
Background Information for
Proposed Standards
Control of Volatile Organic
Compound Equipment Leaks from
Natural Gas/Gasoline Processing
Plants
Development of Flare Emission
Measurement Methodology, Draft
Report
Ambient Air Quality Standards
and Air Quality Control
Regulations
A.2 PLANT VISITS
Date
December 18, 1979
Company
Exxon Company, U.S.A.
Jay Field, Florida
December 19, 1979 Phillips Petroleum
Chatham, Mississippi
January 1980
July 14, 1980
Exxon Company
Plant/Information
Blackjack Creek facility/gained
familiarity with process
equipment and operating conditions
Chatham facility/gained famil-
iarity 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
Tank battery in Kingsville,
Texas/gained familiarity with
gas and oil production processes
and facilities
A-4
-------
Date
July 16, 1980
July 18, 1980
July 24, 1980
Company
Phillips Petroleum Co.
Shell Oil Company
Phillips Petroleum Co.
Plant/Information
Roosevelt County, New Mexico/
acquired firsthand familiarity
with gas and oil production
processes and facilities
State!ine Production Unit in
Sidney, Montana/acquired
firsthand familiarity with gas
and oil production
Canadian County, Oklahoma/gained
information on gas processing
facilities
A.3 EMISSION SOURCE TESTING
Date
Source
October 6-9, 1980 Houston Oil & Minerals
Smith Point gas plant,
Chambers County, Texas
October 14-16,
1980
February 9-27,
1981
March 2-13, 1981
Amoco Production Co.
Hastings gas plant,
Brazoria County, Texas
Texaco, Inc., Paradis
Plant, Paradis,
Louisiana
Gulf Oil Company,
Venice Plant, Venice,
Louisiana
Data or Information
Fugitive VOC emissions testing
Fugitive VOC emissions testing
Fugitive VOC emissions testing
Fugitive VOC emissions testing
A.4 MEETINGS WITH INDUSTRY
Date Attendees
November 30, 1979 API and TRW
December 7, 1979 API and TRW
July 21 & 22, EPA, API and TRW
1980
Topic
Meeting to discuss onshore
production and to solicit the
aid of API in gathering field
data
Introductory Meeting
Meeting concerning NSPS develop-
ment for the Onshore Production
Industry
-------
Date
At-tendees
Topic
April 29 & 30,
1981
May 1, 1981
NAPCTAC
EPA, API and TRW
January 28, 1982 EPA, API and TRW
Meeting concerning natural
gas/gasoline processing plants
Meeting concerning model
plants
Meeting concerning fugitive
VOC emission factor development
for gas plants
A.5 REVIEW PROCESS
Date
January 28, 1980
March 19, 1980
March 1981
April 1981
April 1981
June 1981
August 1981
September 1981
Company
TRW
TRW
TRW
TRW
TRW
TRW
TRW
TRW
Data or Information
Preliminary draft Source
Category Survey Report
Source Category Survey Report
Preliminary draft CTG document,
Control of Volatile Organic
Compound Equipment Leaks from
Natural Gas/Gasoline Processing
Plants
Preliminary Draft, VOC Fugitive
Emissions in Petroleum Refining
Industry Background Information
for Proposed Standards
Model plant package mailed to
industry representatives for
comment
Draft CTG Document, Control of
Volatile Organic Compound
Equipment Leaks from Natural
Gas/Gasoline Processing Plants
(sent to OMB for review)
Draft CTG Document, Control of
Volatile Organic Compound
Equipment Leaks from Natural
Gas/Gasoline Processing Plants
Drafts of Chapters 3 through 6
sent out for industry review
and comments
A-6
-------
Date
December 1981
Attendees
TRW
Draft CTG Document, Control of
Volatile Organic Compound
Equipment Leaks from Natural
Gas/Gasoline Processing Plants
A-7
-------
APPENDIX B - INDEX TO ENVIRONMENTAL IMPACT CONSIDERATIONS
-------
APPENDIX B. INDEX TO ENVIRONMENTAL CONSIDERATIONS
This appendix consists of a reference system which is cross-indexed
with the October 21, 1974, Federal Register (36 CFR 37419) containing
the Agency guidelines for the preparation of Environmental Impact
Statements. This index can be used to identify sections of the document
which contain data and information germane to any portion of the Federal
Register guidelines.
B-2
-------
APPENDIX B
INDEX TO ENVIRONMENTAL IMPACT CONSIDERATIONS
CD
CO
Agency Guidelines for Preparing Regulatory
Action Environmental Impact Statements
(39 FR 37419)
(1) Background and summary of regulatory
alternatives
Statutory basis for proposing standards
Affected industry
Affected sources
Availability of control technology
(2) Environmental, energy, and economic
impacts of regulatory alternatives
Environmental impacts
Location Within The Background Information Document
The regulatory alternatives are summarized in
Chapter 1, Section 1.1, pages 1-1 through 1-2.
The statutory basis for the proposed standards is
summarized in Chapter 2, Section 2.1, pages 2-1
through 2-4.
A discussion of the industry affected by the
regulatory alternatives is presented in Chapter 3,
Section 3.1, page 3-1. Details of the "business/
economic" nature of the industry are presented in
Chapter 9, Section 9.1, pages 9-1 through 9-21.
A description of the sources affected by the
regulatory alternatives is presented in Chapter 3,
Section 3.2, pages 3-1 through 3-7.
A discussion of available emission control
techniques is presented in Chapter 4, Sections 4.2
and 4.3, pages 4-1 through 4-17.
Various regulatory alternatives are discussed in
Chapter 6, Section 6.3, pages 6-2 through 6-9.
The environmental impacts of the various regulatory
alternatives are presented in Chapter 7, Sections 7.1,
7.2, 7.3, and 7.4, pages 7-1 through 7-9.
-------
Agency Guidelines for Preparing Regulatory
Action Environmental Impact Statements
(39 FR 37419)
Energy impacts
Cost impacts
Economic impacts
Location Within The Background Information Document
The energy impacts of the various regulatory
alternatives are discussed in Chapter 7, Section 7.5,
pages 7-9 through 7-11.
Cost impacts of the various regulatory alternatives
are discussed in Chapter 8, Section 8.1, pages 8-1
through 8-28.
The economic impacts of the various regulatory
alternatives are presented in Chapter 9, Sections 9.2
and 9.3, pages 9-21 through 9-31.
-------
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.
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.
The third unit was also not operating, but it was under natural gas
pressure and was tested.
C-2
-------
Table C-l. GAS PLANTS TESTED FOR FUGITIVE EMISSIONS'
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.
03
-------
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-4
-------
Table C-2. INSTRUMENT SCREENING DATA FOR ERA-TESTED GAS PLANTS6
I
en
Valves
Plant
No.
3
4
5
6
Total
No.
Tested
331
506
1,804
1,038
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 EPA-TESTED GAS PLANTS'
o
1
en
Valves
Score
0
1
2
3
4
Total
Number
4,483
322
468
426
274
5,973
% of
Total
75.1
5.4
7.8
7.1
4.6
Relief
Number
123
4
2
2
3
134
valves
% of
Total
91.8
3.0
1.5
1.5
2.2
Open-ended lines
Number
945
63
83
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
% of
Total
28.6
3.6
7.1
25.0
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
% of
Total
92.7
3.6
2.3
1.0
0.3
Includes data from two- API-tested plants and four EPA-tested plants. Reference 6.
-------
C.2 REFERENCES FOR APPENDIX C
1. Eaton, W. S. , et al., Fugitive Hydrocarbon Emissions from Petroleum
Production Operations. API Publication No. 4322. March 1980.
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.
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.
4. Harris, G. E. Fugitive VOC Testing at the Texaco Paradis Gas
Plant, Volume I and II. U.S. EPA, ESED/EMB Report No. 80-OSP-7.
July 1981.
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.
6. DuBose, D. A., J. I. Steinmetz, and G. E. Harris. Emission Factors
and Leak Frequencies for Fittings in Gas Plant. Draft Final Report.
U.S. EPA, ESED/EMB Report No. 80-FOL-l. September 1981.
C-7
-------
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 the 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
(1 2)
measurements. This procedure has been used in several studiesv ' ' 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 semi-quantitative 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
D-2
-------
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 would have been difficult
to establish a leak definition based on 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 principle 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
(3)
that conducted surveys at a distance-of 5 cm from the components^ '. This
(A)
information was used to formulate the test plan for initial 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 at 5 cm, with a leak definition concentration of 100 or
1000 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
fc]
techniques guideline document^ '. Many commentors felt that a measure-
ment distance of 5 cm could not be accurately repeated during screening
tests. Since the concentration profile is rapidly changing between 0 and
about 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
D-3
-------
the interface, or essentially 0 cm. This change required that the leak
definition level be increased. Additional testing at two refineries and
three chemical plants was performed by measuring volatile organic concen-
trations 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.
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 1000 ppmv levels. After the measurement distance was changed,
calibrations at 10,000 ppmv levels were required. Commentors 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 response
factors for several instrument types. ' ' ' The results of these studies
show that the response factors for methane and hexane are similar
D-4
-------
enough for the purposes of this method to be used interchangeably. 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. The variation in response factor is not a signifi-
cant problem because ambient concentrations around leaks are usually much
higher than the leak definition and much lower when no leak exists.
An alternative approach to leak detection was evaluated by EPA 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
D-5
-------
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
ppm 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.^ '
However, because soap scoring could not be used in all cases, this alternate
procedure was not included as a part of the reference test procedure.
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
D-6
-------
monitoring or screening of all 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 evalu-
tion of fixed-point monitoring systems for their effectiveness in leak
(8 12 13)
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 inter-
face where direct leakage to atmosphere could occur. The approach of this
technique assumes that if an organic leak exists, there will 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
determination of "no detectable emissions." The portable VOC analyzer
D-7
-------
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
D-8
-------
and reporting is estimated to be from $3,000 to $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.
D.4 References
1. Joint District, Federal, and State Project for the Evaluation of
Refinery Emissions. Los Angeles County Air Pollution Control District,
Nine Reports. 1957-1958.
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.
3. Telecon. Harrison, P., Meteorology Research, Inc., with Hustvedt,
K.C., EPA, CPB. December 22, 1977.
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.
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.
6. DuBose, D.A., and 6.E. Harris. Response Factors of VOC Analyzers
at a Meter Reading of 10,000 ppmv for Selected Organic Compounds. U.S.
Environmental Protection Agency, Research Triangle Park, NC. Publication
No. EPA 600/2-81-051. September 1981.
D-9
-------
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 600/2-81-022.
May 1981.
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. September 1981.
9. Emission Test Report: Dow Chemical Company, Plaquemine, La.
EMB Report No. 78-OCM-126, December 1980.
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.
11. "Data Analysis Report: Emission Factors and Leak Frequencies for
Fittings in Gas Plants," EMB Report No. 80-FOL-l. May 1982.
12 "Emission Test Report: Sun Petroleum Products Co., Toledo, OH,"
EMB Report No. 78-OCM-12B, October 1980.
13. "Emission Test Report: Union Carbide Corporation, Torrance, CA,"
EMB Report No. 78-OCM-12A, November 1980.
D-10
-------
APPENDIX E. MODEL FOR EVALUATING THE EFFECTS OF LEAK DETECTION
AND REPAIR ON FUGITIVE EMISSIONS FROM PUMPS AND VALVES
-------
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 for
evaluating the effectiveness of leak detection and repair (LDR) programs
on controlling fugitive emissions from pumps and valves. In contrast to
the model presented in the BID for analysis of LDR programs on relief
valves and compressor seals, the model in this appendix incorporates
recently available data on leak occurrence and recurrence and data on
the effectiveness of simple in-line repair (Reference 1). In the BID
model, LDR program impacts are_evaluated through emission correction
factors that are based in part upon engineering judgment.
E.2 DESCRIPTION OF MODEL
The modeled LDR program 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 occurrence.
There are four basic components to the 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 this program.
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
-------
fly fl«lt«t»»v «
Figure E-l. Schematic diagram of the modeled leak detection and repair program.
-------
are assumed to have the same leak rate as sources that were unsuccessfully
repaired. The model does not evaluate gradual changes in leakStates
over time but assumes that all sources in a given category have the same
average leak rate.
The emissions model enables investigation of several LDR program
scenarios. General inputs pertaining to the LDR program itself 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 monthly period; the
monthly occurrence rate is assumed linear within an inspection
period;
4) A turnaround essentially occurs instantaneously at the end of a
quarter 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 sources" category.
E.3 MODEL OUTPUTS
The outputs from the modeled LDR programs are shown in Table E-l
for three LDR scenarios for valves (quarterly, monthly/quarterly, and
monthly) and two LDR scenarios for pumps (quarterly and monthly). 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.
The Statistical Analysis System (SAS) program is provided in Table E-2
The data inputs to the modeled LDR programs are provided in Tables E-3
and E-4. The data outputs appear in Tables E-5 to E-14.
E-3
-------
Table E-l. RESULTS OF THE MODELED LEAK DETECTION AND REPAIR (LDR) 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.
-------
Table E-2. STATISTICAL ANALYSIS (SAS) PROGRAM TO EVALUATE
THE IMPACT OF A MAINTENANCE PROGRAM ON FUGITIVE EMISSIONS
FROM VALVES AND PUMPS
^^^»«>
S
6
7
e
9
in
11
1?
u
10
1?
lf>
17
18
19
?n
21
?7
3D
11
3?
35
id
37
38
39
HO
ul
«2
MS
uu
45
*!
>»»>*!
THIS STATISTICAL ANALYSIS SYSTEM (SAS) PROGRAM
ALLOWS THE USER TO EVALUATE THE IMPACT OF A
nAlNTENANCf PROGRAK ON FUGITIVE EMISSIONS FRO*
CFRTAIN IN-LINE SOURCES.
