o-EPA
United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Research Triangle Park NC 27711
EPA-450/3-81-015a
November 1982
Air
VOC Fugitive
Emissions in
Petroleum Refining
Industry —
Background Information
for Proposed Standards
Draft
EIS
-------
EPA-450/3-81-015a
VOC Fugitive Emissions in
Petroleum Refining Industry
Background Information
for Proposed Standards
Emission Standards and Engineering Division
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air, Noise, and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
November 1982
-------
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 National Technical Information Services, 5285 Port Royal
Road, Springfield, Virginia 22161.
n
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ENVIRONMENTAL PROTECT[ON AGENCY
Background Information
and Draft
Environmental Impact Statement
for VOC Fugitive Emissions in Petroleum Refining Industry
^2^
Don R. Goodwin" '"(Date)
Director, Emission Standards and Engineering Division
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
1. The proposed standards of performance would limit emissions of
volatile organic compounds from new, modified, and reconstructed
compressors and process units in the petroleum refining industry.
Section 111 of the Clean Air Act (42 U.S.C. 7411), as amended,
directs the Administrator to establish standards of performance
for any category of new stationary source of air pollution that
"...causes or contributes significantly to air pollution which
may reasonably be anticipated to endanger public health or welfare."
2. Copies of this document have been sent to the following: Federal
Departments of Labor, Health and Human Services, Defense, Transpor-
tation, Agriculture, Commerce, Interior, and Energy; the National
Science Foundation; and Council on Environmental Quality; members
of the State and Territorial Air Pollution Program Administraors;
the Association of Local Air Pollution Control Officials; EPA
Regional Administrators; and to other interested parties.
3. The comment period for review of this document is 75 days and is
expected to begin on or about January 3, 1983.
4. For additional information contact:
Ms. Susan R. Uyatt
Standards Development Branch (MD-13)
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
telephone: (919) 541-5477
4. Copies of this document may be obtained from:
U.S. EPA Library (MD-35)
Research Triangle Park, NC 27711
National T2chnical Information Service
5285 Port Royal Road
Springfield, VA 22161
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TABLE OF CONTENTS
Title Page
LIST OF TABLES vii
LIST OF FIGURES , . . xiii
METRIC CONVERSION TABLE xiv
1.0 SUMMARY 1-1
1.1 Regulatory Alternatives 1-1
1.2 Environmental Impact 1-2
1.3 Economic Impact 1-3
2.0 INTRODUCTION 2-1
2.1 Background and Authority for Standards 2-1
2.2 Selection of Categories of Stationary Sources. . . 2-4
2.3 Procedure for Development of Standards of
Performance 2-6
2.4 Consideration of Costs 2-8
2.5 Consideration of Environmental Impacts 2-9
2.6 Impact on Existing Sources 2-10
2.7 Review of Standards of Performance 2-11
3.0 DESCRIPTION OF PETROLEUM REFINERY FUGITIVE VOC
EMISSION SOURCES 3-1
3.1 Introduction and General Industry Information. . . 3-1
3.2 Fugitive Emission Definition and Potential
Source Description ..... 3-3
3.3 Baseline Control 3-14
3.4 References 3-17
4.0 EMISSION CONTROL TECHNIQUES 4-1
4.1 Introduction 4-1
4.2 Leak Detection and Repair Programs 4-1
4.3 Preventive Programs 4-12
4.4 References 4-27
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 Refinery
VOC Fugitive Emission Sources 5-3
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TABLE OF CONTENTS (concluded)
Title
5.3 References 5-5
6.0 MODEL UNITS AND REGULATORY ALTERNATIVES 6-1
6.1 Introduction 6-1
6.2 Model Units 6-1
6.3 Regulatory Alternatives 6-4
6.4 References 6-8
7.0 ENVIRONMENTAL IMPACTS 7-1
7.1 Introduction 7-1
7.2 VOC Emissions Impact 7-1
7.3 Water Quality Impact 7-9
7.4 Solid Waste Impact 7-9
7.5 Energy Impacts 7-10
7.6 Other Environmental Concerns 7-10
7.7 References 7-13
8.0 COST ANALYSIS 8-1
8.1 Cost Analysis of Regulatory Alternatives 8-1
8.2 Other Cost Considerations 8-27
8.3 References 8-39
9.0 ECONOMIC IMPACT 9-1
9.1 Industry Characterization 9-1
9.2 Economic Impact Analysis 9-25
9.3 Socioeconomic and Inflationary Impacts 9-40
9.4 References 9-47
APPENDIX A ..... A-l
APPENDIX B . . B-l
APPENDIX C . C-l
APPENDIX D D-l
APPENDIX E E-l
APPENDIX F F-l
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LIST OF TABLES
Table Page
1-1 Environmental and Economic Impacts of Regulatory
Alternatives 1-4
3-1 Uncontrolled Fugitive Emission Factors in the
Petroleum Refining Industry 3-15
3-2 Estimated Fugitive VOC Emissions from a Hypothetical
10-Unit Petroleum Refinery ... 3-16
4-1 Percentage of Sources Predicted to be Leaking in an
Individual Component Survey 4-3
4-2 Percent of Total Mass Emissions Affected at Various
Leak Definitions 4-8
4-3 Emission Correction Factors for Various Inspection
Intervals, Allowable Repair Times, and Leak
Definitions 4-13
6-1 Model Unit Component Counts 6-3
6-2 Fugitive VOC Regulatory Alternative Control
Specifications 6-5
7-1 Controlled VOC Emission Factors for Various
Inspection Intervals 7-3
7-2 VOC Emissions for Regulatory Alternatives 7-4
7-3 Annual Model Unit Emissions and Average Percent
Emission Reduction from Regulatory Alternative I .... 7-7
7_4 Projected VOC Fugitive Emissions from Affected
Model Units for Regulatory Alternatives for
1982-1986 7-8
7-5 Projected Energy Impacts for Regulatory
Alternatives for 1982-1986 7-10
8-1 Installed Capital Cost Data 8-2
8-2 Installed Capital Cost Estimates for New Model
Units 8-5
8-3 Monitoring and Maintenance Labor-Hour Requirements . . . 8-9
8-4 Leak Detection and Repair Costs 8-10
vn
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LIST OF TABLES (continued)
Table Paqe
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 , 8-14
8-8 Recovery Credits 8-16
8-9 Annualized Control Cost Estimates for New
Facilities for Model Unit A 8-17
8-10 Annualized Control Cost Estimates for New
Facilities for Model Unit B 8-18
8-11 Annualized Control Cost Estimates for New
Facilities for Model Unit C 8-19
8-12 Cost-Effectiveness for Model Units for New
Facilities 8-20
8-13 Installed Capital Cost Estimates for Modified/
Reconstructed Facilities 8-22
8-14 Annualized Control Cost Estimates for Modified/
Reconstructed Facilities for Model Unit A 8-23
8-15 Annualized Control Cost Estimates for Modified/
Reconstructed Facilities for Model Unit B 8-24
8-16 Annualized Control Cost Estimates for Modified/
Reconstructed Facilities for Model Unit C 8-25
8-17 Fifth-Year Nationwide Costs for the Petroleum
Refining Industry Above Regulatory Alternative I
Costs 8-26
8-18 Fifth-Year Nationwide Costs for the Petroleum
Refining Industry Above Baseline Costs 8-28
8-19 Statutes That May Be Applicable to the Petroleum
Refining Industry 8-29
8-20 Summary of Fifth-Year Annualized Costs by Standard . . 8-31
9-1 Total and Average Crude Distillation Capacity
by Year, United States Refineries, 1970-1980 9-2
vm
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LIST OF TABLES (continued)
Table Page
9-2 Percent Volume Yields of Petroleum Products by
Year, United States Refineries, 1971-1978 9-4
9-3 Production of Petroleum Products by Year, United
States Refineries, 1969-1978 9-5
9-4 Number and Capacity of Refineries Owned and
Operated by Major Companies, United States
Refineries, 1980 . . . 9-6
9-5 Employment in Petroleum and Natural Gas Extraction
and Petroleum Refining by Year, United States,
1969-1978 9-8
9-6 Average Hourly Earnings of Selected Industries
by Year, United States, 1969-1978 9-10
9-7 Estimated Gasoline Pool Composition by Refinery
Stream, United States Refineries, 1981 9-11
9-8 Refinery Capacity, Capacity Utilization, and
Refined Product Demand Projections Under Three
World Oil Price Scenarios, United States Refineries,
1978-1985-1990-1995 9-14
9-9 Price Elasticity Estimates for Major Refinery
Products by Demand Sector, United States, 1985 .... 9-16
9-10 Crude Oil Production and Consumption By Year,
United States, 1970-1979 9-18
9-11 Oil Exploration and Discoveries by Year, United
States, 1970-1979 9-19
9-12 Average Prices: Gasoline, Distillate Fuel Oil,
and Residual Fuel Oil by Year, United States,
1968-1979 9-20
9-13 Price Projections for Selected Petroleum Products
by Year, United States, 1978-1985-1990-1995 9-21
IX
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LIST OF TABLES (continued)
lable Page
9-14 Imports of Selected Petroleum Products by Year,
United States, 1969-1979 9-23
9-15 Exports of Selected Petroleum Products by Year,
United States, 1969-1978 9-24
9-16 Profit Margins for Major Corporations with
Petroleum Refinery Capacity, By Company Type
and Year, 1975-1976 9-26
9-17 Return on Investment for Major Corporations with
Petroleum Refining Capacity, By Company Type
and Year, 1975-1979 9-27
9-18 Petroleum Refining Income Data by Quarter, United
States Refineries, 1978-1980 9-28
9-19 Revenue Estimation - Model Unit A 9-30
9-20 Revenue Estimation - Model Unit B 9-31
9-21 Revenue Estimation - Model Unit C 9-32
9-22 Annual Revenue Summary by Model Unit 9-33
9-23 Percent Increases in Price Under Full Cost
Pricing by Model Unit 9-38
9-24 Profit Margins Under Full Cost Absorption by
Model Unit . 9-39
9-25 Summary of Fifth-Year Net Annual ized Cost 9-42
C-l Sampled Process Units from Nine Refineries C-3
C-2 Leak Frequencies and Emission Factors for Fugitive
Sources C-5
C-3 Summary of Components Tested and Percent Leaking in
Six Refineries C-6
C-4 Summary of Maintenance Study Results from the Union
Oil Company Refinery in Rodeo, California C-10
C-5 Summary of Maintenance Study Results from the Shell
Oil Company Refinery in Martinez, California .... C-12
C-6 Summary of EPA Refinery Maintenance Study Results . . C-13
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LIST OF TABLES (continued)
Table Page
C-7 Maintenance Effectiveness Ethylene Unit Block
Valves C-14
C-8 Occurrence Rate Estimates for Valves and Pumps by
Process in EPA-ORD Study C-16
C-9 Valve Leak Recurrence Rate Estimates C-17
C-10 Summary of Valve Maintenance Test Results C-18
E-l Crude Distillation Capacity by Refinery by State, United
States and United States Territories,
January 1, 1980 E-2
E-2 Refinery Process Unit Growth Projections (1981-86) . . E-9
F-l Statistical Analysis System (SAS) Program to
Evaluate the Impact of a Maintenance Program
on Fugitive Emissions F-5
F-2 Impact Data for Evaluating the Reduction in Average
Leak Rate Due to a Valve Maintenance Program F-16
F-3 Valve Emission Factors and Mass Emission Reductions. . F-17
F-4" Fraction of Valves Screened and Operated On F-18
F-5 Emission Factors and Mass Emission Reduction for
Valves by Inspection Period F-19
F-6 Fraction of Sources Screened and Operated on for
Valves by Month F-20
F-7 Fractional Distribution of Sources for Valves by
Inspection Period F-24
F-8 Input Data for Examining the Reduction in Average
Leak Rate Due to a Pump Maintenance Program F-28
F-9 Pump Emission Factors and Mass Emission Reduction. . . F-29
F-10 Fraction of Pumps Screened and Operated on F-30
F-ll Emission Factors and Mass Emission Reduction for
Pumps by Inspection Period F-31
F-12 Fraction of Sources Screened and Operated on for Pumps
by Month F-32
XI
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LIST OF TABLES (continued)
Table Page
F-13 Fractional Distribution of Sources for Pumps by
Inspection Period F-34
F-14 Controlled VOC Emission Factors for Various Inspection
Intervals Using the LDAR Model F-37
F-15 VOC Emissions for Regulatory Alternatives Based on LDAR
Model F-38
F-16 Annual Model Unit Emissions and Average Percent Emission
Reduction From Regulatory Alternative I Based on LDAR
Model Results F-41
F-17 Project VOC Fugitive Emissions from Affected Model Units
for Regulatory Alternatives for 1982-1986 Based on LDAR
Model Results F-42
F-18 Projected Energy Impacts of Regulatory Alternatives for
1982-1986 Based on LDAR Model Results F-43
F-19 Monitoring and Maintenance Labor-Hour Requirements Based
on LDAR Model Results F-44
F-20 Leak Detection and Repair Costs Based on LDAR Model
Results F-45
F-21 Recovery Credits F-46
F-22 Annualized Control Cost Estimates for New Facilities for
Model Unit A Based on the LDAR Model F-47
F-23 Annualized Control Cost Estimates for New Facilities
for Model Unit B Based on the LDAR Model F-48
F-24 Annualized Control Cost Estimates for New Facilities
for Model Unit C Based on the LDAR Model F-49
F-25 Cost Effectiveness for Model Units for New Facilities
Based on the LDAR Model F-50
F-26 Annualized Control Cost Estimates for Modified/
Reconstructed Facilities for Model Unit A Based on the
LDAR Model F-51
F-27 Annualized Control Cost Estimates for Modified/
Reconstructed Facilities for Model Unit B Based
on the LDAR Model F-52
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LIST OF TABLES (concluded)
Table Page
F-28 Annual izeti Control Cost Estimates for Modified/
Reconstructed Facilities for Model Unit C Based on
the LDAR Model F-53
F-29 Fifth-Year Nationwide Costs of the Regulatory
Alternatives Above Regulatory Alternative I Costs Based
on the LDAR Model F-54
F-30 Fifth-Year Nationwide Costs for the Petroleum Industry
Above Baseline Costs Based on the LDAR Model F-55
F-31 Percent Increases in Price Under Full Cost Pricing by
Model Unit Based on LDAR Model Results F-56
F-32 Profit Margins Under Full Cost Absorption by Model Unit
Based on LDAR Model Results F-57
F-33 Summary of Fifth Year Net Annualized Costs Based on
LDAR Model Results F-57
F-34 Comparison of Results from the LDAR Model with the
ABCD Model Analysis F-58
F-35 Comparison of Overall Emission and Cost Impacts
Using LDAR Model Program Values with ABCD Model Analysis
Impacts F-59
xm
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-LIST OF FIGURES
Figure Page
3-1 Simplified Flow Chart for a Typical Gasoline
Producing Refinery 3-2
3-2 Diagram of a Simple Packed Seal „ . 3-5
3-3 Diagram of a Basic Single Mechanical Seal 3-5
3-4 Diagram of a Dual Mechanical Seal
(back-to-back arrangement) 3-7
3-5 Diagram of a Dual Mechanical Seal
(tandem arrangement) 3-7
3-6 Chempump Canned-motor Pump 3-8
3-7 Shriver Mechanically Actuated Diaphragm Pump 3-8
3-8 Liquid-film Compressor Shaft Seal 3-10
3-9 Globe Valve with Packed Seal 3-10
3-10 Diagram of a Spring-loaded Relief Valve 3-12
3-11 Cooling Tower (cross-flow) 3-12
4-1 Seal-less Canned Motor Pump 4-15
4-2 Sealed Bellows Valve 4-18
4-3 Rupture Disk Installation Upstream of a
Relief Valve 4-20
4-4 Simplified Closed-Vent System with Dual Flares .... 4-22
4-5 Diagram of Two Closed-Loop Sampling Systems. ..... 4-24
F-l Schematic Diagram of the LDAR Model F-3
F-2 Effect of Leak Repair Cycles on Field Emission Test
Results and Leak Detection and Repair Program (LDRP)
Effectiveness F-14
xiv
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METRIC CONVERSION TABLE
EPA policy is to express all measurements in Agency documents in
metric units. Listed below are metric units used in this report with
conversion factors to obtain equivalent English units. A list of
prefixes to metric units is also presented.
To Convert
Metric Unit
centimeter (cm)
meter (m)
liter (1)
3
cubic meter (m )
2
cubic meter (m )
cubic meter (m )
kilogram (kg)
megagram (Mg)
gigagram (Gg)
gigagram (Gg)
joule (J)
Multiply By
Conversion Factor
0.39
3.28
0.26
264.2
6.29
35
2.2
1.1
2.2
1102
9.48 x 10
-4
To Obtain
English Unit
inch (in.)
feet (ft.)
U.S. gallon (gal)
U.S. gallon (gal)
barrel (oil) (bbl)
cubic feet (ft3)
pound (Ib)
ton
million pounds (10 Ibs)
ton
British thermal unit (Btu)
PREFIXES
Prefix
tera
mega
kilo
centi
milli
micro
Symbol
T
G
M
k
c
m
Multiplication
Factor
10
10-
10
10
10
10
12
9
6
3
-2
-3
-6
xv
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1.0 SUMMARY
1.1 REGULATORY ALTERNATIVES
Standards of performance for stationary sources of volatile
organic compounds (VOC) from fugitive emission sources in the petroleum
refining industry are being developed under the authority of Section 111
of the Clean Air Act. These standards would affect new and modified/
reconstructed existing stationary sources of VOC in the petroleum
refining industry.
Six regulatory alternatives were considered. Regulatory Alternative I
represents the level of control within industry in the absence of new
regulations. It provides the basis for comparison of the impacts of
the other regulatory alternatives. The requirements for Regulatory
Alternative II are based upon the recommendations of the refinery VOC
control techniques guideline (CTG) document (EPA-450/2-78-036). The
requirements are as follows:
• Quarterly monitoring for leaks from valves in gas service,
pressure/relief devices in gas service, and compressor seals
(also monitoring relief valves after overpressure relief to
detect improper reseating);
• Annual monitoring for leaks from pump seals and valves in
light liquid service;
• Weekly visual inspections of pump seals and immediate instrument
monitoring of visually leaking pumps; and
• Installation of caps, blind flanges, plugs, or other valves
to seal all open-ended lines.
1-1
-------
Regulatory Alternative III provides more effective control than
Regulatory Alternative II by increasing the frequency of equipment
inspections and by specifying additional equipment requirements:
• Quarterly monitoring for leaks from valves in gas and light
liquid service;
• Monthly monitoring for leaks from pump seals in light liquid
service; and
• Installation of rupture disks on safety/relief valves,
mechanical seals with controlled degassing reservoirs on
compressors, and closed purge sampling systems.
Regulatory Alternative IV reduces emissions further by specifying
equipment for pumps rather than monthly monitoring. Dual mechanical
seals with a barrier fluid and degassing reservoir vents would be
required on pumps in light liquid service. Other controls would be
required as specified for Regulatory Alternative III.
Regulatory Alternative V increases emission control by requiring
more frequent inspections on valves in gas and light liquid service.
Valves would be monitored monthly. The control requirements for other
sources are identical to those required in Regulatory Alternative IV.
Regulatory Alternative VI provides the greatest level of emission
reduction by controlling fugitive VOC emissions through additional
equipment specifications. In addition to the equipment specifications
as required under Regulatory Alternative V, Regulatory Alternative VI
requires the installation of sealed bellows valves in gas and light
liquid service.
1.2 ENVIRONMENTAL IMPACT
1.2.1 Air Emissions Impact
Total fugitive emissions of VOC from new units in the petroleum
refining industry in 1986 are 19.8 gigagrams under Regulatory
Alternative I, compared to 6.2, 4.5, 4.1, 3.6 and 1.4 gigagrams under
Regulatory Alternatives II through VI. The average percent emissions
reductions from the Regulatory Alternative I level effected by Regulatory
Alternatives II through VI are 69, 77, 79, 82 and 93 percent, respectively.
1-2
-------
For the maximum number of modified and reconstructed units, total
VOC fugitive emissions in 1986 are expected to be 43.5 gigagram? under
Regulatory Alternative I, compared to 13.6, 9.9, 9.0, 8.0, and
3.1 gigagrams under Regulatory Alternatives II through VI.
1.2.2 Hater and Sol id Waste Impacts
In addition to reducing emissions to atmosphere, implementation
of Regulatory Alternatives II through VI would reduce the waste load
on wastewater treatment systems by preventing leakage from process
equipment from entering the wastewater system. The impact of solid
wastes generated by replacing mechanical seals, rupture disks, plugs,
and other metal parts would be insignificant, since these wastes could
be recycled.
1.2.3 Energy Impacts
Energy savings would result under Regulatory Alternatives II
through VI. Only a minimal increase in energy consumption would
result from operation of combustion devices and installation of dual
mechanical seals. Assuming recovery of all emission reduction achieved
by the regulatory alternatives, the energy savings over a 5-year
period from new units would have an energy content ranging from 1,090
terajoules (Regulatory Alternative II) to 1,770 terajoules (Regulatory
Alternative VI.) An additional 2,450 to 3,970 terajoules could be
recovered from modified and reconstructed units for the same period.
A more detailed analysis of environmental and energy impacts is
presented in Chapter 7. A summary of the environmental impacts
associated with the six regulatory alternatives is shown in Table 1-1.
1.3 ECONOMIC IMPACT
Cumulative capital and annualized costs, including recovery
credits, for the entire petroleum refining industry were estimated for
the first five years of implementing each of the regulatory alternatives
(1982 - 1986). The estimates for new and modified/reconstructed units
are based on May 1980 dollars. Table 1-1 summarizes the economic
impacts that result from these costs for each of the regulatory alternatives,
1-3
-------
TABLE 1-1. ENVIRONMENTAL AND ECONOMIC IMPACTS OF REGULATORY ALTERNATIVES
Regulatory
Alternative
I (no action)
II
III
IV
V
VI
Air
Impact
_4**
+2**
+3**
+3**
+3**
+4**
Water
Impact
-1*
+1*
+1*
•n*
+1*
-i-l*
Sol id Haste
Impact
0
0
0
0
0
0
Energy
Impact
0
-hi*
+1*
-n*
+1*
-H*
.. ._ — . _ .
Noise
Impact
0
0
0
0
0
0
Economic
Impact
_}**
+1*
0
-1*
-1*
-3**
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
-------
During the first five years of implementation of Regulatory
Alternative II, the cumulative capital costs for the petroleum refining
industry would be $1.8 million for new units and an additional $3.7 million
for modified/reconstructed units. In the fifth year, the industry
would incur net annualized credits of $1.3 million and $3.3 million
for new and modified/reconstructed units, respectively, due to the
value of the recovered product.
Under Regulatory Alternative III, cumulative capital costs would
be $8.2 million for new units and $19.0 million for modified/reconstructed
units. Net annualized costs of $31 thousand for new units and $900 thousand
for modified/reconstructed units would be incurred by the industry in
1986.
Under Regulatory Alternative IV, cumulative capital costs for the
period from 1981 to 1986 would be $20.0 million and $47.0 million for
new units and modified/reconstructed units, respectively. The net
annualized costs in the fifth year would be $3.2 million for new units
and $7.7 million for modified/reconstructed units.
The 5-year cumulative capital costs as a result of implementing
Regulatory Alternative V would be $20.0 million for new units and
$47.0 million for modified/reconstructed units. The net annualized
costs in the fifth year would be $3.6 million and $9.2 million for new
and modified/reconstructed units, respectively.
Regulatory Alternative VI incurs the greatest capital cost and
net annualized cost of all the regulatory alternatives. Cumulative
capital costs for the industry would be $274.0 million for new units
and $610.0 million for modified/reconstructed units. The net annualized
costs in 1986 would be $64.1 million for new units and $146.3 million
for modified/reconstructed units. A more detailed analysis of costs
is included in Chapter 8.
Industry-wide price increases are not expected to result from
implementation of any of these regulatory alternatives because the net
annualized costs to the industry are an insignificant fraction of the
net annual revenues. A more detailed economic analysis is presented
in Chapter 9.
1-5
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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 able to see 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.
2-1
-------
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 perform-
ance. 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
performance revised.
2. EPA is required to review the standards of performance every
four years and, if appropriate, revise them.
3. EPA is authorized to promulgate a standard based on design,
equipment, work practice, or operational procedures when a standard based
on emission levels is not feasible.
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 six months.
Standards of performance, by themselves, do not guarantee protection
of health or welfare because they are not designed to achieve any specific
air quality levels. Rather, they are designed to reflect the degree of
emission limitation achievable through application of the best adequately
demonstrated technological system of continuous emission reduction, taking
into consideration the cost of achieving such emission reduction, any
nonair quality health and environmental impacts, and energy requirements.
Congress had several reasons for including these requirements. First,
standards with a degree of uniformity are needed to avoid situations where
some States may attract industries by relaxing standards relative to other
States. Second, stringent standards enhance the potential for long-term
growth. Third, stringent standards may help achieve long-term cost savings
2-2
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by avoiding the need for more 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
incentives 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 signif-
icant 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, environmental, and economic impacts and
other costs, determines is achievable for such facility through
application of production 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 technol-
ogy" 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 stand-
ard 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 Administra-
tor must find: (1) a substantial likelihood that the technology will
produce greater emission reductions than the standards require or an equiva-
lent 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 three years to meet the standards with a mandatory
progress schedule.
2.2 SELECTION OF CATEGORIES OF STATIONARY SOURCES
Section 111 of the Act directs the Adminstrator to list categories
of stationary sources. The Administrator "... shall include a category
of sources in such list if in his judgment it causes, or contributes
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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 Act 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) estimated levels of control that might be required from standards of
performance for the source category, (3) projections of growth and
replacement of existing facilities for the source category, and (4) the
estimated incremental amount of air pollution that could be prevented in
a preselected future year by standards of performance for the source
category. Sources for which new source performance standards were
promulgated or under development during 1977, or earlier, were selected
on these criteria.
The Act amendments of August 1977 establish specific criteria to be
used in determining priorities for all major source categories not yet
listed by EPA. These are: (1) the quantity of air pollutant emissions
that each such category will emit, or will be designed to emit; (2) the
extent to which each such pollutant may reasonably be anticipated to
endanger public health or welfare; and (3) the mobility and competitive
nature of each such category of sources and the consequent need for
nationally applicable new source standards of performance.
The Administrator is to promulgate standards for these categories
according to the schedule referred to earlier.
In some cases it may not be feasible immediately to develop a standard
for a source category with a high priority. This might happen when a
program of research is needed to develop control techniques or because
techniques for sampling and measuring emissions may require refinement. In
the developing of standards, differences in the time required to complete
the necessary investigation for different source categories must also be
considered. For example, substantially more time may be necessary if
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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, inability 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
pollution, and emissions from some of these facilities may vary from
insignificant to very expensive to control. Economic studies of the source
category and of applicable control technology may show that air pollution
control is better served by applying standards to the more severe pollution
sources. For this reason, and because there is no adequately demonstrated
system for controlling emissions from certain facilities, standards often
do not apply to all facilities at a source. For the same reasons, the stan-
dards may not apply to all air pollutants emitted. Thus, although a source
category may be selected to be covered by a standard of performance, not
all pollutants or facilities within that source category may be covered
by the standards.
2.3 PROCEDURE FOR DEVELOPMENT OF STANDARDS OF PERFORMANCE
Standards of performance must (1) realistically reflect best
demonstrated control practice; (2) adequately consider the cost, the 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
representatives. Information is also gathered from many other sources,
and a literature search is conducted. From the knowledge acquired about
the industry, EPA selects certain plants at which emission tests are con-
ducted 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
alternatives are essentially different levels of emission control.
EPA conducts studies to determine the impact of each regulatory
alternative on the economics of the industry and on the national economy,
on the environment, and on energy consumption. From several possibly
applicable alternatives, EPA selects the single most plausible regulatory
alternative as the basis for a standard of performance for the source
category under study.
In the third phase of a project, the selected regulatory alternative
is translated into a standard of performance, which, in turn, is written in
the form of a Federal regulation. The Federal regulation, when applied to
newly constructed plants, will limit emissions to the levels indicated in
the selected regulatory alternative.
As early as is practical in each standard-setting project, EPA
representatives discuss the possibilities of a standard and the form it
might take with members of the National Air Pollution Control Techniques
Advisory Committee. Industry representatives and other interested parties
also participate in these meetings.
The information acquired in the project is summarized in the Background
Information Document (BID). The BID, the standard, and a preamble explain-
ing 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
2-7
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expert reviewers are taken into consideration as changes are made to the
documentation.
A "proposal package" is assembled and sent through the offices of EPA
Assistant Administrators for concurrence before the proposed standard is
officially endorsed by the EPA Administrator. After being approved by the
EPA Administrator, the preamble and the proposed regulation are published
in the Federal Register.
As a part of the Federal Register announcement of the proposed
regulation, the public is invited to participate in the standard-setting
process. EPA invites written comments on the proposal and also holds a
public hearing to discuss the proposed standard with interested 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.
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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 captured
potential air pollutants may pose a solid waste disposal problem. The
total environmental impact of an emission source must, therefore, be analyzed
and the costs determined whenever possible.
A thorough study of the profitability and price-setting mechanisms of
the industry is essential to the analysis so that an accurate estimate of
potential adverse economic impacts can be made for proposed standards. It
is also essential to know the capital requirements for pollution control
systems already placed on plants so that the additional capital requirements
necessitated by these Federal standards can be placed in proper perspective.
Finally, it is necessary to assess the availability of capital to provide
the additional control equipment needed to meet the standards of performance.
2.5 CONSIDERATION OF ENVIRONMENTAL IMPACTS
Section 102(2)(C) of the National Environmental Policy Act (NEPA) of
1969 requires Federal agencies to prepare detailed environmental impact
statements on proposals for legislation and other major Federal actions
significantly affecting the quality of the human environment. The objective
of NEPA is to build into the decisionmaking process of Federal agencies a
careful consideration of all environmental aspects of proposed actions.
In a number of legal challenges to standards of performance for
various industries, the United States Court of Appeals for the District
of Columbia Circuit has held that environmental impact statements need
not be prepared by the Agency for proposed actions under Section 111 of
the Clean Air Act. Essentially, the Court of Appeals has determined that
the best system of emission reduction requires the Administrator to take
2-9
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into account counter-productive environmental effects of a proposed
standard, as well as economic costs to the industry. On this basis,
therefore, the Court established a narrow exemption from NEPA for EPA
determination under Section 111.
In addition to these judicial determinations, the Energy Supply and
Environmental Coordination Act (ESECA) of 1974 (PL-93-319) specifically
exempted proposed actions under the Clean Air Act from NEPA requirements.
According to Section 7(c)(l), "No action taken under the Clean Air Act
shall be deemed a major Federal action significantly affecting the quality
of the human environment within the meaning of the National Environmental
Policy Act of 1969." (15 U.S.C. 793(c)(l))
Nevertheless, the Agency has concluded that the preparation of
environmental impact statements could have beneficial effects on certain
regulatory actions. Consequently, although not legally required to do so
by Section 102(2)(C) of NEPA, EPA has adopted a policy requiring that
environmental impact statements be prepared for various regulatory actions,
including standards of performance developed under Section 111 of the Act.
This voluntary preparation of environmental impact statements, however,
in no way legally subjects the Agency to NEPA requirements.
To implement this policy, a separate section in this document is
devoted solely to an analysis of the potential environmental impacts associ-
ated 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 lll(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.
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3.0 DESCRIPTION OF PETROLEUM REFINERY FUGITIVE VOC EMISSION SOURCES
3.1 INTRODUCTION AND GENERAL INDUSTRY INFORMATION
3.1.1 Introduction
The intent of this chapter is to define the petroleum refining
industry and describe the potential fugitive VOC emission sources that
are typically found in the petroleum refining industry. The leak
rates of uncontrolled emissions from the various fugitive VOC emission
sources are quantified where possible.
3.1.2 General Information
A petroleum refinery is defined as any facility that is engaged
in the production of gasoline, aromatics, kerosene, distillate fuel
oils, residual fuel oils, or other products through the distillation
of petroleum, or through the redistillation, cracking, rearrangement,
or reforming of unfinished petroleum derivatives. The type and
complexity of the processes in operation at an individual refinery
vary depending on the crude oil composition (e.g., paraffinic,
napthenic, and aromatic hydrocarbon content; sulfur content; and
metals content) and on the types of finished products desired.
Figure 3-1 presents a generalized flow diagram for a refinery
maximizing gasoline production. Each process unit is comprised of a
set of components or equipment pieces such as valves, pumps, flanges,
etc., that are used to move and control the flow of organic compounds
to and from various process vessels. Equipment pieces represent
potential fugitive VOC emission sources whenever they handle a process
stream containing organic compounds. For example, some sources
develop leaks after some period of operation due to the failure of
sealing mechanisms. These could include pumps, compressors, valves,
flanges, and safety/relief valves. Other types of equipment emit VOC
3-1
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CO
ro
Crude
Oil
Gas
Gas Concentration
Atmospheric
DistlHatior
Straight Run Gasoline
Naptha
Vacuum
Distillation
TEaT
Catalytic
Reforming
Light
Distillate
Light
Distillate
Residium
Gas
Catalytic
Cracking
Coker
Refinery
Fuel Gas
LPG
Reformate
Alkylate^
Gas
Hydrotreatlng
Motor
Gasoline
Blending
Light
Fuel 011
Blending
Figure 3-1. Simplified Flow Chart for a Typical Gasoline Producing Refinery
-------
intermittently, and only under certain scheduled operating circumstances,
such as sampling connections during sampling or open-ended lines
during venting. Other unscheduled intermittent VOC sources would
include emissions from safety/relief valves during upset conditions.
Cooling towers and wastewater separators are highly variable VOC
emission sources depending on the characteristics of the material
being cooled or separated.
3.2 FUGITIVE EMISSION DEFINITION AND POTENTIAL SOURCE DESCRIPTION
3.2.1 Definition
In this study, fugitive emissions in the petroleum refining
industry are considered to be those volatile orqanic compound (VOC)
emissions that result when petroleum fluids (either liquid or gaseous)
are emitted from plant equipment. Exempted from this study are fugitive
emission sources that have been designated as affected sources by
other standards of performance and facilities involved in the production
of natural gasoline from natural gas.
3.2.2 Potential Source Characterization and Description
There are many potential sources of VOC fugitive emissions in a
typical petroleum refinery. The following sources are considered in
this chapter: pumps, compressors, in-line process valves, safety/
relief valves, open-ended valves, sampling connections, flanges,
cooling towers, and wastewater separators. These potential sources
are described below.
3.2.2.1 Pumps. Pumps are used extensively in the petroleum
refining industry for the movement of organic fluids. The centrifugal
pump is the most widely used pump; however, other types, such as the
positive-displacement, reciprocating, rotary action, and special
canned and diaphragm pumps, are also used in this industry. Petroleum
fluids transferred by centrifugal pumps can leak at the point of
contact between the moving shaft and stationary casing. Consequently,
a seal is usually required at the point where the shaft penetrates the
housing in order to isolate the pump's interior from atmosphere.
Two generic types of sealing devices, packed and mechanical, are
currently in use on pumps in the petroleum refining industry. Packed
seals can be used on both centrifugal and reciprocating types of
pumps. As Figure 3-2 shows, a packed seal consists of a cavity
3-3
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("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. To prevent the buildup of frictional heat between the seal and
shaft, lubrication is required. A sufficient amount of either the
liquid being pumped or another liquid that is injected must be allowed
to flow between the packing and the shaft to provide the necessary
lubrication. Deterioration of this packing and/or the shaft seal face
after a period of usage can be expected to eventually result in leakage
of organic compounds to atmosphere.
Mechanical seals are limited in application to pumps with rotating
shafts and can be further categorized as single and dual mechanical
seals. There are many variations to the basic design of mechanical
seals, but all have a lapped seal face between a stationary element
and a rotating seal ring. In a single mechanical seal application
(Figure 3-3), the rotating-seal ring and stationary element faces are
lapped to a very high degree of flatness to maintain contact throughout
their entire mutual surface area. As with pump packing, mechanical
seal faces must be lubricated to remove frictional heat; however,
because of the seal's construction, much less lubricant is needed.