RADIAN CORPORATION
AUSTIN. TEXAS
AUGUST. 1981
*****
I
t
I
I
I
I
I
I
>:
OPTION* LS=l32
*»»»>»»»»*>*»»<
In ORDFR TO PROPERLY I«PuE"CnT THE PROGRAM THE FOLLOWING
TIIPUT PARAMETERS ARE
Ttprs sruf'r.E TYPE IDENTIFICATION
«rrvicc=scnvicr TTPE IDENTIFICATION
MflTsP^fCEsS L'NlT IDFUTIFICATION
TTi srnACTlOU OF SOURCES LEAKluG INITIALLY
»»n ERROR OF FE1 (MUST P,E ZERO IF OPTION1 = 0)
rrssFMAcTinu or SUCCTSSFULLY REPAIRED souRcrs THAT EXPERIENCE
rAPLY FAILURE
ERROR OF FE2 «MU$T BE ZERO IF OPTIO()1=0)
OF sourtcrs OPERATING PROPERLY AT THE BEGINNING
THAT BECOME LCAxTRS OURluG A PERIOO.
FTA=i OWPR BOUND OF A THO-TAI(.EO 95* CONFIDENCE INTERVAL ON
ff (MUST BE ZERO IF OPTION1=0>
TFnrtiPPER HOUND OF A TWO-TABLED 95X CONFIDENCE INTERVAL ON
FF (MUST BE ZEF.P IF OpTlONl = 0>
rlsItalTJAL EHISSlOfi FACTOR { KG/HR/SOURCE ) FOR ALL SOURCES
FlAsi OfcFR POUND OF A T»'0-TAlLEO 95t CONFIDENCE INTERVAL ON
rl (MUST OE ZEI'O IF OpTjONlsQ)
FlnsiiPPFR noUflO OF A TwO-TAjLEH 95* CONFIDENCE INTERVAL ON
t
I
1
»
J
I
I
I
E-5
-------
Table E-2. CONTINUED
47- rl (MUST BE 7LU.O IF OPTiDMlEO)
n TURMrFRrouEuCY OF TURNAROUND UN MONTHS)
9 FEsTuE VALUE OF FCl tfllEN A PROCESS TURNAROUND OCCURS.
50 PPTIONlcOi IF COMFlflrNCE INTERVALS ON EMISSION AND REDUCTION
51 ESTlMATfS ARE NOT DESIRED.
*9 si IF COMFIOFNCE INTERVALS ARE DESIRED.
53 PPTION2=0. IF PROGKAv. IS TO 9C RUN FOR ALL CASES*
54 sl« IF THE PPflGRAM IS TO RE RUN ONLT FOR THOSE
55 CASES I'-1 WHICH Fr<=IFL.
S6 OPTION3=0. IF MONTHLY FOLLO»-UPS ARE NOT TO BE PERFORMED
1,7 BETWEEN THE PERIODIC SCREENING AND MAINTENANCE
*« Of SOURCE*- THE FREOUEMCY OF THESE CHECKS MuST
59 <3t SPECIFIED (SEE 'PERIOD''PARAMETER BELOW)
60 sl» IF "ONTHLY FOLLO -u^S ARE TO BE PERFORMED
61 BETWEEN THE PERIODIC SCREENING AND MAlNT-
6? ENANCE OF SOURCES.
63 PERlrD=FREOUENCY
-------
Table E-2. CONTINUED
^^ .0 FllE PRINT LL=L IIEADCRsH NOTlTLFSt
in* IF FF>tF(. THEN k='«M
107 AHRAY A Sfl-SCs TFA FFB ElA EIBt
in« IF OPTTOnlsn THEN TO OvCR At A=.| CNO«
109 JF L<7 THEM PUT -PAGE-J
110 IF FIPsT.TTPE THEN PUT // TYPE' IF FIRST.UNIT THEN PUT /.UNIT "UfllTSM
111 PUT / Sfr «
11? s>7 $rRUtr.F a?9 El a<»7 FF »63 Irl »76 Fl 8B9 F2 9102 FE1 »H5 Fc2 / S-25 'i1 EIA
113 *.« *S2 EIP fr.M a39 '»' P«t3 M« FF* 6.«« S50 «. FFfl 6.1* 957 ) P62
im
-------
Table E-2. CONTINUED
1*0
J«tl
i«s
1«il
J««S
1«7
1*49
150
151
15?
1«3
]5u
155
157
1 fc 1
169
IfS
16A
167
170
171
172
17U
171
17*
177
17P
179
l^n
101
»rr? r INACTION or PFPAIKED SOURCES THAT LXPCHICNCL FAHLY IAJ LUKES* ;
|F CHCCKd THEN DOl
LFAK ncciiREncE RATE IFF> FO« «« PCRJOD is GREATER THAN THE «
'INITIAL FRACTION OF SOURCES LEAKING UFI. ) /
»lo «TliI< WILL KESULT IN * NEGATIVf EMISSIONS REDUCTION. « 81
»l
IF OPTTOu?=1 TllFH PUT *?. 'THE OPTION TO NOT RUN THE PROGRAM FOR THIS /
*ln 'CASr HAS pEEfj SELECTED. 'r
RETUPrit
»' PUT 8>56 'I II P U T D T At // 826 'FOR EXAMINING THE REDUCTION IM
'AvfRAFC LFAK PATE DllE TO A MAINTENANCE PROGRAM' ////SSI 'El' 8m
»f.tt "ITL* S78 'Fl' S91 'F2« 810M 'FEl' S117 'FE2« / as 'TTPE OF' 32& lS,'.
»«tu J3»'-' S62 «'- 875 9*1-' 88B 9«»-« 8101 9«'-' 8il«» 9««-: /
«6 "tOURCf/U'lIT' 826 'HE AM (95? ell' 8MH 'MCAN(95X CD'
»69 «»'f.EAti CSEI « / fl! 120*'-' I
RETURN!
»»
» **«***»*»**»a»««*«*«««*»tt»**»««»*tt*«tt**»tt»*««*«**«ttB9**tt«tt|
!
«
Tlir FOiLOklMR MACRO CPEVELOP* CALCULATES EMISSION RATES AS A
FUNCTION OF TIVE C IN MONTHS)
ARRAY
ARRAY
ARRAY
ARRAY
ARRAY
ARRAY
ARRAY
ARllAY
»«»»»»»»»»'»»»«»*»«»»»«
lOFVELOP " :
Vlll FEU FE21 Fpl FLU ARRAY XOfL) TflFEll TOFE21 TflFpl ToFLU
X?lS> T2FE12 T2FE29 T2Fp2 T?FL? T?FE11 T2FE21 T2FR1 T2FL1«
XIiSl T1FE12 T1FC29 TlFp2 T1FL2 TlFEll'TlrE21 TlFpl TlFLJI
XMS) TSFEl?. T3FC32 T3FP? T3FL2 T3FE11 T3FE21 T3FP1 T3FLU
XMS) T»»FEl2 TNFf?2 T«4FP.i T"»F|.2 TUFEll T«(FE21 T*»FP1 TuFLlJ
X«.(S) TSFE1? TSFTP2 TSrP? T**FL2 TlFEll T5FE21 T5FP1 TpFLlJ
XMS) T^FE12 T6FEP2 T6FP2 T«.FL2 TftFEll T6FE21 T6FP1 TftFLl!
X7«S) T7FE12 T7FE92 T7FP2 T7FL2 T7FE11 T7FE21 T7FP1 T7FL1I
X«(Sl TflFEl2 T8Fr?2 T8FP£ TCFL2 TftFEll TBFE21 T8FP1
X«ISl TeFEl? T9FEP? T9FP? T9FL2 T9FE11 T9FE21 T9FP1
XlO««) TJOFE12 TlnFf22 TippP2 T10FL2 T10FEH T10FC21 TlOFpl T10FL1:
XlllS) T11FC1? TMFE?2 THFP2 T11FL2 TllFEU TllFr2l TllFpl T11FL1I
*12(S) T12PE12 T12FE22 T!?FP2 T12FL2 T12FEH Tl?FF2l T12FP1 T1?FLU
Yll ) TFE12 TFE22 TFP2 TFL2J
XX(SS) K X1-X12I
TTIL) FEl?. FE22 FP2 FL2;
Yin) FEl? FE22 FP2 FL2 FElJ FE21 FPl FL!I
FS/T) FSi-FSfo: ARRAY FM(T) FMI.FM&OJ
I KIT) LEAKl-LFAKfiOs ARRAY RPIT) REOUCTl-REDUtTfeO:
AHRAY »Fri2lT) FE12_l-rri?.60: ARRAY AFE22IT) FE22.1-FF22.60:
ARRAY A!-P?
-------
Table E-2. CONTINUED
) rin.i-f ril.r.o; «I»HAT nrcinTi f tki.i-rt2l.bn;
in«, i\R* FLI.I-FLI.&O;
1»7 CU=ET/nFL«Cl-IFL)«F?M EE=Fl»ltt EP=F2«EU
16* FEjlrOi FE?1=C» FLl=lFi J FPlsl-Fl.il
1^2 0" OwfP tTI X=TTt XO=Vl
I'JS FEulnsOi rE2l.O=Ol FL1.0=lrLj FPl.Osl-FLl-OI
1^« FE12* 0=Frll_0+(FE2lln+Fl1_OI«FEli
j FL2_I>=0»
197 pO Tr1 TO 60«
0=t»On
-------
Table E-2. CONTINUED
>M t* YPso'-fuEu Lit ;
939 FEl2=«l-rPl|»Fri
FE?2=<1-FPH«(1-F£|,FE?|
?3S ELSE Dot
93*. FEl?sFrlt«tFE2l4FLl)«FEl i
9.37
93S
239
9110 FL9=ni
9«i ou OVER vi xo=v«
?M3 00 S«s? TO
?m» Q
?«45 s
00 Srl.?.5«6«
SUvErsSUMlSUMCC.XX) t
950 00 SsS.Ti
?5l SUMEP=SU
?f? ENOJ
?53 FHHI
?57
9S»« «Ds FE21.l-rE91.60j ARRAY OFPKMI Fpl.l-FPl.AO «
969 ARRAY OP) l(M) FLl-l-FLl_£Ol
970 «=OS
271 00 TrPrfllOD TO 60 PY PERlOOl
S79 M-M»H LlsLK! RsROI HFE12sAFEl?. : BFE??=AFE22| BFp?.sAFP2l BFL2=AFL9.I
973 DrrilsAFril; BFr21=AFr21l BFPl=ftrPl; BFL1=AFLU ENDI
97u KEPP TYPr SF.RVTCE UNIT L1-U60 R1-R6H Ffl2.0-FEl2.60
9.75 Fr'?".0-FE29_60 rP2.0-FP2.60 FL?._ft-FL2.*0 FE11.0-FEH.60 Fr.21_0-FE?l-f>n
.0 Fuj.O-n.1.60 IPS FSI-FS60 IFM FMl-FMfeO EL EE EP IFL
E-10
-------
Table E-2. CONTINUED
.S77 Tl F? PfblOn UlKlAL 0»'1TON2t
?76 *
son »*»»««*»»» i
sei THE roLLOwiiic COPE COMPUTES AMD PRINTS OUT THE TOTAL TRACTION »i
?B? Or OliRCrS SCREENED AMD OPERATED 0N OVER EACH TEAR OF THE FIVE !
2*3 TrAQ irAlNTEnANCE PROGRAM. !
2*5 «
?««, DATA RAW i SF.T IljPUT IDROP=SE1-SE5 FF« FFO ElA EIBll
PB7 IF OPTTOM2=1 AMD FF>IFL THEN
DATA .NUIL.JSET RAW( KEEPsTTPE SrRVlCE UNIT IPS FSl-FSfeO
RY TYPr UNIT SCRVICCt
FlLC PRINTS H=PS lirAOERni NOTlTLrS«
??? ARRAY ISIIHFS l.ll SllMFSl-SU«FS5« ARRAT _SUMFn IJ1
IPS FSI-FS12) iSUHp^irSUMtOF IF" FH
FSl3-FS2«4)i SUKF"?zSlJM t OF FM13-FM2UH
?9S SU' I
SOO IF Rurisfl THFH 00«
301 C=A7in=77:C2=fi2!C
302 IF RtlNsl THEN D0»
303 PUT "_P»GF_J
PUT *m aC3 SERVICE 'SERVICE' / S>C1 HI*'-'/
W r.l 'TOTAL FRACTION OF' *6 'TOTAL FRACTION OF' »
|F R(|Ms1 TMFIJ PyT a 15 'YEAR* Bt
30« PUT a ri 'SOUHCES SCOEEHrO' +6 'SOURCES OPERATED ON' I
309 IF Riifjsl TMCN PUT 812 2«'-" 81 PUT 8C 5u»'-' ///j
Sin DO Jrl TO 5 l
311 IF RllNsl THF.N PUT 816 J 9. 3|
312 PUT aC9 ISUKFS 7.<« *16 _?6 'SUMMARY OF TOTAL FRACTION OF SOURCES SCREENED AND
316 'OPERATED 'ON FOR'*1 TYPE "BY YFAR' / 859 UNIT 'UNITS' /////I
S17 RETURfU
31* »
U9 .»«««««»»
J20 TuE FPLLOWlnG COOC SIMULATES RCTENING 'NO EMISSIONS DATA USING <
521 SAMPIF VAL'IFS CINPUT) IN OwDcP TO ESTlMftTF CONFIDENCE INTERVALS «|
A?? on r*lSMGns ANO EHICSIONS RCOUCTION. «i
E-ll
-------
Table E-2. CONTINUED
32*
32« »
32* DMA GrwtPATCJ SET
S?A If OPTTOm2=l AriO FF>IFL THEN DELETE!