A mechanical seal is not a leak-proof device. If the seal becomes
imperfect due to wear, the organic compounds being pumped can leak
between the seal faces and be emitted to atmosphere.
In a dual mechanical seal application, two seals can be arranged
back-to-back or in tandem. In the back-to-back arrangement (Figure 3-4),
the two seals provide a closed cavity between them. A barrier fluid
is circulated through the cavity. Because the barrier fluid surrounds
the dual seal and lubricates both sets of seal faces in this arrange-
ment, the heat transfer and seal life characteristics are much better
than those of the single seal. In order for the seal to function, the
barrier fluid must be at a pressure greater than the operating pressure
of the stuffing box. As a result some barrier fluid will leak across
the seal faces. Liquid leaking across the inboard face will enter the
stuffing box and mix with the petroleum liquid. Barrier fluid going
across the outboard face will exit to atmosphere. Therefore, the
barrier fluid must be compatible with the petroleum liquid as well as
3
with the environment.
3-4
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*=UUIO
e-uo
i»O4Aie>l_E.
A* ex
Figure 3-2. Diagram of a simple packed seal.
1
Figure 3-3. Diagram of a basic single mechanical seal
3-5
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In a tandem dual mechanical seal arrangement (Figure 3-5), the
seals face the same direction. The secondary seal provides a backup
for the primary seal. A seal flush is used in the stuffing box to
remove the heat generated by friction. As with the back-to-back seal
arrangement, the cavity between the two tandem seals is filled with a
barrier fluid. However, the barrier fluid is at a pressure lower than
that in the stuffing box. Therefore, any leakage will be from the
stuffing box into the seal cavity containing the barrier fluid. Since
this liquid is routed to a closed reservoir, petroleum liquid that has
leaked into the seal cavity will also be transferred to the reservoir.
At the reservoir, the petroleum liquid could vaporize and be emitted
to atmosphere. To ensure that VOCs do not leak from the reservoir,
4.
the reservoir can be vented to a control device.
Another type of pump that has been used in the petroleum refining
industry is the seal less pump which includes canned-motor and diaphragm
pumps. In canned-motor pumps (Figure 3-6) the cavity housing, the
motor rotor, and the pump casing are interconnected. As a result, the
motor bearings run in the pumped liquid, and shaft seals are eliminated.
Because the liquid is the bearing lubricant, abrasive solids cannot be
tolerated. Canned-motor pumps are being widely used for handling
organic solvents, organic heat transfer liquids, light oils, as well
as many toxic or hazardous liquids, or where leakage is an economic
problem.
Diaphragm pumps (see Figure 3-7) perform similarly to piston and
plunger pumps. However, the driving member is a flexible diaphragm
fabricated of metal, rubber, or plastic. The primary advantage of
this arrangement is the elimination of packing and shaft seals exposed
to the petroleum liquid. This is an important asset when hazardous or
toxic liquids are handled.
3.2.2.2 Compressors. Three types of compressors are commonly
used in the refining industry: centrifugal, reciprocating, and rotary.
The centrifugal compressor utilizes a rotating element or series of
elements containing curved blades to increase the pressure of a gas by
centrifugal force. Reciprocating and rotary compressors increase
pressure by confining the gas in a cavity and progressively decreasing
3-6
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Stuffing-box
Barrier fluid
out (top)
I
plate
- Pumped liquid
Inner mating ring—
Inner primary-—
ring
Outer mating ring
Outer primary
ring
Figure 3-4. Diagram of a dual mechanical seal
(back to back arrangement).7
Stuffing-box Bypass
housing / flush
Barrier fluid
out in
(topi (bottom)
Gland
plate
ring
Outer Outer
primary mating
ring
Shaft
Figure 3-5. Diagram of a dual mechanical seal
(tandem arrangement).°
3-7
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Circulating tuOe
Integral h«ot excnonger
Figure 3-6. Chempump canned-motor pump9
Suction ball
vaiv«-
Suclion
Figure 3-7. Shriver mechanically actuated diaphragm pump.10
3-8
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the volume of the cavity. Reciprocating compressors usually employ a
piston and cylinder arranqement while rotary compressors utilize
rotating elements such as lobed impellers or sliding vanes.
As with pumps, sealing devices are required to prevent leakage
from compressors. Packed seals, mechanical seals, or liquid film seals
(Figure 3-8) can be used to limit leakage from compressors that employ
rotating drive shafts. For reciprocating compressors, various arrangements
of packing glands and packing must be used for this purpose.
3.2.2.3 Process Valves. One of the most common pieces of equipment
in refineries is the valve. The types of valves commonly used are globe,
gate, plug, ball, relief, and check valves. All except the relief valve
and check valve are activated by a valve stem, which may have either a
rotational or linear motion, depending on the specific design. This
stem requires a seal to isolate the process fluid inside the valve from
atmosphere as illustrated by the diagram of a globe valve in Figure 3-9.
The possibility of a leak through this seal makes it a potential source
of VOC fugitive emissions. Since check valves do not have an external
actuating mechanism in contact with process fluids, they are not
considered to be potential sources of VOC 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 tetrafluorethylene; the packing
13
material used depends on the valve application and configuration.
These conventional packing glands can be used over a wide range of
operating temperatures. At high pressures these glands must be quite
14
tight to attain a good seal.
Elastomeric 0-rings are also used for sealing process valves.
These 0-rings provide good sealing but are not suitable where there is
sliding motion through the packing gland. These seals are rarely used
in high pressure service, and operating temperatures are limited by
15
the seal material.
3-9
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GAS PRE.S5UR£-
COM TAM1 MATS.O
O«l_ OUT
TO
Oil. OUT
Figure 3-8. Liquid-film compressor shaft seal
HANDWHEEL
STEM
PACKING NUT
PACKING
BONNET
SEAT
Figure 3-9. Globe valve with packed seal12
3-10
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3.2.2.4 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 the petroleum refining industry is the pressure relief valve
(Figure 3-10). Typically, relief valves are spring-loaded and designed
to open when the process pressure exceeds a set pressure, allowing the
release of vapors or liquids until the system pressure is reduced to
its normal operating level. When the normal pressure is reattained,
the valve reseats, and a seal is again formed.16 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.
Two potential causes of leakage from relief valves are: (1) "simmering"
or "popping," a condition due to the system pressure being close to
the set pressure of the valve, and (2) improper reseating of the valve
after a relieving operation.1'
Rupture disks are also common in the petroleum refining industry.
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, and a relief valve is not in series with
the rupture disk, the system depressurizes until atmospheric conditions
are obtained; this could result in an excessive loss of product or
correspondingly an excessive release of VOC fugitive emissions.
3.2.2.5 Cool ing Towers. Cooling towers (Figure 3-11) dissipate
heat from water used to cool process equipment such as reactors,
condensers, and heat exchangers. Cooling water is circulated through
process units and returned to a cooling tower where the water is
evaporatively cooled by forced air circulation. Petroleum fluids can
enter the cooling water from leaking process equipment if the equipment
is operating at a pressure greater than that of the cooling water.
VOCs can be released to atmosphere as cooling water vaporizes in the
tower.
3-11
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SE.A.T
1SK.
WOZXL.E
PR.OC£iS> SHOE.
Figure 3-10. Diagram of a spring-loaded relief valve.
18
Figure 3-11. Cooling tower (cross-flow).
19
3-12
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3-2.2.6 Wastewater Separators. Contaminated wastewater can
originate from several sources including, but not limited to, leaks,
spills, pump and compressor seal cooling and flushing, sampling equipment
cleaning, stripped sour water, desalter water effluent, and rain
runoff. Contaminated wastewater is collected in the process drain
system and directed to the wastewater treatment system where oil is
skimmed in a separator, and the wastewater undergoes additional treatment
as required. Organic compounds can be emitted wherever wastewater is
exposed to atmosphere due to evaporation of organic compounds contained
in the wastewater. As such, the primary emission points include
surface of forebays and separators.
3.2.2.7 Qpen-Ended Lines. Some valves are installed in a system
so that they function with the downstream line open to atmosphere.
Open-ended lines are used mostly in intermittent service for sampling
and venting. Examples are purge, drain and sampling lines. Some
open-ended lines are needed to preserve product purity. These are
normally installed between multi-use product lines (e.g., in load-out
racks) to prevent products from collecting in cross-tie lines due to
valve seat leakage. In addition to valve seat leakage, an incompletely
closed valve could result in VOC emissions to the atmosphere.
3.2.2.8 Sampling Connections. The operation of a process unit
is checked periodically by routine analyses of feedstocks and products.
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 sewer drain, where it can
evaporate and release VOC emissions to atmosphere.
3.2.2.9 Flanges. 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. Normally,
flanges are employed for pipe diameters of 50 mm or greater and are
classified by pressure and face type.
Flanges may become VOC fugitive emission sources when leakage
occurs due to improperly chosen gaskets or a poorly assembled flange.
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 seal between the flange faces.20
3-13
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3.2.2.10 Slowdown Systems. Refinery process units are periodically
shutdown and emptied for internal inspection and maintenance. The
process of unit shutdown, repair or inspection, and start-up is termed
a unit turnaround. Purging the contents of a vessel to provide a safe
interior for workmen is termed a vessel blowdown.
In a typical process unit turnaround, the liquid contents of the
vessel are pumped to a storage facility. The vessel is then depres-
surized, flushed with water, steam, or nitrogen, and ventilated. The
vapor content of the vessel may be vented to a fuel gas system, flared,
or released directly to atmosphere. When vapors are released directly
to atmosphere, it is through a knockout drum (which removes condensible
vapors) and a blowdown stack which is usually remotely located to
ensure that combustible mixtures are not released within the refinery.
3.3 BASELINE CONTROL
3.3.1 Industrial Practices
In the past, the petroleum refining industry has generally not
monitored equipment for fugitive VOC emissions nor repaired equipment
on the basis of reducing the level of fugitive VOC emissions. While
leaks that are physically evident (leaks that can be seen, heard, or
smelled) are normally repaired to minimize product loss and prevent
safety hazards, a significant number of fugitive VOC emission sources
are not so "easily detectable."
In most nonattainment areas, the States or local agencies have or
are in the process of adopting rules similar to the EPA Guideline
Series, Control of Volatile Organic Compound Leaks from Petroleum
Refinery Equipment, EPA-450/2-78-036.21 With full implementation by
1983, these rules are expected to affect about 56 percent of existing
refineries.22
3.3.2 Magnitude of VOC Emissions from Refinery Production Operations
To illustrate the potential magnitude of fugitive VOC emissions
from refinery operations, emissions were estimated from a hypothetical
10-unit petroleum refinery (approximately 15,900 m^/day capacity) as
presented in Table 3-2. The number of pieces of each equipment type
were multiplied by their respective uncontrolled emission factors
given in Table 3-1. Table 3-2 also shows the percentage of the total
uncontrolled emissions contributed by each source.
3-14
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TABLE 3-1. UNCONTROLLED FUGITIVE EMISSION FACTORS IN THE PETROLEUM
REFINING INDUSTRY
Uncontrolled emission
Fugitive emission source factor,3 kg/day
Pump seals
Light liquids5 2.7
Heavy Liquids0 0.50
Valves
Gas . 0.64
Light liquid" 0.26
Heavy liquid 0.005
Safety/relief valves
Gas 3.9
Open-ended lines 0.055
Flanges 0.007
Sampling connections 0.36
Compressor seals 15
aThese uncontrolled emission levels are based upon the refinery
data presented in reference 23.
Light liquid is defined as a petroleum liquid with a vapor pressure
greater than the vapor pressure of kerosene.
GHeavy liquid is defined as a petroleum liquid with a vapor pressure
equal to or less than that of kerosene.
3-15
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Table 3-2. ESTIMATED FUGITIVE VOC EMISSIONS FROM
A HYPOTHETICAL 10-UNIT PETROLEUM REFINERY
(15,900 m3/Day Capacity)
Equipment type
Pump Seals
Light liquids
Heavy 1 iquids
Valves
Gas
Light 1 iquid
Heavy 1 iquid
Safety/ relief valves
Gas
Open-ended 1 ines
Fl anges
Sampling connections
Compressor Seals
Totals
Reference 24.
bT,
Number of
pieces of
equipment3
125
125
6,000
9,750
9,750
130
1,750
64,000
250
14
93,339
Uncontrolled
emissionsb
kg/day
340
62
3,800
2,500
50
500
96
400
90
210
8,048
Percentage of
total
emissions
4
1
47
31
1
6
1
5
1
3
The number of equipment pieces multiplied by their uncontrolled
emission factors (given in Table 3-1) yields the uncontrolled emissions
per refinery.
3-16
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3.4 REFERENCES
1. Erikson, D.G., and V. Kalcevic. Emissions Control Options for
the Synthetic Organic Chemicals Manufacturing Industry, Fugitive
Emissions Report, Draft Final. Hydroscience, Incorporated.
February 1979. p. 11-2. Docket Reference Numher II-A-11.*
2. Reference 1, p. II-3.
3. Ramsden, J.H. How to Choose and Install Mechanical Seals.
Chemical Engineering. £>5_(22): 97-102. October 9, 1978. Docket
Reference Number 11-1-33.*
4. Reference 3, p. 99.
5. Perry, R.H., and C.H. Chilton. Chemical Engineers' Handbook, 5th
Ed. New York. McGraw-Hill Book Company. 1963. p. 6-8. Docket
Reference Number II-I-15.*
6. Reference 5, p. 6-13.
7. Reference 3, p. 100.
8. Reference 3, p. 101.
9. Reference 5, p. 6-12.
10. Reference 5, p. 6-13.
11. Reference 1, p. II-8.
12. Edwards, J.A. Valves, Pipe and Fittings-A Special Staff Report.
Pollution Engineering. 6:24. December 1974. Docket Reference
Number II-I-19.*
13. Lyons, J.L., and C.L. Ashland, Jr. Lyons' Encyclopedia of Valves.
New York. Van Nostrand Reinhold Company. 1975. 290 p. Docket
Reference Number II-I-20.*
14. Templeton, H.C. Valve Installation, Operation and Maintenance.
Chemical Engineering. _78(23)141-149. October 11, 1971. Docket
Reference Number II-I-13.*
15. Reference 14, p. 147-148.
16. Steigerwald, B.J. Emissions of Hydrocarbons to the Atmosphere
from Seals on Pumps and Compressors. Report No. 6, PB 216 582,
Joint District, Federal and State Project for the Evaluation of
Refinery Emissions. Air Pollution Control District, County of
Los Angeles, California. April 1958. 37 p. Docket Reference
Number II-I-4.*
3-17
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17. Reference 1, p. 11-7.
18. Reference 1, p. II-6.
19. Cooling Tower Fundamentals and Application Principles. Kansas City,
Missouri. The Marley Company. 1969. p. 4. Docket Reference
Number II-I-8.*
20. McFarland, I. Preventing Flange Fires. Chemical Engineering
Progress. j>5_(8): 59-61. August 1969. Docket Reference
Number II-I-9.*
21. Control of Volatile Organic Compound Leaks from Petroleum Refining
Equipment. EPA-450/2-28-036, OAQPS No. 1.2-111. June 1978.
Docket Reference Number II-A-6.*
22. Carruthers, J.E. and J.L. McClure, Jr. Overview Survey of Status
of Refineries in the U.S. with RACT Requirements (Draft Report).
Prepared for U.S. Environmental Protection Agency. Division of
Stationary Source Enforcement. Washington, D.C. Contract
No.. 68-01-4147. PEDCo, Dallas, TX. p. A-2. October 1979.
Docket Reference Number II-A-30.*
23. Wetherhold, R.G., C.P. Provost, and C.D. Smith. Assessment of
Atmospheric Emissions from Petroleum Refining. Volume 3, Appendix B.
EPA-600/2-80-075c. April 1980. Docket Reference Number II-A-19.*
24. Memorandum with attachments from Helms, G.T., EPA-CPOB, to Chief,
Air Branch, Regions I-X. Cost-Effectiveness for RACT Applications
to Leaks from Petroleum Refining Equipment. December 2, 1980.
Docket Reference Number II-B-33.*
*References can be located in Docket Number A-80-44 at U.S. Environmental
Protection Agency Library, Waterside Mall, Washington, D.C.
3-18
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4.0 EMISSION CONTROL TECHNIQUES
4.1 INTRODUCTION
This chapter discusses control techniques that can be applied to
reduce fugitive VOC emissions from petroleum refining operations. In
general, two approaches to emission control are available. The first
entails a leak detection and repair program in which fugitive sources
are located and repaired at certain intervals. The second is a preven-
tive approach whereby potential fugitive sources are controlled either
by installing specified controls or leakless equipment. The following
details the technical application of these control methods and their
estimated effectiveness.
4.2 LEAK DETECTION AND REPAIR PROGRAMS
Chapter 3 discusses the types of equipment that have the potential
to become fugitive VOC emission sources (i.e., pumps, compressors,
etc.). When such a piece of equipment develops a leak, the leak can
be detected by various techniques. Once detected, leaks can be repaired
through repair procedures, such as tightening the packing for valves.
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 measurement
methods would yield qualitative indications of leaks.
4.2.1.1 Individual Component Survey. Each fugitive emission
source (e.g., pump, valve, compressor) is checked for VOC leakage in
an individual component survey. Two individual component survey
methods were identified as follows: (1) leak detection by spraying
each component with a soap solution and observing bubble formation and
(2) leak detection by measuring VOC concentration with a portable VOC
detector.
4-1
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In the first method, if the soap solution forms bubbles or is
blown away, a leak from the component is indicated. However, the
magnitude of leak rates based on bubble formation is difficult to
assess. In addition, soap bubble formation does not distinguish VOC
emissions from other leaking gases or vapors, and bubble formation is
subject to component temperature and component configuration restraints.
In the second method, a portable hydrocarbon detector is used to
identify leaks of VOC from equipment components. The instrument
samples and analyzes the air in close proximity to the potential leak
surface by traversing the sampling probe tip over the entire area
where leaks may occur. The hydrocarbon concentration of the sampled
air is displayed on the instrument meter. This meter reading provides
a reasonable qualitative assessment of whether a source is leaking.
Performance criteria for the instrument and a description of the leak
testing methods are given in Appendix D. Data from petroleum refineries
have been used to develop approximate relationships between instrument
meter readings and mass emission rates. The data also indicate that
variations in mass emission rate and meter reading may occur over
short time periods for an individual piece of equipment. More frequent
monitoring intervals, therefore, tend to enhance the detection of
"large leaks" because there would be more opportunities to find the
high leak periods. Table 4-1 shows the percentage of pieces of equip-
ment that are predicted to have meter readings greater than or equal
to certain 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 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.
4-2
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Table 4-1. PERCENTAGE OF SOURCES PREDICTED TO BE LEAKING
IN AN INDIVIDUAL COMPONENT SURVEY1
Equipment
Typea
Pump Seal s
Light Liquidb
Heavy Liquid0
Valves
Gasd
Light Liquidb
Heavy Liquid0
Safety/Relief Valves
(Gas)d
Pipeline Flanges
Compressor Seals
>100,000
7
0
4
2
0
1
0
7
Predicted Percent of
ppmv >50,000 ppmv
9
0
5
4
0
2
0
13
Sources Leaking
>10,000 ppmv >1
24
2
10
11
0
7
0
36
,000ppmv
49
12
22
25
1
19
2
68
aThis type of information would not be appropriate for open-ended lines,
sampling connections, wastewater separators, vacuum producing systems,
cooling towers, and relief valve over-pressure.
bLight liquid is defined as a petroleum liquid with a vapor pressure
greater than the vapor pressure of kerosene.
CHeavy liquid is defined as a petroleum liquid with a vapor pressure
equal to or less than that of kerosene.
dEquipment in gas service contain process fluid in the gaseous state.
4-3
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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 back-
ground concentration sufficiently to allow for reliable detection.2
The major advantages of the unit area survey are that leaks from
accessible leak sources near the ground can be located quickly and
that the leak detection manpower requirements can be lower than those
for the individual component survey. Some of the shortcomings of this
method are that VOC emissions from adjacent units can cause false leak
indications; high or intermittent winds (local meteorological conditions)
can increase dispersion of VOC, causing leaks to be undetected; elevated
equipment leaks are not 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
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 effi-
ciency of this method is not well established, but it has been estimated
that 33 percent of the number of leaks identified by a complete individual
component survey could be located by fixed-point monitors.3 Fixed-point
monitors operate continuously, however, so that the leaks that are
detected would be detected sooner than they would if a periodic
component survey were used. 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
ca^ be selected as the sampling criterion.
4-4
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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 appli-
cation, visual inspections can be used to detect the failure of the
outer seal of a pump dual mechanical seal system. Observation of
liquid leaking along the shaft indicates an outer seal failure and
signals the need for seal repair.4
4.2.2 Repair Techniques
When leaks are located by the leak detection methods described in
this section, the leaking component can then be repaired or replaced.
Many components can be serviced on-line. This is generally regarded
as routine maintenance to keep operating equipment functioning properly.
Equipment failure, as indicated by a leak not eliminated by servicing,
requires isolation of the faulty equipment for either repair or
replacement.
4.2.2.1 Pumps. Most critical service process pumps are backed
up with a spare so that they can be isolated for repair. Of those
pumps that are not backed up with spares, some can be corrected by
on-line repairs (e.g., tightening the packing). However, most leaks
that need correction require that the pump be removed from service for
seal repair.
4.2.2.2 Valves. Most valve leaks can be reduced on-line by
tightening the packing gland for valves with packed seals or by lubri-
cation for plug valves, for example. Based on field observations, one
refinery study assumed that 75 percent of leaking valves could be
repaired on-line.5 Age can be an important factor in on-line
maintenance effectiveness because of corrosion of packing bolts,
insufficient packing, or aging of packing materials. If corroded
valve bolts are replaced and sufficient new packing is added to exist-
ing valves during a turnaround, future on-line repair attempts will be
greatly facilitated.
Various valve maintenance programs have been performed by EPA and
refinery personnel. Union Oil Company and Shell Oil Company each
4-5
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conducted studies at their California refineries on maintenance of
leaking valves. Emission rates were estimated based on screening
value correlations.6,7 EPA studied the effects of maintenance on
fugitive emissions from valves at four refineries.1 Each valve was
sampled to determine emission rates before and after maintenance to
evaluate emission reductions. In a separate study, EPA examined
maintenance effectiveness on block valves at an ethylene production
unit based on screening values alone.8 In a subsequent study,9 rou-
tine on-line maintenance achieved a 70 percent reduction in mass
emissions.
In each of these studies, maintenance consisted of routine
procedures, such as adjusting the packing gland while the valve was in
service. In general, the programs concluded that (1) a reduction in
emissions may be obtained by performing maintenance on valves with
screening values above 10,000 ppmv; (2) for valves with screening
values (before maintenance) below 10,000 ppmv, a slight reduction
in emissions after maintenance may result; however, sometimes emis-
sions from these valves may increase; and (3) directed maintenance
(emissions measured during repair until VOC concentration drops to
a specified level) is preferable to undirected maintenance (no
measurement of the effect of repair). A detailed description of
the testing programs and results is presented in Appendix C, Emission
Source Test Data.
Valves that need to be repacked or replaced to reduce leakage
must be isolated from the process. While control valves can usually
be isolated, block valves, which are used to isolate or by-pass process
equipment, normally cannot be isolated. One refiner estimates that
10 percent of the block valves can be isolated.10
When leaking valves can be corrected on-line, repair servicing
can be done immediately after detection of the leak. When the leaks
can be corrected only by a total or partial shutdown, the temporary
emissions could be larger than the continuous emissions that would
result from not shutting down the unit until it was time for a shutdown
for other reasons. Simple maintenance procedures, such as packing
gland tightening and grease injection, can be applied to reduce emissions
4-6
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from leaking valves until a shutdown is scheduled. Leaks that cannot
be repaired on-line can be repaired by drilling into the valve housing
and injecting a sealing compound. This practice is growing in acceptance,
especially for safety concerns.H
4.2.2.3 Flanges. One refinery field study noted that most
flange leaks could be sealed effectively on-line by simply tightening
the flange bolts.5 For a flange leak that requires off-line gasket
seal replacement, a total or partial shutdown of the unit would
probably be required because most flanges cannot be isolated.
For many of these cases, there are temporary flange repair
methods that can be used. Unless a leak is major and cannot be
temporarily corrected, the temporary emission from shutting down a
unit would probably be larger than the continuous emissions that would
result from not shutting down the unit until time for a shutdown for
other reasons.
4.2.2.4 Compressors. Leaks from compressor seals may be reduced
by the same repair procedure that was described for pumps (i.e., tight-
ening the packing). Other types of seals, however, require that the
compressor be taken out of service for repair. Since most compressors
do not have spares, seal replacement necessitates a partial or complete
unit shutdown. The shutdown for repair and the subsequent start-up
can result in greater emissions than the emissions from the seal if it
were allowed to leak until the next scheduled shutdown.
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 rneter reading for defining a leak is influenced by several consider-
ations. 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 predicted to be affected at various leak definitions
-------
Table 4-2. PERCENT OF TOTAL MASS EMISSIONS
AFFECTED AT VARIOUS LEAK DEFINITIONS1
Source Type
Percent of Mass Emissions Affected at This
Leak Definition^
100,000 ppmv 50,000 ppmv 10,000 ppmv 1,000 ppmv
Pump Seals
Light Liquid^
Heavy Liquidc
Valves
Gasd
Light Liquidb
Heavy Liquidc
Safety /Relief Valves
(Gas)d
Compressor Seals
Flanges
62
0
89
53
0
30
48
0
73
0
95
65
0
47
66
0
92
37
98
86
0
74
91
0
98
85
99
98
35
95
98
57
aThese figures relate the leak definition to the percentage of total mass
emissions that can be expected from sources with concentrations at the
source greater than the leak definition. If these sources were instan-
taneously repaired to a zero leak rate and no new leaks occurred, then
emissions could be expected to be reduced by this maximum theoretical
efficiency.
Light liquid is defined as a petroleum liquid with a vapor pressure
greater than the vapor pressure of kerosene.
p
Heavy liquid is defined as a petroleum liquid with a vapor pressure
equal to or less than that of kerosene.
Equipment in gas service contain process fluid in the gaseous state.
4-8
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for a number of equipment types. From the table, it can be seen that,
in general, a low meter reading leak definition results in larger
potential emission reductions. The monitoring instruments presently
in use for fugitive emission surveys have a maximum meter reading of
10,000 ppm. Add-on dilution devices are available to extend the range
of the meter beyond 10,000 ppm, but these dilution probes are inaccurate
and impractical for fugitive emissions monitoring surveys. 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 few 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. Information
obtained through EPA in-house testing and industry testing1-2'13
indicates that in actual fugitive emission surveys, most sources of
VOC have meter readings which are very low or very high. 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 main-
tenance is attempted on low leak valves. These valves should, however,
be able to achieve essentially 100 percent emission reduction through
off-line repair because the leaking valves can either be repacked or
replaced. 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 will occur for a leak detection and repair program
with a 10,000 ppm leak definition.
For pump and compressor seals, 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. The routine leakage is generally
low, so these seals would tend to have low instrument meter readings.
With time, however, as the seal begins to wear, the concentration and
4-9
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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, slightly over 90 percent of
the emissions from pump and compressor seals are from sources with
instrument meter readings greater than or equal to 10,000 ppm. Properly
designed, installed, and operated seals have low instrument meter
readings, and 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.
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. Monitoring may also be scheduled
for a "skip period" approach.
A skip-period schedule would allow less frequent monitoring for
units that achieve a specified level of performance over a number of
consecutive periods. For example, a unit that achieves less than
2 percent of its valves leaking for five consecutive quarterly monitoring
periods might use an annual monitoring schedule as long as the percentage
of its valves leaking does not exceed 2 percent. The skip-period
approach allows flexibility for units that do not require regular
monitoring to maintain good performance.
In the refinery VOC leak Control Technique Guideline (CTG)
document,^ the recommended leak detection intervals are as follows:
annual — pump seals and pipeline valves in liquid service; quarterly —
compressor seals, pipeline valves in gas service, and safety/relief
valves in gas service; weekly -- visual inspection of pump seals; and
no individual monitoring — pipeline flanges and other connections,
and safety/relief valves in liquid service. The choice of the
interval affects the emission reduction achievable, since more frequent
inspection will result in earlier detection and repair of leaking
sources.
4-10
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4.2.3.3 Allowable Repair Time. If a leak is detected, the
equipment should be repaired within a certain time period. The allow-
able repair time should reflect an interest in reducing emissions, but
it should also 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 VOCs.
4.2.3.4 Estimation of Reduction Efficiency. Data are presented
in Table 4-2 that show the expected fraction 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.
This approach can be expressed mathematically by the following
equation:14
Reduction efficiency - AxBxCxD
Where:
A = Theoretical Maximum Control Efficiency = fraction of
total mass emissions from sources with VOC concentra-
tions 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.
4-11
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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.
An alternative to the ABCD correction factor model that may be
used to determine leak detection and repair program effectiveness is
an empirical approach which utilizes recently available data on leak
occurrence, leak recurrence, and effectiveness of simple in-line
repair (LDAR model). Estimates of leak detection and repair program
effectiveness based on LDAR model results are presented in Appendix F.
4.3 PREVENTIVE PROGRAMS
An alternative approach to controlling fugitive VOC emissions
from refinery operations is to replace components with leakless equipment.
This approach is referred to as a preventive program. This section
will discuss the kinds of equipment that could be applied in such a
program and the advantages and disadvantages of this equipment.
4.3.1 Pumps
As discussed in Chapter 3, 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, or it can be eliminated entirely by installing
seal less pumps.
4-3.1.1 Dual Mechanical Seals. As discussed in Chapter 3, dual
mechanical seals consist of two mechanical sealing elements usually
arranged in either a back-to-back or a tandem configuration. In both
configurations a (nonpolluting) barrier fluid circulates between the seals.
The barrier fluid system may be a circulating system, or it may rely on
4-12
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Table 4-3.
INTERVALS, ALLOWABLE REPAIR TIMES, AND LEAK DEFINITIONS
EMISSION CORRECTION FACTORS FOR VARIOUS INSPECTION
a (Reference 14)
I
CO
Leak Occurrence and
Recurrence Correction
Factor
Non-Instantaneous
Repair Correction
Factor0
Imperfect Repair
Correction
Factor
Allowable Repair
Inspection Interval
Source
Pump Seals
Light Liquid6
Valves
Gasf
Light Liquid
Safety/Relief Valves9
Compressor Seals
Yearly
0.800
0.800
0.800
0.800
0.800
Quarterly
0.900
0.900
0.900
0.900
0.900
Monthly
0.950
0.950
0.950
0.950
0.950
Time (Days)
15
0.979
0.979
0.979
0.979
0.979
5
0.993
0.993
0.993
0.993
0.993
1
0.999
0.999
0.999
0.999
0.999
Leak Definition (ppmv)
100,000
0.974
0.998
0.988
0.995
0.994
50,000
0.972
0.998
0.980
0.993
0.992
10,000
0.941
0.996
0.958
0.985
0.984
1,
0.
0.
0.
0.
0.
000
886
992
916
968
972
Note that these correction factors taken individually do not correspond exactly to the overall anission reduction obtainable
by a monitoring and maintenance program. The overall effectiveness of the program is determined by the product of all correction
factors.
Values are assumed and account 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 could
not be repaired.
"•"Accounts for emissions that occur between detection of a leak and subsequent repair.
Accounts for the fact that some sources that are repaired are not reduced to zero. The average repair factors at 1,000 ppmv
are assumed.
eLight liquid is defined as a petroleum liquid with a vapor pressure greater than that of kerosene.
"Valves in gas service carry process fluids in the gaseous state.
9Gas service only.
-------
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 atmosphere, as in the case of pumping easily oxidizable
materials which 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 which have been used are water (or steam)s 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, (discussed further in Section 4.3.5), 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 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 of the seals.2
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.
Dual mechanical seals are used in many refinery process applications;
however, there are some conditions that preclude the use of dual
mechanical seals. Their maximum service temperature is usually limited
to less than 260°C, and mechanical seals cannot be used on pumps with
reciprocating shaft motion.2
4-3.1.2 Seal!ess Pumps. The sealless or canned-motor pump is
designed so that the pump casing and rotor housing are interconnected.
As shown in Figure 4-1, the impeller, motor rotor, and bearings are
completely enclosed and all seals are eliminated. A small portion of
process fluid is pumped through the bearings and rotor to provide
lubrication and cooling.
4-14
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DISCHARGE
t
COOLANT CIRCULATING TUBE
STATOR LINER
SUCTION
IMPELLER
BEARINGS
Figure 4-1. Seal-less Canned Motor Pump
-------
Standard single-stage canned-motor pumps are available for flows
up to 160 cubic meters per second and heads up to 76 meters. Two-stage
units are also available for heads up to 183 meters. Canned-motor
pumps are widely used in applications where leakage is a problem.15
The main design limitation of these pumps is that only clean
process fluids may be pumped without excessive bearing wear. Since
the process liquid is the bearing lubricant, abrasive solids cannot be
tolerated. Also, there is no potential for retrofitting mechanical or
packed seal pumps for sealless operation. Use of these pumps in
existing plants would require that existing pumps be replaced.
4.3.2 Compressors
As discussed in Chapter 3, there are three types of compressors
used in refinery processes: centrifugal, rotary, and reciprocating.
Centrifugal and rotary compressors are driven by rotating shafts while
reciprocating compressors are driven by shafts having a linear
reciprocating motion. In either case, fugitive emissions occur at the
junction of the moving shaft and the stationary casing, but the kinds
of controls that can be effectively applied depend on the type of
shaft motion involved.
4.3.2.1 Centrifugal and Rotary Compressors. Centrifugal and
rotary compressors are both driven by rotating shafts. Emissions from
these types of compressors can be controlled by the use of mechanical
seals with barrier fluid (liquid or gas) systems or by the use of
liquid film seals. In both of these types of seals, a fluid is injected
into the seal at a pressure higher than the internal pressure of the
compressor. In this way, leakage of the process gas to atmosphere is
prevented except when there is a seal failure. As in the case of
pumps, seal fluid degassing vents must be controlled with a closed
vent system (see Section 4.3.5) to prevent process gas from escaping
from the vent.
4.3.2.2 Reciprocating Compressors. This type of compressor
usually involves a piston, cylinder, and drive-shaft arrangement.
Since the shaft motion is linear, a packing gland arrangement is nor-
mally employed to prevent leakage around the moving shaft. This type
of seal can be improved by inserting one or more spacer rings into the
4-16
-------
packing and connecting the void area or areas thus produced to a
collection system through vents in the housing. This is referred to
as a "scavenger" system. As with other fugitive emission collection
systems, these vents must be controlled to prevent fugitive emissions
from entering the atmosphere.
4.3.2.3 Seal Area Enclosures. There may be some compressors to
which the above controls may not be applied. In these situations the
seal area may be enclosed and the captured fugitive emissions routed
to a control device by a closed vent system.
4.3.3. Valves
As in the case of pumps, valves can be sources of fugitive VOC
emissions because of leakage through the packing used to isolate pro-
cess fluids from atmosphere (see Chapter 3). This source of emissions,
however, can be eliminated by isolating the valve stem from the process
fluid. Sealed bellows valves are designed to perform in this manner.
The basic design of a sealed bellows valve appears in Figure 4-2.
The stem in this type of valve is isolated from the process fluid by
metal bellows. The bellows is generally welded to the bonnet and dish
of the valve, thereby isolating the stem.
There are two main disadvantages to these valves. First, they
are only available in globe and gate valve configurations. Second,
the crevices of the bellows may be subject to corrosion under severe
conditions if the bellows alloy is not carefully selected.
The main advantage of these valves is that they can be designed
to withstand high temperatures and pressures so that leak-free service
can be provided at operating conditions beyond the limits of diaphragm
valves.
4.3.4 Safety/Relief Valves
As discussed in Chapter 3, safety/relief values can be sources of
fugitive VOC emissions because of leakage through the valve seat.