327 ARRAy L«n(Z) SOI S02j
328 SPl=M«» FPM3 ElH3;
D? ARRAY Ml 7.) FFCl EIC1I ARRAY C2 ( z ) FTC? E1CJ1 ARKAY C3(Z) FTC3 EIC31
SAS ARRAY n?(Z) FFps Cin?1 «RRAY 0^(21 FFDS EIOSI
*»» ARRAY YO«Z) FFYO ElYOI ARRAY RVAR(Z) RV.FF nV.EH
335 ARKAY PTlZ) FFPT EIPTI ARRAT CQIZJ FFCO ClCOl
336 ARRAY IsrrDcIl SECOl-SETDSl
13* ARRAY Mill!) IPL Fl F2 FE1 FE2t »RRAY RV(I) RV_1FL Rtf.Fl Rtf.F2 RV_FEl RV F
339 ARRAY CF(X) SEi-SESt
SMn IF OPTTONl=l THE" 001
3X1 00 Owrfl A: H1S.02S/A; ri=U-«A»«?l»Hi)/2-((((R*3«a)»»2)-(B««2) )«H!/6»1
3«2 C2s( (U««2l-(«««2) J/jj 02=U-At
i«3 C3=< (B«.2)-«ll«*2) 1/2j 03=8-UI
X'tn H3=( (C1.D2)-(.95«C2» )/( CC3.0? »-«C2»03l >< H2s( ,»5-(03«H3 ) 1/021
5<45 PTs0.025*H2»(U-A)« END;
306 nO Jsl TO NTRlAL' ;"
DO OVF.P MU> RVsHU+sr«NORWALI.SErD> » END|
DO OVER vo: Yr=UMiroRM('sp»
3U9 IF n<=YO<.0?5 THEN RVARsYO/HXl ,
350 FL^F IF .025 OUTPllT!EMl);END:ELSr IF OoTIONl=0 THEN OOl
ASA DO OVER *u:iw="u!ENOJ
357 00 OufP U;PVAP=U!ENO«
SSfl " OUTPUT JENOJ
559 KEEP TYPr SFRVTCE UNIT Pu.IFL QV.F1 RV.F2 RV.FE1 RV.FE2 RV_FF Rv.EI IFL Fl F?
560 FEl FE? TUPn FE MTRUL OPTION? PERIOD OPTIONS;
3«-l »
)6 y *<*»»»«******« |
S6S THE FOLLOWING CODE COMPUTES AMD PRINTS THE ESTIMATED EMISSION ;
564 FACTOaS MJD FKACTTOtiAI. REDUCTION IN EMISSIONS (INCLUDING 90S ;
365 cnrrmEwrr LIMITS) PER TURNAROUND. ;
QATA CrurpftTEt SET GENERATE I
E-12
-------
Table E-2. CONTINUED
if IBV'IFL «?«irt n OR t?»n » OK
170 CSV FP <0 CR RV_F2 >(2*F2 )) OR IRV.Fr.KO OR FV_FEl>C?»FEi U OR
37J «RV_rr2 <0 pu «V_FE2 ><2«FE2 II THCN DELETE!
578 ARPAY miltl IFL FI F2 FE1 FE2« ARRAY Rv(I) RVllFU «V_F1 Wv_r2 RV.FF.l RV.Fr2|
S7S APPAT 11(71 FF Ell ARRAT Rv^PCZI RV.FF RV.EII
37« 00 OuEP MUl MUsRVI ErtOl 00 OVrd Ul UsRvARl ENOI
375 .OrvruoPi
S7fc PROC UMlV/ARlATc NOPRTNTl BT TYPE UNIT SERVICEI
577 VAR I 1-L60 R1-IR60 t
37B OUTPUT OUTrSTATS P5=l Ok'Ll-LoWL&O
J7^ LOVR1-LOWR60 P95=HIGIU 1-HlGHt.fO HI6HR) -MI6HR60 I
3i«n O*TA EFKrAN«s;r«rn6E STATS INPUT IKCEP=TTPE UNIT SERVICE TURN
3*1 OPTION: PERIOD OPTION2 FF
3*9 RAH «KEEP=TTH£ (iMjT SERVICE L1-L60 R1-R60)!
S«1S I'.T Typr UrilT SERVICEi
W« JF OPTtON2=l AMD FT>lFc THEN nELfTEl
S95 ARRAy lFF(K)
S67 flRRAt "rrU«Kl FFU1-EFU20I
A«RAY _R(K) RDl-ROSOt
ARRAY 'RI «KI RLI-"L?O«
ARRAY _R(I(K) Rt)l-RU?OI
ARRAY _«M IT) Ll-t6n«
ARPAY *»«(L(T) LOwLl-LOWLftOl
3*?3 ARRAY _«IU(T» MI6IIL1-HIGIIL60I
3»M ARRAY iHR(T) Rl-R60l
ARRAY >«L(T)
AR«AY IMPU(T)
0° OvCP
_»«PL=(1»«R-_MRL
uOl ARfAY ISUM SU*j-SUK6tOO OVER .Su»"t _SUMrO«ENDJ
ul?
DM N=60/PrRiOO:
i»C5 00 T=1 TO HJ
u07
un«
<«P» IF I-Ttl THEM DO! K=K4lJ
ulO .ErseL'wl /TfJi_EFL=.Er-SOPT«SUM2/TN) I .EFUr
11 lRrSil«»u/TN« _RL=-R-S?RT(SLIM5/TNI j _R
E-13
-------
Table E-2. CONTINUED
IS KfTP TYPF OtilT SEHVICL K EH-EF?o
if, rnu-TFUpo RDI-RD?O KLI-RL?O RUI-RUSO OPTIONI i
17 DAT* .MlllL.lSET EFMEANSlBY TTPE UNIT SERVICE!
IB FILE PPINT1 N=PS HEADERsH NOTITL.CS!
19 ARRAY '.tf lATELT FOLLOWING prRIODIC »t
50 MMNTrNAHCE) AMD FOR THE END (JUST BEFORE PERIODIC MAINTENANCE »l
St I« PERFCnuEOI OF EACH PERIOD. «j
uS? »»«»»»*»«»***»«»»»»«»!
53 «
5M DATA IHULL.J SET RAW: BY TYPE UHIT SEPVICEI
55 Fll E PPTMT3 Ll.=L MEADERsu UOTlTirSj
5A AHRAv Ir^l |JJ FS1-FS12J ARRAY _FM1 (J) FM1-F>«12«
57 AHRAY lF«!2 (Jl FS13-FSP«« ARRAY _Fi«2 (J) FM13-FM2HI
5« ARRAY _r«3 (J> PS25-FSS6: ARRAY _rf3
-------
Table E-2. CONTINUED
«ti FORMAT Fs:-FS6n F*I_FM«,P ir« IFS fc.«n
«.? If FIRST. SERVICE OR L<1"« THEN P. T .PASE.I
«f.S PUT / Bl 'INITIAL' BIS TFS 82* TF" 8"»2 853 - 867 * 87* 89? --
»6» »103 8117 -- 812? //|
«65 00 Jcl TO 121
46 PUT S3 J 2. 815 -FSl 826 .FMl Sur .FS2 OS1 .FH2
»** IFSS 876 _FMS 6*n .FS<« eioi _FMH BUS .FSS
S 12*. .FM5 //I
«7n RETURNS
»7i H: PUT /// »3l 'FRACTION OF TOTfti RPURCES SCREENED AND OP««TED ON F0»» +1
«7? TtPE «nY KONTH« / 851 UNIT 'UNITS - ' .
»73 SERVtCr «SERVlCE' /////
i»7« 9l« '1ST YEAR1 81** '2ND YEAR' afi9 '3RD YEAR' 89M «"«TH TfAR* »119 '5TH TEAR1 /
u75 91« 19»'.« »39 l9»«.« a«u 19»«-« 8B9 !»-' BllH 19»'.» / 925 'FRACTION* »50
«7A 'FpArTTOM' 975 'FRACTION' 8100 'FRACTION' 8125 'FRACTION' / 81 "»
«77 "FRACTTON OPERATED' 839 'FRACTION OPERATED'
«7« 86u TRACTION OPERATED' 8B« 'FRACTION OPERATED' 8U«» 'FRACTION OPERATED'
u79 /»? 'KONTH' Si* 'SrREEnEO' S2« 'ON' 839 'SCREENED' S55 'ON'
«en P«M 'sr»»rENED' a7» 'ow su9 'SCREENED* 8103 «ON' aim 'SCREENED* sisa 'ON* /
«»«1 91 7.'-« Sti« 8.'-' S85 «.'-' 839 fl»'-; 8RO « S6K «' 871 *'' »69 «'.«
«t»? sioo R«'-' S»HM e«'-' PIPS e»'-»i
ueo '
ulf, THF FOLLOWING CODE PRINTS OUT THE ESTIMATED- EMISSION FACTORS »l
467 Ann FRACTIONAL REDUCTION IN EMISSIONS UNCLUDING 90X CON. <
U«>M nnr.HCC LlriTS) FOR FACM PCs j on or THE FIVE YEAR MAINTENANCE «i
UB9 PROfiRAK. ;
U91 »
«99 D*TA _r«lLL_« Hr.RGE STATS INPUTIKrEP=TTPE UNIT SERVICE PERIOD
»93 OPTIOHI OPTIONS FF IFD
««tt RAW t«EEP=TTPF UNIT SERVICE L1-L20 Rl-R20||
«95 OY TTPF UNIT SERVICE*
»96 IF OPTIOn2=l AMO FF>lFt THEN
97 FILE PRINT"* W=PS HEAOERaH
«$A ARRAY >l (J) L1-L20:ARRAY .LOW) (J> LOWL1-LOWL20I
U?q ARFlAv 'HTI5HL IJ> HlfiHLl-HIGHLaOi ARRAY _MR «J» Rl-R?0l
50n ARRAY linwR Ul LOwR1-LOwR20J ARPAY .HlRHR (Jl HI6HR1-HI6MR20 «
501 IF FIRST. UHTT THEN K=OI K+U RUM=MOD
-------
Table E-2. CONTINUED
S07 PUT PC? 'MEAfl rMlSSIPN-KK/IIR (9fl» til KEPUCTION «90« CI»M
SDK C>-*C IF OPTTOMjsO THEN PUT 8C2 *3 'MEAN E«ISSION-KG/HR« «l«l
50* 'REDUCTION* |
MO Ir KtiNsl THFN PUT «i« *'.« 81 PUT BCS «' // I
511 LsftO/PrRTOOl
SI? If L>20 TllCN LsSOl
SI 3 DO J=l TO Ll
sm IF RtiMsi THFN PUT ire J 2. 8« IF OPTIONISI THEN PUT ec
515 1"| *.«» *2 «( _LOwL 5.3
51ft *t» .HTRHL 5.3 )*? ^MR fc.3 *?. M« _LOWR 5.2 «
517 .HT6MR *.? ') /»
sie c>-sc IF oPTiOMisO THEN PUT ac *s .VL S.K *zi .MR 6.3 /«
519 cNm
5?0 RCTURHl
Ml H: PUT ///// KI37 'ESTIKATED EMISSION FACTORS (KG/HP) AND FRACTIONAL REDUCTION*
5?2 / 8*8 Mf MASS EMISSIONS FOR TTPf *BT QUARTER - *1 UMIT 'UNITS' //// i
RETURru
525 »*«»»«»«»*»«»««"*»!
526 THr FOLLOWING CODE PRINTS OUT THE FRACTION OF TOTAL SOURCES »l
527 «CRCrNCO AflD OPERAjED ON FOR rACH MONTH OF THE FIVE TEAP »J
52M MAINTENANCE PROGRAM. »
5J9 «»« »»* »«*»»» |
ssn »
SSI DATA .NULL- 1 SfT RAW; BY -TTPE UI4JT SERVICE! . ;
S3? FllE PRIHT5 LL=L HEADERsu NOTlTLfSl
53S ARRAY _H 2 (J) FL2.0-FL2*19I ARRAT -FLl (J) FLl.l-FLl.20l
53«t ARRAY _rrl2 «J) FEl2_0-Frl2.l9 ; ' '
53S ARRAY 'Frll «JJ FEll.l-Frll.2n«
53ft AKnAY _FP22 (J) FE22.0-Fr22.19 « ARRAY .FE21 (Jl FE21.1-FE21-20J
537 A"RAY 1FP2 u) FP2_n-FP2li9i A"RAY -FPI (J) FPi.i-FPi.2ot
5?6 IP FTRST. SERVICE OR L<1"» THEN PUT .PAGE.J
S3fl PUT / a« 'INITIAL' S2l --- 833 FL1.0 S.3 850 '- 862 Fcil.O 5.3 879 «-.-t
5*0 «91 FE?1_0 fe.H 81 OB ' ' »120 FP1.0 5.S /I
SMI Ls60/PrR10D|
m? IF L>?n THEM L=20«
S« 3 00 Jsl TH Ll
SMI* PUT 88 J 2. 820 .FL2 5. S 833 .F|.t 5.3 8U9 .FE12 5.3 862 .FEn 5.3
5US «i7r. *Fr22 &.<« 891 _FE?1 6.«» 8107 .FP2 5.3 8120 .FPI 5.3 /«
5«7 If FIPCT.SEPVlCE OR L<1* THEN P»T "61 87 ' LEAKERS REFERS TO THOSE SOllKCES '
'SCRrEMING GREATER THAN OR EcuAL TO iO.OOO PPMV.' I
550 Ht PUT //// »39 'FRATTIOWAL nl^TRIBUTION OF SOURCES FOR' +1
551 'PY PERTOO' / 951 UNrT MjfilTS' «1 '-' +1 SERVICE 'SERVICE' ////
552 an 'FRACTION OF LEAKERS*' »5^ 'FRACTION OF' S7P 'FRACTION OF SOURCES'
E-16
-------
Table E-2. CONCLUDED
SS3 S.Jfl7 'FpACTlOli OF SOURCES' / P?l «ru;l TO OCCURPFMCr'
S">«t ft* «UtmEPAIREf» FOUhrES' »Ts tEXPERlENCiNG E«RLY FAILURE*
55S »in7 OPERATING PROPrRtt1 / 316 S3*'-' P<*7 23»*-* 875 26**-1 BIOS 23»«-« /
el* tBCGjriljIMG' p3«( «CNO« 8u7 'PEGlNNlNG* 863 «EMO*
»9? "CUD* *l05 'BEGIwnlNG' Sjjl "EMO* / 8«» «( PERIOD ««»OMTHS|t
»1* »OF PEniOO OF PERIOD' S«»7 'OF PERIOD OF PERIOD*
»7t »OF PtniOD OF PERIOD* S105 'OF PERIOD OF PERIOD* / &«»
Sf.1 RETURN*
E-17
-------
Table E-3. INPUT DATA FOR EXAMINING THE REDUCTION IN
AVERAGE LEAK RATE DUE TO A MAINTENANCE PROGRAM (VALVES)
I
»-*
CD
TYPE OF
SOURCE/UNIT
VALVES
MONTHLY UNITS
THC
VOC
QUART /MONTH UNITS
THC
VOC
QUARTERLY UNITS
THC
VOC
El
MEAN (95Z CD
0.02
0.0075
( t )
0.02
( 9 }
0.0073
( t 1
0.02
( )
0.0073
( )
FF
HEAN(95X CD
0.038
1 > )
0.038
( t 1
0.038
1 1
0.038
f f )
0.038
4 )
0.038
( i )
IFL
MEAN (8EI
.
0.18
( 1
0.18
< »
*.*- 1
0.18
( )
0.18
( )
o.ie
( )
0.18 "
( )
Fl
MEAN (BE)
0.374
0.374
1 >
0.374
( 1
0.374
( )
. 0.374
( )
0.374
( )
F2
MEAN (SE)
0.023
( >
0.023
' >
0.023
( )
0.023
( )
0.023
( )
0.023
( )
FE1
MEAN (SE)
O.I
0.1
( 1
0.1
( )
0.1
C I
0.1 |
( 1 )
' 0.1
( 1
FE2
HE AN (1
0.14
0.14
'
0.14
(
0.14
(
0.14
|
.0.14
f
»E>
*
)
1
)
1
y
TURNAROUND EVERY 12 MONTHS FRACTION OF SOURCES UNREPAIRED (FED IS 0 AT THE TURNAROUNDS
El EMISSION FACTOR (KG/HR/SOURCE) FOR ALL SOURCES INITIALLY
FF FRACTION OF NON-LEAKING SOURCES AT THE BEGINNING THAT BECONE LEAKERS
(SCREENING VALUE GREATER THAN OR EQUAL TO 10.000 PPHV) DIIRINft A .1 MONTH PCRIOD (LEAK OCCURRENCE)
IFL FRACTION OF SOURCES LEAKING INITIALLY
Fl » ONE MINUS EMISSIONS REDUCTION FROM AN UNSUCCESSFUL REPAIR. DfFINFD BY EE'FltFL UHERE.
EL-AVERAfiE EMISSION FACTOR FOR SOURCES LKAKIHG AT OR ABOVE THE ACTION LEVEL. AND
EE'AVERAGE EMISSION FACTOR FOR SOURCES UHICH EXPERIENCE EARLY LEAK RECURRENCES
F2 ONE MINUS EMISSIONS REDUCTION FROM A SUCCESSFUL REPAIR. DEFINED BY EP"F2*EL UHERE EL IS AS DEFINED ABOVE. AND
EP-AVERAGE EMISSION FACTOR FOR SOURCES LEAKING BELOU THE ACTION LEVEL
FE1 " FRACTION OF SOURCES THAT ARE LEAKING AND FOR UHICH ATTEMPTS AT REPAIR HAVE FAILED
FE2 " FRACTION OF REPAIRED SOURCES THAT EXPERIENCE EARLY FAILURES
-------
Table E-4. INPUT DATA FOR EXAMINING THE REDUCTION IN
AVERAGE LEAK RATE DUE TO A MAINTENANCE PROGRAM (PUMPS)
u>
TYPE OF
SOURCE/UNIT
PUHPS
MONTHLY UNITS
THC
VOC
OUART/HONTH UNITS
THC
VOC
QUARTERLY UNITS
THC
VOC
TURNAROUND
El
HE AH (95Z
0.063
( i
O.OS
( ,
0.063
( i
0.05
( i
0.063
( i
0.05
( f
EVERY 12 MONTHS
FF
CD HCAN(93Z CD
0.102
> ( t I
0.102
> ( i )
0.102
> ( f >
0.102
> ( i )
0.102
> ( i 1
0.102
) ( i >
-- FRACTION OF SOURCES
IFL
HEAN (SE)
0.33
( )
0.33
( )
0.33
( )
0.33
( )
0.33
( )
0.33
( )
UNREPAIRED (FED
Fl
HEAN (SE)
1
( )
1
( )
1
( )
1
( )
1
( )
1
( )
IS 0 Al THE
F2
HEAN (SE)
0.13
( )
0.13
( )
0.13
( )
0.13
( )
0.13
( )
0.13
( )
TURNAROUNDS
FE1
HEAN (SE)
i
0
( )
0
( )
0
( )
0
( )
0
( )
0
( )
FE2
HEAN
)
)
)
)
)
)
El * EMISSION FACTOR (KG/HR/SOURCE) FOR ALL SOURCES INITIALLY
FF = FRACTION OF NON-LEAKING SOURCES AT THE BEGINNING THAT HfCOHE LEAKERS
(SCREENING VALUE GREATER THAN OR EQUAL TO lOtOOO PPHV> DURING A 3 HONTH PERIOD (LEAK OCCURRENCE)
IFL = FRACTION OF SOURCES LEAKING INITIALLY
Fl » ONE HINUS EMISSIONS REDUCTION FROM AN UNSUCCESSFUL REPAIR. DFFIHEU BY EE*-F1*EL WHERE.
EL'AUERAGE EMISSION FACTOR FOR SOURCES LEAKING AT OR ABOVE THK ACTION I.EVELt AND
EE»AVERA(!E EMISSION FACTOR FOR SOURCES UHICH EXPERIENCE EARLY LEAK RECURRENCES :
F2 " ONE HINUS EMISSIONS REDUCTION FROH A SUCCESSFUL REPAIRi DEFINED BY EP"F2*EL WHERE EL IS AS DEFINED AkOVE> AND
EP'AVERAGE EMISSION FACTOR FOR SOURCES LEAKING BELOU THE ACTION LEVEL
FE1 - FRACTION OF SOURCES THAT ARE LEAKING AND FOR UHICH ATTEHPTS AT REPAIR HAVE FAILED
FE2 « FRACTION OF REPAIRED SOURCES THAT EXPERIENCE EARLY FAILURES
-------
Table E-5. ESTIMATED EMISSION FACTORS AND MASS EMISSION REDUCTIONS (VALVES)
SUMMARY OF ESTIMATED EMISSION FACTORS (KG/HR) AND FRACTIONAL REDUCTION
IN HASS EMISSIONS. FOR VALVES BY TURNAROUND - MONTHLY UNITS
THC SERVICE
VOC SERVICE
TURNAROUND
1
2
3
4
3
HEAN EMISSION-KG/HR
0.0040
0.0033
0.0033
0.0033
0.0033
REDUCTION
0.798
0.835
0.836
0.836
0.836
MEAN EMISSION-KO/HR
0.001S
0.0012
0.0012
0.0012
0.0012
REDUCTION
0.798
0.83S
0.836
0.836
0.836
SUMMARY OF ESTIMATED EMISSION FACTORS (KG/HR) AND FRACTIONAL REDUCTION
IN HASS EMISSIONS FOR VALVES BY TURNAROUND - QUART/MONTH UNITS
m
o
THC SEItVICE
VOC SERVICE
TURNAROUND
1
2
3
4
5
HEAN EH1SSION-KO/HR
0.0051
0.0044
0.0044
0.0044
0.0044
REDUCTION
0.745
0.778
0.779
0.779
0.779
MEAN EMISSION-KG/HR
0.0019
0.0017
0.0017
0.0017
0.0017
REDUCTION
0.745
0.778
0.779
0.779
0.779
SUMMARY OF ESTIMATED EMISSION FACTORS (KG/HR) AND FRACTIONAL REDUCTION
IN MASS EMISSIONS FOR VA1VES BY TURNAROUND - QUARTERLY UNITS
THC SERVICE
VOC SERVICE
TURNAROUND
1
2
3
4
5
HEAN EMISSION-KG/HR
0.0054
0.0046
0.0046
0.0046
0.0046
REDUCTION
0.732
0.769
0.771
0.771
0.771
MEAN EHISSION-KG/HR
0.0020
0.0017
0.0017
0.0017
0.0017
REDUCTION
0.732
j 0.769
0.771
! 0.771
j 0.771
-------
Table E-6. ESTIMATED EMISSION FACTORS AND MASS EMISSION REDUCTIONS (PUMPS)
SUMMARY OF ESTIMATED EMISSION FACTORS ftMK FRACTIONAL REDUCTION
IN MASS EMISSIONS FOR PUMPS BY TURNAROUND - MONTHLY UNITS
TURNAROUND
THC SERVICE
MEAN EHISSION-KO/HR
REDUCTION
VOC SERVICE
NEAN EHISS10N-KO/HK
REDUCTION
1 0.0219
2 0.0219
3 0.0219
4 0.021?
5 0.021?
0.653
0.653
0.653
0.653
0.653
0.0174
0.0174
0.0174
0.0174
0.0174
0.653
0.653
0.653
0.653
0.653
SUMMARY OF ESTIMATED EMISSION FACTORS (KO/HR> AND FRACTIONAL REDUCTION
IN MASS EMISSIONS FOR PUMPS BY TURNAROUND - QUART/MONTH UNITS
I
ro
TURNAROUND
THC SERVICE
MEAN EMISSION-KO/HR
VOC SERVICE
REDUCTION
MEAN EHISSIOH-KC/HR
REDUCTION
0.0256
0.0258
0.0258
0,0258
0.0258
0.594
0.590
0.590
0.590
0.590
0.0203
0.0205
0.0205
0.0205
0.0205
0.594
0.590
0.590
0.590
0.590
SUMMARY OF ESTIMATED EMISSION FACTORS (KO/HRi AND FRACTIONAL REDUCTION
IN MASS EMISSIONS FOR PUMPS BY TURNAROUND - QUARTERLY UHI1S
TURNAROUND
THC SERVICE
MEAN EMISSION-KO/HR
REDUCTION
VOC SERVICE
MEAN EMISSION-KO/HR
REDUCTION
1
2
3
4
5
0.0262
0.0262
0.0262
0.0262
0.0262
0.5B4
0.584
0.584
0.584
0.584
0.020B
0.0208
0.0208
0.0208
0.0208
0.584
0.584
0.584
0.584
0.584
-------
Table E-7. FRACTION OF SOURCES SCREENED AND OPERATED ON BY YEAR (VALVES)
SUMMARY OF TOTAL FRACTION OF SOURCES SCREENED AND OPERATED OH FOR VALVES BY YEAR
MONTHLY UNITS
THC SERVICE
VOC SERVICE
YEAR
1
2
3
4
S
TOTAL FRACTION OF
SOURCES SCREENED
12.6653
11.8787
11.9020
11.9020
11.9020
TOTAL FRACTION OF
SOURCES OPERATED ON
0.4082
0.1943
0.1911
0.1910
0.1910
SUMMARY OF TOTAL FRACTION OF SOURCES SCREENED AND
QUART/MONTH UNITS
YEAR
1
2
3
4
5
THC
TOTAL FRACTION OF
SOURCES SCREENED
5.4014
4.3013
4.2664
4.2659
4.2659
SERVICE
TOTAL FRACTION OF
SOURCES OPERATED ON
0.4007
0.1899
0.1867
0.1867
0.1867
SUMMARY OF TOTAL FRACTION OF SOURCES SCREENED AND
QUARTERLY UNITS
YEAR
1
2
3
4
S
THC
TOTAL FRACTION OF
SOURCES SCREENED
4.8975
3.9729
3.9737
3.9737
3.9737
SERVICE
TOTAL FRACTION Of
SOURCES OPERATED ON
0.3980
0.1884
0.1BS4
0.1853
0.1853
TOTAL FRACTION OF
SOURCES SCREENED
12.6653
11.8987
11.9020
11.9020
11.9020
OPERATED ON FOR VALVES
VOC SERVICE
TOTAL FRACTION OF
SOURCES SCREENED
5.4014
4.3013
4.2664
1.2659
4.2659
OPFRATED ON FOR VALVES
VOC SERVICE
TOTAL FRACTION Of
SOURCES SCREENED
4.8975
3.9729
3.9737
3.9737
3.9737
TOTAL FRACTION OF
SOURCF.S OPERATED ON
0.4082
0.1943
0.1911
0.1910
0.1910
BY YEAR
TOTAL FRACTION OF
SOURCES OPERATED ON
0.4007
0.1899
0.1B67
0.1367
0.1867
BY YEAR
1
TOTAL FRACTION OF
SOURCES OPERATED ON
0.3980
0.1884
0.1854
0.1853
0.1853
E-22
-------
Table E-8. FRACTION OF SOURCES SCREENED AND OPERATED ON BY
(PUMPS)
SUHHARY OF TOTAL FRACTION OF SOURCES SCREENED AND OPERATED OH FOR PUHPS »Y YEAR
HONTHLY UNITS
THC SERVICE
WOC SERVICE
TOTAL FRACTION OF
YEAR SOURCES SCREENED
1 13.0000
2 12.0000
3 12.0000
« 12.0000
3 12.0000
TOTAL FRACTION Of
SOURCES OPERATED ON
0.7360
0.4080
0.4080
0.4080
0.4080
SUMMARY 01- TOTAL FRACTION OF SOURCES SCREENED ANli
QUART/MONTH UNITS
THC
TOTftL FRACTION OF
YEAR SOURCES SCREENED
1 6.1867
2 4.7107
3 4.7407
4 4.7407
5 4.7407
SERVICE
TOTAL FRACTION OF
SOURCES OPERATED OH
0.7263
0.3956
0.3936
0.3956
0.3956
SUMMARY OF TOTAL FRACTION OF SOURCES SCREEHKD AND
QUARTERLY UNITS
THC
TOTAL FRACTION Of
YEAR SOURCES SCREENED
1 9.0000
2 4.0000
3 4.0000
4 4.0000
5 4.0000
SERVICE
TOTAL FRACTION Of
SOURCES OPERATED ON
0.7243
0.3943
0.3943
0.3943
0.3943
TOTftL FRACTION OF
SOURCES SCREENED
13.0000
12.0000
12.0000
12.0000
12.0000
OfKRATED OH FOh PUHPS
TOTAL FRACTION OF
SOURCES OPERATED ON
0.7380
0.4080
0.4080
0.40SO
0.4080
BY YEAR
VOC SERVICE
TOTAL FRACTION 0*
SOURCES SCREENED
6.1867
4.7407
4.7407
4.7407
4.7407
OPERATED ON FOR PUMPS
TOTAL FRACTION OF
SOURCES OPERATED ON
0.7263
0.3956
0.3956
0.39'j6
0.3956
BY YEAR
VOC SfcKVICE
TOTAL FRACTION Of
SOURCES SCREENED
5.0000
4.0000
4.0000
4.0000
4.0000
TOTAL FRACTION OF
SOURCES OPERATED ON
0.7243
0.3943
0.3943
0.3943
0.3943
E-23
-------
Table E-9. FRACTION OF SOURCES SCREENED AND OPERATED ON BY MONTH (VALVES)
FRACTION Of TOTAL SOURCE! SCREENED M* OTfRATEO M FM VALVES it MMTH
MMTM.T Utlltl - TMC SERVICE
NONTM
INITIAL
10
11
12
RONTH
INITIAL
1
11
RONTH
INI IAL
10
11
12
FRACTION
SCREENED
1.0000
0.0020
0.0709
0.0740
0.0794
0.0740
0.0724
0.0712
0.04*0
0.0484
0.0470
0.0494
0.0442
1ST
FRACTION
SCREENED
1 .0000
0.0020
0.0740
0.0734
0.0740
0.0724
0.04*8
0.0470
0.0434
0.0442
FRACTION
OCREENED
1.00.0
0.1420
0.1904
0.0700
0.0324
0.0310
0.0710
0.0322
0.*44D
FRACTION
OPERATED
ON
0.1800
0.0348
0.0147
0.0149
8.0142 .