This type of leakage can be prevented by installing a rupture disk
upstream of the valve, by connecting the discharge port of the valve
to a closed-vent system, or by use of soft seat technology such as
elastomer "0-rings." A rupture disk can be used upstream of a
safety/relief valve so that under normal conditions it seals the
4-17
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STEM
YOKE
BELLOWS
Figure 4-2. Sealed Bellows Valve
-IS
-------
system tightly but will break when its set pressure is exceeded, at
which time the safety/relief valve will relieve the pressure. Figure 4-3
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 preventing the valve from being reseated if the disk
ruptures. It is important that no pressure be allowed to build in the
pocket between the disk and the 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 may be necessary to install a 2-port valve and parallel relief
valve when using a rupture disk upstream of a relief valve. Such a
system may be required to isolate the relief valve/rupture disk system
for repair in case of an overpressure discharge. The parallel system
would provide a backup relief valve during repair. However, a block
valve upstream of the rupture disk/relief valve system will accomplish
the same purpose where safety codes allow the use of a block valve for
this purpose.
An alternative method for controlling relief valve emissions due
to improper reseating is the use of a soft elastomer seat in the
valve. An elastomer "o-ring" can be installed so that the valve
always forms a tight seal after an overpressure discharge. However,
this approach will not prevent leakage due to "simmering" as described
in Chapter 3.
4.3.5 Closed-Vent Systems and Control Devices
A closed-vent system can be used to collect and dispose of gaseous
VOC emissions resulting from seal oil degassing vents, pump and compressor
seal leakage, relief valve leakage, and relief valve discharges due to
overpressure operation. As mentioned in Section 4.3.1.1, a closed
vent system consists of piping connectors, flame arresters, and where
needed, flow inducing devices. To obtain maximum emission reduction
closed vent systems should be designed and operated such that all VOC
emissions are transported to a control device without leakage to the
atmosphere.
4-19
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— -Tension-adjustment
thimble
To
atmospheric
vent
CONNECTION FOR
PRESSURE GAUGE
& BLEED VALVE
FROM SYSTEM
Figure 4-3. Rupture Disk Installation Upstream of a. Relief Valve
4-20
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Control devices which can be utilized in a closed vent system
include process heaters and boilers, carbon adsorption units,
refrigeration units, and gas recovery compressors. The efficiency of
the system will be controlled by the efficiency of the control device.
Emission measurements that reflect the effectiveness of these control
devices in reducing VOC that are captured and transported to the
devices by closed vent systems are limited. Without elaborate and
costly materials balancing of VOC entering control devices, it is not
practicable to measure the emissions from these control devices.
However, efficiencies of greater than 90 percent may be provided by
any of the above mentioned devices.16'1^
Flares are used in the petroleum refining industry as a means of
handling large emergency releases from process units and for combusting
continuous, low flows of VOC that are transported by closed vent
systems. A number of studies have contributed to the current state of
knowledge of flare flames. However, the VOC emission reduction efficiency
of flares used in refineries is uncertain because measurement
methodologies have not been completely developed. Four flare studies
provide information on flare gas composition, flow rate, and destruction
efficiency. These flare studies present flare destruction efficiencies
ranging from 91 to 100 percent for perfectly maintained, modern flares
burning easily combusted gases.18'21
The best available flare design or state-of-the-art flare design
is the smokeless flare. A smokeless flare is desirable because any
smoke produced during flaring of VOC contains particulate, carbon
monoxide, and unburned or partially oxidized VOC. The smokeless flare
minimizes the amount of particulate, carbon monoxide, and VOC emitted by
injecting steam or air into the VOC stream that is present in the
flare header. The injection of steam or air increases the mixing of
gases within the flare zone thereby increasing destruction of the VOC.
There are a number of engineering practices currently in use
which help flares achieve smokeless operation. One system involves
the use of staged elevated flare systems, where a small diameter flare
is operated in tandem with a large diameter flare. The staged elevated
flare system, shown in Figure 4-4, is designed such that the small
flare takes the continuous low flow releases (such as seal oil degassing
4-21
-------
,Pll_OT
MAIM
WE.ADE.R-5n
&
• EL_E.VAT E.D' P= V_ ARE.
REJ-ISIF VAL.VE.
Figure 4-4. Simplified Closed-Vent System with Dual Flares
4-22
-------
vents) and the larger flare accepts large intermittent flows (such as
relief valve discharges). A second system involves the use of a
small, separate line to the flare tip for continuous low volume, low
pressure releases. The small conveyance line is used in order to
maintain higher exit velocities of gases entering the flare head,
thereby aiding combustion of the low flow VOC stream. A third system,
sometimes used in conjunction with either of the above systems involves
the use of flare gas recovery. In the third system, a compressor is
used to recover the continuously generated flare gas "base load." The
compressor is sized to handle the "base load," and any excess gas is
flared.
4.3.6 Open-Ended Lines
Caps, plugs, and double block and bleed valves are devices for
closing off open-ended lines. When installed downstream of an open-ended
line, they are effective in preventing leaks through the seat of the
valve from reaching atmosphere. In the double block and bleed system,
it is important that the upstream valve be closed first. Otherwise,
product will remain in the line between the valves, and expansion of
this product can cause leakage through the valve stem seals.
The control efficiency will depend on such factors as frequency
of valve use, valve seat leakage, and material that may be trapped in
the pocket between the valve and cap or plug and lost on removal of
the cap or plug. Annual emissions from a leaking open-ended valve are
approximately 100 kg.22 Assuming that open-ended lines are used an
average of 10 times per year, that 0.1 kg of trapped organic material
is released when the valve is used, and that all of the trapped organics
released are emitted to atmosphere, the annual emissions from closed
off open-ended lines would be 1 kg. This would be a 99 percent
reductions in emissions. Due to the conservative nature of these
assumptions, a 100 percent control efficiency has been to estimate the
emission reductions of closing off open-ended lines.
4.3.7 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 in order
that the handling losses are minimized. Figure 4-5 gives two examples
4-23
-------
PROCESS. L.IME.
•RROCE.SS LI WE.
SAMPLE.
COklTAlMER
SAMPLE.
COMTA.IME.R.
Figure 4-5. Diagram of Two Closed-Loop Sampling Systems'
4-24
-------
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
23
require no line pressure drop. For emission calculations, it has
been assumed that closed-purge sampling systems will provide 100 percent
control efficiency for the sample purge.
4.3.8 Cooling Towers
In a recent survey, the majority of cooling towers tested did not
have significant VOC emissions. These cooling towers use indirect
(non-contact) condensation which is expected to be used in all future
applications. Presently there are no known techniques to reduce the
VOC emissions from indirect condensation cooling towers beyond the
level of control presently found in the industry. Direct contact
condensation is used in some existing refineries, but its use is being
phased out due to environmental considerations.
4.3.9 Process Drains and Wastewater Separators
There are several known techniques for reducing VOC emissions
from process drains and wastewater separators. Process drain emissions
can be controlled by reducing the amount of VOC that is spilled or
otherwise put into the drain system. The drains can also be controlled
by installing inverted U-bends to trap VOC within the drain system.
Available data show that only a small percentage of drains have
concentrations greater than 10,000 ppmv. Wastewater separators can
be controlled by covering or enclosing the only water surface of the
separator. Although uncontrolled wastewater separator emissions can
be quite large, the results of ongoing studies will need to be
reviewed to determine the magnitude of emissions under existing controls,
If the emissions from process drains or wastewater separators are
found to be significant, these sources will be addressed in future
regulations.
4.3.10 Slowdown Systems
As stated in Chapter 3, a typical process unit turnaround with
vessel blowdown includes pumping the liquid contents to a storage
facility, depressur.izing the vessel to remove vapors, flushing any
4-25
-------
remaining vapors, and then ventilating the vessel before the workmen
enter. Industry practice and existing State and local regulations
provide venting of hydrocarbons and purge gases to flares or vapor
recovery systems to the extent that the overall impact of a turnaround
?fi
on fugitive emissions is probably no longer significant.
4-26
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4.4 REFERENCES
1. Wetherold, R.G., L.P. Provost, and C.D. Smith. Assessment of
Atmospheric Emissions from Petroleum Refining: Volume 3. Appendix B.
Radian Corporation. Austin, TX. For U.S. Environmental Protection
Agency. Research Triangle Park, NC. Report Number EPA-600/2-80-075c.
April 1980. Document Reference Number II-A-19.*
2. 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.
Document Reference Number II-A-11.*
3. 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. Document Reference Number II-I-30.*
4. Hustvedt, K.C., R.A. Quaney, and W.E. Kelly. Control of Volatile
Organic Compound Leaks from Petroleum Refinery Equipment. U.S.
Environmental Protection Agency. Research Triangle Park, NC.
Report Number EPA-450/2-78-036. June 1978. Document Reference
Number II-A-6.*
5. Emissions from Leaking Valves, Flanges, Pump and Compressor
Seals, and Other Equipment in Oil Refineries. Report Number
LE-78-001. State of California Air Resources Board. April 24,
1978. Document Reference Number II-I-26.*
6. Letter and attachments from Bottomley, F.R., Union Oil Company,
to Feldstein, M., Bay Area Air Quality Management District.
April 10, 1979. 36 p. Document Reference Number II-B-30.*
7. Letter and attachments from Thompson, R.M., Shell Oil Company, to
Feldstein, M., Bay Area Air Quality Management District. April 26,
1979. 46 p. Document Reference Number II-B-29.*
8. U.S. Environmental Protection Agency. Air Pollution Emission
Test at Phillips Petroleum Company. Research Triangle Park, NC.
EMB Report No. 78-OCM-12E. December 1979. Document Reference
Number II-A-13.*
9. Langley, 6.J. and R.G. Wetherold. Evaluation of Maintenance
for Fugitive VOC Emissions Control. Final Report. EPA-600/
52-81-080. Radian Corporation, Austin, TX. For U.S. Environ-
mental Protection Agency. Industrial Environmental Research
Laboratory. Cincinnati, OH. May 1981. Document Reference
Number II-A-21.*
4-27
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10. J. Johnson, Exxon Co., letter to Robert T. Walsh, EPA. July 28,
1977. Document Reference Number II-D-22.*
11. Teller, J.H. Advantages found in On-Line Leak Sealing. The Oil
and Gas Journal. .77(29): 54-59. July 16, 1979. Document Reference
Number 11-1-40.*
12. Exxon Chemical Company, U.S.A. Test Fugitive Emission Monitoring.
January 1980. Attachment to letter from McClure, H.H., Texas
Chemical Council, to Barber, W., EPA:OAQPS. June 30, 1980.
Docket Reference Number II-D-69.*
13. Lee, Kun-Chieh, et. al. A fugitive Emissions Study in Petrochemical
Manufacturing Unit. Paper presented at annual Air Pollution
Control Association Meeting. Montreal, Quebec. June 22-27,
1980. p. 2. Docket Reference Number 11-1-57.*
14. 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.
Document Reference Number II-A-16.*
15. Perry, John H. Chemical Engineers Handbook. Robert Perry, Cecil
Chilton, Sidney Kirkpatrick, eds. McGraw-Hill Book Company. New
York. 1963. p. 6-7. Document Reference Number II-A-15.*
16. Bulk Gasoline Terminals - Background Information Document for
Proposed Standards. Draft. U.S. Environmental Protection Agency
EPA-450/3-80-038a. December 1980. Document Reference
Number II-A-35.*
17. Memorandum. Mascone, D.C., U.S. EPA/CPB, to J.R. Farmer, U.S.
EPA/CPB. Thermal Incinerator Performance for NSPS. June 11,
1980. Document Reference Number II-B-37.*
18. Palmer, P.A. "A Tracer Technique for Determining Efficiency of
an Elevated Flare," E.I. duPont de Nemours and Co., Wilmington,
DE (1972). Docket Reference Number 11-1-59.*
19. Lee, K.C., and G.M. Whipple. "Waste Gas Hydrocarbon Combustion
in a Flare," Union Carbide Corporation, South Charleston, WV
(1981). Docket Reference Number II-I-60.*
20. Siegel, K.D. "Degree of Conversion of Flare Gas in Refinery High
Flares," Dissertation. Karlstrohe University. February 16,
1980. Attachment to letter from McClure, H.H., Texas Chemical
Council to Barber, W., EPA: OAQPS. June 30, 1980. Document
Reference Number II-D-69.*
21. Howes, J.E., T.E. Hill, R.N. Smith, G.R. Ward, W.F. Herget.
"Development of Flare Emission Measurement Methodology, Draft
Report," EPA Contract No. 68-02-2682 (1981). Docket Reference
Number II-A-39.*
4-28
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22. Fugitive Emission Sources of Organic Compounds - Additional
Information on Emissions, Emission Reductions, and Costs. U.S.
Environmental Protection Agency. EPA-450/3-82-010. April 1982.
Docket Reference Number II-A-41.*
23. Letter and Attachments from McClure, H.H., Texas Chemical Council,
to Patrick, D.R., EPA. May 17, 1979. Document Reference Number II-D-50.*
24. Compilation of Air Pollutant Emission Factors. Second Edition.
U.S. Environmental Protection Agency. AP-42 Part B. April 1973.
Document Reference Number II-A-2.*
25. Workplan for Determination of Atmospheric Hydrocarbon Emissions
for Petroleum Refinery Wastewater Systems. Engineering Science.
For U.S. Environmental Protection Agency. EPA Contract Number
68-02-3160. November 1979. Document Reference Number II-A-31.*
26. Wetherold, R.G. and D.D. Rosebrook. Assessment of Atmospheric
Emissions from Petroleum Refining: Volume 1. Technical Report.
Radian Corporation. Austin, TX. For U.S. Environmental Protection
Agency. Industrial Environmental Research Laboratory. Research
Triangle Park, NC. Report Number EPA-600/2-80-075a. April 1980.
p. 25, 27. Document Reference Number II-A-17.*
*References can be located in Docket Number A-80-44 at the U.S. Environmental
Protection Agency Library, Waterside Mall, Washington, D.C.
4-29
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5.0 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 petroleum
refinery operations 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 which 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
will not be 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/hr of pollutant.
Paragraph (c) affirms that the addition of an affected facility to a
stationary source through any mechanism — new construction, modifica-
tion, 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 recon-
structed 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 techno-
logically 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 of EPA. As
stated in Section 60.15(f), 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 tech-
nical limitations 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
REFINERY VOC FUGITIVE EMISSION SOURCES
Changes in refinery product demand and in available refinery
feedstocks are expected to result in a number of modernization and
alteration projects at existing refineries over the next several
years. Some of these projects could result in existing units becoming
subject to the provisions of Sections 60.14 and 60.15. Examples in
which this could occur are presented below.
5.2.1 Modification
VOC fugitive emissions from existing refinery process units could
increase in several ways. This might occur if the number of pumps and
valves associated with the unit were increased. The number of pumps
and valves associated with a process unit may be increased in order to
increase its production rate or in order to increase downstream capacity
because of the production increase of the unit.
This kind of process unit alteration is expected when increased
production of light hydrocarbon products (e.g., gasoline, diesel, and
jet fuel) occurs by increased processing of residual oils. Demand for
residual oils is expected to decline steadily in the future due to
increased competition from coal and natural gas. Therefore, it is
desirable to convert residual oils to lighter, more profitable products.
To upgrade residual oils, it is necessary to increase the ratio
of hydrogen to carbon. Hydrogen may be added through a variety of
commercially available hydroprocessing units or carbon may be removed
through traditional carbon rejection operations such as delayed coking
or thermal cracking. The products of these operations may be further
processed by catalytic cracking to produce light hydrocarbons for
gasoline, jet fuel, or diesel.
It is expected that a number of residual oil conversion projects
will be undertaken by existing refineries in the near future to increase
production of more desirable light hydrocarbon products. These conversion
projects could increase VOC fugitive emission rates by the addition of
fugitive emission sources to existing process units.
5-3
-------
Routine changes and additions of fugitive emission sources are
commonly made to increase ease of maintenance, to increase productivity,
to improve plant safety, and to correct minor design flaws. These
additions of fugitive emission sources may cause an increase in fugitive
emissions. However, fugitive emissions from other sources could be
reduced to compensate for this increase.
5.2.2 Reconstruction
An existing refinery process unit may replace a number of unit
components during modernization or process alteration projects. This
could occur if an existing crude distillation unit that is designed to
process low sulfur, light crude oil is converted to accommodate high
sulfur, heavy crude oil. Many of the unit's fugitive emission sources
(pumps, valves, etc.) would have to be replaced in order to withstand
the more corrosive conditions caused by the change in feedstocks. It
is possible that the cost of converting the unit could exceed 50 percent
of the cost of a new unit.
The replacement of several fugitive emission sources at an existing
process unit might also be considered a reconstruction. For example,
if several pumps, compressors, and sampling loops were replaced at an
existing gas processing plant, the fixed capital cost of the new equip-
ment might exceed 50 percent of the cost of a new unit.
5-4
-------
5.3 REFERENCES
1. Aalund, Leo R. U.S. Refiners Moving to Expand Resid Processing.
Oil and Gas Journal. January 5, 1981. pp. 43-48. Docket Reference
Number II-I-53.*
*References can be located in Docket Number A-80-44 at the U.S.
Environmental Protection Agency'Library, Waterside Mall, Washington, D.C,
5-5
-------
6.0 MODEL UNITS AND REGULATORY ALTERNATIVES
6.1 INTRODUCTION
This chapter presents model unit parameters and regulatory
alternatives for reducing VOC fugitive emissions from petroleum refining
facilities. The model units consist of three groupings of process
equipment that are representative of the range of process complexity
present in the petroleum refining industry. They provide a basis for
comparing the environmental and economic 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 UNITS
Emission testing data from petroleum refineries indicate that VOC
fugitive emission rates are dependent on the number of pieces of
equipment (pumps, valves, etc.) present in a process unit and not
dependent on equipment throughput, age, temperature, or pressure.
For this reason, model units were developed based on process unit
equipment populations. Refinery process units of similar complexity
(equipment populations) were categorized into the three model units as
discussed below.
6.2.1 Derivation of Model Units
In the development of new source standards, model plants are
normally used to assess the impacts of the regulatory alternatives.
Since process emissions are generally porportional to plant production
rates, model plants are usually defined in terms of production rates
or throughputs for a given process. However, the majority of VOC
fugitive emissions originate from leaks in process equipment such as
pumps, valves, and compressors. Thus, in order to assess the impacts
of the regulatory alternatives on VOC fugitive emissions, it is necessary
6-1
-------
to develop model units based on the number of pieces of equipment
utilized in various refinery process units.
In developing the model units, the array of petroleum refining
processes was first condensed into 12 basic operations as follows:
crude distillation, vacuum distillation, thermal cracking, catalytic
cracking, hydrotreating, isomerization, alkylation, hydrogen production,
reforming, solvent extraction, lube oil production, and asphalt units.
234
Next, average equipment inventories for each type of unit were derived. ' '
Unit equipment counts consider only those components operating in less
than 10 percent benzene service. Components servicing greater than
10 percent benzene streams are covered by the proposed national emission
standard for benzene fugitive emissions.
The equipment counts for existing units were weighted with respect
to projected unit growth for the period from 1982 to 1986 (growth
projections are discussed in Appendix E). Thus, the unit component
counts reflect the range of source populations that are expected in
refinery units during implementation of standards of performance.
The weighted average unit equipment inventories revealed three
groups of refining processes of similar complexity. These three
categories represent the model units discussed in Section 6.2.2.
6.2.2 Model Unit Parameters
Model Unit A characterizes an equipment inventory characteristic
of the least complex production units within a petroleum refinery.
The individual process units reflected in Model Unit A include
hydrotreating, isomerization, lube oil, asphalt, and hydrogen production.
Model Unit B represents alkylation, thermal cracking, reforming,
vacuum distillation, and solvent extraction. Model Unit Cs the most
complex process unit, is representative of crude distillation (including
a saturated gas plant) and catalytic cracking (including an unsaturated
gas plant). The technical parameters for the model units are shown in
Table 6-1.
The model unit components are further categorized according to
the nature of the process streams they handle. This distinction is
made because emission rates increase with increasing vapor pressure
(volatility) of the process stream. Hence, valves are subdivided into
three categories: (1) gas/vapor service (valves in gas or vapor
6-2
-------
TABLE 6-1. MODEL UNIT COMPONENT COUNTS
Source
Valves
Open-Ended Lines5' (Purge,
drain, sample lines)
Sampling Connections
Pump Seals
Flanges
Pressure Relief Devices
Compressor Seals
Service
Gas/Vapord
Light Liquid6
Heavy Liquid
All
All
Light Liquid6
Heavy Liquid
All
Gas/Vapord
All
Model3
Unit
A
130
250
150
70
10
7
3
1,900
3
1
Model5
Unit
B
260
500
300
140
20
14
6
3,800
7
3
Model
Unit
C
780
1,500
900
420
60
40
20
11,000
20
8
aModel Unit A represents hydrotreating, isomerization, lube oil,
asphalt blowing, and hydrogen.
'•'Model Unit B represents alkylation, thermal cracking, solvent
extraction, reforming, and vacuum distillation.
cModel Unit C represents crude distillation and fluid catalytic
cracking.
Components in gas/vapor service at process conditions.
6Light liquid is defined as a fluid with a vapor pressure greater
than 0.3 kPa at 20°C. This vapor pressure represents the split
between kerosene and naphtha.
fHeavy liquid is defined as a fluid with a vapor pressure less than
or equal to 0.3 kPa at 20°C. This vapor pressure represents
the split between kerosene and naphtha.
^Ratio: 7 open-ended lines to 1 pump seal. Reference 5.
6-3
-------
service at process conditions); (2) light liquid service (streams with
a vapor pressure greater than kerosene, greater than 0.3 kPa at 20°C);
and (3) heavy liquid service (streams with a vapor pressure equal to or
less than kerosene, or less than or equal to 0.3 kPa at 20°C). Pump
seals similarly distinguish between light and heavy liquid service.
6.3 REGULATORY ALTERNATIVES
This section presents six regulatory alternatives for controlling
fugitive VOC emissions from petroleum refineries. The alternatives
define feasible programs for achieving varying levels of emission
reduction. The first alternative represents a "status quo" of fugitive
emission control 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 6-2 summarizes the requirements of the regulatory
alternatives.
6.3.1 Regulatory Alternative I
Regulatory Alternative I reflects normal existing 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. While refineries in
some States may be subject to some fugitive VOC emission controls
through prevention of significant deterioration (PSD) regulations, SIP
regulations, and other permitting requirements, the existing levels of
control would not be expected to have a significant national impact.
An uncontrolled baseline has, therefore, been assumed for model process
units.
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 requirements
of this alternative are based upon the recommendations of the refinery
VOC leak control techniques guideline (CTG) document.0
The alternative specifically entails yearly monitoring for valves
in light liquid service and pump seals in light liquid service.
6-4
-------
Table 6-2. FUGITIVE VOC REGULATORY ALTERNATIVE
CONTROL SPECIFICATIONS
I
tn
Regulatory Alternatives
IIb III IV
Inspection Equipment Inspection Equipment Inspection
Source Interval Specification Interval Specification Interval
Valves
Gas/Vapor Quarterly None
Light Liquid Yearly None
Open-ended Lines
(purge, drain,
sample lines) None Cap
Sampl ing
Connections None None
Pump Seals
Light Liquid Yearly None
Relief Valves Quarterly None
Compressor Seals Quarterly None
Quarterly None Quarterly
Quarterly None Quarterly
None Cap None
None Closed- None
purge
sampl ing
Monthly0 None Nonec
None Rupture None
Disks
None Controlled None
Degasing
Vents
V
VI
Equipment Inspection Equipment Inspection Equipment
Specification Interval Specification Interval Specification
None Monthly
None Monthly
Cap None
Closed- None
purge
sampl ing
Dual Mechan- None
ical Seals
Controlled
Degassing
Vents
Rupture None
Disks
Controlled None
Degassing
Vents
None
None
Cap
Closed-
purge
sampl ing
Dual Mechan-
i r id
ical Seals
Control led
Degas sinq
Vents
Rupture
Disks
Controlled
Degassing
Vents
None Sealed Bellows
Valve
None Sealed Bellows
Valve
None Cap
None Closed-
purge
sampl ing
None Dual Mechang
ical Seals
Control led
Degassing
Vents
None Rupture
Disks
None Controlled
Degassing
Vents
Regulatory Alternative I (baseline) includes no new regulatory specifications and, hence, is not included in this table.
Alternative II is equivalent to controls recommended in the refinery CTG for fugitive VOC emissions.
cFor pumps, instrument monitoring would be supplemented with weekly visual inspections for liquid leakage. If liquid is noted to be leaking from
the pump seal, the pump seal will be repaired.
A pressure sensing device should be installed between the dual mechanical seals and should be monitored to detect seal failure.
eQuarterly monitoring and repair is not generally an effective control technique for all compressors. In some instances, compressor repair may
necessitate a process unit turnaround because compressors generally are not spared.
-------
Quarterly monitoring for leaks from valves, pressure relief devices,
and compressors in gas/vapor service is required. Pump seals would
additionally receive weekly visual inspection. Visual detection of a
leak would direct that monitoring be initiated. Subsequently, any leaks
found in excess of a predetermined VOC concentration would require repair.
Finally, caps would be installed on open-ended lines including purge,
drain, and sample lines.
6.3.3 Regulatory Alternative III
Regulatory Alternative III provides more restrictive emission
control than Regulatory Alternative II by increasing the frequency of
equipment inspections and by specifying additional equipment requirements.
By increasing the monitoring intervals, emissions are reduced from
residual leaking sources (i.e., those that are found leaking and are
repaired and recur before the next inspection, and those sources that
begin leaking between inspections). In Regulatory Alternative III,
the inspection interval for light liquid valves and light liquid pump
seals are increased to a quarterly and monthly basis, respectively.
Leak monitoring is replaced by installation of rupture disks for safety/
relief valves and by mechanical contact seals with controlled degassing
reservoirs for compressors. Closed purge sampling systems are also
required. Other requirements are the same as for Alternative II.
6.3.4 Regulatory Alternative IV
The incremental emission reduction offered in Regulatory
Alternative IV is achieved by installing dual mechanical seals with a
barrier fluid system and degassing reservoir vents on light liquid
pumps. Subsequently, monthly monitoring for pumps is no longer required.
Other controls remain as in Regulatory Alternative III.
6.3.5 Regulatory Alternative V
Regulatory Alternative V increases emission control by requiring
more frequent inspections on gas/vapor and light liquid valves. Valve
monitoring is required on a monthly basis. All other specifications
remain as in Regulatory Alternative IV.
6.3.6 Regulatory Alternative VI
Regulatory Alternative VI offers the highest level of emission
reduction of the regulatory alternatives. This regulatory alternative
controls fugitive VOC emissions through stringent equipment specifications,
6-6
-------
Alternative VI employs the equipment specifications required in
Alternative V with the addition of sealed bellows valves on gas/vapor
and light liquid service valves.
6-7
-------
6.4 REFERENCES
1. Wetherhold, R.G., C.P. Provost, and C.D. Smith. Assessment of
Atmospheric Emissions from Petroleum Refining. Volume 3. Appendix B,
EPA-600/2-80-075c. April 1980. Docket Reference Number II-A-19.*
2. Powell, et al. Development of Petroleum Refinery Plot Plans.
Pacific Environmental Services, Inc. EPA-450/3-78-025. June 1978.
Docket Reference Number II-A-7.*
3. Wetherhold, R.G., and D.D. Rosebrook. Assessment of Atmospheric
Emissions from Petroleum Refining. Volume 1. Technical Report.
EPA-600/2-80-075a. April 1980. Docket Reference Number II-A-17.*
4. The 1978 Refining Handbook Issue. Hydrocarbon Processing. 57(9):99.
September 1978. Docket Reference Number II-I-32.*
5. Control of Volatile Organic Compound Leaks from Petroleum Refinery
Equipment. EPA-450/2-78-036, OAQPS No. 1.2-111. June 1978.
Docket Reference Number II-A-6.*
*References can be located in Docket Number A-80-44 at the U.S.
Environmental Protection Agency Library, Waterside Mall, Washington, D.C.
6-8
-------
7.0 ENVIRONMENTAL IMPACTS
7.1 INTRODUCTION
This chapter discusses the environmental impacts of implementing
the regulatory alternatives presented in Chapter 6. The primary
emphasis is on the quantitative assessment of fugitive VOC emissions
that would result from implementation of each regulatory alternative.
The impacts of the regulatory alternatives on water quality, solid
waste, energy, and other environmental concerns are also addressed in
this chapter.
The environmental impacts presented in this chapter are based on
emission reductions calculated using the ABCD model discussed in
Section 4.2.3.4. An alternative approach used to estimate the environmental
impacts of each regulatory alternative (the LDAR model) is based on
leak occurrence/leak recurrence data and data on the effectiveness of
simple in-line repair. Environmental impacts based on LDAR model
results are presented in Tables F-14 through F-18.
7.2 VOC EMISSIONS IMPACT
7.2.1 Emission Source Characterization
As discussed in Chapter 6, the model units consist of several
types of process equipment (for example, valves and pumps) that comprise
the major fugitive VOC emission sources within petroleum refineries.
The emission factors presented in Table 3-1 are characteristic of
existing conditions in refineries. These emission factors represent
"uncontrolled" emissions and are used to estimate VOC emissions under
Regulatory Alternative I. Regulatory Alternative II represents emission
reductions achieved through the use of control technology and leak
detection/repair programs delineated in Control of Volatile Organic
Compound Leaks from Petroleum Refining Equipment (CTG). Regulatory
Alternatives III through VI represent progressive increments of the
7-1
-------
control technology and leak detection/repair programs discussed in
Chapter 4.0. A baseline emissions level is used to evaluate the
emission reduction potentials of Regulatory Alternatives II through VI
on affected model units nationwide. The baseline VOC emission levels
are calculated as the weighted average emissions of refineries operating
in National Ambient Air" Quality Standard (NAAQS) for ozone attainment
areas (no controls) and refineries operating in NAAQS for ozone nonattainment
areas (CTG controls).2
7.2.2 Development of VOC Emission Levels
In order to estimate the impacts of the regulatory alternatives
on fugitive VOC emission levels, emission factors for the model units
are determined for each regulatory alternative. Controlled VOC emission
factors are developed for those sources that would be subject to a
leak detection and repair program. Controlled VOC emission factors
are calculated by multiplying the uncontrolled emission factor for
each type of equipment by a set of correction factors (see Chapter 4).
The correction factors account for imperfect repair, noninstantaneous
repair, and the occurrence or recurrence of leaks between leak detection
inspections. Where the regulatory alternatives specify equipment to
be used, it is assumed that there are no emissions from the controlled
source. The resulting controlled VOC emission factors appear in
Table 7-1.
Table 7-2 presents fugitive VOC emissions by source type for each
model unit under Regulatory Alternatives I through VI; the percent of
total emissions attributable to each source type is also presented.
Table 7-3 compares annual VOC emissions from model units operating
under Regulatory Alternatives II through VI to emissions from model
units operating under Regulatory Alternative I. Average emission
reductions from Regulatory Alternative I (uncontrolled) levels for
model units operating under Regulatory Alternatives II through VI are
69, 78, 80, 83, and 93 percent, respectively.
7.2.3 Future Impact on Fugitive VOC Emissions
Future impacts of the regulatory alternatives on fugitive refinery
VOC emissions are estimated for the 5-year period, 1982 to 1986, as
shown in Table 7-4. Future impacts of the regulatory alternatives are
determined as the product of the number of affected model units projected
7-2
-------
Table 7-1. CONTROLLED VOC EMISSION FACTORS FOR VARIOUS
INSPECTION INTERVALS3
Source
type
Valves
Gas/vapor
Light
1 iquid
Pump Seals
Light
1 iquid
Rel ief valves
Gas/vapor
Compressor
Seals
Uncontrolled .
Inspection emission factor
interval (kg/day)
Quarterlyh>1 >J
llonthlyj
Annually*1
Quarterly1'1-1
Monthly^
Annually
Monthly1
Quarterly
h
Quarterly
0.64 0.
0.
0.26 0.
0.
0.
2.7 0.
0.
3.9 0.
15.0 0.
Correction
factors
Ac
98
98
86
86
86
92
92
74
91
Bd
0.90
0.95
0.80
0.90
0.95
0.80
0.95
0.90
0.90
C
0.
0.
0.
0.
0.
0.
0.
0.
0.
e
98
98
98
98
98
98
98
98
98
Df
1.0
1.0
0.96
0.96
0.96
0.94
0.94
0.98
0.98
Control
efficiency
(AxBxCxD)
0.
0.
0.
0.
0.
0.
0.
0.
0.
36
91
65
73
77
68
80
64
79
Control led
emission factor^
(kg/day)
0.
0.
0.
0.
0.
0.
0.
1.
3.
090
058
091
071
060
86
54
4
2
Values presented in this table are analogous to LDAR model values presented in Table F-14.
bFrom Table 3-1. Reference 1.
cTheoretical maximum control efficiency — From Table 4-2.
dLeak occurrence and recurrence correction factor — assumed to be 0.80 for yearly inspection, 0.90 for quarterly
inspection and 0.95 for monthly inspection.
eNoninstantaneous 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.
Imperfect repair correction factor— from Table 4-3, 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.
^Controlled emission factor uncontrolled emission factor x [l-(AxBxCxD)]
Required in Regulatory Alternative II.
'Required in Regulatory Alternative III.
^Required in Regulatory Alternative IV.
Required in Regulatory Alternative V.
7-3
-------
Table 7-2. VOC EMISSIONS FOR REGULATORY ALTERNATIVES*
I
Uncontrolled
emissions
Source type
Valves
gas/vapor
light liquid
heavy liquid
Open-Ended Lines
Sampling
connections
Pump Seals
light liquid
heavy liquid
Flanges
Relief Valves
gas/vapor
Compressor Seals
Total
(kg/day)
83
65
0.80
3.9
3.6
19
2.0
13
12
15
220
Percent
of
total
38
30
1
2
2
9
1
6
5
7
II
Controlled
emissions'"
(kg/day)
12
23
0.80
0
3.6
6.0
2.0
13
4.2
3.2
68
Percent
of
total
18
34
1
0
5
9
3
19
6
5
III
Controlled
emissions0
(kg/day)
12
18
0.80
0
0
3.8
2.0
13
0
0
50
Regulatory Alternatives
IV
Percent
of
total
24
36
2
0
0
8
4
26
0
0
Control 1 ed
emissions0
(kg/day)
12
18
0.80
0
0
0
2.0
13
0
0
46
Percent
of
total
26
39
2
0
0
0
4
28
0
0
V
Controlled
emissions0
(kg/day)
7.5
15
0.80
0
0
0
2.0
13
0
0
38
Percent
of
total
20
39
2
0
0
0
5
34
0
0
VI
Controlled
emissions
(kg/day)
0
0
0.80
0
0
0
2.0
13
0
0
16
Percent
of
total
0
0
5
0
0
0
13
82
0
0
aValues presented in this table are analogous to LDAR model values presented in Table F-15.
b
Uncontrolled emissions are obtained by multiplying the uncontrolled emission factors for each source (Table 3-1) by their respective model unit
component counts (Table 6-1).
""Controlled emissions for Regulatory Alternatives II through VI are obtained by multiplying the controlled emission factors for each source (Table 7-1)
by their respective model unit component counts (Table 6-1).
-------
Table 7-2. VOC EMISSIONS FOR REGULATORY ALTERNATIVES (Continued)'
r
cn
I
Uncontrolled
emissions
Source type
Valves
gas/vapor
1 ight liquid
heavy liquid
Open-Ended Lines
Sampl ing
connections
Pump Seals
light liquid
heavy liquid
Flanges
Relief Valves
gas/vapor
Compressor Seals
Total
(kg/day)
170
130
2
7
7.2
38
3
27
27
45
460
Percent
of
total
37
28
1
2
2
8
1
6
6
10
II
Controlled
emissions
(kg/day)
23
46
2
0
7.2
12
3
27
9.8
9.6
140
Percent
of
total
16
33
1
0
5
9
2
19
7
7
III
Controlled
emissions0
(kg/day)
23
35
2
0
0
7.6
3
27
0
0
98
Regulatory Alternatives
IV
Percent
of
total
23
36
2
0
0
8
3
28
0
0
Controlled
emissions0
(kg/day)
23
35
2
0
0
0
3
27
0
0
90
Percent
of
total
26
39
2
0
0
0
3
30
0
0
V
Controlled
emissions
(kg/day)
15
30
2
0
0
0
3
27
0
0
77
Percent
of
total
19
3d
3
0
0
0
4
35
0
0
VI
Controlled
emissions0
(kg/day)
0
0
2
0
0
0
3
27
0
0
32
Percent
of
total
0
0
6
0
0
0
9
84
0
0
Values presented in this table are analogous to LDAR model values presented in Table F-15.