0.0141
0.0141
0.0141
0.0140
0.0140
0.0140
0.0140
0.0408
FRACTIS
TfAR
FRACTION
OPERATED
ON
0.1800
0.0148
0.0145
0.0142
0.0141
FRACTION
SCREENED
.0000
.0080
.0049
.*031
.*014
.0022
.0*08
.0001
.007*
.M4S
.0091
.0814
IN OF TOTAL
2*18
SCREENED
1.0000
FRACTION OF TOTAL
TEAR 2ND
FRACTION
OPERATED
ON
0.1000
0.0244
0.0091
0.0114
0.004*
0.0190
0.004*
0.04BB
FRACTION
SCREENED
0.0488
0.0470
0.0*87
0.0130
O.**01
0.0128
O.*0«0
FRACTION
OJTCRATCB
ON
0.0109
0.0191
0.0145
0.0144
0.0144
0.0144
0.0141
0.0141
8.0141
0.0141
0.0143
0.0304
OOURCI1 81
MNTNLT
TCAR
FRACTION
ON
0.0103
FRACTION
SCREENED
1.0000
0.0001
0.0*40
O.*054
0.0*3*
0.0025
O.M1I
O.ODV4
0.0882
0.0840
0.0834
0.0810
VNITO - VOC 01
WB
OI:REENED
1.0000
SOURCES SCREENED AND OPE
TEAR
FRACTION
ON
0.0104
0.0021
0.03*1
0.0030
0.034S
0.0050
0.0503
1RD
SCREENED
0.0501
0.04*5
0.0*01
0.0330
0.0370
O.*043
FRACTION
OPERATED
ON
0.0140
0.0147
0.014S
0.0144
0.0144
0.0144
0.0141
0.0141
0.0141
0.0141
0.0141
0.8101
MICE
TEAR
FRACTION
ON
0.0140
RATEII OR FOR
TEAR
FRACTION
ON
0.0074
0.0014
0.0143
0.0030
0.0030
0.0010
0.0500
FRACTION
SCREENED
1.0000
0.0081
0.0*40
0.0*54
O.**40
0.0023
O.**ll
0.08*4
0.*8S2
0.0048
0.«S34
0.081*
4TH
SCREENED
1.0000
FRACTION
OPERATED
ON
0.0140
0*0147
0.0143
0.0144
0.0144
0.0144
0.014
0.014
0.014
0.014
0.014
0.010
TEAR
FRACTION
ON
0.014*;
VALVES BT NONTH
4TH TEAR
SCREENED
0.0500
O.***l
0.0120
O.0330
0.0320
0.0323
FRACTION
ON
0.0073
0.0143
0.0050
0.0030
0.0030
0.0010
FRACTION
OCREENED
1.0000
o.ooo*
0.0040
O.*034
0.0040
0.0023
0.0011
0.08*4
0.0082
0 . 0040
0.0034
0.081*
5TN
SCREENED
1.0000
O.**03
0.0*40
.*040
0.003*
STN
SCREENED
0.0900
0.04*7
O.»**l
0.032D
0.0130
0.012B
0.0323
FRACTION
OPERATED
ON
.0140
.0147
.0143
.0144
.0144
.014
0.014
0.014
0.014
0.014
0.014
0.0301
TEAR
FRACTION
ON
0.0140
0.0147
0.0143
0.0143
0.0303
TEAR
FRACTION
ON
0.0075
0.0014
0.0343
0.0030
0.0050
0.0145
0.0050
0.0010
FRACTION OF TOTAL ImMCFO SCREENtO AND OFERATEO ON FOR VALUES OT AONTH
OUART/NONTH UNIT! - DOC SERVICE
1ST
FRACTION
MONTH SCREENED
INI
I
1
i:
IAL 1.0000
0.1420
0.0301
.0324
9.9710
0.0322
.0317
Q.fAAtt
YEAR 2ND
FRACTION
ON SCREENED
9.1IOO
0.0244
O.M4S
0.004V
0.035S
O.M4f
9,9919
0.0AM
.04H
.0323
.0330
.0323
.0323
.fS40
YCAR
TRACTION
3RD
OH SCREENED
0.0104
0.004
0.003
0.001
.034
0.001
0.050
0
0
0
0
0
.0503
.032S
.0330
. TfO*
.0323
.fD43
TfAR
FRACTION
ON
0.0074
.0030
.0030
0.0343
O.OSOO
4TH
SCREENED
0.0300
0.032R
0.0330
0.ftA3
VCAR
TRACT I UK
OH
0.0073
0.0020
0.0050.
O.OOSO
0.0500
STH
SCREENED
0.0300
0.0321
0.0330
0.032D
O.VS43
YEAR
FRACTION
ON
0.0075
0.0030
0.0010
0.0050
0.0010
0.0030
O.OSOO
FRACTION OF TOTAL SOURCES SCREENED AND OFCRATF.fl ON FOR VALUES ST MONTH
OUARTCMLV UNIT* - THC SERVICE
NO.
INI
a
i
i
FRACTION
TH SCREENED
IAL
i
t
.0000
F.OOOO
.0000
of 120
.000*
.0000
.f741
oOOOO
.0000
oTTIS
.0000
.0000
.f47*
FRACTION
QPF.RATED FRACTION
ON SCREENED
O.ltOO
0.0000
0.0000
.0917
oOOOO
0.0000
0.0437
O.OOOO
.0000
0.0411
0.0000
0.0000
«.07»
1.0000
>.oooo
.0000
.0000
,00«
.ffS]
.0000
.0000
,ffO»
.0000
.0000
.fS47
FRACTION
OPERATED
ON
0.0000
0.0000
0.0475
0.0000
0.0000
0.0431
0.0000
oOOOO
0.0424
0.0000
0.0000
0.03S9
FRACTION
SCRF.F.NFD
0.0000
0.0000
1.0009
0.0000
O.OOOO
o.ftsa
0.0000
0.0000
O.M12
0.0000
0.0000
0.9B70
FRACTION
OPERATED
ON
0.0000
0.0000
0.0430
.0000
0.0000
0.047H
0.0000
OoOOOO
0.0000
0.0000
0.0332
FRACTION
fCRFtMCP
0.0000
0.0000
1.0000
0.0000
0 . 0000
O.ffSS
0.0000
0.0000
0.0000
o.tooo
O.W70
FRACTION
OPERATED
ON
0.0000
0.0000
0.0430
0.0000
OoOOOO
0.042B
0.0000
0.0000
OoOOOO
0.0000
0.0352
FRACTION
SCREENED
0.0000
0.0000
1.0000
0.0000
0.0000
.f»35
0.0000
0.0000
O.OOOO
0.0000
0.fS7l
FRACTION
OPERATED
ON
0.0000
0.0000
0.0430
0 . 0000
0.0000
0.042S
0.0000
0.0000
0.0000
.0000
o 0532
FRACTION OF TOTAL SOURCES SCREENED AND OPERATED W FOR VALVES DT MWTN
iff TEA* MO
FRACTION
FRACTION OPERATED FRACTION
MNTH SCREENED ON SCREENED
INI
i
i
i:
IAL
:
,0*10
.MM
.MO*
.f020
.0000
.MM
.0000
.000
.f7H
.0000
.0000
.9474
t. 1IKIQ
.MO
.MOO
.05S7
.MO*
.400
.0000
.0000
.041.1
.000
.0000
.73S
,.0000
.0000
.0000
.MM
.MOO
.0000
.0000
off Of
.0000
.0000
.fS47
YCAN
FRACTION
OPERATED
ON
.OOOO
0.0000
0.047S
0.0000
0.0000
OoOOOO
0.0000
.0424
0.0000
.OOOO
.0333
3RD
FRACTION
SCREENED
0.0000
0.0000
1.0000
0.0000
0.0000
O.ffSS
0.0000
0.0000
O.ffl?
0.0000
0.0000
.tore
TEAR 4TH
TRACTION
OPERATED FRACTION
ON SCREENED
0.0000
0.0000
0.0430
0.0000
.OOOO
0.042S
0.0000
.OOOO
.0474
.OOOO
0.0000
0.0332
,.0000
.0000
.0000
.0000
.OOOO
.ffSS
.0000
.0000
.V*12
.0000
.0000
.9970
YEAR
FRACTION
Off RATED
ON
.MOO
.OOOO
0.0430
0.0000
.MOO
0.012*
0.0000
0.0000
0.0424
0.0000'
0.0000
0332'
STH TEAR
FRACTION
FRACTION OPERATED
SCREENED ON
.MOO
.OOOO
1.0000
0.0000
.OOOO
O.VV33
0.0000
.OOOO
O.f*12
O.OOOO
0.0000
0.9970
.0000
.0000
.0410
.0000
.0000
.042S
.0000
.0000
.0424
.0000
.0000
.0332
-------
Table E-10. FRACTION OF SOURCES SCREENED AND OPERATED ON BY MONTH (PUMPS)
I » I»l«l MIMCLI icitlno Ml ortMtct * rut rum »T
MI«.T (Mill - IK U'VICC
M*TN
Ml IAL
1
1
1
111 IAL
1
II
12
INI IAL
11
12
F
FRACTION 01
OCRCCNCB
.MO*
.999
.9000
.MM
.MO
.MM
.9009
.9999
.990
.MM
.MM
1»T TCM
F
OCRKINCB
.MOO
.9999
.9990
.9999
.MOO
.9009
.000
.000
.99
.9009
.9999
.90*4
IBT YfM
ACTION
ON
.1199
.9149
.9149
.914*
.9149
.9149
.9349
.9140
!oi40
FOACTION
ACTION
ON
.1100
.0140
.9149
.149
.9140
.146
.6146
.0140
.9149
.9349
.9149
.9149
FRACTION
1
FR AC 11 OH
BCRCCNCB ON
1 OM0 O.IOM
0 Jl** .112
1 O.*771
*771 O.M24
1 MM .*!*
6*25 0.9031
9*25 9.9011
1 9990 9.9*2*
BCMCNiB
I.MM
I.MOO
1.0000
I.M90
I.MO
I.MO
I.MO
1.999
1.9999
1.0000
OF TOTAL
MB
CRCCNCB
..