Uncontrolled emissions are obtained by multiplying the uncontrolled emission factors for each source (Table 3-1) by their respective model unit
component counts (Table 6-1).
°Controlled emissions for Regulatory Alternatives II through VI are obtained by multiplying the controlled emission factors for each source (Table 7-1)
by their respective model unit component counts (Table 6-1).
-------
Table 7-2. VOC EMISSIONS FOR REGULATORY ALTERNATIVE (Concluded)'
I
Uncontrolled
emissions
Source type
Valves
gas/vapor
light 1 iquid
heavy liquid
Open-Ended Lines
Sampling
connections
Pump Seals
light liquid
heavy liquid
Flanges
Relief Valves
gas/vapor
Compressor Seals
Total
(kg/day)
500
390
4
20
22
110
10
77
78
120
1330
Percent
of
total
38
29
1
2
2
8
1
6
6
9
II
Controlled
emissions'"
(kg/day)
70
140
4
0
22
34
10
77
28
26
410
Percent
of
total
17
34
1
0
5
8
2
19
7
6
III
Controlled
emissions0
(kg/day)
70
105
4
0
0
22
10
77
0
0
290
Regulatory Alternatives
IV
Percent
of
total
24
36
1
0
0
8
3
27
0
0
Controlled
emissions0
(kg/day)
70
105
4
0
0
0
10
77
0
0
270
Percent
of
total
26
39
1
0
0
0
4
29
0
0
V
Controlled
emissions0
(kg/day)
45
90
4
0
0
0
10
77
0
0
250
Percent
of
total
18
36
2
0
0
0
4
31
0
0
VI
Control led
emissions0
(kg/day)
0
0
4
0
0
0
10
77
0
«. 0
91
Percent
of
total
0
0
4
0
0
0
11
85
0
0
aValues presented in this table are analogous to LDAR model values presented in Table F-15.
bUncontrolled emissions are obtained by multiplying the uncontrolled emission factors for each source (Table 3-1) by their respective model unit
component counts (Table 6-1).
""Controlled anissions for Regulatory Alternatives II through VI are obtained by multiplying the controlled emission factors for each source (Table 7-1)
by their respective model unit component counts (Table 6-1).
-------
Table 7-3. ANNUAL MODEL UNIT EMISSIONS AND AVERAGE PERCENT EMISSION
REDUCTION FROM REGULATORY ALTERNATIVE Ia
Regulatory
Alternative
Ic
II
III
IV
V
VI
Model unit emissions
(Mq/year)b
A
80
25
18
17
14
6
B
170
51
36
33
28
12
C
485
150
110
99
91
33
Average percent emission reduction
From Regulatory
Alternative I
—
69
78
80
83
93
Incremental
—
69
28
8
14
59
aValues presented in this table are analogous to LDAR model values presented in
Table F-16.
From Table 7-2. Based on 365 days per year.
Regulatory Alternative I represents "uncontrolled" emissions.
c
-------
Table 7-4. PROJECTED VOC FUGITIVE EMISSIONS FROM AFFECTED
MODEL UNITS FOR REGULATORY ALTERNATIVES FOR 1982-19863
co
Number of affected
model units
New
Units
Modified/
Reconstructed
Units
Year
1982
1983
1984
1985
1986
1982
1983
1984
1985
1986
A
9
19
29
39
49
9
18
27
37
47
B
5
10
15
21
27
15
31
47
67
79
C
4
9
14
19
24
11
22
33
44
56
r*
Total fugitive emissions projected under
regulatory alternative (Gg/yr)
I
3.5
7.6
11.7
15.9
20.1
8.6
17.4
26.1
35.7
44.3
Base-i
Lined
2.2
4.5
7.2
9.7
12.3
5.2
10.6
16.0
21.8
27.1
II
1.1
2.1
3.6
4.9
6.2
2.6
5.3
8.0
10.9
13.6
III
0.8
1.7
2.6
3.5
4.5
1.9
3.9
5.8
7.9
9.9
IV
0.7
1.5
2.4
3.2
4.1
1.7
3.5
5.3
7.2
9.0
V
0.6
1.4
2.1
2.9
3.6
1.5
3.1
4.7
6.4
8.0
VI
0.2
0.5
0.8
1.1
1.4
0.6
1.2
1.8
2.5
3.1
aValues presented in this table are analogous to LDAR model values presented in Table F-17.
The numbers of affected model units projected through 1986 are cumulative and distinguish between new unit construction
and modification/reconstruction. Units in existence prior to 1982 are otherwise excluded. A discussion of the growth
projections is in Appendix E.
cThe total fugitive emissions from Model Units A, B, and C are derived from the emissions per model unit 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 unit
times the emission per model unit.
The baseline emission level is the weighted sum of the emissions in Regulatory Alternatives I (uncontrolled) and II
(CTG controls) and is based on the proportion of refineries in nonattainment (169/302 = 56 percent) and attainment
(133/302 = 44 percent) areas (Reference 2).
-------
for each year (detailed in Appendix E) and the total quantity of
fugitive emissions per model unit estimated for each of the regulatory
alternatives (from Table 7-3).
Over the 5-year period, total fugitive VOC emissions for new
units under baseline conditions are projected to be 40.2 gigagrams;
baseline emissions from existing modified/reconstructed units may con-
tribute an additional 90.3 gigagrams of fugitive VOC. Implementation
of Regulatory Alternatives II through VI would reduce total new unit
emissions over the 5-year period to 17.9, 13.1, 11.9, 10.6, and 4.0 gigagrams,
respectively. For modified/reconstructed units, Regulatory Alternatives II
through VI are expected to reduce fugitive VOC emissions for the
5-year period to 40.4, 29.4, 26.7, 23.7, and 9.2 gigagrams, respectively.
Over the 5-year period, percent emission reductions from the baseline
level for new and modified/ reconstructed units under Regulatory
Alternatives II through VI are 55, 67, 70, 74, and 90 percent, respectively.
7.3. WATER QUALITY IMPACT
Although fugitive VOC emissions from refinery equipment primarily
impact air quality, they also adversely impact water quality. In par-
ticular, leaking components handling liquid hydrocarbon streams increase
the waste load entering wastewater treatment systems. Leaks from
equipment contribute to the waste load by entering process unit drains
via run-off. Implementation of Regulatory Alternatives II through VI
would reduce the waste load on wastewater treatment systems by preventing
leak-age from process equipment from entering the wastewater system.
7.4 SOLID WASTE IMPACT
Solid wastes that are generated by the petroleum refining industry
and that are associated with the regulatory alternatives include
replaced mechanical seals, seal packing, rupture disks, and valves.
Sources of solid waste not related to the regulatory alternatives
include separator and tank sludges, filter cakes, treating clays, and
slop oil.
Implementation of Regulatory Alternatives II through VI would
increase solid waste quantities whenever equipment specifications
require the replacement of existing equipment. For example, dual
mechanical seals would replace packed and single mechanical seals
under Alternatives IV, V, and VI.
7-9
-------
Implementation of Alternatives II through VI would not have a
significant impact beyond baseline solid waste levels. Solid waste
impacts of the regulatory alternatives can be minimized by recycling
metal solid wastes (for example, mechanical seals, rupture disks,
caps, plugs, and valve parts). Further, most refinery solid waste is
unrelated to the regulatory alternatives.
7.5 ENERGY IMPACTS
The regulatory alternatives would require a minimal increase in
energy consumption because of the operation of monitoring instruments,
the operation of degassing vents, the use of closed loop sampling, and
the operation of combustion devices. However, implementation of
Regulatory Alternatives II through VI would result in a net positive
energy impact, as energy savings from the "recovered" VOC emissions
far outweigh the energy requirements of the alternatives.
The average energy value of the "recovered" emissions is estimated
at 49 terajoules per gigagram.3 Assuming that all of the emission
reduction achieved by the regulatory alternatives is recovered as
usable energy, the energy savings over a 5-year period from new units
is estimated to be from 1,090 terajoules (Regulatory Alternative II)
to 1,770 terajoules (Regulatory Alternative VI). Energy savings by
modified/ reconstructed units operating under Regulatory Alternatives II
through VI represent an additional 2,450 to 3,970 terajoules, respectively.
Energy impacts of each regulatory alternative are presented in Table
7-5; energy savings in crude oil equivalents are also presented.
7.6 OTHER ENVIRONMENTAL CONCERNS
7.6.1 Irreversible and Irretrievable Commitment of Resources
Implementation of the regulatory alternatives is not expected to
result in any irreversible or irretrievable commitment of resources.
Rather, implementation of Alternatives II through VI would save resources
because of energy savings associated with reductions in fugitive VOC
emissions. As previously noted, the generation of solid waste used in
the control equipment would not be significant.
7.6.2 Environmental Impact of Delayed Regulatory Action
As discussed in the above sections, implementation of the regulatory.
alternatives would not significantly impact water quality or solid
7-10
-------
TABLE 7-5. PROJECTED ENERGY IMPACTS OF REGULATORY ALTERNATIVES FOR 1982-1986°
M_. .
Units
Modified/
Reconstructed
Units
Regulatory
Alternative
II
III
IV
V
VI
II
III
IV
V
VI
Five-year
total reduction from
baseline (Gg)
18.0
22.8
24.0
25.3
31.9
40.3
51.3
54.0
57.0
71.5
Energy value
of emission reduction
(tera joules)0
882
1,120
1,180
1,240
1,560
1,970
2,510
2,650
2,790
3,500
Crude oil equ
ivalent
of emission reduction
/ -, n3 3x d
(10 m )
23
29
31
32
41
51
65
69
72
91
Values presented in this table are analogous to LDAR model values presented in Table F-18.
Estimated total fugitive VOC emission reduction from Model Units A, B, and C, from Table 7-4.
cBased on 49 TJ/Gg, these values represent energy credits (Reference 4).
dBased on 38.5 TJ/Mm3 (6.12 x 109 J/bbl) crude oil. Reference 5.
-------
waste generation. However, a delay in regulatory action would adversely
impact air quality at the rates shown in Table 7-4. The energy loss
associated with delayed regulatory action represents less than 1 percent
of annual crude oil imports for the industry."
7-12
-------
7.7 REFERENCES
1. Hustvedt, K.C., R.A. Quaney, and W.G. Kelly. Control of Volatile
Organic Compound Leaks from Petroleum Refining Equipment. EPA-450/
2-78-036. June 1978. Docket Reference Number II-A-6.*
2. Carruthers, J.E. and J.L. McClure, Jr. Overview Survey of Status
of Refineries in the U.S. with RACT Requirements (Draft Report).
Prepared for U.S. Environmental Protection Agency. Division of
Stationary Source Enforcement. Washington, DC. October, 1979.
p. A-2. Docket Reference Number II-A-30.*
3. Wetherold, R.G., C.P. Provost, and C.D. Smith. Assessment of
Atmospheric Emissions from Petroleum Refining. Volume 3, Appendix B.
Prepared for U.S. Environmental Protection Agency, EPA-600/2-80-075c.
April 1980. Docket Reference Number II-A-19.*
4. Perry, R.H. and C.H. Chilton. Chemical Engineer's Handbook.
Fifth Edition. McGraw-Hill Book Company. New York. 1973.
Docket Reference Number II-I-15.*
5. Petroleum Facts and Figures. American Petroleum Institute.
Washington, D.C. 1971. Docket Reference Number II-I-ll.*
6. Industry Surveys -- Oil. Standard and Poor's. August 7, 1980.
(Section 2). p. 74. Docket Reference Number II-I-50.*
*References can be located in Docket Number A-80-44 at the U.S. Environmental
Protection Agency Library, Waterside Mill, Washington, D.C.
7-13
-------
8.0 COST ANALYSIS
8.1 COST ANALYSIS OF REGULATORY ALTERNATIVES
8.1.1 Introduction
The following sections present estimates of the captial costs,
annualized costs, and cost-effectiveness for each model unit and
regulatory alternative discussed in Chapter 6.0. These estimates are
used to ascertain the economic impact of the regulatory alternatives
upon the petroleum refining industry in Chapter 9.0. To ensure a
common cost basis, Chemical Engineering cost indices are used to
adjust control equipment to May 1980 dollars.
Annualized cost impacts and cost effectiveness values presented
in this chapter are calculated using the ABCD model discussed in
Section 4.2.3.4. An alternative approach used to estimate the annualized
cost impact and cost effectiveness of each regulatory alternative (the
LDAR model) is based on leak occurrence/leak recurrence data and data
on the effectiveness of simple in-line repair. Cost impacts based on
LDAR model results are presented in Tables F-12 through F-23.
8.1.2 New Facilities
8.1.2.1 Capital Costs. The bases for the capital costs of
monitoring instruments and control equipment are presented in Table 8-1.
These data are used to tabulate the capital costs for each model unit
under the regulatory alternatives as given in Table 8-2. The capital
cost figures used may be conservative. For example, one degassing
system is assumed to serve every two dual mechanical pump seals; in
normal practice, several pump seals may be tied to a single barrier
fluid degassing reservoir. Further, the cost for the rupture disk
system includes extra fittings (for example, tee and elbow,) and the
cost of sealed bellows valves is for a 5.1 cm control valve, which
costs considerably more than smaller bellows valves. Engineering
8-1
-------
TABLE 8-1. INSTALLED CAPITAL COST DATA
(May 1980 Dollars)
Item
Installed
Capital Cost
Cost Basis
Reference
1. Monitoring
Instrument
Caps for
Open-Ended
Lines
Dual Mech-
anical Seals
6.
Barrier
Fluid System
for Dual
Mechanical
Seals
Pump Seal
Barrier
Fluid
Degassing
Reservoir
Vent
Compressor
Degassing
Reservoir
Vents
$9,200/Model Unit
$53 (new or
retrofit)
$1,260 (new)
$1,592 (Retrofit)
$1,850 (new or
retrofit)
$4,000/pump seal
(new or retrofit)
$8,000/compressor
seal (new or
retrofit)
Cost is for two instruments, 1
$4,600 each. Assumes one
instrument is used as a
spare.
Based on the cost of «i 2, 3, 4
2.5 cm screwed valve.
Cost (1967) = $12. Cost
index = 329.0/113. Installa-
tion = 1 hour at $18/hr.
Seal cost = $1,250. Seal 3, 4, 5, 6
credit (last quarter 1978) =
$225. Cost index = 328.9/266.6.
Installation = 16 hours at $18/hr.
Seal cost = $1,250. Field instal-
lation = 19 hours at $18/hr.
Pressurized Reservoir system 3, 4, 7
cost (January 1979) = $700.
System cooler cost (January
1979) = 800. Cost index =
328.9/266.6.
Based on installation of a 122 m 4, 5, 7
length of 5.1 cm diameter sche-
dule 40 carbon steel pipe at a
cost of $6,400, plus three 5.1 cm
cast steel plug valves and one
metal gauge flame arrestor at a
cost of $1,600. These costs in-
clude connection of the degassing
reservoir to an existing enclosed
combustion device or vapor recovery
header. Cost of a control device
added specifically to control the
degassing vents is, therefore, not
included. It is assumed that two
pump seals are connected to a single
degassing vent.
The costs have the same basis as 4, 5, 7
pump seals with a single compres-
sor seal connected to a vent.
5-2
-------
TABLE 8-1. INSTALLED CAPITAL COST DATA (Cont.)
(May 1980 Dollars)
Item
Installed
Capital Cost
Cost Basis
Reference
7.1
Rupture
Disk System
With Block
Valve
$2,000/Relief
Valve (new)
$3,636/Relief
Valve (retrofit)
7.2 Rupture Disk
System With
3-way Valve
$4,100/Relief
Valve (new)
$4,800/Relief
Valve (retrofit)
Cost of rupture disk assembly:
one 7.6 cm rupture disk stain-
less = $230; one 7.6 cm rupture
disk holder, carbon steel = $384;
one 0.6 cm pressure gauge, dial
face = $18; one 0.6 cm bleed valve,
carbon steel, gate = $30; and instal-
lation = 16 hrs at $18/hr. To allow
in-service disk replacement, a block
valve is assumed to be installed up-
stream of the rupture disk. Cost
for one 7.6 cm gate valve = $700.
Installation = 10 hrs at $18/hr.
To prevent damage to the relief
valve by disk fragments, an offset
mounting is required. Cost for one
10.2 cm tee and one 10.2 cm elbow =
$21. Installation = 8 hrs. at
$18/hr.
Costs for the rupture disk, holder,
and block valve are the same as
for the new applications. An addi-
tional cost is added to replace the
derated relief valve. No credit is
assumed for the used relief valve.
Cost for one 7.6 cm pressure relief
valve, stainless steel body and
trim = $1,456. Installation =
10 hrs. at $18/hr.
Costs for rupture disk assembly
are the same as for new rupture
disk system (above), except
replace block valve with one 3-way
valve (7.6 cm, 2-port) = $1320.
Additional cost for one 7.6 cm
pressure relief valve, stainless =
$1456; Cost for two 7.6 an elbows =
$30. Total installation =
36 hrs. at $18/hr.
Costs for rupture disk assembly
and 3-way valve costs are the
same as for new applications
except total installation =
72 hrs at $18/hr.
3, 4, 5
5-3
-------
Table 8-1. INSTALLED CAPITAL COSTS DATA (Concluded)
(May 1980 Dollars)
Item
Instal led
Capital Cost
Cost Basis
Reference
8.
9.
Closed-loop
Sampling
Connections
Sealed
Bellows
Valves
$530 (new or
retrofit)
$2,730 (new or
retrofit)
Based on 6 m length of 2.5 cm diam-
eter schedule 40, carbon steel
pipe and three 2.5 cm carbon steel
ball valves. Installation = 18 hrs.
at $18/hr.
Cost for 5.1 cm sealed bellows 4, 9
control valve.
Lines larger than 2.5 cm may be controlled by installing blind flanges at similar
cost.
DThe compressor seal area could be vented directly to a control device at similar cost,
"Engineering codes will allow a single relief valve protected by rupture disk with
block valve upstream. Some refineries may opt to install a parallel relief/valve
and rupture disk system at nearly double the cost.
8-4
-------
TABLE 8-2. INSTALLED CAPITAL COST ESTIMATES
FOR NEW MODEL UNITS
(Thousands of May 1980 Dollars)
Capital Cost Item
Regulatory Alternative
II III IV V VI
Model Unit A
1. Monitoring Instrument 9.2 9.2 9.2 9.2 9.2
2. Caps for Open-Ended
Lines 3.7 3.7 3.7 3.7 3.7
3. Dual Mechanical Seals
• Seals 6.8 6.8 6.8
• Installation 2.0 2.0 2.0
4. Barrier Fluid System for
Dual Mechanical Seals 13 13 13
5. Pump Seal Barrier
Fluid Degassing
Reservoir 28 28 28
6. Compressor Degassing
Reservoir Vents 8888
7.
8.
9.
Rupture Disk System
• Disks
• Assembly and Instal-
lation
Closed-loop Sampling
Connections
Sealed Bellows Valves
0.69
8.5
5.3
0.69
8.5
5.3
0.69
8.5
5.3
0.69
8.5
5.3
1000
Total 13 35 85 85 1100
8-5
-------
TABLE 8-2. INSTALLED CAPITAL COST ESTIMATES
FOR NEW MODEL UNITS (Continued)
(Thousands of May 1980 Dollars)
Regulatory Alternative
Capital Cost Item II
III IV
V
VI
Model Unit B
1.
2.
3.
4.
5.
6.
7.
8.
9.
Monitoring Instrument 9.2
Caos for Open-Ended
Lines 7.4
Dual Mechanical Seals
• Seals
• Installation
Barrier Fluid System for
Dual Mechanical Seals
Pump Seal Barrier
Fluid Degassing
Reservoir
Compressor Degassing
Reservoir Vents
Rupture Disk System
• Disks
» Assembly and Instal-
lation
Closed-loop Sampling
Connections
Sealed Bellows Valves
Total 17
9.2 9.2
7.4 7.4
14
4.0
26
56
24 24
1.6 1.6
20 20
11 11
73 168
9.2
7.4
14
4.0
26
56
24
1.6
20
11
168
9.2
7.4
14
4.0
26
56
24
1.6
20
11
2100
2300
8-6
-------
TABLE 8-2. INSTALLED CAPITAL COST ESTIMATES
FOR NEW MODEL UNITS (Concluded)
(Thousands of May 1980 Dollars)
Regulatory Alternative
Capital Cost Item II
III IV
V
VI
Model Unit C
1.
2.
3.
4.
5.
6.
7.
8.
9.
Monitoring Instrument 9.2
Caps for Open-Ended
Lines 22
Dual Mechanical Seals
• Seals
• Installation
Barrier Fluid System for
Dual Mechanical Seals
Pump Seal Barrier
Fluid Degassing
Reservoir
Compressor Degassing
Reservoir Vents
Rupture Disk System
• Disks
t Assembly and Instal-
lation
Closed-loop Sampling
Connections
Sealed Bellows Valves
Total 31
9.2 9.2
22 22
39
12
74
160
64 64
4.6 4.6
56 56
32 32
190 470
9.2
22
39
12
74
160
64
4.6
56
32
470
9.2
22
39
12
74
160
64
4.6
56
32
6200
6600
5-7
-------
judgment indicates that refineries may use either block valves or
3-way valves to isolate ruptured discs from streams during disc replace-
ment. When block valves are used, the process stream does not have a
pressure relief valve outlet during periods when the pressure relief
device is isolated for in-service replacement of the rupture discs.
When 3-way valves are employed, the process stream is routed around
the ruptured disc assembly to a pressure relief valve. To account for
the use of block valves and 3-way valves in this cost analysis, it is
assumed that 50 percent of the affected refineries employ block valves
and the remainder use 3-way valves.
Regulatory Alternative I requires no additional controls and
therefore, incurs no capital costs. Under Regulatory Alternatives II
through VI, caps for open-ended lines and two monitoring instruments
would be purchased. Although only one instrument is required, the
cost of a second instrument is included, as it is assumed that refiners
will use the second monitor in the event the first monitor becomes
inoperable. There are no other capital costs associated with Alter-
native II. Regulatory Alternatives III, IV, V, and VI bear the added
costs of controlled degassing reservoir vents for compressors, rupture
disk system using block valves or 3-way valves, and closed-loop sampling
connections. Regulatory Alternatives IV and V bear similar capital
costs. In addition to the capital costs projected in Alternative III,
Regulatory Alternatives IV and V incur the cost of dual mechanical
seals, barrier fluid systems, and pump seal barrier fluid degassing
reservoirs. Further, Regulatory Alternative VI capital costs include
the costs of sealed bellows valves for valves in light liquid and
gas/vapor service.
8.1.2.2 Annual Costs. Implementation of Regulatory Alternatives II
through V would require visual and/or instrument monitoring of potential
VOC emissions. The monitoring requirements are given in Table 6-2.
Table 6-2 also shows that Regulatory Alternative VI requires equipment
specifications rather than detection and repair of leaks from existing
equipment. Table 8-3 summarizes the leak detection and repair labor
requirements; Table 8-4 presents annual labor costs of leak detection
and repair by model unit type for Regulatory Alternatives II through IV.
8-8
-------
Table 8-3. MONITORING AND MAINTENANCE LABOR-HOUR REQUIREMENTS'
co
i
Id
Components
Per
Model Unit
Source Type ABC
Valves
Gas/Vapor 130 260 780
light liquid 250 500 1500
Pump Seals
1 ight liquid 7 14 40
Relief Valves
Gas/Vapor 3 7 20
Compressor Seals
Gas/Vapor 138
LEAK DETECTION
Monitoring
Type of
Monitoring
Instrument
Instrument
Instrument
Instrument
Instrument
Instrument
Instrument
Visual
Instrument
Instrument
Times Labor-Hours
Monitored Requiredc'a
Per Year A
4h,i.j 17
12k 52
lh 8.3
4llJ 33
12k 100
lh 1.2
121 14
52n,i,j,k,l 3
4h 3.2
4h 1
B
35
104
17
67
200
2.3
28
6.1
7.5
2
C
104
312
50
200
600
6.7
80
17
21.3
5.3
LEAK REPAIR
Estimated
Percent of Number o.f
Sources Leaks
Leaking" ABC
10 6 11 32
8 16 47
11 6 11 33
11 22 66
17 33 99
24 112
1 2 6
7 000
35 111
Maintenance
Labor-Hours^
ABC
7 12 36
9 18 53
7 12 37
12 25 75
19 37 112
so an 160
80 160 480
000
40 40 40
NOTES:
aValues presented in this table are analogous to LDAR model values presented in Table F-19.
Assumes that instrument monitoring requires a two-person team and visual monitoring one person.
cMonitoring time per person: pumps-instrument 5 min., visual 1/2 min.; compressors 5 min.; valves 1 min., and safety/relief valves 8 min.
Reference 10.
Monitoring labor-hours = number of workers x number of components x time to monitor x times monitored per year.
riReference 11.
Annual percent recurrence factors have been applied for monthly, quarterly, and annual instrument inspections. It is assumed that
5 percent of leaks initially detected are found with monthly monitoring (0.05 x 12 = 0.6), that 10 percent of leaks initially de-
tected are found with quarterly monitoring (0.1 x 4 = 0.4), and that 20 percent of leaks initially detected are found by annual monitoring
(0.2 x 1 - 0.2). Number of leaks = Number of Components x % Sources Leaking x Annual % Recurrence Factor.
9Leak Repair = Number of Leaks x Repair Time. Labor-Hours': Repair time per component: pumps - 80 hrs., compressors - 40 hrs.,
valves - 1.13 hrs. (Basis: weighted average on 75 percent of the leaks repaired on-line requiring 10 minutes per repair, and on 25 percent of
the leaks repaired off-line requiring 4 hrs. per repair. Reference 12), safety relief valves - 0 hrs. (It is assumed that these leaks are
corrected by routine maintenance at no additional labor requirement). Reference 10.
Required in Regulatory Alternative II.
Required in Regulatory Alternative III.
JRequired in Regulatory Alternative IV.
Required in Regulatory Alternative V.
Required in Regulatory Alternative VI.
-------
TABLE 8-4. LEAK DETECTION AND REPAIR COSTSa'b
(May 1980 Dollars)
Regulatory ,
Alternatives
II
III
IV
V
Leak Detection Cost
Model Units
A
610
1,200
1,000
2,800
B
1,300
2,500
1,900
5,600
C
4,500
7,200
5,800
17,000
Repair Cost
Model Units
A
2,400
1,800
340
500
B
2,600
3,500
670
990
C
4,900
11,000
2,000
3,000
aValues presented in this table are analogous to LDAR model values presented
in Table F-20.
bCost = Hours (From Table 8-3) x $18.00 per hour.
cRegulatory Alternatives I and VI have zero costs.
8 -10
-------
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 is assumed to be $18.00 per hour.
Administrative and support costs are 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 Annualized Costs. The bases for deriving the annual ized
control costs are presented in Table 8-5. The annualized capital,
maintenance, and miscellaneous costs are calculated by taking the
appropriate factor from Table 8-5 and multiplying it by the corresponding
capital cost from Table 8-2. The capital recovery factors (CRF) are
calculated using the equation:
CRF=
(1 + i)n -1
where i = interest rate, expressed as a decimal,
n = economic life of the component, years.
The interest rate used is 10 percent. The expected life of the
monitoring instrument is six years. Dual mechanical seals and rupture
disks are assumed to have a nominal 2-year life. All other control
equipment is assumed to have a nominal 10-year life.
Implementation of Regulatory Alternative II, III, IV, or V results
in an initial discovery of leaking components. The repair labor-hour
requirements of the initial survey are derived by multiplying the
percentage of sources leaking and the repair time per source by the
model unit component counts as shown in Table 8-6. Fractions are
rounded up to the next integer, since in practice it is the whole
valve or seal that is replaced, not just part of one unit. The cost
of repairing initial leaks is amortized over a 10-year period, since
it is a one-time cost. Administrative and support costs to implement
the regulatory alternatives are assumed to be 40 percent of the leak
detection and repair labor costs. The initial leak repair costs
presented in Table 8-7 show Alternative II to incur the highest costs.
Costs for the other alternatives decrease as equipment specifications
replace labor intensive equipment repairs.
8-11
-------
TABLE 8-5. DERIVATION OF ANNUALIZED LABOR,
ADMINISTRATIVE, MAINTENANCE, AND CAPITAL COSTS
3.
Capital Recovery factor for Capital Costs
• Dual mechanical seals and rupture disks
0 Other control equipment
e Monitoring instruments
Annual Maintenance Costs
t Control equipment
0 Monitoring instruments
Annual Miscellaneous Costs
4. Labor Costs
5. Administrative and Support Costs
to Implement Regulatory Alternative
6. Annualized Charge for Initial Leak
Repairs
0.58 x Capital
0.163 x Capital1
0.23 x Capital0
0.05 x Capital
$3,000e
0.04 x Capitalf
$18/hr9
0.40 x (Monitoring
Labor ± Maintenance
Labor)"
(estimated number of
leaking components per
model unit1 x repair
time) x $18/hr x 1.4 x 0.163J
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.
Ten year life, ten percent interest. Reference 7.
cSix year life, ten percent interest. Reference 7.
Reference 7.
elncludes materials and labor for maintenance and calibration.
Reference 3.
9Includes wages plus 40 percent for labor-related administrative and overhead
costs.
L
Reference 7.
1 Shown in Table 8-3.
JInitial leak repair amortized for ten years at ten percent interest.
8-12
-------
Table 8-6. LABOR-HOUR REQUIREMENTS FOR INITIAL LEAK REPAIR
00
I
Source Type
Valves H f
Gas/Vaporc>d'ef .
light liquidc'a'e>T
Pump Seals .
light liquidc'a
Safety/Relief Valves
Gas/Vapor
Compressor Seals
Gas/Vapor
Number
Per
A
130
250
7
3
1
of Components
Model
B
260
500
14
7
3
Unit
C
780
1,500
40
20
8
Percent of
Sources
Leaking 1n
Initial Survey3
10
11
24
7
35
A
13
28
2
1
1
Estimated
Number of Leaks
B C
26 78
55 165
3 10
1 2
1 3
Repair Time.
Per Source
(hours)
1.13
1.13
80
09
40
Repair
A
15
32
160
0
40
Labor- Hours
B
29
62
240
0
40
C
88
186
800
0
120
Based on the number of sources leaking at ^10,000 ppm from Table 4-3. Reference 11.
bFrom Table 8-3.
cRequired in Regulatory Alternative II.
Required 1n Regulatory Alternative III.
eRequired in Regulatory Alternative IV.
Required in Regulatory Alternative V.
^Because of safety requirements, it is assumed that leaks are corrected by routine maintenance and therefore require no additional
labor. Reference 10.
-------
TABLE 8-7. INITIAL LEAK REPAIR COSTS
(Thousands of May 1980 Dollars)
Regulatory fl
Alternative
II
III
IV
V
Initial Repair Costs
For Model Unitsb
A
4.4
3.7
0.8
0.8
B C
6.7 21
6.0 19
1.1 4.9
1.1 4.9
Initial Annual ized Repair
Costs For Model Units0
A
1.00
0.84
0.18
0.18
B
1.53
1.37
0.25
0.25
C
4.79
4.34
1.12
1.12
Regulatory Alternatives I and VI have zero costs.
From Table 8-5, Labor-Hour Requirements for Initial Leak Repair.
Cost = hours x $18.00 per hour.
r*
"Initial annual ized repair costs for model units = Initial repair cost x capital
recovery factor x 1.4. The capital recovery factor (CRF) for model units is
determined through the equation:
CRF .
(l+i)-l, where n = 10 years and i = 10 percent.
Therefore, the CRF =0.163.
8-14
-------
8.1.2.4 Recovery Credits. VOC emission reductions achieved
under each regulatory alternative are expected to be realized as
additional marketable product or as additional refinery process heat.
The additional product or process heat is referred to as recovery
credits. Regulatory Alternative I represents uncontrolled emissions
and therefore has no recovery credits. The dollar value of recovery
credits achieved under the baseline and Regulatory Alternatives II
through VI is based on the May 1980 retail price for LPG and regular
13 14
gasoline. ' Assuming that the recovered VOC comprises a nominal
60:40 LPG-to-gasoline ratio, the dollar value of the recovered VOC is
estimated to be $215 per Mg. Annual VOC emissions, total emission
reductions achieved, and dollar values for product recovered annually
are presented for each model unit and regulatory alternative in Table 8-8.
8.1.2.5 Net Annualized Costs. The net annualized costs for new
affected facilities, shown in Tables 8-9 through 8-11, are determined
by subtracting the annual recovered product credit from the total cost
before credit. For example, Model Unit A under Regulatory Alternative II
has a net annualized cost of $100, representing $12,000 in costs and
$11,900 in recovery credits.
8.1.2.6 Cost Effectiveness. The cost effectiveness of the
regulatory alternatives for each new affected model unit is shown in
Table 8-12. Regulatory Alternatives II, III, IV, and V entail relatively
low costs per megagram (Mg) of VOC emission reduction. Model Unit B
Regulatory Alternative II and Model Unit C Regulatory Alternatives II
and III have net annualized credits. Regulatory Alternative VI proves
significantly less cost-effective with ratios for all new model units
above $3,000/Mg VOC. The high cost effectiveness ratio of Regulatory
Alternative VI results from the high cost of installing sealed bellows
valves.
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 costs for Alternatives I and II are the same as for new
model units. The costs for retrofitting monitoring instruments, caps
for open-ended lines, barrier fluid systems and fluid degassing reservoir
8-15
-------
Table 8-8. RECOVERY CREDITS9
Regulatory
Alternative
I
II
III
IV
V
VI
VOC
Emissions
Mg/yr
80
25
18
17
14
6
Model Unit A
Emission
Reduction
from
Regulatory
Alternative I
Mg/yr
__
55
62
63
66
74
Recovered
Product
Value
$/yr
— -
11,900
13,400
13,600
14,200
15,900
VOC
Emissions
Mg/yr
170
51
36
33
28
12
Model Unit B
Emission
Reduction
from
Regulatory
Alternative I
Mg/yr
__,
119
134
137
142
158
Recovered
Product
Value
$/yr
__
25,600
28,800
29,500
30,600
34,000
VOC
Emissions
Mg/yr
485
150
110
99
91
33
Model Unit C
Emission
Reduction
from
Regul atory
Alternative I
Mg/yr
__
335
375
386
394
452
Recovered
Product
Value
$/yr
_.
72,000
80,600
83,000
84,700
97,200
CO
I
Values presented in this table are analogous to LDAR model values .presented in Table F-21.
This value is obtained by multiplying the emission reduction from Regulatory Alternative I (recovery credit) in Mg per year by $215 per Mg
(May 1980 value of 60:40 LPG to Gasoline Price Ratio). References 13, 14.