I.MO
I.MO
I.MO
1.000
I.MO
|.0«0
I.MO
1.9000
1.4000
I.MOO
OF TOTAL
MB
BCRCCNCB
0 O*3*
1 4000
9*3*
1 M99
9 6*2*
I 0000
FRACTION
ON
1«140
140
.140
.140
.14*
.149
I.M96
1.9999
1.9990
1.999
1.900
FRACTION
ON
.140
.140
0.*140
.0149
9.9149
149 1.990 140
!*i4o I!MM oloato
OUNCCf BCRCCNCB M» OttkftTCH ON F0«
ftONTNLT IMITB - VOC BCRW1CC
TCM lk» T»M
FRACTION
ON
«
0.0140
*.*140
.140
0.6346
.140
.140
.140
CM.CNCB
«
1.9990
1.9099
1.9009
I.M09
l.«999
1.9990
I.MOO
FRACTION
ON
.0149
149
9.9149
140
0.9340
0.0140
140
.0149
.0140 1.0009 ,0140
.0140 I.MOO .140
0.0140 t.M*0 0.0140
OURCCt BCNICRCB ANB OfCBATCB ON FO*
OUMt/MONfM VNlfV - INC BCRV1CC
TCM MB TLA*
FRACTION
ON
Mil
Mil
**24
0031
9 0*2*
CBCIHIB
O.O*2*
1.9900
,2*
1.9990
0.0*2*
0.0*2*
1.0000
f ACTION
ON
.Mil
.Mil
.*3*
O.M11
.0*2*
0.0011
0.0031
0.0*2*
FRACTION
BCRCLNC*
1.9009
1.9009
1,9000
1.M09
I.0000
I.MOO
1 .0009
1.0999
1.9999
1.9999
I.MM
POTT* OT Ml
4TN
CRCCNCB
1.4000
1.0900
1.0000
1.0000
1.0000
1.0900
I.MOO
1.0000
1.0000
1.0000
1.0000
PIMM BT MM
4TN
CRLtNCU
9.4*24
-*?*
I.M99
.9*3*
I.MOO
*24
I . 9990
0.9*24
1.0400
FRACTION
OPCRATCB
ON
.140
140
*.*140
.9140
4.4140
.14«
O.*140
.4140.
O.OJ49
0.0140
TH
TCM
FRACTION
ON
-140
9.0140
.0140
0.0140
.140
.140
0.0140
0.9140
0.0140
9.9140
0.0149
TN
TCM
FRACTION
OR
O.M11
.Mil
!*011
.*24
.0031
.**:.*
0.9031
9.9*24i
FRACTION
FRACTION OPCRATCB
Bty !«*»-_ ON
I.O**9
I.M99
I.MOO
I.MM
I.MM
I.999O
I.MOO
1.9009
1.9999
I.MM
I.MM
STM
BCNCKMB
1.9999
I.MM
I.MOO
I.MM
I.MOO
1.0000
1.0000
1.M69
1.9999
1.9900
I.MOO
I.MM
TN
CRCCNXB
0.0*2*
0.**2*
1.90*0
.0*3*
I.MOO
.0*24
.0*2*
1.0*00
9.9*2*
.9*2*
1.9900
.149
149
0.9140
.140
.149
.349
149
.140
.14*
140
.J4*
TIAR
FRACTION
ON
.140
*.*140
*.*14»
.0140
.9149
.140
.140
.140
.140
0.0140
.0140
.340
TCAR
Ft ACT ION
ON
.Mil
.011
4.4*2*
.Mil
0.0*3*
.9011
Oil
.9*2*
9.9911
.9011
0.0*3*
WH
INI
I
1
1
IBT
ITM BCftCCNCB
IAL
1
.9999
.J100
.1100
.M00
.0771
.MOO
.9*14
.9669
.099
TtAR 2MB
FRACTION
OH tCtCCHCD
9.11*9
9.0113
*.OM2
.9934
.*14
0.0033
0.0*29
.0*2*
.0*34
.0*24
.0*24
.000
.0*74
.0060
.9009
TtAK MB
FRACTION
OH BCRCCNCB
9.0031
.Mil
.Mil
.9*24
9.9911
9.9*24
.0*24
.9*24
.9*24
.4*34
.9*24
.000
.9*34
.0*34
.4000
.0*7*
.MOO
MA*
FRACTION
ON
.Mil
.031
.0011
.9911
0.0*34
0.9011
0.9031
9.6*2*
0.0031
9.0*2*
4TM
CfttlNl*
--
9.9*34
9.9*24
1.0000
.0*24
.0*7*
I. 0000
.0*2*
1.9900
TCM
FRALT10H
ON
..
;;»
9.9911
4.4*:*
.911
.0031
.9*2*
9.9031
.0*24
JTN
CRCCNiP
..
0.9*34
1.M99
9.9*24
.4*1*
1.9000
*2*
0.0*2*
1.0000
9.0*2*
9.9*24
1.9990
TFAR
FRACTION
ON
-
9.9031
9.0*24
.9911
9. Mil
9.0*24
9.9011
9.9031
9.9*24
0.0031
9.0011
9.9*2*
FRACT
IBT TCAR
FRACTION
FRACTION OPCRATCB
MN1M BCAUNCB ON
INITIAL I.MOO .!!
O.M90
.9990
.M99
.4900
.MOO
.M49
.M««
| .0000
I .9999
I .0040
UT TCAI
F
FRACTION 04
NOWTN CCRCCNCB
INI IAL 1 MM
M99
M99
1 OM9
M99
MM
I MM
MM
M99
1 MM
1 M90
I MOO
12 1 MM
.090
.9000
.**
.0009
.0*0*
.99
.***
.9000
.000
.**
ACTION
CRATCB
ON
.11*0
.MOO
.0900
.0*9*
.9009
.9000
.**
.MM
.094
.0*04
.MOO
.M94
**
2N»
FRACTION
CRCCNCB
00
.0000
1.0000
.0000
1.0060
0.0999
1.4000
9.9069
.9600
1.M99
2W
FRACTION
O.MM
.066
I.OOOO
9.9999
.9999
I.M69
.MM
.000*
I.MM
0,000*
.99
I.90M
OUARUKLT
TCM
FRACTION
ON
..
.099
0.6900
.**
9.9099
6.9*1*
4.4000
.V04
4.0OO0
0.0004
.**
UftRTCIlT
TCM
OfCRATCB
ON
O.MM
.006
**
4.00*0
0.4000
*.***
O.MM
O.MM
.«**
06
O.M0*
*.**
UNIT* - THC
FRACTION
CRCLNiB
..
*.MOO
.0000
.0066
.6000
.0000
.0000
.0000
.OOOO
.0606
.606
UNITt ' VOC
IRB
BCRCCNCB
.MO
.0660
.0*60
.0MO
.MOO
.0000
.0990
.0*04
.9999
.9999
.M66
.9909
BCRWICC
TFM
FRACTION
OfCRATCB
ON
..
O.MOO
.009
*.0»B4
.9009
*.***
.999
*.**«4
.999
4.4000
«*
BCRV11C
TI.AR
f CACTI OH
QfCfcAIC*
ON
O.OMO
9.M90
.**
9. MOO
O.M90
*.**
O.MM
.MOO
.**
.990
.999
*.9*0*
4TM
FRACTION
BCRCLNIft
..
9.9990
9. OOOO
1.0000
.OOOO
1,4000
9.M09
1.9099
9. MOO
4.0000
1.9990
4TH
FRACTION
CRCCNCB
9.9999
000
1.0000
9.9999
9.9999
1.9000
.00
.4000
I.MOO
.009
.0009
I.MOO
TCAR
FRACTION
OPCRA1CD
ON
._
.MO
. 4000
. 0*04
.9900
9.9***
*.MOO
*.***4
9.9090
0.9009
9.9*«*
TCAR '
FRACTION
OPCRATCV
N
9.M96
.OOOO
4.0V44
.090
.000
**
.000
«.M60
**
.060
60
»*
3TN
INACTION
CRCCHt
. 00*0
.066
1.0090
9.9906
1 . 9669
i*660
0.0000
I.M09
9.9009
.666
1.0000
5TN
FRACTION
tCRCINtO
.0400
9.0906
1 . 9966
9.6996
.MM
1 .MOO
9.9990
9.9906
1 . OOOO
.M
. 0000
I.MOO
TCM
FRACTION
OPCRATCD
ON
_
.9999
.00
.*94
.0090
**
000
9. MOO
*.*»*
000
>4000
.4
TtAR
FRACTION
OPCRATCB
ON
A AAAB
*AAOA
4.4*4*
9.M90
*. 0000
*.***
.MM
000
>**
. MOO
9.9966
9.9*0*
-------
Table E-ll. ESTIMATED EMISSION FACTORS AND MASS EMISSION REDUCTION
BY QUARTER (VALVES)
ESTIMATED EHIfllON FACTORS (KI/HIt) AND FRACTIONAL REDUCTION
IN MASS EMISSIONS FOR VAI.VEI IT CHARTER - MONTHLY UNITS
PERIOD
11 HONTHS)
1
2
I
4
1
t
1
1
»
to
11
12
11
14
13
It
17
11
IT
20
T*C SERVICE VOC SERVICE
MEAN ENISSION-KS/NR REDUCTION MEAN EM1SSION-KG/HR
0.0041
0.0018
0.0038
0.001*
0.001*
0.001*
0.0040
0.0040
0.0041
0.0041
0.0042
0.0042
0.0012
0.0011
0.0031
0.0032
0.0032
0.0033
0.0011
0.0014
.711
.SOS
.SO*
.007
.105
.803
.800
.7*8
.7*3
.7*3
.7*0
. 7BB
.841
.84*
.844
.842
.83*
.837
.834
.832
.001*
.0014
.0014
.0014
.0015
.0013
.0013
.0015
.0013
.0014
.001*
.001*
.0012
.0012
.0012
.0012
.0012
.0012
.0012
.0013
REDUCTION
0.783
0.808
0.80*
0.807
0.803
0.803
O.SOO
0.7*8
0.795
0.7*3
0.7*0
0,788
0.841
0.846
0.844
0.842
0.83*
0.837
0.814
0.832
ESTIMATED EMISSION FACTORS (KG/HR) AHI1 FRACTIONAL REDUCTION
IN MASS EMISSIONS FOR VALVES 8T OIlnRTFK - BUART/MONTH UNITS
PERIOD
(3 MONTHS)
1
2
3
4
3
t
7
8
»
10
11
12
13
14
13
1*
17
18
1*
20
THC SERVICE
MEAN ENISSION-KO/HR
0.004*
0.0030
0.0032
0.0023
0.0042
0.0044
0.0043
0.0046
0.0042
0.0044
0.0045
0.004*
0.0042
0.0044
0.004S
0.004*
0.0042
0.0044
0.0043
0.004*
REDUCTION
0.733
0.74*
0.742
0.733
0.786
0.782
0.775
0.7*8
0.78*
0.782
0.773
0.7*8
0.78*
0.782
0.773
0.7*8
0.78*
0.782
0.773
0.7*8
VOC SERVICE
MEAN EHISSION-KG/HR
0.001*
0.001*
0.001*
0.0020
0.001*
0.001*
0.0017
0.0017
0.001*
0.001*
0.0017
0.0017
0.001*
0.001*
0.0017
0.0017
0.001*
0.001*
0.0017
0.0017
0.753
0.71*
0.742
0.735
0.7BB
0,782
0.775
0.7*8
0.78*
0.782
0.773
0.7*U
0.78*
0.782
0.773
0.7*8
0.78*
0.782
0.775
0.7*8
ESTIMATED EMISSION FACTORS (KG/HR) AHIi FRACTIONAL REDUCTION
IN MASS EMISSIONS FOR VALVES 8V DUARTER - OUARTERLT UNITS
THC SERVICE
(1 MONTHS) MEAN EHISSION-K6/HR REDUCTION
1 .0053
2
3
4
3
*
7
8
»
10
11
12
13
14
13
1*
17
18
1*
20
.0032
.0033
,0054
.0045
.0045
.0047
.0048
.0044
.0045
.004*
.0048
.0044
.0043
.004*
.0048
.0044
.0045
.004*
.0048
.724
.73*
.735
.72*
.774
.774
.7*7
.7*0
.77*
.77!
.7*8
.7*1
.77*
.775
.7*8
.7*1
.77*
.773
.7*8
.7*1
VOC SERVICE
MEAN EMISSION-KO/HR
0.0021
0.0020
0.0020
0.0020
0.0017
0.0017
0.0017
0.0018
0.0017
0.0017
0.0017
0.0018
0.0017
0.0«17
0.0017
0.0018
0.0017
0.0017
0.0017
0.0018
REDUCTION
0.724
0.73*
0.733
0.72*
0.774
0.774
0.7*7
0.7*0
0.77*
0.775
0.7*8
0.7*1
0.77*
0.773
0.7*8
0.7*1
0.77*
0.775
0.7*8
0.7*1
E-26
-------
Table E-12. ESTIMATED EMISSION FACTORS AND MASS EMISSION REDUCTION
BY QUARTER (PUMPS)
CITIMTEI E«IIIION FACTORS C«O/M«> *NI> FRACTIONAL REDUCTION
m MII EHiiiiONt ro* ruitrt IT QUARTER - MWTHLT IWITI
(I MONTHS) KM 11
1
3
1
4
9
4
7
(
*
10
tl
12
11
14
IS
14
17
II
1*
20
TNC SERVICE
18810N-KI/HR II
.021*
.021?