-------
Table 8-9. ANNUALIZED CONTROL COST ESTIMATES FOR NEW
FACILITIES FOR MODEL UNIT Aa
(Thousands of May 1980 Dollars)
Regulatory Alternatives
Cost Item II
Annual ized Capital Costs
A. Control Equipment
1. Monitoring Instrument 2.1
2. Caps for Open-Ended Lines 0.60
3. Dual Mechanical Seals
o Seal s
o Installation
4. Barrier Fluid System for
Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk System
o Disks
o Assembly and Installation
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
B. Initial Leak Repair 1.0
Operating Costs
A. Maintenance Charges
1. Monitoring Instrument 3.0
2. Caps for Open-Ended Lines 0.19
3. Dual Mechanical Seals
4. Barrier Fluid System
for Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir Vents
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk Systems
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
B. Miscellaneous Charges (taxes,
insurance, administration)
1. Monitoring Instrument 0.37
2. Caps for Open-Ended Lines 0.15
3. Dual Mechanical Seals
4. Barrier Fluid System for
Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk System
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
C. Labor Charges
1. Monitoring Labor 0.61
2. Leak Repair Labor 2.4
3. Administrative and Support 1.2
Total Before Credit 12
Recovery Credits (11.9)
Net Annual ized Cost 0.1
III
2.1
0.60
1.3
0.40
1.4
0.86
0.84
3.0
0.19
0.40
0.46
0.27
0.37
0.15
0.32
0.37
0.21
1.2
1.8
1.2
17
(13.4)
3.6
IV
2.1
0.60
3.9
0.33
2.1
4.6
1.3
0.40
1.4
0.86
0.18
3.0
0.19
0.44
0.65
1.4
0.40
0.46
0.27
0.37
0.15
0.35
0.52
1.1
0.32
0.37
0.21
1.0
0.34
0.54
30
(13.6)
16.4
V
2.1
0.60
3.9
0.33
2.1
4.6
1.3
0.40
1.4
0.86
0.18
3.0
0.19
0.44
0.65
1.4
0.40
0.46
0.27
0.37
0.15
0.35
0.52
1.1
0.32
0.37
0.21
2.8
0.5
1.3
33
(14.2)
18.8
VI
2.1
0.60
3.9
0.33
2.1
4.6
1.3
0.40
1.4
0.86
169
3.0
0.19
0.44
0.65
1.4
0.40
0.46
0.27
52
0.37
0.15
0.35
0.52
1.1
0.32
0.37
0.21
42
0.0
0.0
0.0
291
(16)
275
aValues presented in this table are analogous to LDAR model values presented in
Table F-22.
bFrom Tables 6-1 and 8-1. 8-17
-------
Table 8-10. ANNUALIZED CONTROL COST ESTIMATES FOR NEW
FACILITIES FOR MODEL UNIT Bd
(Thousands of May 1980 Dollars)
Regulatory Alternatives
Cost Item II
Annual ized Capital Costs
A. Control Equipment
1. Monitoring Instrument 2.1
2. Caps for Open-Ended Lines 1.2
3. Dual Mechanical Seals
o Seal s
o Installation
4. Barrier Fluid System for
Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk System
o Disks
o Assembly and Installation
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
B. Initial Leak Repair 1.5
Operating Costs
A. Maintenance Charges
1. Monitoring Instrument 3.0
2. Caps for Open-Ended Lines 0.37
3. Dual Mechanical Seals
4. Barrier Fluid System
for Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir Vents
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk Systems
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
B. Miscellaneous Charges (taxes,
insurance, administration)
1. Monitoring Instrument 0.37
2. Caps for Open-Ended Lines 0.30
3. Dual Mechanical Seals
4. Barrier Fluid System for
Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir Vents
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk System
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
C. Labor Charges
1. Monitoring Labor 1.3
2. Leak Repair Labor 2.6
3. Administrative and Support 1.6
Total Before Credit 14
Recovery Credits (25.6)
Net Annual ized Cost (11.6)
Ill
2.1
1.2
3.9
0.93
3.3
1.7
1.4
3.0
0.37
1.2
1.1
0.53
0.37
0.30
0.96
0.86
0.42
2.5
3.5
1.8
30
(28.8)
1.2
IV
2.1
1.2
7.9
0.65
4.2
9.1
3.9
0.93
3.3
1.7
.25
3.0
0.37
0.88
1.3
2.8
1.2
1.1
0.53
0.37
0.30
0.70
1.0
2.2
0.96
0.86
0.42
1.9
0.67
1.0
57
(29.5)
27.5
V
2.1
1.2
7.9
0.65
4.2
9.1
3.9
0.93
3.3
1.7
.25
3.0
0.37
0.88
1.3
2.8
1.2
1.1
0.53
0.37
0.30
0.70
1.0
2.2
0.96
0.86
0.42
5.6
0.99
2.6
62
(30.6)
31.4
VI
2.1
1.2
7.9
0.65
4.2
9.1
3.9
0.93
3.3
1.7
338
3.0
0.37
0.88
1.3
2.8
1.2
1.1
0.53
100
0.37
0.30
0.70
1.0
2.2
0.96
0.86
0.42
83
0.0
0.0
0.0
570
(34)
536
a , , , .
Table F-23.
aFrom Tables 6-1 and 8-1.
8-18
-------
Table 8-11. ANNUALIZED CONTROL COST ESTIMATES FOR NEW FACILITIES
FOR MODEL UNIT Ca
(Thousands of May 1980 Dollars)
Regulatory Alternatives
Cost Item II
Annual ized Capital Costs
A. Control Equipment
1. Monitoring Instrument 2.1
2. Caps for Open-Ended Lines 3.6
3. Dual Mechanical Seals
o Seal s
o Installation
4. Barrier Fluid System for
Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk System
o Disks
o Assembly and Installation
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
B. Initial Leak Repair 4.8
Operating Costs
A. Maintenance Charges
1. Monitoring Instrument 3.0
2. Caps for Open-Ended Lines 1.1
3. Dual Mechanical Seals
4. Barrier Fluid System
for Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir Vents
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk Systems
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
B. Miscellaneous Charges (taxes,
insurance, administration)
1. Monitoring Instrument 0.37
2. Caps for Open-Ended Lines 0.89
3. Dual Mechanical Seals
4. Barrier Fluid System for
Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir Vents
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk System
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
C. Labor Charges
1. Monitoring Labor 4.5
2. Leak Repair Labor 4.9
3. Administrative and Support 3.8
Total Before Credit 29
Recovery Credits (72.0)
Net Annual ized Cost (43)
III
2.1
3.6
10
2.7
9.1
5.2
4.3
3.0
1.1
3.2
3.0
1.6
0.37
0.89
2.6
2.4
1.3
7.2
11.0
4.8
73
(30.6)
(7.6)
IV
2.1
3.6
23
1.9
12
26
10
2.7
9.1
5.2
1.1
3.0
1.1
2.5
3.7
8.0
3.2
3.0
1.6
0.37
0.89
2.0
2.9
6.4
2.6
2.4
1.3
5.8
2.0
3.1
152
(83.0)
69
V
2.1
3.6
23
1.9
12
26
10
2.7
9.1
5.2
1.1
3.0
1.1
2.5
3.7
8.0
3.2
3.0
1.6
0.37
0.89
2.0
2.9
6.4
2.6
2.4
1.3
17.0
3.0
8.0
170
(84.7)
85
VI
2.1
3.6
23
1.9
12
26
10
2.7
9.1
5.2
1,000
3.0
1.1
2.5
3.7
8.0
3.2
3.0
1.6
310
0.37
0.89
2.0
2.9
6.4
2.6
2.4
1.3
250
0.0
0.0
0.0
1,700
(97)
1,600
aValues presented in this table are analogous to LDAR model values presented in
Table F-24.
bFrom Tables 6-1 and 8-1.
8-19
-------
Table 8-12. COST EFFECTIVENESS FOR MODEL UNITS FOR NEW
FACILITIES3
(May 1980 Dollars)
Regulatory Alternative
Model Unit A
Total Capital
Cost ($1,000)
Total Annual ized
Cost ($1,000)
Net Annual ized
Cost ($1,000)
Total VOC
Reduction (Mg/yr)
Cost Effectiveness
($/Mg VOC)
Model Unit B
Total Capital
Cost ($1,000)
Total Annual ized
Cost ($1,000)
Net Annual ized
Cost ($1,000)
Total VOC
Reduction (Mg/yr)
Cost Effectiveness
($/Mg VOC)
Model Unit C
Total Capital
Cost ($1,000)
Total Annual ized
Cost ($1,000)
Net Annual ized
Cost ($1,000)
Total VOC
Reduction (Mg/yr)
Cost Effectiveness
($/Mg VOC)
II
13
12
0.1
55
2
17
14
(12)b
119
(100)b
31
29
(43)b
335
(130)b
III
35
17
3.6
62
58
73
30
1.2
134
9
190
73
(7.6)b
375
(20)b
IV
85
30
16
63
250
168
57
28
137
200
470
152
69
386
180
V
85
33
19
66
290
168
62
31
142
220
470
170
85
394
210
VI
1,100
291
275
74
3,800
2,300
570
540
158
3,400
6,600
1,700
1,600
452
3,500
aValues presented in this table are analogous to LDAR model values presented in
bTable F-25.
Parentheses denote a net credit.
8-20
-------
for dual mechanical seals, compressor degassing reservoir vents,
closed-loop sampling systems, and sealed bellows valves are the same
as costs for new model units. The cost of replacing single mechanical
seals with dual mechanical seals is estimated at $1,592; this cost
includes 19 labor-hours of installation at $18 per labor hour. Rupture
disks for relief valves are estimated to cost from $3,636 to $4,800 per
retrofitted relief valve, depending on whether a block valve or 3-way
valve is used; the additional costs result from the extra labor-hours
expected to be needed to replace a derated relief valve. The total
capital cost estimates for modified/reconstructed facilities are
presented in Table 8-13.
8.1.3.2 Annualized Costs. The annualized control costs for
modified/reconstructed units are derived from the same basis as new
units (see Table 8-5). Net annualized costs for modified/reconstructed
facilities operating under Regulatory Alternatives I and II are the
same as net annualized costs for new facilities. The net annualized
costs for modified/reconstructed facilities are higher than for new
facilities under Regulatory Alternatives III through VI; higher annualized
costs are the result of higher capital costs for rupture disks and
dual mechanical seals. The recovery credits for modified/reconstructed
facilities are the same as for new units. Annualized control cost
estimates for modified/reconstructed facilities operating under Regulatory
Alternative III through VI are presented in Tables 8-14 through 8-16.
8.1.3.3 Cost-Effectiveness. The cost-effectiveness of modified/
reconstructed facilities operating under the regulatory alternatives
is similar to that of new facilities. Like new facilities, modified/
reconstructed facilities operating under Regulatory Alternative VI
have cost-effectiveness values exceeding $3,000 per Mg of VOC removed.
The cost-effectiveness values for reconstructed/modified facilities
which are operating under Regulatory Alternatives III through VI are
shown in Tables 8-14 through 8-16.
8.1.4 Projected Cost Impacts
The projected fifth-year nationwide costs of implementing Regulatory
Alternatives II through VI are compared to the fifth-year nationwide
costs of Regulatory Alternative I in Table 8-17. The projected fifth-year
nationwide costs of implementing Regulatory Alternatives II through VI
8-21
-------
00
IX)
ro
Table 8-13. INSTALLED CAPITAL COST ESTIMATES FOR MODIFIED/RECONSTRUCTED FACILITIES
(Thousands of May 1980 Dollars)
\ Model Unit A
Capital Cost Item \ Regulatory h
\Alternatives III IV and V VI
1.
2.
3.
4.
5.
6.
7.
8.
9.
Monitoring Instrument
Caps for Open-Ended
Lines
Dual Mechanical Seals
t Seal s
« Installation
Barrier Fluid System for
Dual Mechanical Seals
Pump Seal Barrier
Fluid Degassing
Reservoir
Compressor Degassing
Reservoir Vents
Rupture Disk System
• Disks
• Assembly and Instal-
lation
Closed-loop Sampling
Connections
Sealed Bellows Valves
Total
9.2 9.2
3.7 3.7
8.8
2.4
13
28
8 8
0.7 0.7
12 12
5.3
34 91
9.2
3.7
8.8
2.4
13
28
8
0.7
12
5.3
1000
1100
Model Unit B
III IV and V VI
9.2 9.2
7.4 7.4
18
4.8
26
56
24 24
1.6 1.6
28 28
11
70 180
9.2
7.4
18
4.8
26
56
24
1.6
28
11
2100
2300
Model Unit C
III IV and V VI
9.2 9.2
22 22
50
14
74
160
64 64
4.6 4.6
80 80
32 32
210 510
9.2
22
50
14
74
160
64
4.6
80
32
6200
6700
From Tables 6-1 and 8-1
SFor Regulatory Alternatives I and II the capital costs for modified/reconstructed facilities are the same as for new units
(Table 8-2).
-------
Table 8-14. ANNUALIZED CONTROL COST ESTIMATES
MODIFIED/RECONSTRUCTED
FACILITIES FOR MODEL UNIT A3
(Thousands of May 1980 Dollars)
FOR
Regulatory Alternatives
Cost Item
Annual ized Capital Costsc
A. Control Equipment
1. Monitoring Instrument
2. Caps for Open-Ended Lines
3. Dual Mechanical Seals
o Seal s
o Installation
4. Barrier Fluid System for
Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk System
o Disks
o Assembly and Installation
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
B. Initial Leak Repair
Operating Costs
A. Maintenance Charges
1. Monitoring Instrument
2. Caps for Open-Ended Lines
3. Dual Mechanical Seals
4. Barrier Fluid System
for Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir Vents
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk Systems
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
B. Miscellaneous Charges (taxes,
insurance, administration)
1. Monitoring Instrument
2. Caps for Open-Ended Lines
3. Dual Mechanical Seals
4. Barrier Fluid System for
Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk System
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
C. Labor Charges
1. Monitoring Labor
2. Leak Repair Labor
3. Administrative and Support
Total Before Credit
Recovery Credits
Net Annual ized Cost
Total VOC Reduction (Mg/yr)
Cost Effectiveness ($/Mg)
III
2.1
0.60
1.3
0.4
2.0
0.86
0.84
3.0
0.19
0.40
0.64
0.27
0.37
0.15
0.32
0.51
0.21
1.2
1.8
1.2
18
(13.4)
4.6
62
74
IV
2.1
0.60
5.1
0.39
2.1
4.6
1.3
0.4
2.0
0.86
0.18
3.0
0.19
0.56
0.65
1.4
0.40
0.64
0.27
0.37
0.15
0.44
0.52
1.1
0.32
0.51
0.21
1.0
0.34
0.54
32
(13.6)
18.4
63
290
V
2.1
0.60
5.1
0.39
2.1
4.6
1.3
0.4
2.0
0.86
0.18
3.0
0.19
0.56
0.65
1.4
0.40
0.64
0.27
0.37
0.15
0.44
0.52
1.1
0.32
0.51
0.21
2.8
0.5
1.3
34
(14.2)
19.8
66
300
YI
2.1
0.60
5.1
0.39
2.1
4.6
1.3
0.4
2.0
0.86
169
3.0
0.19
0.56
0.65
1.4
0.40
0.64
0.27
52
0.37
0.15
0.44
0.52
1.1
0.32
0.51
0.21
42
0.0
0.0
0.0
300
(16)
284
74
3,800
aValues presented in this table are analogous to LDAR model values presented in
Table F-26.
bFor Regulatory Alternatives I and II the annualized costs for modified/
reconstructed facilities are the same as for new units (Table 8-9).
cFrom Tables 6-1 and 8-1.
8-23
-------
Table 8-15. ANNUALIZED CONTROL COST ESTIMATES FOR
MODIFIED/RECONSTRUCTED FACILITIES FOR MODEL UNIT B'
(Thousands of May 1980 Dollars)
Regulatory Alternatives0
Cost Item
Annual ized Capital Costs
A. Control Equipment
1. Monitoring Instrument
2. Caps for Open-Ended Lines
3. Dual Mechanical Seals
o Seals
o Installation
4. Barrier Fluid System for
Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk System
o Disks
o Assembly and Installation
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
B. Initial Leak Repair
Operating Costs
A. Maintenance Charges
1. Monitoring Instrument
2. Caps for Open-Ended Lines
3. Dual Mechanical Seals
4. Barrier Fluid System
for Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir Vents
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk Systems
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
B. Miscellaneous Charges (taxes,
insurance, administration)
1. Monitoring Instrument
2. Caps for Open-Ended Lines
3. Dual Mechanical Seals
4. Barrier Fluid System for
Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir Vents
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk System
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
C. Labor Charges
1. Monitoring Labor
2. Leak Repair Labor
3. Administrative and Support
Total Before Credit
Recovery Credits
Net Annual ized Cost
Total VOC Reduction (Mg/yr)
Cost Effectiveness ($/Mg)
III
2.1
1.2
3.9
0.9
4.6
1.7
1.4
3.0
0.37
1.2
1.5
0.53
0.37
0.30
0.96
1.2
0.45
2.5
3.5
1.8
34
(28.8)
5.2
134
39
IV
2.1
1.2
10
0.78
4.2
9.1
3.9
0.9
4.6
1.7
0.25
3.0
0.37
1.1
1.3
2.8
1.2
1.5
0.53
0.37
0.30
0.91
1.0
2.2
0.96
1.2
0.45
1.9
0.67
1.0
61
(29.5)
31.5
137
230
V
2. 1
1.2
10
0.78
4.2
9.1
3.9
0.9
4.6
1.7
0.25
3.0
0.37
1.1
1.3
2.8
1.2
1.5
0.53
0.37
0.30
0.91
1.0
2.2
0.96
1.2
0.45
5.6
0.99
2.6
67
(30.6)
36.4
142
260
VI
2. 1
1.2
10
0.78
4.2
9.1
3.9
0.9
4.6
1.7
338
3.0
0.37
1.1
1.3
2.8
1.2
1.5
0.53
100
0.37
0.30
0.91
1.0
2.2
0.96
1.2
0.45
83
0.0
0.0
0.0
580
(34)
546
158
3,400
Values presented in this table are analogous to LDAR model values presented in
Table F-27.
For Regulatory Alternatives I and II the annualized costs for modified/
reconstructed facilities are the same as for new units (Table 8-10).
CFrom Tables 6-1 and 8-1.
8-24
-------
Table 8-16. ANNUALIZED CONTROL COSTS ESTIMATES FOE
MODIFIED/RECONSTRUCTED FACILITIES FOR MODEL UNIT Cc
(Thousands of May 1980 Dollars
Regulatory Alternatives
Cost Item
Annual ized Capital Costs
A. Control Equipment
1. Monitoring Instrument
'i. Caps for Open-Ended Lines
3. Dual Mechanical Seals
o Seals
o Installation
4. Barrier Fluid System for
Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk System
o Disks
o Assembly and Installation
3. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
3. Initial Leak Repair
Operating Costs
A. Maintenance Charges
1. Monitoring Instrument
2. Caps for Open-Ended Lines
3. Dual Mechanical Seals
4. Barrier Fluid System
for Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir Vents
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk Systems
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
B. Miscellaneous Charges (taxes,
insurance, administration)
1. Monitoring Instrument
2. Caps for Open-Ended Lines
3. Dual Mechanical Seals
4. Barrier Fluid System for
Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir Vents
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk System
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
C. Labor Charges
1. Monitoring Labor
2. Leak Repair Labor
3. Administrative and Support
Total Before Credit
Recovery Credits
Net Annual ized Cost
Total VOC Reduction (Mg/yr)
Cost Effectiveness ($Mg)
III
2.1
3.6
10
2.7
13
5.2
4.3
3.0
1.1
3.2
4.2
1.6
0.37
0.89
2.6
3.4
1.3
7.2
11.0
4.8
86
(80.6)
5.4
375
14
IV
2.1
3.6
29
2.3
12.0
26
10
2.7
13
5.2
1.1
3.0
l.l
3.2
3.7
8.0
3.2
4.2
1.6
0.37
0.89
2.6
2.9
6.4
2.6
3.4
1.3
5.8
2.0
3.1
161
(83.0)
73
386
200
V
2.1
3.6
29
2.3
12.0
26
10
2.7
13
5.2
1.1
3.0
1.1
3.2
3.7
8.0
3.2
4.2
1.6
0.37
0.89
2.6
2.9
6.4
2.6
3.4
1.3
17.0
3.0
3.0
181
(84.7)
96.3
394
240
VI
2.1
3.6
29
2.3
12.0
26
10
2.7
13
5.2
1,000
3.0
1.1
3.2
3.7
8.0
3.2
4.2
1.6
310
0.37
0.89
2.6
2.9
6.4
2.6
3.4
1.3
250
0.0
0.0
0.0
1,700
(97)
1,600
452
3,500
aValues presented in this table are analogous to LDAR model values presented in
Table F-28.
bFor Regulatory Alternatives I and II the annual ized costs for modified/
reconstructed facilities are the same as for new units (Table 8-11).
LFrom Tables 6-1 and 8-1.
8-25
-------
TABLE 8-17. FIFTH-YEAR NATIONWIDE COSTS
OF THE REGULATORY ALTERNATIVES ,
ABOVE REGULATORY ALTERNATIVE I COSTS3'0
(Thousands of May 1980 Dollars)
Regulatory Alternatives
Cost Item0 II III IV V VI
New Units
Total Capital Costd
Total Annual ized Cost6
Total Recovery Credit
Net Annual ized Cost
ModifiedyReconstructed Units
Total Capital Costd
Total Annual ized Cost6
Total Recovery Credit
Net Annual ized Cost
1,800
1,660
3,000
(1,340)
3,700
3,290
6,610
(3,320)
8,200
3,400
3,370
30
19,000
8,350
7,420
930
20,000
6,660
3,450
3,210
47,000
15,300
7,600
7,700
20,000
7,180
3,550
3,630
47,000
17,000
7,800
9,200
274,000
70,000
4,000
66,000
610,000
155,000
8,900
146,100
aValues presented in this table are analogous to LDAR model values presented in
Table F-29.
Regulatory Alternative I assumes that no control costs are incurred; therefore,
costs for Regulatory Alternatives II through VI are compared to zero.
d
°Parentheses denote savings.
Total cumulative capital costs in 1986.
6Annualized costs for model units subject to each regulatory alternative in the
fifth year are calculated by multiplying cost estimates for each model unit
under each regulatory alternative by the number of affected model units (from
Table 7-4).
8-26
-------
are compared to the fifth-year nationwide baseline costs in Table 8-18.
The cost estimates are obtained by multiplying the costs per model
unit by the model unit growth estimates for 1981 to 1986, which are
given in Table 7-4. The cost impacts for new units and modified/
reconstructed units are reported separately in order to differentiate
between expected impacts represented by new units, and maximum impacts
represented by the combination of new unit and modified/reconstructed
unit impacts. Thus, maximum impacts would result if all changes to
existing units constitute modification/reconstruction. The total
capital costs reflect the accumulative costs of implementing the
regulatory alternatives through 1986. All other costs shown are for
units subject to the regulatory alternatives in the fifth year.
8.2 OTHER COST CONSIDERATIONS
8.2.1 General Regulatory Considerations
Environmental, safety, and health statutes that may cause an
outlay of funds by the petroleum refining inudstry are listed in
Table 8-19. Specific costs to the industry to comply with the pro-
visions, requirements, and regulations of the statutes are unavailable.
Few refineries are expected to close solely due to the cost of
compliance with the total regulatory burden, although some may accelerate
closings prompted by changing crude supplies and product demand.15
The costs incurred by the petroleum refining industry to comply with
all health, safety, and environmental regulations are not expected to
prevent compliance with the regulatory alternatives for refinery
fugitive emissions.
8.2.2 New Source and Hazardous Pollutant Standards
As noted above, a review of the total cost of all government
regulations affecting petroleum refineries is not feasible. One
reason is that the necessary data do not exist; it would require a
substantial investment of resources to estimate all of the component
costs. Another reason is that there is no generally accepted accounting
procedure that permits translation of widely diverse cost impacts into
dollars and aggregation of those dollars into a meaningful total.
These limitations are less restrictive if the focus is narrowed
to encompass only air pollution standards EPA is considering for
8-27
-------
TABLE 8-18. FIFTH-YEAR NATIONWIDE COSTS FOR h
THE PETROLEUM REFINING INDUSTRY ABOVE BASELINE COSTSd'D
(Thousands of May 1980 Dollars)
Regulatory Alternative
Cost Item0 II III IV V VI
New Units
Total Capital Costd
Total Annual ized Cost6
Total Recovery Credit
Net Annual ized Cost
Modified/Reconstructed Units
Total Capital Cost
Total Annual ized Cost
Total Recovery Credit
Net Annual ized Cost
790
730
1,320
(590)
1,630
1,450
2,910
(1,460)
7,190
2,470
1,690
780
16,900
6,510
3,710
2,800
19,000
5,730
1,770
3,960
44,900
13,500
3,900
9,600
19,000
6,250
1,870
4,380
44,900
15,200
4,100
11,100
273,000
67,200
2,320
64,900
607,000
153,000
5,200
148,000
aValues presented in this table are analogous to LDAR model values presented in
Table F-30.
Baseline costs are calculated from baseline emission levels. As discussed in
Chapter 7, the baseline VOC emission level represents a weighted average of
emissions from refineries operating in National Ambient Air Quality Standard
(NAAQS) for ozone attainment areas (no control) and refineries operating in
NAAQS for ozone non-attainment areas (CTG controls). Approximately 44 percent
of existing refineries are expected to be operating in ozone attainment areas,
and 56 percent are expected to be operating in ozone non-attainment areas.
°Parentheses denote savings.
Total cumulative capital cost above baseline cost in 1986 = total cumulative
capital cost in 1986 for each regulatory alternative - total cumulative capital
cost in 1986 for baseline (for example, at new units: 0.56 x $1,800 = $1,008).
g
Total annualized cost above baseline cost = total annualized cost for each
regulatory alternative - annualized cost for baseline (for example, at new
units: 0.56 x $1,660= $930).
Total recovery credit above baseline credit = total recovery credit for each
regulatory alternative - total baseline recovery credit (for example, at new
units: 0.56 x $3,000 = $1,680).
8-28
-------
TABLE 8-19. STATUTES THAT MAY BE APPLICABLE TO THE PETROLEUM REFINING INDUSTRY
Statute
Applicable provision, regulation or
requirement of statute
Statute
Applicable provision, regulation or
requirement of statute
Clean A1r Act and Amendments • State implementation plans
• National emission standards for
hazardous air pollutant
Benzene fugitive emissions
• New source performance standards
FCCU unit partlculate matter
FCC unit carbon monoxide
Petroleum storage vessels VOC
Claus sulfur recovery plants
• PSD construction permits
• Non-attainment construction permits
Clean Water Act (Federal
Water Pollution Control Act)
CO
i
ro
• Discharge permits
• Effluent limitations guidelines
• New source performance standards
• Control of oil spills and discharges
• Pretreatment requirements
• Monitoring and reporting
• Permitting of Industrial projects
that impinge on wetlands or
public waters
• Environmental impact statements
Toxic Substances Control
Act
Occupational Safety & Health
Act
Coastal Zone Management Act
• Premanufacture notification
• Labeling, recordkeeping
• Reporting requirements
• Toxicity testing
• Walking-working surface standards
• Means of egress standards
• Occupational health and environ-
mental control standards
• Hazardous material standards
• Personal protective equipment
standards
• General environmental control
standards
• Medical and fist aid standards
• Fire protection standards
• Compressed gas and compressed
air equipment standards
• Welding, brazing, and cutting
standards
• States may veto federal permits
for plants to be sited in
coastal zone
Resource Conservation and
Recovery Act
• Permits for treatment, storage, and
disposal of hazardous wastes
• Manifest System to track
hazardous wastes
• Recordkeeping, reporting,
labeling, and monitoring
system for hazardous
wastes
State Environmental Policy
Acts
Safe Drinking Water Act
Marine Sanctuary Act
Comprehensive Environmental
Response, Compensation, and
Liability Act
Superfund
Require environmental impact
statements
Requires underground injection
control permits
• Ocean dumping permits
• Recordkeeping and reporting
-------
refineries. Since the Clean Air Amendments of August 1977, EPA has
initiated development or revision of numerous new source and hazardous
pollutant standards under Sections 111 and 112 of the Clean Air Act.
Ten of these actions may result in the imposition of costs on newly
constructed, modified, and reconstructed refinery units. These costs
are reviewed and cumulated below. The total is conservative because
worst case assumptions are used and, except for some product recovery
credits, no regulatory benefits are used to offset any of the costs.
The results are summarized in Table 8-20, and indicate that the total
regulatory cost burden of new source and hazardous pollutant standards
does not exceed reasonable bounds. The 10 actions are:
• VOC Fugitive Emissions in the Petroleum Refining Industry -
NSPS
* ^x Emissions from Fluid Catalyst Cracking Unit Regenerators -
NSPS
• Benzene Fugitive Emissions - NESHAP
Benzene Emissions from Benzene Storage Tanks - NESHAP
Bulk Gasoline Terminals - NSPS
Asphalt Roofing Industry - NSPS
Petroleum Liquid Storage Vessels - NSPS
Volatile Organic Liquid Storage Tanks - NSPS
VOC Fugitive Emissions - NSPS
• VOC Emissions from Distillation Process Vents in the SOCMI - NSPS.
The costs of the first nine of these potential standards have
been considered in this analysis. The last standard listed above has
not been included in this analysis because detailed cost estimates are
not yet available.
The method used to estimate the effect that each standard will
have upon refining costs has three basic steps:
• The collection of fifth-year annualized cost estimates for
each standard,
• The adjustment of such costs to a common year's dollars, and
• The determination of the portion of each standard's costs
that can be expected to affect petroleum refineries.
8-30
-------
Table 8-20. SUMMARY OF FIFTH-YEAR ANNUALIZED COSTS BY STANDARD
Standard
Fifth-Year
Annual ized
Costs
(Current $)
Fifth-Year
Annual ized
Costs
(May 1980 $)
Refinery Cost
Factor Contribution
VOC Fugitive Emissions
in the Petroleum Re-
fining Industry NSPS
SO Emissions from Fluid
Catalytic Cracking Unit
Regenerators NSPS
Benzene Fugitive Emis-
sions NESHAP
Benzene Emissions from
Benzene Storage Tanks
NESHAP
$15,300,000 $15,300,000
May 1980
$73,700,000 $70,604,600
November 1980
$ 2,700,000 $ 2,949,915
May 1979
$ 1,844,521 $ 2,237,488
February 1979
1.000 $15,300,000
1.000 $70,604,600
0.239
0.344
$ 705,030
$ 769,696
Bulk Gasoline Terminals
NSPS
Asphalt Roofing Industry
NSPS
Petroleum Liquid Storage
Vessels NSPS
Volatile Organic Liquid
Storage Tanks NSPS
VOC Fugitive Emissions
NSPS
$ 4,300,000
July 1979
$ 90,000
November 1978
($ 5,790,000)a
February 1980
$11,000,000
May 1980
TOTAL
$ 4,644,000
$ 103,538
($ 5,967,763)a
$12,654,651
0.206
0.200
1.000
0.200
0.297
$
$
($ 1.
$ 3,
$91,
956,664
20,708
192.553)3
758,431
291,176
aParentheses denote savings.
NOTE: These costs have been carried out to the last dollar so that their
derivation will be clear; however, the numbers are only, at best, very
rough estimates. The fifth-year refers to the fifth-year after
implementation of each standard, and does not refer to any one calendar
year. Costs are costs to society, less than half of which will be
borne by refineries, their owners, customers, and suppliers. See page
8-30.
8-31
-------
The method used to estimate the total cost of NSPS and NESHAP
standards to the petroleum refining industry relies heavily upon the
estimated "fifth-year costs" of each standard. Fifth-year or "nationwide"
costs are estimated for all NSPS and NESHAP standards for two reasons.
First, because more sources will become subject to a standard as time
passes, due to the construction of new and modification/reconstruction
of existing sources, annualized costs to the industry will increase as
the focus shifts further into the future. Second, because all NSPS
and NESHAP standards are reviewed on a five-year basis, to reexamine
the need for the effects of regulation, it is not certain that any
standard will remain unchanged after 5 years. It should be noted that
because fifth-year annualized costs are determined before taxes, they
represent total costs to society.
In the adjustment of costs to May 1980 dollars, the Chemical
Engineering Plant Cost Index is used.
Several of the standards listed above affect other industries in
addition to petroleum refining, such as the Synthetic Organic Chemicals
Manufacturing Industry (SOCMI). Thus, an attempt has been made to
identify, for each standard, the portion of the annualized costs that
can be reasonably attributed to the refining industry. This has been
accomplished through the definition of "refinery factors" for each
standard.
The determination of estimated cumulative annualized costs for
the petroleum refining industry is described below and summarized in1
Table 8-20.
8.2.2.1 VOC Fugitive Emissions in the Petroleum Refining Industry
NSPS. The estimated environmental and economic impacts of this standard
are summarized in this document, and the estimated costs of this
standard are presented in the various tables of this section. If
Regulatory Alternative IV is proposed, the fifth-year annualized costs
of this alternative are estimated to be $15,300,000 (May 1980).
Because of costs summarized in this report are expressed in terms
of May 1980 dollars, no cost adjustment is required.
Because all of the costs noted above will be incurred by petroleum
refineries, the refinery factor is 1.000 and the cost contribution of
this standard is $15,300,000.
8-32
-------
8.2.2.2 SO Emissions from Fluid Catalytic Cracking (FCC) Unit
A
Regenerators NSPS. This NSPS would limit SOV emissions from FCC unit
- ' — ™~~1--1 ,11 ^
regenerators and has not yet been proposed. Data pertaining to the
costs of this standard have been obtained from Section 9.3 of a draft
background information document (BID) prepared for this potential
standard.
The project team has noted the probable recommendation of Regulatory
Alternative III, which would entail fifth-year annualized costs of
$73,700,000 (November 1980).
Costs of this standard have been adjusted by the CE Plant Cost
Index where May 1980 = 258.5 and November 1980 = 269.7. Fifth-year
annualized costs in May 1980 dollars are therefore $70,604,600.
Finally, because all costs related to this standard will affect
petroleum refineries, the refinery factor is 1.000 and thus the cost
contribution of this standard is $70,604,600.
8.2.2.3 Benzene Fugitive Emissions NESHAP. This NESHAP, which
addresses fugitive benzene emissions from petroleum refinery and SOCMI
sources, was proposed on 1/5/81 in Federal Register 46, page 1165.
Cost data related to this standard are contained in Benzene Fugitive
Emissions - Background Information for Proposed Standards, Draft EIS,
EPA-430/3-80-032a, November 1980.
Regulatory Alternative III for both new and existing sources has
been proposed and fifth-year costs of $2,700,000 (May 1979) have been
estimated.
The costs of this standard have been expressed in terms of May
1980 dollars through the CE Plant Cost Index, which notes that May
1980 = 258.5 and May 1979 = 236.6. Fifth-year annual ized costs in May
1980 dollars are therefore estimated to be $2,949,915.
Because this standard affects SOCMI as well as petroleum refinery
sources, an attempt has been made to "distribute" total costs among
both general types of sources, so that only those costs expected to
affect petroleum refineries are considered. This distribution has
been accomplished by determining the refinery factor as described
below. First, there are 241 units affected by the standard and these
units are represented by three model units: A (145 units); B (72 units);
8-33
-------
and C (24 units). Furthermore, only 20 of the model A units and 49 of
the model B units are found at refineries, while no model C units are
located at refineries. Thus, 13.8 percent of model A units and 68 percent
of model B units are refinery units. Second, the control costs for
each model unit vary with model unit type. Using the sum of costs to
control one each of model units A, B, and C as a base, unit A represents
26.0 percent, unit B accounts for 29.8 percent, and unit C represents
44.2 percent of that base. Therefore, because:
(.138 x .260) = (.680 x .298) = .239,
23.9 percent of the fifth-year annualized costs have been assumed to
affect petroleum refineries.
Because the fifth-year annual ized costs of this standard are
$2,949,915 and the refinery factor is .239, $705,030 of the costs have
been assigned to refineries.
8.2.2.4 Benzene Emissions from Benzene Storage Tanks NESHAP.
This NESHAP would limit benzene emissions from benzene storage facilities,
regardless of their location. The standard was proposed on 12/19/80
in Federal Register 45, page 83952, and cost information pertinent to
the proposed standard is summarized in Benzene Emissions from Benzene
Storage Tanks - Background Information for Proposed Standards, Draft
EIS, EPA-450/3-80-034a, December 1980.
As noted in the Federal Register, Regulatory Alternative III is
proposed for new sources while Regulatory Alternative IV is proposed
for existing sources. The fifth-year annualized costs of these
alternatives are estimated to be $1,844,521 (February 1979).^
The costs of this standard have been adjusted to May 1980 through
the CE Plant Cost Index, which notes that May 1980 = 258.5 and February 1979
= 213.1. Fifth-year annualized costs in May 1980 dollars therefore
estimated to be $2,237,488.
Only a portion of these costs will affect petroleum refineries
because benzene can be stored at either the production sites, the
consumption site, or at bulk terminals. Also, benzene is produced by
chemical companies as well as petroleum refineries. With regard to
storage sites, it is estimated18 that of all facilities that store
benzene, 43 percent are benzene producers, 54 percent are benzene
8-34
-------
consumers, and 3 percent are bulk storage terminals. Concerning type
of producer, about 80 percent of all benzene produced is done so by
petroleum refineries.19 For these reasons, 34.4 percent (i.e., .43 x
.80) of the costs have been assigned to petroleum refineries.
Because the fifth-year annual ized costs of this standard are
$2,237,488 and the refinery factor is .344, $769,696 of the costs have
been assigned to petroleum refineries.
8.2.2.5 Bulk Gasoline Terminals NSPS. This NSPS affects VOC
emissions from bulk gasoline truck loading terminals, and was proposed
on 12/17/80 by Federal Register 45, page 83126. Cost data related to
this standard have been obtained from the Federal Register noted above
and Bulk Gasoline Terminals - Background Information for Proposed
Standards. Draft EIS, EPA-450/3-80-038a, December 1980.
The proposed standard is in the form of Regulatory Alternative IV
and would limit VOC emissions to 35 mg of VOC per liter of gasoline
loaded. The fifth-year annualized costs of this standard are estimated
to be $4,300,000 (July 1979).20
Adjusting costs to May 1980 dollars, where the CE Plant Cost
Index notes May 1980 = 258.5 and July 1979 = 239.3, gives fifth-year
annualized costs of $4,644,000.
While the BID referenced above does not specify the number of
bulk gasoline terminals located at refineries, it does indicate that a
?1
total of 1,511 bulk terminals exist. Making the assumption that
each of the 311 refineries operating in the United States has one bulk
terminal gives an estimate of 20.6 percent of all terminals are located
at refineries.
Because the fifth-year annualized costs of this standard are
$4,644,000, and the refinery factor is .206, $956,644 of those costs
have been assigned to petroleum refineries.
8.2.2.6 Asphalt Roofing Manufacturing Industry NSPS. This NSPS
addresses emissions of particulates from asphalt roofing manufacturing
activities. One of these activities, specifically the asphalt blowing
still, is in some cases found at petroleum refineries. This NSPS was
proposed on 11/18/80 by Federal Register 45, page 76404. Cost data
pertaining to this standard have been obtained from the Federal Register
8-35
-------
noted above as well as from Asphalt Roofing Manufacturing Industry -
Background Information for Proposed Standards. Draft EIS, EPA-450/3-80-021a,
June 1980.
The proposed standard, in the form of Regulatory Alternative V,
entails fifth-year annualized costs of $90,000 (November 1978).22
The CE Plant Cost Index notes that May 1980 = 258.5 while November
1978 = 224.7. Fifth-year annualized costs in May 1980 dollars are
therefore estimated at $103,538.
Because most asphalt blowing stills are located at asphalt roofing
plants, rather than petroleum refineries, only a fraction of the costs
of this NSPS can be assigned to refineries. It has been observed that
while 17 petroleum refineries have blowing stills, 2 asphalt plants
and 70 percent of all (118) asphalt roofing plants operate such facilities.^
For this reason, a refinery factor of .200 or 17/(2 = .7 x 118), has
been defined.
Because the fifth-year annualized costs of this standard are
$103,538, and the refinery factor is .200, $20,708 are estimated to
affect refineries.
8.2.2.7 Petroleum Liquid Storage Vessels NSPS. This NSPS was
originally promulgated in 1974 and was revised 4/4/80 by Federal Register
45, page 23373 and all cost data have been obtained from this Federal
Register notice.
The annualized costs to control one storage tank with a diameter
of 61 meters, has been estimated to range from $1,100 to $3,300, in
1980 dollars.24
Fifth-year annualized costs have been estimated through the
following method. Because the United States has 18 million barrels
per calendar day refining capacity, annual output of petroleum products
is estimated at 678,934,817 m3/year (based upon 65 percent capacity
utilization, a conversion factor of 6.29 barrels per cubic meter, and
365 days per year). Also, because each model storage tank has a
diameter of 61 meters, the capacity of such a tank is 29,225 m3 (based
upon an assumed tank height of 10 meters). If the average throughput
of each tank is 13 times the tank's capacity,25 each tank has an
annual throughput of 379,925 m3 of petroleum products. This throughput
8-36
-------
level, along with the annual output estimated above, would indicate
the existence of 1,787 tanks (if all tanks had a diameter of 61 neters).
Because the IRS allows petroleum refining equipment to be depreciated
o r
over a period of 13 to 19 years, the average life of storage tanks
is assumed to be 16 years, indicating that about 112 tanks would
require replacement each year.
Fifth-year annualized costs are estimated to be $369,600, given
$3,300 per tank annualized costs and 112 tanks replaced each year.
All costs are assigned to refineries, because the method used to
estimate tank population considers storage at refineries alone.
8.2.2.8 Volatile Organic Liquid Storage Tanks NSPS. This NSPS
is aimed toward the control of VOC emissions from storage tanks.
Information pertaining to the costs of this standard have been obtained
from VOC Emissions from Volatile Organic Liquid Storage Tanks - Background
Information for Proposed Standards, Draft EIS, EPA-450/3-81-003a,
April 1981.
According to the draft EIS, Regulatory Alternative IV is recommended.
The fifth-year annualized costs of this alternative are estimated to
be a credit of $5,790,000. Such credits are a result of recovered
product and are expressed in terms of February 1980 dollars.
The costs of this potential standard have been adjusted to May
1980 dollars through the CE Plant Cost Index, which indicates that May
1980 = 258.5 and February 1980 = 250.8. Fifth-year annualized costs
in May 1980 dollars are therefore estimated to be a credit of $5,967,763.
Volatile organic liquids are manufactured by many industries
other than petroleum refining, and such liquids are stored at the site
of consumption as well as production. For this reason, an attempt has
been made to approximate the portion of the costs that can be expected
to affect the petroleum refining industry. This portion is estimated
to be 20 percent of all industrial organic chemical shipments originate
from facilities other than those classified as industrial organic
27
chemical producers by the Department of Commerce.
Because the fifth-year annualized costs of this standard are
estimated to be a credit of $5,967,763, and the refinery factor is
.200, a credit of $1,193,553 has been assigned to petroleum refineries.
8-37
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8.2.2.9 VQC Fugitive Emissions - NSPS. This potential NSPS is
aimed toward the control of fugitive VOC emissions from the SOCMI, and
was proposed on 1/5/81 in Federal Register 46, Number 2, page 1136.
Cost information related to this potential standard are presented in
VOC Fugitive Emissions in the Synthetic Organic Chemicals Manufacturing
Industry - Background Information for Proposed Standards, Draft EIS,
EPA-450/3-80-033a, November 1980.
As noted in the Federal Register, Regulatory Alternative IV is
recommended and the fifth-year annualized costs of this alternative are
$11,000,000 (November 1978).
Costs have been expressed in terms of May 1980 dollars through
the CE Plant Cost Index, which indicates that May 1980 = 258.5 and
November 1978 = 224.7. Fifth-year annualized costs in May 1980 dollars
are estimated to be $12,654,651.
Because this standard affects some SOCMI chemicals that are
manufactured at petroleum refineries, an attempt has been made to
distribute costs among refineries and other SOCMI sources. According
to production data presented by the International Trade Commission28
SOCMI chemical production is defined according to four groups, with
the following levels of 1977 production; Tar and Crudes - 1.48 Gg;
Primary Products from Petroleum and Natural Gas - 42.42 Gg; Cyclic
Intermediates - 7.12 Gg; and Miscellaneous Cyclic and Acyclic Chemicals
- 29.88 Gg. However, within the group called Primary Products from
Petroleum and Natural Gas, are included five products are Cumene,
Cyclohexane, Styrene, Ethyl benzene, and Ethylene and the total 1977
production of these chemicals was 18.39 Gg. Costs attributable to
refineries have been estimated by subtracting this amount from the
total produced from petroleum and natural gas and expressing the
result as a fraction of total SOCMI production (i.e., 80.9 Gg). This
method gives a refinery factor of .297.
Because the fifth-year annualized costs of this proposed standard
are estimated to be $12,654,651 and the refinery factor is .297, the
cost expected to affect the petroleum refining industry is $3,758,431.
8-38
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8.3 REFERENCES
1. Telecon. Rhoads, T.W., PES, Incorporated, with Analabs. August 19,
1980. Docket Reference Number II-E-7.*
2. Peters, M.S. and V.D. Timmerhaus. Plant Design and Economics for
Chemical Engineers. Second Edition, New York, McGraw-Hill, 1968.
Docket Reference Number 11-1-7.*
3. Control of Volatile Organic Compound Leaks from Petroleum Refinery
Equipment EPA-450/2-78-036. OAQPS No. 1.2-111. U.S. Environmental
Protection Agency. Research Triangle Park, N.C. June 1978.
Docket Reference Number II-A-6.*
4. Chemical Engineering. Economic Indicators. 87(20). October 6,
1980. Docket Reference Number 11-1-51.*
5. Chemical Engineering. Economic Indicators. 86(7). March 26,
1979. Docket Reference Number 11-1-37.*
6. Letter from H.H. McClure, Texas Chemical Council, to W. Barber
EPA:OAQPS, June 30, 1980. Docket Reference Number II-D-69.*
7. Emissions Control Options for the Synthetic Organic Chemicals
Manufacturing Industry. Fugitive Emissions Report. Hydroscience.
February 1979. Draft Report. Docket Reference Number II-A-11.*
8. Memorandum from Cole, D.G., PES, Inc., to K.C. Hustvedt, U.S.
Environmental Protection Agency. Estimated Costs for Rupture
Disk System with a 3-way valve. July 29, 1981. Docket Reference
Number II-B-35.*
9. Telecon. Mclnnis, J.R., PES, Incorporated, with Hetrick, C.,
Crane Chempump Division, Warrington, PA. August 23, 1979.
Docket Reference Number II-E-5.*
10. Letter with attachments from Johnson, J.M., Exxon Company, to
Walsh, R.T., EPA:CPB. July 28, 1977. Docket Reference Number
II-D-22.*
11. Assessment of Atmospheric Emissions from Petroleum Refining:
Volume 3. Appendix B. U.S. Environmental Protection Agency.
EPA-600/2-80-075c. April 1980. Docket Reference Number II-A-19.*
12. Emissions from Leaking Valves, Flanges, Pump and Compressor
Seals, and other Equipment at Oil Refineries. Report No. LE-78-001.
California Air Resources Board. April 24, 1978. Docket Reference
Number II-1-26.*
13. Chemical Engineering. Gasoline or Olefins from an Alcohol Feed.
87(8):86. April 21, 1980. Docket Reference Number II-I-46.*
8-39 "
-------
14. Oil and Gas Journal. OGJ Production Report. 78(22):194. June
2, 1980. Docket Reference Number II-I-48.*
15. Economic Impact of EPA's Regulations on the Petroleum Refining
Industry. Part III - Economic Impact Analysis. EPA-230/3-76-004.
U.S. Environmental Protection Agency. April 1976. Docket
Reference Number II-A-1.*
16. Benzene Fugitive Emissions - Background Information for Proposed
Standards, Draft EIS. EPA-450/3-80-032a. U.S. Environmental
Protection Agency. November 1980. Page 9-57. Docket Reference
Number II-A-33.*
17. Benzene Emissions from Benzene Storage Tanks - Background Information
for Proposed Standards, Draft EIS. EPA-450/3-80-034a. U*S.
Environmental Protection Agency. December 1980. Docket Reference
Number II-A-34.*
18. Benzene Emissions from Benzene Storage Tanks - Background Information
for Proposed Standards, Draft EIS. EPA-450/3-80-034a. U.S.
Environmental Protection Agency. December 1980. Page 3-1. Docket
Reference Number II-A-34.*
19. Benzene Emissions from Benzene Storage Tanks - Background Information
for Proposed Standards, Draft EIS. EPA-450/3-80-034a. U.S.
Environmental Protection Agency. December 1980. Page 7-21. Docket
Reference Number II-A-34.*
20. Bulk Gasoline Terminals - Background Information for Proposed
Standards, Draft EIS. EPA-450/3-80-038a. U.S. Environmental
Protection Agency. December 1980. Docket Reference Number II-A-35.*
21. Bulk Gasoline Terminals - Background Information for Proposed
Standards, Draft EIS. EPA-450/3-80-038a. U.S. Environmental
Protection Agency. December 1980. Page 8-3. Docket Reference
Number II-A-35.*
22. Federal Register. Vol. 45. November 18, 1980. page 76404.
Docket Reference Number II-J-4.*
23. Federal Register. Vol. 45. November 18, 1980. page 76405.
Docket Reference Number II-J-4.*
24. Federal Register. Vol. 45. April 4, 1980. Page 23373. Docket
Reference Number II-J-3.*
25. Development of Petroleum Refinery Plot Plans. EPA-450/3-78-025.
U.S. Environmental Protection Agency. June 1978. Docket Reference
Number II-A-7.*
26. Commerce Clearing House, Inc., 1979 U.S. Master Tax Guide. Page 432.
Docket Reference Number 11-1-56.*
8-40
-------
27. VOC Emissions from Volatile Organic Liquid Storage Tanks - Background
Information for Proposed Standards, Draft EIS. EPA-450/3-81-003a.
U.S. Environmental Protection Agency. April 1981. Page 9-3.
Docket Reference Number II-A-36.*
28. Research Triangle Institute. Synthetic Organic Chemical
Manufacturing Industry: An Economic Impact Study of
Fugitive Emissions. U.S. Environmental Protection Agency.
Contract No. 68-02-3071. January 1980. page 46. Docket
Reference Number II-I-32.*
*References can be located in Docket Number A-80-44 at the U.S.
Environmental Protection Agency Library, Waterside Mall, Washington, D.C.
8-41
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9.0 ECONOMIC IMPACT
9.1 INDUSTRY CHARACTERIZATION
9.1.1 General Profile
9.1.1.1 Refinery Capacity. On January 1, 1980, there were 311 petro-
leum refineries operating in the United States (excluding Puerto Rico, Virgin
Islands, Guam, and the Hawaiian Foreign Trade Zone) with a total crude capa-
city of 3,005,000 m3 per stream day.l With respect to location, refining
capacity is fairly well-concentrated, with 54 percent of domestic crude
throughput capacity located in three states: Texas (27%), California (14%),
and Louisiana (13%). Table E-l (Appendix E) summarizes U.S. refining capa-
city as of January 1, 1980.
Although refining capacity has grown steadily through the 1970s (see
Table 9-1), a similar trend in capacity growth is not anticipated during
the 1980s. The decrease in the rate of capacity expansion can be traced
to demand reductions resulting from rising gasoline prices, the slowdown of
economic growth, the availability of substitutes (e.g., coal) in some appli-
cations, environmental opposition to new refineries, and the increasing fuel
efficiency of newer automobiles. Those additions to capacity that will be
made will most likely occur at existing refineries to allow the processing
of lower-quality high-sulfur crudes, and increase the output of unleaded
gasoline.12
It should be noted that in the production and capacity tables that fol-
low, a distinction is often made between stream days (i.e., sd) and calendar
days (i.e., cd). The basic difference between the two terms is that "stream
day" refers to the maximum capacity of a refinery or unit on a given operat-
ing day, while "calendar day" production represents the average daily produc-
tion over a one-year period. Since most refineries do not operate 365 days
each year, stream day numbers are always slightly larger than those for
calendar days.
9-1
-------
Table 9-1. TOTAL AND AVERAGE CRUDE DISTILLATION CAPACITY BY YEAR^
UNITED STATES REFINERIES, 1970-1980
Year
(January 1)
1970
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980b
Number of
Refineries
253
247
247
247
259
256
266
285
289
297
311
Total Capacity
(m3/sd)c
2,112,000
2,180,000
2,225,000
2,365,000
2,459,000
2,494,000
2,689,000
2,801,000
2,870,000
2,975,000
3,005,000
Average Refinery
Capacity
(m3/sd)C
8,300
8,800
9,000
9,600
9,500
9,700
10,100
9,800
9,900
10,000
9,700
References 1 through ll.
^Reference 1.
cNote: Capacity in stream days,
9-2
-------
9.1.1.2 Refinery Production. In terms of total national output, tht
percentage yields of most refined petroleum products have remained con-
stant over recent years, although several exceptions are noted below. The
percentage yields of refined petroleum products from crude oil for the years
1969 through 1978 are summarized in Table 9-2, while Table 9-3 notes the
average daily output of the major products.
The diversity of refinery product output varies with refinery capacity.
Large integrated refineries operate a wide variety of processing units, thus
enabling the production of many or all of the products noted in Table 9-2.
On the other hand, many refineries are relatively small operations, have only
a few processing units, and produce selected products such as distillate oil
and asphalt.
Through the 1970's residual fuel oil and petrochemical feedstocks have
accounted for increasing shares of total refinery output. These increases
can be traced to the use of residual fuel oil in industrial applications and
the growth in petrochemical markets due to the increased production of
synthetic rubber, fibers, plastics, and other materials manufactured from
petrochemicals. The increased output of residual fuel oil and petrochemicals
have been balanced by declining output of gasoline and kerosene.
9.1.1.3 Refinery Ownership, Vertical Integration and Diversification. A
large portion of domestic refining capacity is owned and operated by large.
vertically integrated oil companies, both domestic and international. The
remainder is controlled by independent refiners such as Charter. Crown
Central Petroleum, Holly, Tosco, and United Refining.
Table 9-4 lists twenty companies with the greatest capacity to process
crude oil. Based upon the capacities noted, and a total domestic capacity of
3.005.000 m3 per stream day,l the 4- and 8-firm concentration ratios are
31 and 51 percent, respectively. Since there are currently 158 companies^
engaged in refining activities, these ratios are indicative of a high degree
of ownership concentration of refinery capacity.
Refinery ownership is but one aspect of the vertical integration of the
major oil companies. Such companies are integrated "backward" in that they
own or lease crude oil production facilities, both domestic and international,
as well as the means to transport crude by way of pipeline and tankers. On
the international level, access to Saudi Arabian crude is maintained through
9-3
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Table 9-2. PERCENT VOLUME YIELDS OF PETROLEUM PRODUCTS BY YEAR*
UNITED STATES REFINERIES, 1971-1978
(Percent)
Product
Motor Gasoline
Jet Fuel
Ethane
Liquefied Gases
Kerosene
Distillate Fuel Oil
Residual Fuel Oil
Petrochem. Feedstocks
Special Naphthas
Lubricants
Wax
Coke
Asphalt
Road Oil
Still Gas
Miscellaneous
Processing Gainb
Total
1971
46
7
0
2
2
22
6
2
0
1
0
2
3
0
3
0
- 3
100
.2
.4
.2
.9
.1
.0
.6
.7
.7
.6
.2
.6
.8
.2
.8
.4
.4
.0
1972
46.2
7.2
0.2
2.8
1.8
22.2
6.8
2.9
0.7
1.5
0.1
2.8
3.6
0.2
3.9
0.4
- 3.3
100.0
1973
45.6
6.8
0.2
2.8
1.7
22.5
7.7
2.9
0.7
1.5
0.2
2.9
3.6
0.2
3.9
0.4
- 3.6
100.0
1974
45
6
0
2
1
21
8
3
0
1
0
2
3
0
3
0
- 3
100
.9
.8
.1
.6
.3
.8
.7
.0
.8
.6
.2
.8
.7
.2
.9
.5
.9
.0
1975
46
7
0
2
1
21
9
2
0
1
0
2
3
0
3
0
- 3
100
.5
.0
.1
.4
.2
.3
.9
.7
.6
.2
.1
.8
.2
.1
.9
.7
.7
.0
1976
45.5
6.8
0.1
2.4
1.1
21.8
10.3
3.3
0.7
1.3
0.1
2.6
2.8
0.0
3.7
1.0
- 3.5
100.0
1977
43.4
6.6
0.1
2.3
1.2
22.4
12.0
3.6
0.6
1.2
0.1
2.5
2.9
0.1
3.6
1.0
- 3.6
100.0
1978
44.1
6.6
0.1
2.3
1.2
22.4
12.0
3.6
0.6
1.2
0.1
2.5
2.9
0.1
3.6
1.0
- 3.6
100.0
Reference 13.
bProcessing Gain = Product Yield - Process Feed (Input)
Yields are reported as negative because product yields are greater than
process feeds. In the catalytic reforming process, for example, straight-
chain hydrocarbons are converted to branched configurations with hydrogen
as a by-product, resulting in an overall net increase in volume.
9-4
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Table 9-3. PRODUCTION OF PETROLEUM PRODUCTS BY YEARd>b
UNITED STATES REFINERIES, 1969-1978
(1,000 m3/cd)
Year
1969
1970
1971
1972
1973
1974
1975
1976
1977
1978
Motor
Gasol ine
872
909
951
1,000
1,039
1,011
1,037
1,088
1,118
1,140
Distillate
Fuel Oil
370
391
397
419
449
424
422
465
521
501
Residual
Fuel Oil
116
112
120
127
154
170
197
219
279
266
Jet Fuel
140
131
133
135
137
133
138
146
155
155
Kerosene
45
42
38
35
35
25
24
24
27
24
NGL and LRGC
54
55
57
57
60
54
49
54
56
--
Reference 13. Section VII. Tables 5, 6, 6a, 7, 7a, 14, 15, 16, 16a,
17, and 17a.
^Total and product output reports may vary slightly by data source.
CNGL = Natural Gas Liquids; LRG = Liquefied Refinery Gases.
9-5
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Table 9-4. NUMBER AND CAPACITY OF REFINERIES OWNED AND OPERATED
BY MAJOR COMPANIES*
UNITED STATES REFINERIES, 1980
Company
Exxon
Chevron
Amoco
Shell
Texaco
Gulf
Mobil
ARCO
Marathon
Union Oil
Sun
Sohio/BP
Ashl and
Ph i 1 1 i ps
Conoco
Coastal States
Cities Service
Champl in
Tosco
Getty
Number of
Refineries
5
12
10
8
12
7
7
4
4
4
5
3
7
5
7
3
1
3
3
2
Crude Capacity
(1,000 m3/cd)
251
233
197
183
168
145
142
133
93
78
77
72
73
68
58
47
46
38
35
35
aReference 12, p. 075.
9-6
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Aramco which is owned by four international companies: Exxon, Standard Oil
of California, Texaco, and Mobil.
With regard to transportation by pipeline, the major oil companies have
been the main source of capital for the construction and operation of these
facilities, due largely to the huge investments required. On the other hand,
tanker ownership is split among the major oil companies and independent oper-
ators who charter tankers to oil companies and traders.14 Tne presence of
independent tanker operators is a result of relatively small financial
requirements, compared to pipeline ownership.
While many of the low-volume refinery products are marketed directly by
the refiners themselves, the sale of gasoline on the retail level is handled
primarily by franchised dealers and independent operators. The major refiners
do, however, have a high degree of control over the distribution of their pro-
ducts with regard to market area. This is so since the major refiners select
sites for the construction of service stations before the facilities are
leased to independent operators under franchise agreements. The major refin-
ers do maintain the direct operation of some service stations for purpose of
measuring the strength of the retail market. However, no more than 5 percent
of all facilities in operation are managed in this fashion.15
Many of the firms that operate refineries, notably the larger oil compa-
nies, are diversified as well as vertically integrated. Several refiners are
vertically integrated through the manufacture of petrochemicals and resins.
Among the firms that have interests in these areas are Clark Oil and Refin-
ing, Getty Oil, Occidental Petroleum, and Phillips Petroleum. Ashland Oil's
construction division operates the nation's largest highway paving company.
Several instances of diversification can be observed. Exxon Enter-
prises develops and manufactures various high-technology products. The
Kerr-McGee Corporation is the largest supplier of commercial grade uranium
for electricity generation and also manufactures agricultural and industrial
chemicals. Mobil Oil Corp. is owned by Mobil Corp. which owns both Montgom-
ery Ward and Co. and The Container Corporation of America. The Charter Co.,
the largest of the independent refiners, is also engaged in broadcasting,
insurance, publishing, and commercial printing.
9.1.1.4 Refinery Employment and Wages. Total employment at domestic
petroleum refineries has grown steadily since the mid-19601s, with minor dis-
ruptions due to the recessions of 1970 and 1974. As Table 9-5 demonstrates,
9-7
-------
Table 9-5.• EMPLOYMENT IN PETROLEUM AND NATURAL GAS EXTRACTION
AND PETROLEUM REFINING BY YEARa
UNITED STATES, 1969-1978
(1,000 Workers)
Year Petroleum and Natural
Gas Extraction Petroleum Refining
1969 279.9 144.7
1970 270.1
L 153.7
1971 264.2 152.7
1972 268.2 152.3
1973 277.7 149.9
1974 304.5 155.4
1975 335.7 154.2
1976 360.3 157.1
1977 404.5 160.3
1978 417.]
L 163.0
Reference 13. Section V. Table 2.
9-8
-------
there were 163 thousand workers employed at refineries in 1978.16 with 289
refineries operating that year,H average employment at each refinery is
approximately 564 persons.
The average hourly earnings of petroleum refinery workers have consis-
tently exceeded average wage rates for both the mining and manufacturing
industries.17 Petroleum refinery hourly earnings have also exceeded those
for other sectors of the oil industry as noted in Table 9-6.
9.1.2 Refining Processes
Refineries process crude oil through a series of physical and chemical
processes into myriad products. The four major product areas are as follows:
• Transportation fuels --motor gasoline, aviation fuel;
• Residential/commercial fuels --middle distillates;
• Industrial/utility fuels -- residual fuel oils; and
• Other products -- liquified gases and chemical process feeds.
As noted in Table 9-2, motor gasoline is by far the largest volume product of
U.S. refineries. Motor gasoline is produced through blending the products of
various refinery units such as those described below. Estimated 1981 gasoline
pool composition is presented in Table 9-7.
9.1.2.1 Crude Distillation. The initial step in refining crude oil is
to physically separate the oil into distinct components or fractions through
distillation at atmospheric pressure. There are several possible combina-
tions of fractions and quantities available from crude distillation dependent
upon the type of crude being processed and the products desired.^9 High
boiling point components are often further separated by vacuum flashing or
vacuum distillation. The crude oil still provides feedstock for downstream
processing and some final products.20
9.1.2.2 Thermal Operations. Thermal cracking operations include regu-
lar coking as well as visbreaking. In each of these operations, heavy oil
fractions are broken down into lighter fractions by the action of heat and
pressure while heavy fuels and coke are produced from the uncracked residue.21
Visbreaking is a mild form of thermal cracking that causes very little reduc-
tion in boiling point but significantly lowers the viscosity of the feed.
The furnace effluent is quenched with light gas oil and flashed in the bottom
of a fractionator while gas, gasoline, and heavier fractions are recycled.
Coking is a severe form of thermal cracking in which the feed is held
at a high cracking temperature long enough for coke to form and settle out.
9-9
-------
Table 9-6. AVERAGE HOURLY EARNINGS OF SELECTED INDUSTRIES BY YEARa
UNITED STATES, 1969-19783
($/Hour)b
Year
1969
1970
1971
1972
1973
1974
1975
1976
1977
1978
Petroleum
Refining
4.23
4.49
4.82
5.25
5.54
5.96
6.90
7.75
8.44
9.32
Petroleum and
Natural Gas Extraction
3.43
3.57
3.75
4.00
4.29
4.82
5.34
5.76
6.23
7.01
Total
Manufacturing
3.19
3.36
3.57
3.81
4.08
4.41
4.81
5.19
5.63
6.17
Total
Mining.
3.61
3.85
4.06
4.41
4.73
5.21
5.90
6.42
6.88
7.67
Reference 13. Section V.
^Current dollars.
Table 1.
9-10
-------
Table 9-7. ESTIMATED GASOLINE POOL COMPOSITION BY REFINERY STREAM^
UNITED STATES REFINERIES, 1981
Stream
Re form ate
FCC Gasoline
Al kyl ate
Raffinate
Butanes
Coker Gasoline
Natural Gasoline
Light Hydrocrackate
I some rate
Straight Run Naphtha
Total
Amount
(m3/cd)
355,000
408,000
162,000
17,000
75,000
15,000
30,000
22,000
16,000
86,000
1,186,000
% of
Total
29.9
34.4
13.7
1.4
6.3
1.3
2.5
1.9
1.3
7.3
100.0
Reference 18.
9-11
-------
The cracked products are separated and drawn;off and heavier materials are
recycled to the coking operations.19
9.1.2.3 Catalytic Cracking. Catalytic cracking is used to increase the
yield and quality of gasoline blending stocks and produce furnace oils and
other useful middle distillates.21 By this process the large hydrocarbon
molecules of the heavy distillate feedstocks are selectively fractured into
smaller olefinic molecules. The use of a catalyst permits operations at lower
temperatures and pressures than those required in thermal cracking. In the
fluidized catalytic cracking processes, a finely-powdered catalyst is handled
as a fluid as opposed to the beaded or pelleted catalysts employed in fixed
and moving bed processes.19
9.1.2.4 Reforming. Reforming is a molecular rearrangement process to
convert low-octane feedstocks to high octane gasoline blending stocks or to
produce aromatics for petrochemical uses.19 Hydrogen is a significant
co-product of reforming, and is in turn, the major source of hydrogen for
processes such as hydrotreating and isomerization.
9.1.2.5 Isomerizaton. Isomerization, like reforming, is a molecular
rearrangement process used to obtain higher octane blending stocks. In this
process, light gasoline materials (primarily butane, pentane, and hexane),
are converted to their higher octane isomers.
9.1.2.6 Alkylation. Alkylation involves the reaction of an isoparaffin
(usually isobutane) and an olefin (propylene or butylenes) in the presence of
a catalyst to produce a high octane alkylate, an important gasoline blending
stock.19,21
9.1.2.7 Hydrotreating. Hydrotreating is used to saturate olefins and
improve hydrocarbon streams by removing unwanted materials such as nitrogen,
sulfur, and metals. The process uses a selected catalyst in a hydrogen
environment.19 Hydrofining and hydrodesulfurization are two subprocesses
used primarily for the removal of sulfur from feedstock and finished pro-
ducts. Sulfur removal is typically referred to as "sweetening".
9.1.2.8 Lubes. In addition to or in place of drying and sweetening of
hydrotreating units, petroleum fractions in the lubricating oil range are
further processed through solvent, acid, or clay treatment in the production
of motor oils and other lubricants. These subprocesses can be used to finish.
waxes and for other functions.19
9-12
-------
9.1.2.9 Hydrogen Manufacture. The manufacture of hydrogen has become
increasingly necessary to maintain growing hydrotreating operations. Natural
gas and by-products from reforming and other processes may serve as charge
stocks. The gases are purified of sulfur (a catalyst poison) and processed
to yield moderate to high purity hydrogen. A small amount of hydrocarbon
impurity is usually not detrimental to processes where hydrogen will be
used.19
9.1.2.10 Solvent Extraction. Solvent extraction processes separate
petroleum fractions or remove impurities through the use of differential
solubilities in particular solvents. Desalting is an example whereby water
is used to wash water soluble salts from crude.20 Several complex refining
processes employ solvent extraction during the production of benzene-related
compounds.
9.1.2.11 Asphalt. Asphalt is a residual product of crude distillation.
It is also generated from deasphalting and solvent decarbonizing -- two spe-
cialized steps that increase the quantity of cracking feedstock.20
9.1.3 Market Factors
9.1.3.1 Demand Determinants. 1980 Department of Energy (DOE) projec-
tions conclude that, on the national level, existing refinery capacity is
capable of satisfying the future domestic demand for refined petroleum
products.22 Expansions and modifications will, however, be undertaken in
order to allow the processing of greater proportions of high-sulfur crudes,
and to permit the production of increasing levels of high-octane unleaded
gasoline. It is also possible that shifts in demand on the regional level
may call for capacity expansions at existing refineries.22
Evidence of sufficient refining capacity is provided by Table 9-8. In
that table, estimates of percent refinery capacity utilization, along with
daily demand levels for the four major refinery products, are presented under-
several assumptions regarding the world price of oil. In each case the
projected utilization rate is well below the 1978 level of 86 percent.
Reduced driving and greater vehicle efficiency have combined to reduce
the future demand for motor gasoline. As Table 9-8 indicates, it is unlikely
that gasoline demand will, within the forecast period, reach those levels
observed during 1978. This conclusion holds true regardless of specific
assumptions concerning the future of world oil prices.
9-13
-------
Table 9-8. REFINERY CAPACITY, CAPACITY UTILIZATION, AND REFINED
PRODUCT DEMAND PROJECTIONS UNDER THREE WORLD OIL PRICE SCENARIOSa
UNITED STATES REFINERIES, 1978-1985-1990-1995
Year
1978
1985
Low
Mid
High
1990
Low
Mid
High
1995
Low
Mid
High
World Crude Refinery
Oil Priceb Capacity
($/m3) (1,000 m^/cd)
97
170
201
245
170
233
277
170
258
352
2,719
3,068
3,068
3,068
3,148
3,148
3,148
3,211
3,211
3,211
Capacity
Utilization
(Percent)
86
70
65
64
74
66
63
76
65
60
Product Demand (1
Motor
Gasoline
1,176
1,017
986
922
1,017
938
859
1,097
986
859
Distillate
Fuel Oil
572
493
461
445
541
493
461
588
493
429
,000 m3/cd)
Residual
Fuel Oil
477
223
207
191
238
191
175
207
111
95
Jet
Fue^
175
238
175
223
270
191
238
318
207
254
aReference 22, p. 115.
bWeighted average price including imported, domestic, Alaskan, and stripper oil,
etc., in constant (1979) dollars.
9-14
-------
Reduced total gasoline demand does not, however, imply that existing
gasoline production facilities are currently capable of meeting future
gasoline requirements. In particular the continued phase-out of leaded
gasoline and demand for higher octane ratings will require some additions
to refinery capacity. Consequently, refiners can be expected to increase
cracking, catalytic reforming, and alkylation capacities in order to main-
tain octane requirements.23
Distillate fuel oils are used in home heating, utility and industrial
boilers, and as diesel fuel. With the exception of diesel fuel, demand in
all applications is expected to fall.2? Declining demand is essentially
due to the availability of lower cost substitutes, in particular coal-fired
utility boilers, coal-fired industrial boilers and natural gas for home
heating purposes. With the exception of low crude oil prices in 1995, Table
9-8 indicates that the demand for distillate fuel oil declines in all cases.
Residual fuel oil is used as a bunker fuel in large ships, large utility
and industrial boilers, and in the heating of some buildings. Residual fuel
oil competes with coal for use as a fuel in the applications noted above.
Table 9-8 shows that the demand for residual fuel oil falls steadily under
all price scenarios. This is so because the ability to crack residual fuel
into more valuable lighter products ensures that its price will not fall to
that point where it can serve as a cost-effective replacement for coal-24
The elasticity of demand is a measure of the percent change in demand
prompted by a one percent change in price. With regard to the elasticity of
demand for various petroleum products, most econometric studies conclude that
demand is not sensitive to price changes. Recent estimates made by DOE
and summarized in Table 9-9, support this conclusion.25 Since all values
presented in that table are within _+ 1, the general conclusion is that demand
is not particularly sensitive to price changes.
9.1.3.2 Supply Determinants. As noted in the previous section, it is
unlikely that the supply of refined petroleum products will be restricted for
reason of inadequate domestic refining capacity. It is, however, quite pos-
sible that disruptions in the flow of imported oil could result from interna-
tional developments, in particular, political instability in the Middle East.
The major thrust of national energy policy is therefore the reduction of
dependence upon imported oil.
9-15
-------
Table 9-9. PRICE ELASTICITY ESTIMATES FOR MAJOR REFINERY PRODUCTS
BY DEMAND SECTOR3
UNITED STATES, 1985
Demand Sector
Residential
Commerical
Industrial
Transportation
Refinery Product
Distillate Oil
Distillate Oil
Distillate Oil
Residual Oil
Liquid Gas
Gasoline
Distillate Oil
Residual Oil
Jet Fuel '
Price Elasticity
-0.4
-0.4
-0.5
-0.4
-0.4
-0.3
-0.7
-0.1
-0.4
Reference 22, pp. 332-3.
9-16
-------
Attempts to reduce dependence upon imported oil have focused upon three
major areas: reduced consumption through conservation, and increased domestic
production through both the decontrol of domestic oil prices and the develop-
ment of a synthetic fuels industry. While price decontrol and synthetic fuels
development may have a significant impact in terms of import reductions, these
measures are essentially mid- to long-term solutions. Conservation, on the
other hand, has offered more immediate results.