.021*
.021* '
.021*
.021*
.021*
.021*
.021*
.021*
.021*
.021*
.021*
.021*
.021*
.0:1*
.021*
.021*
.021*
.021*
DUCTION MEAN Cl
.453
.193
.431
.451
.431
.433
.433
.4=3
.453
.453
,403
.411
.433
.413
.433
.413
.433
.453
.433
.453
VOC URVICE
IISS10N-KI/HR t
.0174
.0174
.0174
.0174
.0174
.0174
.0174
.0174
.0174
.0174
.0174
.0174
.0174
.0174
.0174
.0174
.0174
.0174
.0174
.0174
EDUCTION
.433
.433
.433
.453
.433
.433
.433
.453
.433
.433
.453
.433
.453
.453
.433
.423
.433
.453
.433
.433
ESTIMATED EMISSION FACTORS (KB/MR) AN1I FRACTIONAL Id DUCT ION |
IN MASS missions FOR ruHPS iv OUAKTER OUAKI/HUNIH unlit i
i
THC liRVICC VOC ICRVICt 1
II MONTHS) HEAN EMISSION-KB/HR REDUCTION MEAN EHISSIOH-KG/HR REDUCTION
1
2
3
4
3
4
7
1
»
10
11
12
11
14
15
14
17
11
1*
20
.0241
.023*
.0251
.0251
.0251
.0231
.0231
.0231
.0238
.0231
.0231
.0251
.0230
.0251
.0251
.0258
.025f
.0251
.0258
.0258
.407
.38*
.5*0
.3*0
.5*0
.5*0
.5*0
.5*0
.5*0
.5*0
.5*0
.5*0
.5*0
.5*0
.5*0
.5*0
.5*0
.5*0
.5*0
.5*0
.01*7
.0205
.0205
.0205
.0203
.0205
.0205
.0205
.0203
.0205
.0205
.0205
.0305
.0205
.0305
.0205
.0205
.0205
.0205
.0203
.407
.58*
.3*0
.5*0
.5*0
.3*0
.5*0
.5*0
.3*0
.5*0
.5*0
.5*0
.5*0
.5*0
.5*0
.5*0
.3*0
.5*0
.3*0
.3*0
EITIHATED ENIIIION FACTORS (KO/HRI AH1I FRACTIONAL KIDUCTION
I* HAVE EHISS10NS FUR PUHPS IT QUARTER - OUARTERLT UNITS
PER
(3 KOI
THC (ERVICE VOC SERVICE
ITHS) MEAN EN1S$10H-KO/HR REDUCTION HEAN CHISIION-KO/MR REDUCTION
1
2
10
It
12
11
14
15
14
17
11
1*
20
.0242
.0242
.0242
.0242
.0242
.0343
.0242
.0242
.0242
.0242
.0342
.0343
.0342
.0242
.0243
.0342
.0242
.0342
.0242
.0242
.314
.384
.384
.584
.384
.584
.384
.584
.384
.584
.584
.584
.384
.584
.384
.384
.584
.314
.584
.384
.0208
.0201
.0208
.0208
.0208
.0208
.0308
.0308
.0308
.0208
.0308
.0208
.0208
.0208
.0208
.0308
.0308 '
.0208 :
.0208 '
.0208
.584
.384
.384
.514
.584
.584
.584
.304
.58*
.38'!
.384
.384
.584
.384
.384
.314
.384
.384
.384
.514
E-27
-------
Table E-13. FRACTIONAL DISTRIBUTION OF SOURCES BY PERIOD (VALVES)
F«*CTIOM«L DISTRIBUTION Or SOURCES FOR VAI VES IT PERIOD
NOHTHir UNITS - THC ft.RVICE
FRACTION OF LF.AKERSt FRACTION OF FRACTION (IF SOURCES FRACTION OF SOURCES
DUE TO OCCURRENCE UNREPAIRED SOURCES EXPERIENCING EARI » FAILURE OPCKA1 INO PROPERLY
PERIOD IEOINNINO END IEOIHNINO END BEGINNING END BEGINNING END
(1 HONTNS) OF PERIOD OF PERIOD OF PERIOD OF PIRIOD OF PER I OH OF PERIOD OF PERIOD OF PERIOD
INITIAL
1
2
10
11
12
13
14
IS
1*
17
IB
1»
20
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.ISO
.012
.012
.012
.012
.012
.012
.012
.012
.012
.012
.012
.012
.013
.013
.013
.013
.013
.013
.013
.013
.01S
.021
.023
.021
.02*
.027
.02*
.030
.032
.033
.034
.03*
.000
.002
.003
.005
.006
.001
.00*
.011
.000
.019
.021
.023
.025
.021
.027
.02*
.030
.032
.033
.034
.03*
.000
.002
.003
.001
.004
.008
.00*
.011
.0227
.0044
.0021
.0018
.0018
.0018
.0018
.0018
.0018
.0018
.0018
.0018
.0070
.0023
.001*
.0018
.0018
.0018
.0018
.0018
.0000 ' 0.820
.0227 0.»S» 0.»47
.0044 «.*74 0.942
.0021 0.»7S 0.»*2
.0018 0.*74 0.941
.0018 0."72 O.»40
.0018 0.971 0.159
.0018 0.*** 0.957
.0018 0.»*8 0.»S4
.0010 0.»*7 0.954
.0018 0.»»5 0.953
. 001H 0.944 0.952
.0018 0.»42 O.»50
.0070 0.**3 0.980
.0025 0.994 0.983
.001* 0.995 0.982
.0018 0.**3 0.981
.0018 0.992 0.979
.0018 0.990 0.978
.0018 0.989 0.974
.0018 0.988 0.975
LEAKERS REFERS TO TNOSE SOURCES SCREENING GREATER THAN OK EQUAL TO 10 > 000 PPHV.
FRACTIONAL DISTRIIUTION OF SOURCES FOR VALVES IT PERIOD
NONTHLT UNITS - VOC SERVICE
FRACTION OF LEAKERSt FRACTION OF FRACTION OF SOURCES
DUE TO OCCURRENCE UNREPAIRED SOURCES EXPERIENCING EARI T FAILURE
PERIOD BEGINNING END BEGINNING END BEGINNING
(1 MONTHS) OF PERIOD OF PERIOD OF PERIOD OF PERIOD OF PERIOD
INITIAL
1
2
3
4
3
4
7
a
*
10
11
12
13
14
IS
14
17
18
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
1* 0.000
20 0.000
.110
.012 0.018
.012 0.021
.012
.012
.012
.012
.012
.012
.012
.012
.012
.012
.013
.013
.01]
.013
.013
.013
.013
.013
.023
.025
.024
.027
.02*
.030
.032
.033
.034
.034
.000
.002
.003
.005
.004
.008
.00*
.011
.000
.018 0.0227
.021 0.0044
.023
.025
.024
.027
.029
.030
.032
.033
.034
.034
.000
.002
.003
.005
.004
.008
.00*
.011
.0021
.0018
.0018
.0018
.0018
.0018
.0018
.0018
.0018
.0018
.0070
.0073
.001*
.0018
.0018
.0018
.0018
.0018
1 LEAKERS REFERS TO THOSE SOURCES SCREENING GREATER THAN OR EQUAL TO 10.000 PPHV.
END
Of PERIOD
0.0000
0.0727
0.0044
0.0021
0.0018
0.0018
0.0018
0.0018
0.0018
0.0018
0.0018
0.0018
0.0018
0.0070
0.0023
0.001*
0.0018
0.0018
0.0018
0.0018
0.0018
FRACTION
OPERATING
BEGINNING
OF PERIOD
0.959
».»74
0.»73
0.»74
0.9X2
0.971
0.94*
0.948
0.947
0.9*5
0.944
0.942
0.993
0.994
0.9*3
0.993
0.*»2
0.990
0.989
0.988
OF SOURCES
PROPERLY
END
OF PERIOD
0.120
0.947
0.942
0.942
0.941
0.940
0.959
0.957
0.954
0.954
0.953
0.932
0.930
0.980
0.983
0.982
0.981
0.97*
0.978
0.974
0.»7S
FRACTIONAL DISTRIBUTION OF SOURCES FOR VALVES BY PERIOD
OUART/MONTH UNITS - THC SERVICE
FRACTION OF LEAKERS* FRACTION OF FRACTION OF SOURCES FRACTION OF SOURCES
DUE TO OCCURRENCE UNREPAIRED SOURCES EXPERIENCING EARLY FAILURE OPERATING PROPERLY
PERIOD BEGINNING END BEGINNING END BEGINNING END BEGINNING END
(3 BONIHS) OF PERIOD OF PERIOD OF PERIOD OF PSRIOH OF PERIOD OF PERIOD OF PERIOD OF PERIOD
INITIAL
1
2
10
11
12
13
14
IS
14
17
18
1*
20
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.004
.000
.000
.000
.000
.000
.000
.000
.000
.180 - 0.000 0.0000 0.820
.033
.034
.034
.033
.034
.037
.034
.034
.034
.037
.03*
.03*
.034
.037
.034
.034
.034
.037
.034
.034
.018
.024
.028
.033
.000
.005
.00*
.013
.000
.005
.00*
.013
.000
.005
.00*
.013
.000
.005
.00*
.013
.021
.025
.02*
.033
.001
.005
.010
.014
.001
.005
.00*
.014
.001
.003
.00*
.014
.001
.005
.00*
.014
.0227 0.0004
.0042 0.0001
.0045 0.0001
.0045 0.0001
.00** 0.0003
.0049 0.0001
.0044 0.0001
.0044 0.0001
.0070 0.0002
.0044 0.0001
.0044 0.0001
.0044 0.0001
.0070 0.0002
.0044 0.0001
.0044 0.0001
.0044 0.0001
.0070 0.0002
.0044 0.0001
.0044 0.0001
.0044 0.0001
.*S» 0.*44
.971 0.939
.»4T 0.»33
.943 0.931
.*TO 0,943
.**! 0.958
.*84 0.954
.982 0.950
.993 0.943
.991 0.958
.987 0.954
.982 0.950
.993 0.943
.991 0.958
.987 0.954
.*82 O.*30
.993 0.943
.991 0.958
.987 0.934
.982 0.950
LEAKERS REFERS TO THOSE SOURCES SCREENING GREATER THAN OR EQUAL Til 10.000 PPNV.
E-28
-------
Table E-13. CONCLUDED
FRACTIONAL IIITRIIUTION OF tOUKCKI FOR VALVEI IT PERIOD
FRACTION OF LEAKERSt FRACTION OF FRACTION Of SOURCES FRACTION OF SOURCES
DUE TO OCCURRENCE UNREPAIRED SOURCE! EXPERItHC INK IARIV FAILURE OPCKATINi; PROPERLY
PERIOD IEOINNING END IEGIHNINO END tECIKHIHG FHD IEGINNIHG END
(3 HONTHS) OF PERIOD OF PERIOD OF PERIOD OF PFRIOD OF PFRIOD OF PERIOD OF PERIOD OF PERIOD
INITIAL
|
3
1
4
9
4
7
«
»
to
11
12
11
14
IS
1*
17
11
If
20
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.180
.03]
.03*
.034
.033
.034
.037
.034
.03*
.034
.037
.034
.034
.034
.037
.034
.034
.034
.037
.034
.034
.018
.024
.026
.033
.000
.005
.00?
.013
.000
.00:
.00*
.013
.000
.003
.OOf
.013
.000
.005
.009
.013
.000 - 0.0000
.021
.025
.02*
.033
.001
.005
.010
.014
.001
.005
.009
.014
.001
.005
,00V
.014
.001
.005
.OOf
.014
.0227 0.0004 O.fSf
.0042 0.0001 «.f71
.0045 0.0001 0.947
.0043 0.0001 4.943
.009* 0.0003 *.ffO
.0045 o.oooi e.ffi
.0044 0.0001 0.986
.0044 0.0001 0.fB2
.0070 0.0002 0.993
.0044 0.0001 O.ffl
.0044 0.0001 0.987
.0046 0.0001 0.982
.0070 0.0002 0.993
.0044 0.0001 O.ffl
.004« 0.0001 0.907
.0044 0.0001 O.f82
.0070 0.0002 0.993
.OO44 0.0001 0.991
.820
.f44
.f3f
.935
.931
.963
.958
.954
.fSO
.963
.958
.954
.fSO
.963
.950
.954
.950
.963
.958
.0044 0.0001 0.987 0.954
.0044 0.0001 0.982 0.750
> LEAKERS REFERS TO THOSE SOURCES SCREENING GREATER THAN OR EOUAL TO 10.000 PPHV.
FRACTIONAL DISTRIIUTION OF SOURCES FOR VALVES IT PERIOD
QUARTERLY UNITS - THC SERVICE
FRACTION OF LEAKERSI FRACTION OF FRACTION
DUE TO OCCURRENCE UNREPAIRED SOURCES EXPERIENCING
PERIOD
(3 HONTMS)
INITIAL
1
2
3
4
5
4
7
1
9
10
11
12
13
14
IS
16
17
19
If
20
t LEAKERS
IEGIHNINO END IEGINNING
OF PERIOD OF PERIOD OF PERIOD
o.ooo
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
o.ooo
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
.110
.034 0.018
.034 0.024
.034
.036
.037
.037
.037
,037
.037
.037
.037
.037
.037
.037
.037
.037
.037
.037
.037
.037
.028
.032
.000
.005
.OOf
.013
.000
.004
.009
.013
.000
.004
.009
.013
.000
.004
.OOf
.013
REFERS TO THOSE SOURCES SCREENING GREATER
END IEGINNING
OF PERIOD OF PFRIOD
0.000
0.018
0.024
0.028
0.032
0.000
0.005
O.OOf
0.013
0.000
0.004
0.009
0.013
0.000
0.004
0.009
0.013
0.000
0.004
O.OOf
0.013
.0227
.0074
.0055
.0053
.0103
.0040
.0054
.0053
.0078
.0057
.0054
.0053
.0077
.0057
.0054
.0033
.0077
.0057
.0054
.0053
THAN Ok EQUAL TO 10.000 PPHV
OF SOURCES
EARLY FAILURE
END
OF PERIOD
0.0000
0.0227
0.0074
0.0055
0.0053
0.0103
0.0040
0.0054
0.0053
0.0078
0.0057
0.0054
0,0053
0.0077
0.0057
0.0054
0.0033
0.0077
0.0057
0.0054
0.0053
.
FRACTION
OPERATING
IEGIHNIHG
OF PERIOD
O.fSf
0,949
0.966
0.942
0.990
0.989
0.986
0.981
0.992
0.990
0.98*
0.9B?
0.99?
0.990
0.984
0.982
0.992
O.*90
0.986
0.982
OF SOURCES
PROPERLY
END
OF PERIOD
.820
.f23
.932
.930
.926
0.953
0.952
0.949
0.945
0.955
0.953
0.949
0.945
0.955
0.953
0.949
0.943
0.955
0.953
0.949
0.945
FRACTIONAL DISTRIIUTION OF SOURCES FOR VALVES IT PERIOD
QUARTERLY UNITS - Vf>P StRVICE
FRACTION
DUE TO
PERIOD BEGINNING
(3 KONTHS) OF PERIOD
INITIAL
1
2
3
10
11
12
13
14
13
14
17
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
IS 0.000
19 0.000
20 0.000
< LEAKERS REFERS TO
OF LEAKERS* FRACTION OF FRACTION
OCCURRENCE UNREPAIRED SOURCES EXPERIENCING
END IEGINN1HO END lEBIHKING
OF PERIOD OF PERIOD OF PERIOD OF PERIOD
0.180
0.034 0.018
0.034 0.024
0.034
0.034
0.037
0.037
0.037
0.037
0.037
0.037
0.037
0.037
0.037
0.037
0.037
0.037
0.037
0.037
0.037
0.037
.028
.032
.000
.005
.009
.013
.000
.004
.009
.013
.000
.004
.009
.013
.000
.004
.009
.013
.000
.018 0.0227
.024 0.0074
.028 0.0035
.032
.000
.005
.009
.013
.000
.004
.009
.013
.000
.004
.OOf
.013
.000
.'004
.0053
.0101
.0060
.0054
.0053
.0078
.0057
.0054
.0033
.0077
.0057
.0034
.0053
.0077
.0057
.OOf 0.0054
.013 0.0053
OF SOURCES FRACTION
EARLY FAILURE OPERATING
END IEGINNINO
OF PERIOD OF PERIOD
0.0000
0.0227 0.939
0.0074 0.969
0.0053 0.966
0.0053 0.962
0.0103 O.ffO
0.0060
0.0054
0.0053
0.0078
0.0057
0.0054
0.0053
0.0077
0.0057
0.0054
0.0053
0.0077
0.0057
0.0054
0.0053
.989
.986
.981
.992
,990
.986
.982
.992
,990
.984
.982
.992
.990
.986
.982
OF SOURCES
PROPERLY
END
OF PERIOD
0.820
0.923
0.932
0.930
0.924
0.953
0.952
0.949
0.945
0.953
0.953
0.949
0.943
0.955
0.953
0.919
0.945
0.953
0.933
0.949
0.943
THOSE SOURCES SCREENING GREATER THAN OR EOUAL TO 10.000 PPNV.
E-29
-------
Table E-14. FRACTIONAL DISTRIBUTION OF SOURCES BY PERIOD (PUMPS)
FRACTIONAL tlSTRISUTlON 0» SOURCES FOX PUHPS IT PERIOD
HONTHLT UNITS - THC ItRVICE
FMCT10N OF LEAKEMt TRACTION Of FRACTION W SOURCES
tut TO OCCURRENCE UNREPAIRED louncti EIPERIEHIIHG IARLT FAILURE
FRACTION Of SOURCES
OPERATING PkOPCRLT
PERIOD
INITIAL
10
II
13
14
13
17
10
20
1 LEAKERS
BEGINNING
or PERIOD
000
.000
0.000
9.000
.000
0.000
A, 000
0.000
0.000
000
0.000
0.000
0.000
0.000
0.000
00
0.000
0.000
0.000
0.000
REFERS TO
END
F PERIOD
0.110
0.014
.014
0.014
014
0.014
0.014
0.014
0.014
0.014
0.014
0.014
0.014
0.014
0.014
.014
0.014
0.014
0.014
0.014
0.014
THOSE SOURCES
BEGINNING END
UF PERIIID OF PERIOD
.000
0.000
0.000
0.000
.000
.000
0.000
0.000
0.000
0.000
0.000
.000
0.000
0.000
0.000
0.000
o.ooo
.000
.000
0.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
SCREENING GREATER THAN Ok EQUAL
BEGINNING END
IIF PERIOD OF PERIOD
0.0000
0.0000
.0000
.0000
0.0000
0.0000
0.0000
0.0000
.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
,0000
.0000
.0000
.0000
.0000
.0000
,0000
.0000
.0000
.0000
.0000
.0000
TO 10.000 PPNV.
or PERIOD or PERIOD
1.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
.944
.944
.944
.944
if 44
.944
.944
.944
.944
.944
.944
.944
.944
.944
.944
.944
.944
.944
.944
r«*CT!ONAL DISTRIBUTION Or SOUKCES FOR PUMPS DV PERIOD
NON1HLT UNITS - VOC SLKV1CE
FRACTION or LEAKERSt FRACTION OF Fpr.CTION OF SOUkCES FRACTION OF SOUKCES
DUE TO OCCURRENCE UNREPAIRED SOURCES EXPERItHCIHG EAKLT FAILURE OPERATING PkOPERLT
PERIOD BEGINNING END BEGINNING END BEGINNING END DEGINNING END
(1 MONTHS! OF PERIOD OF PERIOD IIF PERIUD OF Pt.RIOD OF PEklUD IIF PERIOD OF PERIOD OF PERIOD
INITIAL
1
2
I
4
3
4
1
B
9
10
11
12
11
14
13
14
17
IB
19
20
...
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.110
.014
.014
.014
.014
.014
.014
.014
.014
.014
.014
.014
.014
.014
.014
.014
.014
.014
.014
.014
.014
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
000 0.0000 . . .470
.000 0.0000 0.0000 1.000
.000 0.0000 0.0000 1.000
.000 0.0000 0.0000 |. 000
.000 0.0000 0.0000 .000
.000 0.0000 0.0000 .000
.000 0.0000 0.0000 .000
000 0.0000 0.0000 .000
.000 0.0000 0.0000 .000
.000 0.0000 0.0000 .000
.000 0.0000 0.0000 .000
.000 0.0000 0.0000 .000
.000 0.0000 0.0000 .000
.000 0.0000 0.0000 .000
000 0.0000 0.0000 .000
.000 0.0000 0.0000 .000
.000 0.0000 0.0000 .000
.000 0.0000 0.0000 .000
000 0.0000 0.0000 .000
.000 0.0000 0.0000 .000
.000 0.0000 0.0000 .000
.944
.944
.944
.944
.944
.944
.944
.944
.944
.944
.944
.944
.944
.944
.944
.944
.944
.944
.944
.944
LEAKERS REFERS TO THOSE SOURCES SCREENING GREATER THAN OR EOUAL Til 10,000 PPNV.
FRACTIONAL DISTRIBUTION OF SOURCES FOk PUMPS Dr PERIOD
BUART/NONTH UNtTS - THC SINVICE
FRACTION OF LEAKERSt FRACTION OF FRACTION OF SOURCES FRACTION OF SOURCES
DUE TO OCCURRENCE UNREPAIRED SOURCES EXPERIENCING CARLT FAILURE OPERATING PROPERLY
PERIOD BEGINNING END BEGINNING END BEGINNING END OE01NHING END
(I MONTHS) OF
INITIAL
PERIOD OF PERIOD OF PERIOD OF PERIOD OF PEKIOO OF PERIOD Or PERIOD OP PERIOD
o'.no o.'ooo
1 0.000 0.077
2 1
1 <
4 1
1.000 0.094
>.000 0.091
1.000 0.093
3 0.000 0.093
4 1
7 <
>.000 0.091
1.000 0.091
t 0.000 0.093
t 1
10 <
11 «
12 <
II t
14 t
IS <
14 <
17 1
10 f
1.000 0.091
i.eoo 0.091
.000 0.091
1.000 0.091
.000 0.091
. *.0tl
.00 0.091
.MO 0.093
.000 0.093
.000 0.091
It 0.000 0.091
20 C
.000 «.091
.000 0.000 0.0000
.000 0.000 0.0000
.000 0.000 0.0000
.000 0.000 0.0000
.000 0.000 0.0000
.000 0.000 0.0000
.000 0.000 0.0000
.000 0.000 0.0000
.00 0.000 0.0000
.000 0.000 0.0000
.000 ».000 0.0000
.000 0.000 0.0000
0 o.ooo o.oooo
.000 0.000 0,0000
.000 0.000 0.0000
.000 0.000 0.0000
.000 0.000 0.0000
.000 0.000 0.0000
.000 0.000 0.0000
.000 0.000 0.0000
.0000 .470
.0000 t.OOO
.0000 1. 000
.0000 1.000
.0000 1.000
.0000 1.000
.0000 1.000
.0000 1.000
.0000 1.000
.0000 1.000
.0000 1.000
. 0000 1 . 000
.0000 1.000
0000 1.000
.0000 1.000
.0000 1.000
.0000 1.000
.0000 1.000
.0000 1.000
.0000 1.000
.0000 i.ooo
.923
.904
.907
.907
.907
.907
.907
.907
.907
.907
.907
.90V
.907
.907
.907
.907
.907
.907
.907
.9D7
B LEAKERS REFERS TO THOSE SOURCES SCREENING OkEATER THAN OR EIIUAL TU 10.000 PPHV.
E-30
-------
Table E-14. CONCLUDED
FRACTIONAL IISTRIDUTION Of SOURCE* re* PUWS »T PFR100
IUART/RONTN IWITI - VOC MRVICC
FRACTION
Ut TO OCCURRENCE
FRACTION 0*
REPAIRED SOUKClt
FRACTION 0* SOURCES
EXPERIENCING EARLT FAILURE
FRACTION a* SOURCES
OPERATING PHOPERLT
PERIOD KIINN1NI Cm IEIINNINI CM* IEOINN1NO CN» ICSIHNINO END
ii MMTHti or remap or rcmoi or PERIOD or PERIOD or PERIOD or PERIOD OFVPERIOP or PERIOD
INITIAL
10
II
12
11
14
13
14
17
10
It
20
.OM
.000
.000
.OOO
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.110
.07? 0.000
.Ot« 0.000
.0*1 0.000
.Ofl 0.000
.Ofl 0.000
.OT1 0.000
.Ofl 0.000
.Ofl O.OOO
.Ofl 0.000
.OtI 0.000
.Ofl 0.000
.Of] 0.000
.Ofl 0.000
.Ofl 0.000
.Ofl 0.000
.Ofl 0.000
.Ofl 0.000
.Ofl 0.000
.Of] 0.000
.Of] 0.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
,0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.170
.»J3
.t04
.to?
.t07
.t07
.fO?
.f07
.f07
.f07
.f07
.f07
.t07
.f07
.f07
.f07
.f07
.f07
.f07
.f07
,f07
LEAKERS Mri«f TO TMOtE (OUKCEt ICRICNUI MC*TC« TM*M M COIMU. TO 10.0*0 PPHV.
FRACTIONAL IISTRIIUTION 01 SOURCES fOR PIMPS IT PERIOD
IUARTERLT UNITS - TMC IfRVICE
r RUCTION or LEAKERS*
UC TO OCCURRENCE
PERIOD SEOINNINO END
11 HONTHS) Or PERIOD Of PERIOD
INITIAL
10
11
12
11
14
IS
It
17
10
If
20
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.130
.Off
.Off
.Oft
.Off
.Oft
.Off
.Off
.Oft
.Oft
.Oft
.Off
.Oft
.Oft
.Off
.Off
.Off
.Off
.Off
.Oft
.Oft
1 LEAKERS RErERi TO THOSE SOURCES
FRACTION Of
UNREPAIRED SOURCES
OEIINNim CNR
Or PERIOD OF PKRIOh
...
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
SCREENIN8 OREATER THAN Ok EQUAL
FRACTIONAL PISTR1RUTION Of SOURCES
FRACTION Or LEAKERS*
SUE TO OCCURRENCE
PERIOD PEOINNINO END
(I MONTHS) Or PERIOD Or PERIOD
INITIAL
1
»
1
4
9
t
7
*
t
10
11
12
11
14
13
1*
17
II
If
10
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.0*0
.0*0
.000
.000
.110
.Off
.Off
.Oft
.Off
.Off
.Oft
.Off
.Oft
.Off
.Off
.Oft
.Off
.Oft
.Oft
.Off
.Off
.0*f
.Off
.Off
.Oft
* LEAKERS REFERS TO THOSE SOURCES
IT
OUARTERLT UNITS - VIIC
FRACTION OP
UNREPAIRED SOURCES
DEOINNINO END
or PERIOD or PERIOD
...
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
SCREENING OREATER THAN (l« KOUAL
rRACTION Or IDURCES
EXPERIENCING EARLY FAILURE
PEOIHMINO END
or PERIOD or PFHIOD
... .0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
Tn toiooo PPHV.
FOR PUNPS IT PERIOD
SFRVICE
FRACTION OF SOURCES
EXPERIENCING EARLT FAILURE
DEOIMNIHG tHt
or ptRion or PERIOD
...
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
o.oooo
o.oooo
0.0000
0.0000
0.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
.0000
TO 10.000 PPNV.
FRACTION Of SOURCES
OPERATING PROPERLT
DCGINNING ENH
OF PERIOD OF PtRIOt
... .470
1.000
4.000
(.000
1. 000
1.000
l.ooo
1.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
l.ooo
1.000
1.000
1.000
1.000
1.000
.tot
.toi
.toi
.tot
.tot
.fOI
.toi
.tot
.toi
.toi
.tO!
.toi
.toi
.toi
.toi
.toi
.toi
.toi
.toi
.tot
PRACTION or SOURCES
OPERATING PROPERLT
DEGINNINB END
or PERIOD or PERIOD
.470
1.000
1.000
1.000
1.000
1.000
1.000
l.ooo
l.ooo
1.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
.toi
.toi
.toi
.tot
.toi
.toi
.toi
.toi
.toi
.toi
.toi
.tot
tot
.toi
»toi
.fOI
.tot
.toi
.toi
. mitt
1
1
E-31
-------
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.
E-32
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