The effects of recent conservation efforts, including decreased gasoline
consumption, and conversion of facilities to coal and natural gas, can be
observed in Table 9-10. In particular, imports of crude oil have leveled-off
after reaching a historic high of 384 million m3 in 1977, while recent
reports26 indicate that the reduction of imports has continued into 1980.
The results of conservation efforts can also be observed in the fact that
year-end stocks of crude are currently at the highest levels recorded in
the recent past.
As part of the Reagan Administration's energy policy, price controls on
domestic crude oil and refined petroleum products were revoked by Executive
Order 12287 (January 28, 1981). This Order essentially rescinded the price
and allocation authority granted to the Department of Energy under the
Emergency Petroleum Allocation Act of 1973. The progressive decontrol of
domestic crude oil prices has been accompanied by increased exploration, and
is expected to increase stocks of already proven reserves. Recent increases
in both drilling activities and proven reserves are noted in Table 9-11.
The development of a domestic synthetic fuels industry will have little
impact upon energy supplies over the next five years since significant output
is not anticipated until the late 1980s.27
9.1.3.3 Prices. Table 9-12 indicates recent price levels for gasoline,
distillate fuel oil,,and residual fuel oil. For each product, a pattern of
stable prices, followed by rapid price increases in 1974 and 1979, can be
observed. The increases in both years are attributed to the pass-through of
increases in the price of crude oil supplied by the OPEC nations.
Future prices of refined products will continue to rise in response to
increases in the price of both imported and domestic crude. Table 9-13 pre-
sents recent DOE projections of world oil, gasoline, distillate fuel oil,
residual fuel oil, and jet fuel prices. With regard to imported oil, it is
anticipated that price pressure from the OPEC nations will continue.
9-17
-------
Table 9-10. CRUDE OIL PRODUCTION AND CONSUMPTION BY YEARa>b
UNITED STATES, 1970-1979
(1,000,000 m3/year)
Domestic
Year Production
1970
1971
1972
1973
1974
1975
1976
1977
1978
1979
559
549
549
534
486
465
452
457
485
474
Imports
77
98
129
188
202
238
308
384
369
376
Domestic
Consumption Exports
633
649
680
723
688
703
760
841
854
850
0.8
0.1
0.1
0.1
0.2
0.3
0.5
2.9
9.2
13.6
Year-End Stocks as Percent
Stocks of Consumption
44
41
39
39
42
43
45
55
60
68
6.94
6.36
5.76
5.33
6.13
6.14
5.97
6.57
7.01
8.05
Reference 12, p. 073.
^Product volume reports may vary by data source,
9-18
-------
Table 9-11. OIL EXPLORATION AND DISCOVERIES BY YEARS
UNITED STATES, 1970-1979
Year
1970
1971
1972
1973
1974
1975
1976
1977
1978
1979
Exploratory
Wells Drilled
7,693
7,000
8,357
7,466
8,619
9,163
9,234
9,961
10,667
10,484
New Reserves Added
(1,000 m3)
l,566,000b
15,000
20,000
18,000
36,000
28,000
11,000
25,000
32,000
38,000
aReference 12, p. 072.
bIncludes Prudhoe Bay, Alaska.
9-19
-------
Table 9-12. AVERAGE PRICES: GASOLINE, DISTILLATE FUEL OIL, AND
RESIDUAL FUEL OIL BY YEARd
UNITED STATES, 1968-1979
Gasol ine
(tf/liter)
Year
1968
1969
1970
1971
1972
1973
1974
1975
1976
1977
1978
1979
Wholesale3
4.4
4.5
4.7
4.8
4.7
5.2
8.1
9.5
10.3
11.2
11.8
16.4
Retail"
8.9
9.2
9.4
9.6
9.5
10.3
13.8
15.1
15.7
16.7
17.4
23.2
Distillate Fuel Oil
(el/liter)
Wholesale^
2.7
2.7
2.9
3.1
3.1
3.6
5.6
8.2
8.7
9.8
9.9
14.3
Retail L
4.6
4.7
4.9
5.2
5.2
6.0
9.5
10.3
11.0
12.5
13.4
19.2
Residual Fuel Oil
U/liter)
Wholesale3
1.5
1.5
1.9
2.6
3.0
3.4
6.8
6.8
6.6
7.9
7.4
10.2
aExcludes tax: Reference 12, p. 079.
bService station price, regular gasoline, includes tax:
Section VI, Table 4.
cReference 13, Section VI, Table 5.
^Current dollars.
Reference 13,
9-20
-------
Table 9-13.
PRICE PROJECTIONS FOR SELECTED PETROLEUM PRODUCTS BY YEARa
UNITED STATES, 1978-1985-1990-1995
($/m3)b
Year
1978
1985
Low
Mid
High
1990
Low
Mid
High
1995
Low
Mid
High
World Crude
Oil Price0
97
170
201
245
170
233
277
170
258
352
Motor
Gasoline
153
240
277
320
241
309
352
240
338
432
Distillate
Fuel Oil
107
185
211
252
187
242
295
190
267
365
Residual
Fuel Oil
80
175
204
243
176
232
279
178
255
352
Jet
Fuel
113
195
221
263
197
252
314
199
279
387
Reference 22, p. 115.
Constant (1979) dollars.
cWeighted average price including imported, domestic, Alaskan, and stripper
oil, etc.
9-21
-------
9.1.3.4 Imports. Imports of both crude oil and refined products are
expected to decline through the mid-1980's. In the case of crude oil, the
fall in import levels can be attributed to sharp increases in the price of
OPEC oil, and the increased production of domestic crude prompted by its
price decontrol.
Low sulfur (sweet) crudes are generally more desirable than high sulfur
(sour) crudes because the refining of the latter requires a larger investment
in desulfurization capacity to meet process as well as environmental needs.
While current crude imports are more than half sweet, only 15 percent of
OPEC's total oil reserve is sweet crude.28 Consequently, it is unlikely
that the sweet-sour crude import balance will remain constant. The price
differential between the two will eventually make sour crude processing a
necessary investment.
With regard to refined petroleum products, the importation of most
of these products is expected to decline as it has since the mid-1970's.
Table 9-14 shows that for the major refined products, imports peaked during
1973-1974. In general, imports of refined products have been relatively
small compared with production at domestic refineries. One notable exception
is residual fuel oil. The relatively high ratio of imports to domestic
production of this product is attributed to the orientation of U.S. refiner-
ies toward the production of higher levels of more valuable lighter products,
such as motor gasoline, through the "cracking" of residual oil. The importa-
tion of greater amounts of residual oil is therefore required to satisfy the
requirements of utilities and large industrial boilers in this country.
9.1.3.5 Exports. Exports of crude oil and refined petroleum products
are a small portion of total U.S. production, and amount to less than 8
percent of the volume imported.29 All exports are controlled by a strict
licensing policy administered by the U.S. Department of Commerce. Recently,
crude oil exports have increased in response to the Canada-United States
Crude Oil Exchange Program. The program is mutually beneficial in that
acquisition costs are minimized through improved efficiency of transporta-
tion.
Table 9-15 summarizes recent trends in major refined product exports.
The decline in exports through the 1970s can be attributed to both increased,
domestic demand and the expansion of foreign refining capacity.
9-22
-------
Table 9-14.
IMPORTS OF SELECTED PETROLEUM PRODUCTS BY YEARa
UNITED STATES, 1969-1979
(1,000 m3/cd)
Year
1969
1970
1971
1972
1973
1974
1975
1976
1977
1978
1979b
Motor
Gasoline
10
11
9
11
21
32
29
21
34
31
27
Distillate
Fuel Oil
22
24
24
29
62
46
25
23
40
27
14
Residual
Fuel Oil
201
243
252
277
295
252
194
225
216
214
178
Jet Fuel
20
23
29
31
34
26
21
12
12
14
11
Kerosene
0.5
0.6
0.2
0.2
0.3
0.8
0.5
1.4
3.0
1.7
1.4
NGL and LRG
6
8
17
28
38
34
29
31
32
N/A
N/A
Reference 13. Section VII.
^Reference 31.
N/A = not available.
9-23
-------
Table 9-15. EXPORTS OF SELECTED PETROLEUM PRODUCTS BY YEAR3
UNITED STATES, 1969-1978
(1,000 m3/cd)
Year
1969
1970
1971
1972
1973
1974
1975
1976
1977
1978
Motor
Gasoline
0.3
0.2
0.2
0.2
0.6
0.3
0.3
0.5
0.3
0.2
Distillate
Fuel Oil
0.5
0.5
1.3
0.5
1.4
0.3
0.2
0.2
0.2
0.5
Residual
Fuel Oil
7.3
8.6
5.7
5.2
3.7
2.2
2.4
1.9
1.0
2.1
Jet Fuel
0.8
1.0
0.6
0.3
0.8
0.3
0.3
0.3
0.3
0.2
Kerosene NGL and LRG
0.2 5.6
4.3
0.2 4.1
4.9
4.3
4.0
4.1
4.0
2.9
N/A
Reference 13. Section VII,
N/A = not available..
9-24
-------
9.1.4 Financial Profile
The financial status of the oil industry is generally regarded as
strong, a situation that is expected to continue into the 1980s.30 This
optimistic outlook is attributed to: increases in proven domestic reserves
and production, decreases in the level of imported oil, and the continuation
of the rising price patterns observed in recent years.
Profit margins and returns on investment for both major oil companies
and independent refiners are summarized in Tables 9-16 and 9-17. In those
tables, profit margin refers to net (after-tax) income as a percentage of
sales, while return on investment expresses net (after-tax) income as a
percentage of total investment or total assets. The general pattern observed
is one of increases in both margins and returns through the five year period
noted.
It should be noted that the margins and returns presented in both tables
are for companies that refine crude oil but are not necessarily indicative of
the profitabil ity of refining activities themselves. An indication of the
profitability of refining activities alone is provided by Table 9-18, which
summarizes the determination of industry profit margins by quarterly intervals,
9.2 ECONOMIC IMPACT ANALYSIS
9.2.1 Introduction and Summary
In the following section the economic impacts of the regulatory alterna-
tives are discussed. Economic impacts are presented in terms of the potential
price and profitability impacts associated with the imposition of each alter-
native.
As detailed in the following analysis, it is most likely that the cost
of regulation will be passed-on to the consumers of refined petroleum
products including gasoline, distillate fuel oil, kerosene, and residual fuel
oil. For all regulatory alternatives, except Alternative VI, the maximum
price increases will not exceed .17 percent at the wholesale level, and will
most likely be lower at the retail level. In the event Regulatory Alterna-
tive VI is promulgated, price increases as high as 2.88 percent may be pos-
sible.
The conclusions noted above are based upon observation of the cost of
required controls, the market values of refined petroleum products, and the
9-25
-------
Table 9-16. PROFIT MARGINS FOR MAJOR COPORATIONS
WITH PETROLEUM REFINERY CAPACITY, BY COMPANY TYPE AND YEAR,9 1975-1976
( Percent)
Integrated -International
British Petroleum
Exxon Corp.
Gulf Oil
Mobil Corp.
Royal Dutch Petroleum
Standard Oil (Calif.)
Texaco, Inc.
Integrated -Domestic
Amerada Hess
Ashland Oil
Atlantic Richfield
Cities Service
Clark Oil and Refining
Conoco, Inc.
Earth Resources
Getty Oil
Kerr-McGee
Marathon Oil
Phill ips Petroleum
Shell Oil
Standard Oil (Indiana)
Standard Oil (Ohio)
Sun Co .
Union Oil of California
Refiners
Charter Co.
Crown Central Petroleim
Holly Corp.
Tosco Corp.
United Refining
Reference 12, p. 088.
N/A = not available.
1975
1.9
5.6
4.9
3.9
6.7
4.6
3.4
4.0
3.3
4.8
4.3
0.9
4.6
4.5
8.6
7.3
4.5
6.7
6.3
7.9
5.1
5.0
4.6
1.0
1.2
3.1
N/A
1.8
1976
1.7
5.4
5.0
3.6
7.2
4.5
3.3
3.9
3.3
6.8
5.5
1.3
5.8
4.6
8.5
6.9
5.6
7.2
7.6
7.7
4.7
6.6
5.0
1.5
2.4
4.0
0.9
0.8
1977
3.0
4.5
4.2
3.1
6.0
4.9
3.3
3.9
3.4
6.4
4.8
1.6
4.4
4.5
9.9
5.5
4.6
8.2
7.3
7.6
5.2
5.6
5.9
1.3
2.0
3.8
1.2
2.1
1978
3.1
4.6
4.4
3.2
5.0
4.8
3.0
3.0
4.7
6.5
2.5
1.6
4.8
2.9
9.3
5.7
4.4
10.2
7.4
7.2
8.7
4.9
6.4
1.2
2.8
3.5
1.6
2.1
1979
8.9
5.4
5.5
4.5
11.1
6.0
4.6
7.5
8.1
7.2
5.5
3.6
6.4
4.1
12.5
6.0
4.4
9.4
7.8
8.1
15.0
6.6
6.6
8.7
6.8
2.6
4.1
3.4
9-26
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Table 9-17- RETURN ON INVESTMENT FOR MAJOR CORPORATIONS
WITH PETROLEUM REFINING CAPACITY, BY COMPANY TYPE AND YEAR,9 1975-1979
(Percent)
Integrated -Inter national
British Petroleum
Exxon Corp.
Gulf Oil
Mobil Corp.
Royal Dutch Petroleum
Standard Oil (Calif.)
Texaco, Inc.
Integrated -Domestic
Amerada Hess
Ashland Oil
Atlantic Richfield
Cities Service
Clark Oil and Refining
Conoco, Inc.
Earth Resources
Getty Oil
Kerr-McGee
Marathon Oil
Phillips Petroleum
Shell Oil
Standard Oil (Indiana)
Standard Oil (Ohio)
Sun Co .
Union Oil of Cal ifornia
Refiners
Charter Co.
Crown Central Petroleum
Holly Corp.
Tosco Corp.
United Refining
Reference 12, p. 087-088.
N/A = not available.
1975
2.0
7.8
5.6
5.6
6.8
6.3
4.8
5.5
6.3
5.2
4.5
1.7
6.7
12.9
8.2
10.1
6.7
8.0
7.8
8.4
3.6
5.2
6.3
2.0
2.9
9.1
N/A
5.0
1976
2.1
7.6
6.3
5.5
8.4
6.6
4.9
5.9
6.6
7.1
6.3
3.0
8.0
12.8
7.5
8.9
7.8
8.5
9.4
8.5
2.6
7.8
6.3
3.2
5.3
11.1
2.6
2.1
1977
4.3
6.5
5.4
5.1
8.0
7.1
5.0
6.0
6.7
6.8
5.7
4.5
6.0
10.9
8.0
6.9
6.1
9.5
8.7
8.4
2.3
6.6
7.0
3.2
5.1
10.6
2.8
5.6
1978
4.1
6.9
5.4
5.2
6.0
7.0
4.4
4.2
8.8
6.7
3.0
4.9
6.4
7.2
7.4
6.1
5.5
11.1
8.3
8.0
5.0
6.8
7.3
3.4
6.4
9.9
4.2
6.2
1979
11.8
9.5
8.2
8.0
13.5
10.2
8.1
11.3
20.2
8.9
7.9
10.6
9.7
8.5
11.2
7.3
7.3
11.5
8.4
9.6
13.4
10.2
8.7
29.1
16.8
8.0
14.2
11.0
9-27
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Table 9-18. PETROLEUM REFINING INCOME DATA BY QUARTER3
UNITED STATES REFINERIES, 1978-1980
($1,000,000,000)c
1978
1979
1980
2
3
Sales
41.75 43.88 46.17 48.52 50.72 54.71 63.68 73.58 79.80
Net Income
Before Tax 3.05 3.77 4.14 4.23 4.65 6.16 6.62 7.81 8.55
Net Income
2.55 3.15 3.41 3.66 3.95 5.25 5.71 6.84 8.04
% Net Income
to Salesb 6.11 7.18 7.39 7.54
7.79 9.60 8.97 9.30 10.08
Reference 12, p. 082.
^Profit margin.
cln current dollars.
9-28
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strength of market demand for such products. The projections of economic
impacts discussed below are based upon the capital and net annual ized control
costs presented in Chapter 8. Economic impacts have been estimated based
upon industry growth and supply and demand balances projected for the five
year period including the years 1982 through 1986.
9.2.2 Economic Impact Methodology
9.2.2.1 Estimation of Model Unit Revenues. Each of the model units
described in Chapter 6 represents a group of several types of refinery
process units, including those that produce directly marketable products
(e.g. gasoline and asphalt), as well as those that produce products subject
to further refining by downstream units (e.g. reformate and isomerate).
However, in order to provide a common basis by which price and profitability
impacts may be evaluated at the model unit level, the revenue potential of
each model unit has been estimated as the approximate market value of each
unit's output, regardless of whether that output is sold or processed further.
The determinations of daily revenues for model units A, B, and C are
summarized in Tables 9-19, 9-20, and 9-21 respectively. Each table includes
the following information related to each model unit;
• The unit types represented by the model unit,
• The major products of each unit type,
• The average daily capacity of each major product,
• The May 1980 wholesale price of each major product, and
• A weighting factor that represents the projected growth in unit
capacity.
Since the model units described in Chapter 6 do not specify capacity/
output levels, those output levels noted in Tables 9-19, 9-20, and 9-21, are
representative of the daily capacities of the "smaller" units currently in
operation. In this way the analysis is representative of the worst case
situation, since most units affected by this standard will probably have
larger capacity levels, and thus be capable of spreading control costs over
a larger volume of output.
In Tables 9-19, 9-20, and 9-21, the daily revenues of each model unit
are approximated by way of a two-step process. First, the daily value of the
output of each unit type is estimated through observation of the amount and
price of each product of each unit type. Then, daily model unit revenues are
9-29
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CO
o
Table 9-19. REVENUE ESTIMATION-MODEL UNIT A
(May 1980 Dollars)
Unit Type
Hyd retreating -
Isomerization-
Lubes-
Asphalt-
Hydrogen-
Product
Distillate Fuel
Residual Fuel
Isobutane,
Isopentane, etc.
Lubricating Oils
Asphalt
Hydrogen
Output
(m3/cd)
238
238
477
477
477
560,000
Y Price _
X ($/m3) -
205a
100a
79b
120b
120b
32.1/
1,000 m3b
Value
($/cd) x
48,790
23,800
72,590
37,683
57,240
57,240
18,000
Weighted
Growth
.72
.03
.06
.06
.13
1.00
Model Unit
Revenue
($/cd)
52,265
1,130
3,434
3,434
+2,340
62,603
Reference 32.
^Reference 33.
-------
I
CO
Table 9-20. REVENUE ESTIMATION-MODEL UNIT B
(May 1980 Dollars)
Unit Type
Alkyl at ion -
Thermal Cr ack ing-
Re form ing -
Vacuum
Distil lation-
Product
Alkyl ates
Coke
Gas & Naphtha
Light & Heavy
Gas Oil
Gasol ine &
Aromatics
LPG
Hydrogen
C4 & Light Dist.
Kerosine & Mid
Distil lates
Vacuum Gas Oil
& Residuals
Output
(m3/cd)
954
397
238
477
795
159
168,000
318
159
795
Price
X ($/m3) =
264a
151a
79a
157a
264a
79a
32.17
1,000 m3a
79a
211a
126a
Model Unit
Value Weighted Revenue
($/cd) x Growth ~ ($/cd)
251,856 .06 15,111
59,947
18,802
74,889
153,638 .19 29,191
209,880
12,561
5,400
227,841 .48 109,364
25,122
33,549
100,170
158,841 .27 +42,887
1.00 196,553
Reference 33.
-------
co
rss
Reference 32
bReference 33.
Table 9-21. REVENUE ESTIMATION-MODEL UNIT C
(May 1980 Dollars)
Unit Type
Crude
Distillation-
Catalytic
Cracking-
Product
C4 & Light Dist.
Kerosene & Mid
Distillates
Gas Oil &
Residuals
LPG
Gasol ine
Light & Heavy
Gas Oil
Output
(m3/cd) X
. 397
238
954
318
1,033
238
Price
($/m3)
79b
21lb
126b
79b
235a
I57b
Value
" ($/cd) x
31,363
50,218
120,204
201,785
25,122
242,755
37,366
305,243
Model Unit
Weighted Revenue
Growth " ($/cd)
.68 137,214
.32 +97,678
1.00 234,892
-------
Table 9-22. ANNUAL REVENUE SUMMARY BY MODEL UNIT
(May 1980 Dollars)
Model Unit
Full Capacity
Daily Revenue
($/cd)
Full Capacity
Annual Revenue
($/year)d
Capacity
Utilization
(percent)
Projected
Annual Revenue
($/year)
A
B
62,603a
196,553b
22,850,095
71,741,845
65e
65e
14,852,562
46,632,199
234,892C
85,735,580
656
55,728,127
^Table 9-19.
bTable 9-20.
cTable 9-21.
^Calendar year.
eReference 34.
9-33
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estimated by way of a weighted average, with weights assigned according to
future unit growth projections as presented in Appendix E. It should be
noted that since the revenue levels presented are based upon unit capacities,
an adjustment is required since it is highly unlikely that the affected units
will operate at full capacity over the forecast period (i.e., up to and
including 1986).
Annual revenues expected to be generated by each model unit are summar-
ized in Table 9-22, which notes the potential revenues of units operating at
full capacity, the projected rate of capacity utilization, and the annual
revenues associated with operation at less than full capacity. The projected
rate of refinery capacity utilization (65%) is that estimated by the U.S.
Department of Energy (see Table 9-8) for the year 1985. The projected annual
revenues noted in Table 9-22 are those used in the estimation of price and
profitability impacts as detailed below.
9.2.2.2 Estimation of Price Increases Under Full Cost Pricing. The
method used to estimate the price consequences of the control costs presented
in Chapter 8, is based upon the assumption that refiners can and will increase
the prices of refined products to a level required to cover the net annualized
costs to control fugutive VOC emissions from both new and modified/reconstructed
units. Under this assumption all control costs are eventually borne by the
consumers of refined petroleum products. Such a full cost pricing assumption
is supported by both the low elasticity of demand for refined products (see
Section 9.1.3.1), and the relatively small price increases required to cover
the estimated control costs.
The specific method used to estimate price increases is the expression
of the net annualized control costs, for each model unit and regulatory
alternative, as a percentage of what the revenue of the unit would be in the
absence of regulation. Such percentages are therefore indicators of the
percentage increases in model unit revenues, and thus product prices, needed
if profits after the implementation of a regulatory alternative are to remain
unaffected. This method assumes that output remains unchanged and that
refiners will not seek a return on the required investment in control equip-
ment. If in fact prices are set so that return on investment remains constant,
price increases as estimated by the method used in this analysis may be
slightly understated, (i.e. by less than .01 percent in the worst case).
9-34
-------
Potential price increases, estimated through the method noted above, are
summarized in Section 9.2.3.1, while the estimates of net annualized control
costs are presented in Tables 8-9, 8-10, and 8-11 for new units, and Tables
8-14, 8-15, and 8-16 for modified/reconstructed units. Estimates of model
unit revenues in the absence of an NSPS are described in Section 9.2.2.1.
9.2.2.3 Estimation of Profitability Impacts Under Full Cost Absorption.
In the unlikely event that refiners affected by this standard are unable to
pass the costs of control on to the consumers of refined petroleum products,
the profitability of particular refining activities could be decreased. In
an attempt to measure the extent of such profitability impacts,a comparison
of profit margins before and after regulation has been made.
There are two commonly used measures of profitability. Profit margin
is the ratio of net (after-tax) income to sales, while the return on invest-
ment (ROI) is the ratio of net (after-tax) income to total investment
or assets. Both measures are directly related by way of the asset turnover
ratio, or the ratio of sales to total investment. The relationship can be
expressed as follows:
net income sales
salesx investment KUi'
and explains why low profit margin, high turnover industries such as retail-
ing, may show the same ROI as a high profit margin, low turnover industries
such as heavy manufacturing. Since this analysis has already estimated sales
revenues for model units (Section 9.2.2.1), and is not complicated by inter-
industry comparisons that would introduce wide variations in the asset turn-
over ratio, the estimation of profitability impacts are discussed in terms of
changes in profit margins for the affected refining activities.
In practice, profit margin is expressed as a percentage rather than a
ratio as described above. Pre-control profit margins are therefore deter-
mined by:
Pre-control Profit Margin = (NI/AR) x 100
where: NI = Net Income (annual), and
AR = Annual Revenue (sales).
Pre-control profit margins and full cost absorption are determined under
the assumption that net income will be reduced by an amount equal to the
after-tax cost of control. After-tax costs are of concern since increased
9-35
-------
costs, in the absence of increased revenues, imply both reductions in taxes
as well as net income. Post-control profit margins with full cost absorption
are therefore determined by:
Post-control Profit Margin = ((NI-(NACC x (l-t)))/AR) x 100,
where: NI = Net Income (annual),
AR = Annual Revenue (sales),
NACC = Net Annualized Control Costs, and
t = Tax Rate (as a decimal).
Annual revenue estimates for each model unit are detailed in Tables 9-19,
9-20, and 9-21. Net annualized control costs are those presented in Tables
8-9, 8-10, and 8-11 for new units and Tables 8-14, 8-15, and 8-16 for modi-
fied/reconstructed units. The tax rate is assumed to be 46 percent since
this is the current Federal tax rate for taxable income greater than $100,000.
Finally, net income for each model unit is determined based upon a profit
margin of 5.12 percent in the absence of control. Net income for each model
unit can therefore estimated as follows:
NI = AR x .0512.
The baseline profit margin used in this analysis, 5.12 percent, has been
selected since it is the average (1979) profit margin reported for Refiners
in Table 9-16 and is considered conservative in light of recently increasing
margins (see Table 9-18). The estimation of profit margins with the regula-
tory alternatives and full cost absorption is made in Section 9.2.3.2.
9.2.3 Economic Impacts
9.2.3.1 Price Impacts. As noted in Section 9.2.2.2 potential price
increases of refined petroleum products have been estimated through the
expression of net annualized control costs as a percentage of individual
model unit revenues. The results of that procedure, summarized in Table
9-23 for for both new and modified/reconstructed units, show that for all
regulatory alternatives, with the exception of Alternative VI, maximum
potential price increases are less than .17 percent. As noted previously, it
is most likely that the very small percentage price increases associated with*
Regulatory Alternatives II through V will not be resisted by consumers in the
9-36
-------
form of decreased consumption. Consequently, the potential for industry
impacts, resulting from control-related demand reductions, is very low.
This conclusion is based upon two major observations. First, the
estimated elasticity of demand for refined petroleum products (see Table
9-9) is very low, due largely to the lack of reasonable substitute products.
The basic implication of low elasticity is that refiners can pass-on cost
increases and not experience significant reductions in demand. Second, the
recent history of rapid increases in the costs of imported crude oil along
with the price decontrol of domestically produced crude, have caused a
well-publicized rapid escalation in refined product prices. For example, for
the year November 1979 to November 1980 alone, wholesale prices for motor
gasoline, distillate fuel and residual fuel increased 28.7, 20.1, and 32.5
percent respectively.36 It is therefore unlikely that the worst case
price increases noted in Table 9-23 will cause further disruption under
the already highly volatile market situation.
It should be noted that the price increases discussed above are those
related to a situation where one refinery unit becomes subject to regulation.
In the event that a refinery constructs, reconstructs, or modifies more than
one unit, potential price increases may be slightly higher, dependent upon
the number, type, and size of additional units affected.
9.2.3.2 Profitability Impacts. For reasons noted in the previous
section, it is highly unlikely that the profitability of refining activities
will be affected by the imposition of control costs related to this standard.
However, this analysis has attempted to quantify the profitability reductions
associated with the inability of refiners to increase prices to a level
sufficient to cover those increased costs.
The method used in the estimation of profitability reduction is detailed
in Section 9.2.2.3, while the results of that procedure are summarized in
Table 9-24. As in the case of price increases, maximum potential profit
margin reductions are very low for Regulatory Alternatives II through V, and
if incurred, would most likely not affect decisions related to refinery unit
construction or modification. Regulatory Alternative VI however, does entail
significant reductions in profitability for all model units.
9.2.3.3 Capital Availability Impacts. Each of the regulatory alterna-
tives requires that capital expenditures be made for the purchase of control
equipment. These capital control costs are summarized in Table 8-2 for new
units and Table 8-13 for modified/reconstructed units.
9-37
-------
Table 9-23. PERCENT INCREASES IN PRICE
UNDER FULL.COST PRICING BY MODEL UNIT*
Regulatory Alternative
Unit Type
New Units
A
B
C
Modified/Reconstructed
A
B
C
II
.00
(.02)
(.08)
.00
(.02)
(.08)
III
.02
.00
(.01)
.03
.01
.01
IV
.11
.06
.12
.12
.07
.14
V
.13
.07
.14
.13
.08
.17
VI
1.85
1.15
2.70
1.91
1.17
2.88
*Values presented in this table are based on the ABCD model
discussed in Section 4.2.3.4. Analogous LDAR model values
are presented in Table F-31.
9-38
-------
Table 9-24. PROFIT MARGINS UNDER
FULL COST ABSORPTION BY MODEL UNIT*
(Baseline Profit Margin = 5.12 Percent)
Regulatory Alternative
Unit Type
New Units
A
B
C
Modified/Reconstructed
A
B
C
I
5.
5.
5.
5.
5.
5.
I
12
13
16
12
13
16
III
5.
5.
5.
5.
5.
5.
11
12
13
10
11
11
IV
5.
5.
06
09
5.05
5.
5.
5.
05
08
04
5
5
5
5
5
5
V
.05
.08
.05
.05
.08
.03
4.
4.
3.
4.
4.
3.
VI
12
50
66
09
49
57
*Values presented in this table are based on the ABCD model
described in Section 4.2.3.4. Analogous LDAR model values
are presented in Table F-32.
9-39
-------
The need to purchase additional capital equipment requires that inves-
tors in new refinery units must obtain capital financing above that which
would be required in the absence of regulation. Therefore, in order to
project the potential for impacts related to the high cost, or unavailability
of debt financing, an estimate of the percent increase in capital requirements
has been made by comparing capital control costs to the capital requirements
for construction of an uncontrolled refinery.
The U.S. Department of Energy has estimated37 that new refinery
construction in 1979 required an expenditure of $22,015 per m3 capacity per
stream day. Furthermore, the average size of the 64 small refineries con-
structed during the period 1974 to 1980 is 2226 m3 per calendar day38, Or
2,368 m3 per stream day assuming a calendar to stream day ratio of .94.1
Therefore the small refinery is estimated to require an investment of $52.1
million (1979) or $56.3 million after adjustment to May 1980 dollars.39
Inspection of Table 8-2 shows that for Regulatory Alternatives II
through V capital control costs for any model unit do not exceed $.47 million.
For these alternatives therefore, the worst case situation, that is the most
costly regulatory alternative and smallest refinery, shows an increase in
capital investment requirements of less than one percent. This fact together
with improved earnings and cash generation should enable refiners to finance
capital expenditures without using outside funds,40 and thus avoid poten-
tial problems related to the unavailability or high cost of debt financing.
9.3 SOCIOECONOMIC AND INFLATIONARY IMPACTS
Section 9.2 described potential impacts of the regulatory alternatives
largely from the viewpoint of the refining industry. Section 9.3 expands
this perspective to encompass the whole economy. In addition, impacts on
small businesses and other small-scale concerns are reviewed.
9.3.1 Fifth-Year Annualized Costs
The total dollar cost of an NSPS increases over the first few years as
more and more new sources are constructed, and old sources are modified and
reconstructed. Then, as control equipment is depreciated and new units are
retired, modified, or reconstructed, the cost levels out and may decline. To
facilitate the analysis, comprehension, and comparison of many diverse regu-
lations, the Environmental Protection Agency, for each regulatory alternative,
calculates one uniform measure of this total cost. This is the fifth-year
annualized cost. It is a before-tax figure, about half of which will be
9-40
-------
deducted from the taxes corporations must pay. Thus, the results are pro-
jections of the total dollar costs of control not just to industry, but to
society as a whole.
Appendix E describes and summarizes the results of the method used to
project the construction of new, and the reconstruction and modification of
existing, refinery units that will be subject to this standard up to the year
1986. According to those projections and the net annualized cost estimates
presented in Chapter 8, the total net annualized costs in the fifth-year after
regulation have been estimated. For all regulatory alternatives with the
exception of Alternative VI, such costs are less than $15.44 million. The
fifth-year annualized costs above baseline estimates are ($2.05), $3.58, $13.55,
$15.44, and $212.99 mill ion, for Regulatory Alternatives II, III, IV, V, and
VI respectively. The fifth-year costs are estimated by the multiplication of
net annualized control costs by the number of units expected to be affected
through 1986. The results of this procedure are summarized in Table 9-25.
9.3.2 Inflationary Impacts
Under Regulatory Alternatives II through V, maximum potential wholesale
price increases for refined petroleum products are less than .17 percent. For
this reason the imposition of those regulatory alternatives will cause virtu-
ally no increase in the rate of inflation as measured by either the Consumer
Price Index or Producer Price Index. However promulgation of a standard in
the form of Regulatory Alternative VI, with possible price increases of as
much as 2.88 percent, could have some impact upon the rate of inflation.
9.3.3 Employment Impacts
With the exception of Regulatory Alternative VI the cost of control
should have very little impact upon the demand for the products of, or the pro-
fitability of the affected units. For this reason the decision to construct
new or modify existing refinery units will be unaffected by such controls.
Under such circumstances, the standard will have no negative impact upon
employment trends in the petroleum refining industry. On the other hand, since
each of the regulatory alternatives entails additional labor support for moni-
toring and the maintenance of control equipment, slightly positive employment
impacts could result.
9-41
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Table 9-25. SUMMARY OF FIFTH-YEAR
NET ANNUALIZED COSTa'b
(Thousands of May 1980 Dollars)
Regulatory Alternative
Unit Type
New Units
Mod i f i ed/Reconstructed
TOTAL
II
(591)c
(l,462)c
(2,053)c
III
782
2,793
3,575
IV
3,956
9,590
13,546
V
4,376
11,064
15,440
VI
64,819
148,166
212,985
Values presented in this table are based on the ABCD model discussed
in Section 4.2.3.4. Analogous LDAR model values are presented in
Table F-33.
Costs are "above baseline" costs as explained in Section 3.3.
cParentheses indicate net cost reduction due to product
recovery credits.
9-42
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9.3.4 Balance of Trade Impacts
As noted in Sections 9.1.3.4 and 9.1.3.5 the import and export of refined
petroleum products represent very small portions of total domestic production
and consumption. This fact together with the small price and profitability
impacts previously noted indicate no potential for impact upon the United
States balance of trade.
9.3.5 Regulatory Flexibility Act - Small Refinery Impacts
The Regulatory Flexibility Act of 1980 requires the identification of
the potentially adverse effects of all Federal regulations upon small busi-
nesses, small governmental units, and small non-profit organizations.
According to current Small Business Administration guidelines established for
the purpose of providing pollution control guarantee assistance under Public
Law 94-305, (43 Federal Register 36052, August 15, 1978) a small business in
the petroleum refining industry is one that has fewer than 1,500 employees.
This total includes the refinery itself along with any affiliated operations.
At the present time there are many small companies that refine petro-
leum and employ fewer than 1,500 persons. A primary reason for the large
population of small refineries is the existence of Federal government subsidy
programs that prompted the construction of many small refineries during the
1970's. Specific subsidies such as the "small refiners bias" built into the
DOE crude oil entitlements program have had the effect of neutralizing the
diseconomies of scale that are inherent in small refinery operations. Such
subsidy programs were effective in encouraging the construction of small
refineries to the extent that about 64 refineries having average capacity of
2,226 m3 per calendar day were constructed during the period January 1,
1974 to January 1, 1980.38
It is not expected that any totally new "grass roots" refineries will
be constructed within the next five years. Furthermore, very few of the
small refineries that are currently in operation will become subject to the
regulatory alternatives previously described. This is true for two reasons.
First, the recent price decontrol of crude oil and refined petroleum products
(Executive Order 12287, January 28, 1981) has had the effect of eliminating
the subsidies noted above, thus removing the competitive advantage those
subsidies provided. Consequently, small refineries, for reasons unrelated to
the regulatory alternatives, may lack the ability to attract the capital
resources required to finance new unit construction and reconstruction or
9-43
-------
modification. Second, the fact that many of the small refineries currently
in operation were constructed during the 1970's suggests that they have not
depreciated to the point where reconstruction or modification is necessary.
Therefore, because Section 111 standards apply only to newly constructed,
modified or reconstructed units, few of the small refineries are expected to
be subject to the regulatory alternatives.
If any small refineries should become subject to the regulatory alter-
natives they will not be adversely affected. This can be said because the
price and profitability impacts previously described have been estimated from
the perspective of the "smaller" refinery units currently in operation. Thus
the results presented can be accurately interpreted as those that may affect
small refineries that become subject to this regulation. It can be concluded,
therefore, that the regulatory alternatives in the form described in the
previous sections, will have no significant economic impact upon small
refineries.
9.3.6 Executive Order 12291
According to the directives of Executive Order 12291 "major rules" are
those that are projected to have any of the following impacts:
• an annual effect on the economy of $100 million or more,
• a major increase in costs or prices for consumers, individual
industries, Federal, State, or local government agencies, or
geographic regions, or
• significant adverse effects on competition, employment, invest-
ment, productivity, innovation, or on the ability of United
States - based enterprises to compete with foreign-based enter-
prises in domestic or export markets.
If a regulation is determined to be a major rule as defined above, the regu-
latory agency is required to undertake a Regulatory Impact Analysis, the form
and content of which is described in Section 3 of the Executive Order.
With the exception of Regulatory Alternative VI, the alternatives
described in Chapter 6 will not cause impacts characteristic of major rules.
This is true because each of Regulatory Alternatives II through V is
estimated to entail fifth-year annualized costs of less than $15.4 million,
petroleum product price increases of less than .17 percent, and no adverse ,
effects on competition, employment, investment, productivity, innovation, or
9-44
-------
the United States' balance of trade. For this reason it has been concluded
that a Regulatory Impact Analysis is not required.
Section 2(b) of Executive Order 12291 requires that, to the extent
permitted by law, regulatory action must not be undertaken unless the
potential benefits to society from the regulation outweigh the potential
costs to society. A formal benefit-cost study has not been completed due
to the costs and time required to complete such an analysis, and because the
regulatory alternatives do not constitute a major rule as defined by the
Executive Order.
Along with the costs and impacts described in both Chapters 8 and 9,
each of the regulatory alternatives will create real benefits to society.
Because the alternatives will reduce the rate of emission of VOC to the
atmosphere, and because VOC are precursors of photochemical oxidants, the
ambient concentrations of such oxidants, particularly ozone, will be affect-
ed. The benefits of reduced exposure to ozone will be expressed in terms of
the avoidance of the following health effects.
• Human health effects - ozone exposure has been shown to cause
increased rates of respiratory symptoms such as coughing, wheez-
ing, sneezing, and short-breath; increased rates of headache,
eye irritation and throat irritation; and increases in the number
of red blood cells (changes in erthrocytes). One experiment
links ozone exposure to human cell damages known as chromosomal
aberations.
• Vegetation effects - reduced crop yields as a result of damages
to the leaves and/or plants have been shown for several crops
including citrus, grapes, and cotton. The reduction in crop
yields was shown to be linked to the level and duration of ozone
exposure.
• Materials effects - ozone exposure has been shown to accelerate
the deterioration of organic materials such as plastics and
rubber (elastomers), textile dyes, fibers, and certain paints and
coatings.
• Ecosystem effects - continued ozone exposure has been shown to be
linked to structural changes of forests such as the disappearance
of certain tree species (Ponderosa and Jeffrey pines) and death
9-45
-------
of predominant vegetation. Hence ozone causes a stress to the
ecosystem.
In addition, the regulatory alternatives are likely to improve the
aesthetic and economic value of the environment through the beautification of
natural forests and undeveloped land through increased vegetation, increased
visibility, reduced incidence of noxious odors, increased length of life for
works of art including paintings, sculpture, architecturally important
buildings and historic monuments, improved appearance of structures, sculp-
tures, and paintings, and improved productivity of workers.
9-46
-------
9.4 REFERENCES
1. U.S. Department-of Energy. Energy Information Administration.
Petroleum Refineries in the United States and U.S. Territories.
January 1, 1980. DOE/EIA-0111 (80). Docket Reference Number 11-1-42.*
2. Cantrell, A. Annual Refining Survey. Oil and Gas Journal. 68(14).
April 6, 1970. Docket Reference Number II-I-10.*
3. Cantrell, A. Annual Refining Survey. Oil and Gas Journal.
69(12):73. March 22, 1971. Docket Reference Number II-I-12.*
4. Cantrell, A. Annual Refining Survey. Oil and Gas Journal.
70(13):84. March 27, 1972. Docket Reference Number II-I-14.*
5. Cantrell, A. Annual Refining Survey. Oil and Gas Journal.
71(14). April 2, 1973. Docket Reference Number II-I-17.*
6. Cantrell, A. Annual Refining Survey. Oil and Gas Journal.
72(13). April 1, 1974. Docket Reference Number II-I-18.*
7. Cantrell, A. Annual Refining Survey. Oil and Gas Journal.
73(14):98. April 7, 1975. Docket Reference Number II-I-21.*
8. Cantrell, A. Annual Refining Survey. Oil and Gas Journal.
74(13):129. March 29, 1976. Docket Reference Number II-I-23.*
9. Cantrell, A. Annual Refining Survey. Oil and Gas Journal.
75(13):98. March 28, 1977. Docket Reference Number II-I-25.*
10. Cantrell, A. Annual Refining Survey. Oil and Gas Journal.
76(12):113. March 20, 1978. Docket Reference Number II-I-28.*
11. Cantrell, A. Annual Refining Survey. Oil and Gas Journal.
77(3): 127. March 26, 1979. Docket Reference Number II-1-38.*
12. Standard and Poor's. Industry Surveys - Oil. August 7, 1980
(Section 2). p. 074. Docket Reference Number II-I-50.*
13-. American Petroleum Institute. Basic Petroleum Data Book.
Section VIII. Tables 4-4a. Docket Reference Number 11-1-34.*
14. Reference 12, p. 081.
15. Reference 12, p. 079.
16. Reference 13, Section V, Table 2.
17. Reference 13, Section V, Table 1.
18. Cost of Benzene Reduction in Gasoline to the Petroleum Refining
Industry. U.S. Environmental Protection Agency. Office of Air
Quality Planning and Standards. EPA-450/2-78-021. April 1978,
page 1-3. Docket Reference Number II-A-5.*
9-47
-------
19. Jones, Harold. Pollution Controls in the Petroleum Industry.
Noyes Data Corporation. Park Ridge, NJ. 1973. 332 pp. Docket
Reference Number 11-1-16.*
20. 1978 Refining Process Handbook. Hydrocarbon Processing. 56(g):97-224.
September 1978. Docket Reference Number II-I-32.*
21. Boland, R.F., et al. Screening Study for Miscellaneous Sources
of Hydrocarbon Emissions in Petroleum Refineries. EPA Report
No. 450/3-76-041. December 1976. Docket Reference Number II-A-3.*
22. Energy Information Administration. U.S. Department of Energy.
Annual Report to Congress 1979. Vol. 3. p. 114. Docket Reference
Number II-I-35.*
23. Hoffman, H.C. Components for Unleaded Gasoline. Hydrocarbon
Processing. 59(2):57. February 1980. Docket Reference
Number II-I-44.*
24. Reference 21, p. 116.
25. Reference 21, p. 333.
26. Reference 12, p. 061.
27. Reference 12, p. 062.
28. Johnson, Axel R. Refining for the Next 20 Years. Hydrocarbon
Processing. 58(9):109. September 1979. Docket Reference
Number II-I-41.*
29. Beck, J.R. Production Flat; Demands, Imports Off. Oil and Gas
Journal. 78(4):108. January 28, 1980. Docket Reference
Number 11-1-43.*;
30. Reference 12, p. 082.
31. Reference 28, p. 109.
32. Chase Manhattan Bank. The Petroleum Situation. 4(8):4. August 1980.
Docket Reference Number 11-1-49.*
33. Letter from T. Rhoads, Pacific Environmental Services, Inc., to T.V.
Costello, JACA Corp. October 13, 1980. Output and value of small
refinery units. Docket Reference Number II-B-31.*
34. Reference 22, p. 115.
35. Commerce Clearing House, Inc. 1979 U.S. Master Tax Guide, p. 26.
Docket Reference Number II-I-36.*
36. Chase Manhattan Bank. The Petroleum Situation. 4(12):4.
December 1980. Docket Reference Number 11-1-52.*
9-48
-------
37. Reference 22, p. 322.
38. Reference 12, p. 075.
39. CE Plant Cost Index. Chemical Engineering. 87(19):7. September 22,
1980. Docket Reference Number II-I-58.*
40. Reference 12. p. 084.
*References can be located in Docket Number A-80-44 at the U.S.
Environmental Protection Agency Library, Waterside Mall, Washington, D.C.
9-49
-------
APPENDIX A
EVOLUTION OF THE BACKGROUND
INFORMATION DOCUMENT
A-l
-------
APPENDIX A - EVOLUTION OF THE
BACKGROUND INFORMATION DOCUMENT
Date
August 9-12, 1976
November 3-4, 1976
November 8-10, 1976
November 16-17, 1976
February 8-14, 1977
April 19-20, 1977
May 1977
April 1978
April 26-28, 1978
June 1978
Nature of Action
Plant visit to Los Angeles Air Pollution
Control District and four Los Angeles area
petroleum refineries (Fletcher Oil and Re-
fining Company, Atlantic Richfield Watson
Petroleum Refinery, Shell Oil Company Wilmington,
Champlin Wilmington Refinery) to obtain
background information on miscellaneous
sources of hydrocarbon emissions from petroleum
refineries.
Meetings with Exxon Company, USA and Shell
Oil Company to discuss EPA request for information
on hydrocarbon emission sources and controls.
Plant visits to four New Orleans, Louisiana,
petroleum refineries (Murphy, Gulf, Tenneco,
and Shell) to obtain background information
on miscellaneous sources of hydrocarbon
emissions in petroleum refineries.
Meetings with Standard Oil of California and
Union Oil of California to discuss EPA requests
for information on hydrocarbon emission
sources and controls.
Emission source testing at Atlantic Richfield
Watson Petroleum Refinery, Carson, California,
and Newhall Refining Company, Newhall, California.
Plant vist to "Refinery A," Corpus Christi,
Texas, to gather information for Control
Techniques Guideline (CTG) documents.
First draft CTG, "Control of Hydrocarbons
from Miscellaneous Refinery Sources."
Second draft CTG, "Control of VOC leaks from
Petroleum Refining Equipment."
Radian/IERL Symposium on refinery emissions,
Jekyll Island, Georgia.
Publication of final CTG, "Control of Volatile
Organic Compound Leaks from Petroleum Refinery
Equipment."
A-2
-------
June 29, 1978
June 30, 1978
July 6, 1978
July 13, 1978
July 14, 1978
November 13-17, 1978
March 5-8, 1979
March 7, 1979
June 20, 1979
June 21, 1979
November 5-6, 1979
July 14, 1980
Plant visit to Phillips Petroleum Company,
Sweeny, Texas, to collect information on
emissions from benzene-related petroleum
refinery operations.
Plant visit to Exxon Chemical Company, Baytown,
Texas, to collect information on emissions
from benzene-related petroleum refinery
operations.
Plant visit to Sun Petroleum Products Company,
Toledo, Ohio, to observe and discuss BTX and
THD units.
Plant visit to Gulf Oil Refinery, Philadelphia,
Pennsylvania, to collect information on
emissions from benzene-related petroleum
refinery operations (UDEX and toluene dealkylation
unit).
Plant visit to Sun Petroleum Products Company,
Marcus Hook, Pennsylvania, to collect infor-
mation on emissions from benzene-related
petroleum refinery operations.
Plant visit and emission source testing at
Sun Petroleum Products Company, Toledo, Ohio,
of BTX and HDA units.
Plant visit and emission source testing at
Phillips Petroleum Company, Sweeny, Texas,
refinery.
Plant visit to Phillips Petroleum Company,
Sweeny, Texas, refinery and NGL Processing
Center.
Visit to Chevron Company, U.S.A., El Segundo,
California, refinery to discuss fugitive VOC
emissions.
Visit to Atlantic Richfield Company, Carson,
California, refinery to discuss fugitive VOC
emissions.
Radian/IERL Symposium on refinery emissions,
Austin, Texas.
Meeting between EPA and the American Petroleum
Institute to discuss pump seal technology,
Durham, N.C.
A-3
-------
September 18, 1980
September -
October 1980
October 15, 1980
May 4, 1981
June 2-3, 1981
July 7, 1981
September 1981
Completion of preliminary model units and
regulatory alternatives for petroleum refinery
VOC fugitive emissions standard development;
request for industry review and comment.
Public comments on preliminary model units
and regulatory alternatives.
EPA request to industry for information on
wastewater separators, cooling towers, and
accumulator vessels.
Completion of Refinery VOC Fugitives preliminary
draft background document and distribution to
NAPCTAC, industry, environmental groups, and
other interested persons.
Meeting of the National Air Pollution Control
Techniques Advisory Committee to review the
refinery VOC fugitive emissions standard,
Alexandria, VA.
Meeting between EPA and American Petroleum
Institute to discuss compressor seal technology,
Durham, N.C.
Model for evaluating the effects of leak
detection and repair (LDAR) programs on
fugitive emissions.
A-4
-------
APPENDIX B
INDEX TO ENVIRONMENTAL CONSIDERATIONS
This appendix consists of a reference system which is cross-indexed
with the October 21, 1974, Federal Register (39 FR 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-l
-------
APPENDIX B
INDEX TO ENVIRONMENTAL IMPACT CONSIDERATIONS
CO
I
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 pages 3-1 through 3-3. Details of
the "business/economic" nature of the industry
are presented in Chapter 9, pages 9-1 through 9-25.
A description of the sources affected by the
regulatory alternatives is presented in Chapter 3,
Section 3.2, pages 3-3 through 3-14.
A discussion of available emission control
techniques is presented in Chapter 4, Section 4.3,
pages 4-12 through 4-25.
Various regulatory alternatives are discussed in
Chapter 6, Section 6.3, pages 6-4 through 6-7.
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 7-10 through 7-11.
Cost impacts of the various regulatory alternatives
are discussed in Chapter 8, Section 8.1, pages 8-1
through 8-27.
The economic impacts of the various regulatory
alternatives are presented in Chapter 9, Sections
9.2 and 9.3, pages 9-25 through 9-46.
ca
i
CO
-------
APPENDIX C
EMISSION SOURCE TEST DATA
C-l
-------
APPENDIX C
EMISSION SOURCE TEST DATA
The purpose of Appendix C is to describe testing results used in
developing the Background Information Document (BID) for fugitive emis-
sions from the Petroleum Refining Industry. The information contained
in this appendix includes a description of the facilities and procedures
used in the studies. Section C.I, the results of fugitive emission
testing, presents leak frequencies and emission factors for fugitive
sources. And, maintenance testing on valve emissions is discussed in
Section C.2.
C.I FUGITIVE EMISSIONS TEST PROGRAMS
C.I.I Description and Results of a 13-Refinery Study
Data concerning the leak frequencies and emission factors for
various fugitive sources were obtained primarily at nine refineries.
More complete information for compressor and relief valve emissions
was obtained by sampling at four additional refineries. The refineries
selected for study comprise a range of sizes and ages and the major
petroleum refinery processing units. The type of process units and the
number of each studied in the first nine refineries are listed in Table C-l.
In each refinery, sources in six to nine process units were selected
for study. The approximate number of sources selected for study and
testing in each refinery is listed below:
Valves 250-300
Flanges 100-750
Pump seals 100-125
Compressor seals 10-20
Drains 20-40
Relief valves 20-40
There were normally 500 to 600 sources selected in each refinery.
C-2
-------
TABLE C-l. SAMPLED PROCESS UNITS FROM NINE REFINERIES9
Number of
Refinery process unit sampled units
Atmospheric distillation 7
Vacuum distillation 4
Thermal operations (coking) 2
Catalytic cracking 5
Catalytic reforming 6
Catalytic hydrocracking 2
Catalytic hydrorefining 2
Catalytic hydrotreating 7
Alkylation 6
Aromatics/isomerization 3
Lube oil manufacture 2
Asphalt manufacture 1
Fuel gas/light-ends processing 11
LPG 2
Sulfur recovery 1
Other 3
TOTAL 64
Reference 1
C-3
-------
The distribution of sources among the process units was determined
prior to the selection and testing of individual sources. Individual
sources were selected from piping and instrumentation diagrams or
process flow diagrams before a refinery processing area was entered.
Only those preselected sources were screened. In this way, bias based
on observation of individual sources was theoretically eliminated.
The sources were screened with portable organic vapor detectors.
The principal device used in this study was the J.W. Bacharach Instrument
Company "TLV Sniffer" calibrated with hexane. The components were
tested on an individual basis, and only those components with concen-
trations in excess of 200 ppmv were considered for further study. A
substantial portion of these leaking sources were enclosed and sampled
to determine both the methane and nonmethane emission rates.
Emission factors and leak frequency information generated during
this study are given in Table C-2.
C.I.2 Description and Results of Testing at Six U.S. Refineries
A field testing program was conducted to collect data for use in
developing an approach for controlling VOC fugitive emissions in the
petroleum refining industry. A total of six refineries located throughout
the continental U.S. were surveyed to collect emission data and/or
maintenance data from individual components of various refinery process
units. All units were operating normally throughout the test period.
Table C-3 presents a summary of the components tested and the percent
of components that were found leaking at or above a specified VOC
concentration level.
C.I.2.1 Discussion and Results of Emission Testing at Refineries
2
1 and 2. Testing was conducted by EPA personnel at refineries 1
and 2 to develop a basic testing approach for VOC leaks from refinery
equipment, to obtain comparative test data for procedure selection,
and to collect emission data for use in formulating a recommended
level of control. Refinery 1 is a medium-sized integrated refinery,
and Refinery 2 is a small-sized crude topping refinery.
C.I.2.2 Saturated Gas Plant and Aromatic Extraction Unit at
4
Refinery 3. Individual component surveys were conducted in a saturated
gas plant and an aromatic extraction unit at a fairly large integrated
refinery in the U.S. Gulf Coast area. Sampling was conducted using a
C-4
-------
TABLE C-2. LEAK FREQUENCIES AND EMISSION FACTORS
FROM FUGITIVE SOURCES*
-.1 II
Percent of
sources having Confidence interval
screening values (%) for
Equipment
type
Valves
Gas service
Light liquid service
Heavy liquid service
Pump seals
Light liquid service
Heavy liquid service
Compressor seals
Pressure relief valves
Flanges
Open-ended lines
>10,000 ppmv percent leaking,
TLV-Hexane
10
11
0
24
2
36
7
0
h
>10,
6
8
0
19
0
26
2
0
000 ppmv
- 14
- 14
- 1
- 26
- 5
- 44
- 13
- 1
b
Reference 1.
'No data were available for open-ended lines.
C-5
-------
TABLE C-3. SUMMARY OF COMPONENTS TESTED AND
PERCENT LEAKING IN SIX REFINERIES
Number of Components Tested (N) and Percent Leaking (%)
Pressure
Relief
Pump seals Compressor Seals Valves Devices
Refinery
1
2
3
4
5
6
a
a
b
c
d
e
N
87
25
43
327
63
190
(«)
(6.
(4.
(16.
(14.
(6.
(21.
9)
o)f
2)
7)
3)f
6)
N
2
0
1
12
0
33
W
(0)
(0)
(0)
(0)
(0)
(3.0)
N
201
28
206
835
1300
3052
(%)
(9.
(0)
(17.
(4.
(3.
(9.
0)
5)
0)
6)
0)
N
15
0
0
0
0
0
(*)
(0)
(0)
(0)
(0)
(0)
(0)
TOTAL
735 (14.6) 48 (2.1)
5622 (7.3) 15 (0)
Reference 2 - Testing was conducted with a Century Systems organic
vapor analyzer, Model OVA-108, calibrated with methane, at 5 cm from
each source. A leak is defined as greater than or equal to 1,000 ppmv
at 5 cm, which is approximately equal to a leak concentration of
greater than or equal to 10,000 ppmv at 0 cm (Reference 3).
Reference 4 - Test method and leak definition as in footnote a.
Reference 5 - Test method and leak definition as in footnote a.
Reference 6 - All measurements were performed by traversing the
instrument probe at the surface of the potential leak interface
(0 cm) with the OVA-108 calibrated with methane. A leak is defined
as greater than or equal to 10,000 ppmv.
Reference 7 - Test method and leak definition as in footnote d.
Some pump seals were equipped with dual mechanical seals.
C-6
-------
Century Systems Corporation OVA-108 organic vapor analyzer calibrated
with methane. Emissions were measured from pump seals, compressor
seals, drains, block valves, control valves, and open-ended valves at
5 cm from the potential leak source. Of the total 274 components
screened, 36 percent were found to have emissions greater than 100 ppm
and 18 percent greater than 1,000 ppm.
It was determined that leak measurement would be conducted at a
distance of 5 cm since localized wind and dispersion conditions made
measurement at greater distances highly variable.
5
C.I.2.3 Emission Testing at Refinery 4. Leaks were measured
from seals, valves, control valves, and drains of the aromatics extraction
(BTX) unit at Refinery 4. A portable hydrocarbon analyzer was used to
determine the localized VOC concentration near individual sources and
the ambient VOC levels in the unit processing areas. Individual
component surveys were conducted at 5 cm from the potential leak
source. Of all the equipment tested in the unit, 4.2 percent of the
total valves and 15 percent of the pump seals were found to have
concentrations greater than 1,000 ppm at 5 cm.
C.I.2.4 Emission Testing at Refinery 5. Refinery 5 is an
intermediate-size integrated petroleum refinery located in the North
Central United States. Testing was conducted during November 1978
primarily to gather data on leaking components (defined by a VOC
concentration of greater than or equal to 10,000 ppmv at 0 cm from the
source) in two units that process pure benzene. Individual component
surveys were performed using the OVA-108 VOC detector calibrated with
methane. The probe was placed at the surface of the potential leak
interface (0 cm) to eliminate the wind variability of the measurements,
thus improving repeatability.
One of the units tested is a BTX aromatics extraction unit that
produces benzene, toluene, and xylene by extraction from refined
petroleum feedstocks. The BTX unit was about one year old when tested,
and special attention was given during the design and start-up to
minimize equipment leaks. Valves were repacked before start-up with
two to three times the normal packing. All pumps in benzene service
were equipped with dual mechanical seals with a barrier fluid, and all
relief valves and process accumulator vessels were tied into the flare
header system.
C-7
-------
The toluene hydrodealkylation (HDA) unit was originally designed
as a naphthalene unit, hut was later shutdown and modified to produce
benzene. Both BTX and HDA units were equipped with area-monitoring
systems.
C.I.2.5 Emissions Testing at Refinery 6. Equipment leak testing
was performed at various units in Refinery 6 in March 1979. Six
process units were surveyed to determine localized VOC concentrations
around individual pieces of equipment by using Model OVA-108 calibrated
with methane. Measurements were made at the surface of potential leak
sources and recorded as the maximum concentration at the seal interface.
The results were used to calculate the frequency of occurrence of various
concentration ranges.
C.2 MAINTENANCE TEST PROGRAMS
This section discusses the results of four studies on the effects
of maintenance on fugitive emissions from valves. The first two studies
were conducted by refinery personnel at the Union Oil Company refinery
in Rodeo, California, and the Shell Oil Company refinery in Martinez,
California. These programs consisted of maintenance on leaking valves
containing fluids with actual vapor pressures greater than 1.5 Reid Vapor
Pressure. The third study was conducted at four refineries by EPA.
The fourth study, also conducted by EPA, examined maintenance
effectiveness at an ethylene production unit. The results and description
of each test program are given in the following sections.
g
C.2.1 Description and Results of the Union Maintenance Study
The Union valve maintenance study consisted of performing undirected
maintenance on valves selected from 12 different process units. Main-
tenance procedures consisted of adjusting the packing gland while the
valve was in service. Undirected maintenance consists of performing
valve repairs without simultaneous measurement of the effect of repair
on the VOC concentration detected. This is in contrast to directed
maintenance where emissions are monitored during the repair procedure.
With directed maintenance, repair procedures are continued until the
VOC concentration detected drops to a specified level or further reduc-
tion in the emission level is not possible. Also, maintenance may be
curtailed if increasing VOC concentrations result.
C-8
-------
The Union data were obtained with a Century Systems Corporation
Organic Vapor Analyzer, OVA-108. All measurements were taken at a
distance of 1 cm from the seal. Correlations developed by EPA have
been used to convert the data from OVA readings taken at 1 centimeter
to equivalent TLV readings at the leak interface (TLV-0).1 This facili-
tates comparison of data from different studies and allows the estimation
of emission rates based on screening values-leak rate correlations.
The results of the Union study are given in Table C-4. Two sets
of results are provided; the first includes all repaired valves with
before maintenance screening values greater than or equal to 5,300 ppmv
(OVA-108), and the second includes valves with before maintenance
screening values below 5,300 ppmv (OVA-108). A screening value of
5,300 ppmv, obtained with OVA at 1 cm from the leak interface, is equiva-
lent to a screening value of 10,000 ppmv measured by a Bacharach Instrument
Company "TLV Sniffer" directly at the leak interface. The OVA-1 cm
readings have been converted to equivalent TLV-0 cm readings because:
1) EPA correlations which estimate leak rates from screening
values were developed from TLV-0 cm data.
2) Additional maintenance study data exists in the TLV-0 cm
format.
3) Method 21 specifies 0 cm screening procedures.
The results of this study indicate that maintenance on valves with
initial screening values above 10,000 ppmv (OVA-108) is much more effec-
tive than maintenance on valves leaking at lower rates. In fact, this
study indicates that emissions from valves are reduced by an average of
51.8 percent for valves initially over 5,300 ppmv, while valves with lower
initial screening values experienced an increase of 30.5 percent.
9
C.2.2 Description and Results of the Shell Maintenance Study
The Shell maintenance program consisted of two parts. First, valve
repairs were performed on 171 leaking valves. In the second part of the
program, 162 of these valves were rechecked and additional maintenance
was performed. Maintenance consisted of adjusting the packing gland
while the valve was in service. The second part of the program was
conducted approximately one month after the initial maintenance period.
It was not determined whether the maintenance procedures were directed
or undirected, based on the information reported by Shell.
C-9
-------
o
I
TABLE C-4. SUMMARY OF MAINTENANCE STUDY RESULTS FROM THE UNION OIL COMPANY
REFINERY IN RODEO, CALIFORNIA3
Number of repairs attempted
Number of successful repairs (<5
Percent successful repairs
,300 ppmv after maintenance)
Estimated emissions before maintenace, kg/hr
Estimated emissions after maintenance, kg/hr
Percent reduction in emissions
Number of valves with decreased
Percent of valves with decreased
Number of valves with increased
Percent of valves with increased
emissions
emissions
emissions
emissions
All valves
with initial
screening values
>5,300 ppmvb
133
67
50.4
9.72
4.69
51.8
124
93.2
9
6.8
All valves
with initial
screening values
<5,300 ppmv
21
—
—
0.323
0.422
-30.5
13
61.9
8
38.1
Reference 8.
The value 5,300 ppmv, taken with the OVA-108 at 1 cm, generally corresponds to a value of
10,000 ppmv taken with a "TLV Sniffer" at 0 cm.
-------
VOC emissions were measured using the OVA-108, and readings were
obtained 1 centimeter from the source. These data have been transformed
to TLV-0 cm values as was the Union data. The same methods of data
analysis described in Section C.2.1 have been applied to the Shell
data. The results of the Shell maintenance study are given in Table C-5.
C.2.3 Description and Results of the EPA Maintenance Study
Repair data were collected on valves located in four refineries.
The effects of both directed and undirected maintenance were evaluated.
Maintenance consisted of routine operations, such as tightening the
packing gland or adding grease. Other data, including valve size and
type and process fluid characteristics, were obtained. Screening data
were obtained with the Bacharach Instrument Company "TLV Sniffer," and
readings were taken as close to the source as possible.
Unlike the Shell and Union studies, emission rates were not based
on the screening value correlations. Rather, each valve was sampled
to determine emission rates before and after maintenance using techniques
developed by EPA during the refinery emission factor study. These
values were used to evaluate emissions reduction.
The results of this study are given in Table C-6. Of interest
here is a comparison of the emissions reduction for directed and undi-
rected maintenance. The results indicate that directed maintenance is
more effective in reducing emissions than is undirected maintenance,
particularly for valves with lower initial leak rates. The results
showed an increase in total emissions of 32.6 percent for valves with
initial screening values less than 10,000 ppmv which were subjected to
undirected maintenance. However, this increase is due to a large
increase in the emission rate of only one valve.
C.2.4 Description and Results of the Ethylene Unit Maintenance Study
at Refinery 6
Maintenance on valves was performed by unit personnel at Refinery 6
(Section C.I.2.5). VOC concentration measurements were made using the
OVA-108, and readings were obtained at the closest distance possible to
the source. The results of this study are shown in Table C-7.
Directed and undirected maintenance procedures were used. The results
C-ll
-------
Table C-5. SUMMARY OF MAINTENANCE STUDY RESULTS FROM THE SHELL OIL COMPANY
REFINERY IN MARTINEZ, CALIFORNIA5
o
i
March maintenance
April maintenance
All repaired valves
with initial screening
values >5,300 ppmv
All repaired valves
with initial screening
values <5,300 ppmv
All repaired valves with
initial (March) screening
values >5,300 ppmv
All repaired valves with
initial (March) screening
values<5,300 ppmv
Number of repairs attempted
Number of successful repairs (<5,300 ppmv after
maintenance)
Percent successful repairs
Estimated emissions before maintenance, kg/hr°
Estimated emissions after maintenance, kg/hr
Percent reduction in emissions
Number of valves with decreased emissions
Percent of valves with decreased emissions
Number of valves with increased emissions
Percent of valves with increased emissions
161
105
65.2
11.08
2.66
76.0
161
100.0
0
0.0
11
—
—
0.159
0.0
100.0
11
100.0
0
0.0
152d
45
83. 3f
2.95
0.421
85.7
151
99.3
1
0.7
lle
-_
--
0.060
- OiO
100.0
11
100.0
0
0.0
Reference 9.
bThe value 5,300 ppmv, taken with the OVA-108 at 1 cm., generally corresponds to a value of 10,000 ppmv taken with a "TLV Sniffer" at 0 cm.
cShell reported the screening value of all valves which measured <3,000 ppmv (<1,500 ppmv-TLV at 0 cm.) as non-leakers. Emissions estimates obtained
from emission factors. Reference 10.
Initial screening value for 90 of these valves was <1,500 ppm-TLV at 0 cm.; 54 valves screened >5,300 (note nine valves from initial data set not
rechecked in April).
elnitial screening value for 10 of these valves was <1,500 ppm-TLV at 0 cm.
"Percent successful repairs" is calculated by dividing 45 (number of successful repairs) by 54 (number of valves actually screened ^5,300 ppmv).
See footnote d.
-------
TABLE C-6. SUMMARY OF EPA REFINERY MAINTENANCE STUDY RESULTS
a,b
o
I
Repaired valves with initial
screening values >10,000 ppmv
Number of valves repaired
Number of successful repairs
(<10,000 ppmv after maintenance)
Percent successful repairs
Measured emissions before maintenance
kg/hr
Measured emissions after maintenance
kg/hr
Percent reduction in emissions
Number of valves with decreased
emissions
Percent of valves with decreased
emissions
Number of valves with increased
emissions
Percent of valves with increased
emissions
Directed
Maintenance
9
8
88.9
0.107
0.0139
87.0
9
100.0
0
0.0
Undirected
Maintenance
23
13
56.5
1.809
0.318
82.4
21
91.3
2
8.7
Repaired valves with initial
screening values <10,000 ppmv
Di rected
Maintenance
10
_.
-
0.0332
0.0049
85.2
6
60.0
4
40.0
Undirected
Maintenance
16
_
-
0.120
0.159
-32.6
15
93.8
1
6.3
Reference 1.
bTLV 0 cm hexane calibration.
-------
TABLE C-7. MAINTENANCE EFFECTIVENESS
ETHYLENE UNIT BLOCK VALVES9>b
1. Total number of valves with VOC >10,000 ppm
from unit survey 121
2. Total number of valves tested for
maintenance effectiveness 46
% Tested 38%
UNDIRECTED MAINTENANCE
3. Total number subjected to repair attempts 37
4. Successful repairs (VOC <10,000 ppm) 22
% Repaired 59%
Followup
DIRECTED MAINTENANCE
5. Number of valves unrepaired by undirected
maintenance subjected to directed maintenance 14
/
6. Number repaired by followup directed
maintenance 5
% of unsuccessful repairs by
directed maintenance 36%
7. Total number repaired based on undirected
maintenance subset (3) above 27
% Repaired 73%
8. Total number of repairs including leaks
not found before initial maintenance 29
Total % repaired 63%
Total % not repaired 37%
Reference 7.
bOVA~108 0 cm.
C-14
-------
show that directed maintenance results in more repairs being successfully
completed than when undirected maintenance is used.
C.2.5 Description and Results of EPA-ORD Valve Maintenance Study
A study was undertaken by the EPA Office of Research and Development
(ORD) in order to determine the effectiveness of routine (on-line)
maintenance in the reduction of fugitive VOC emissions from in-line
valves. The overall effectiveness of a leak detection and repair
program was examined by studying the immediate emission reduction due
to maintenance, the propagation of the leaks after maintenance, and
the rate at which new leaks occur for pumps and valves. Testing was
conducted at six chemical plants, two for each of three chemical
processes (ethylene, cumene, and vinyl acetate production).
It was found that an estimated 71.3 percent (95 percent confidence
limits of 54 percent to 88 percent) reduction in fugitive emissions
from all valves leaking at various concentrations resulted immediately
following maintenance (lasting up to six months). The 30-day rates of
occurrence for valves and pumps initially screened at less than 10,000 ppm
were 1.3 percent (95 percent confidence interval of 0.7 percent to
2.1 percent) and 5.5 percent (95 percent confidence interval of 2.2 percent
to 10 percent), respectively, as shown in Table C-8. In Table C-9,
30-day, 90-day, and 180-day recurrence rate estimates are given along
with approximate 95 percent confidence limits. Maintenance of valves
in the study averaged about 10 minutes per valve.
C.2.6 Comparison of Maintenance Study Results
A summary of the results of the maintenance programs described
in the preceding sections is presented in Table C-10. Generally
speaking, the results of these maintenance programs would tend to
support the following conclusions:
• A reduction in emissions may be obtained by performing maintenance
on valves with screening values above 10,000 ppmv (measured at
the source).
• The reduction in emissions due to maintenance of valves with
screening values below 10,000 ppmv is not as dramatic and may
result in increased emissions.
• Directed maintenance is preferable to undirected maintenance
for valve repair.
C-15
-------
TABLE C-8. OCCURRENCE RATE ESTIMATES FOR VALVES AND PUMPS BY PROCESS IN EPA-ORD STUDY3jb
£-5
I
30-Day
Estimate
VALVES
Cimiene units
Ethyl ene units
Vinyl Acetate units
All units
PUMPS
Cumene units
Ethyl ene units
Vinyl Acetate units
All units
1.
2.
0.
1.
5.
18.
2.
5.
9
0
3
3
8
4
8
5
95%
Confidence
Interval
(0.2,
(0.9,
(0.0,
(0.7,
(0.7,
(2.8,
(0.8,
(2.2,
5.9)
3.6)
0.6)
2.1)
20)
42)
6.2)
10)
90-Day
Estimate
5.6
6.0
0.8
3.8
16.3
45.7
8.1
15.7
95%
Confidence
Interval
(0.6,
(2.7,
(0.1,
(2.0,
(2.1,
(8.2,
(2.2,
(6.6,
17)
10)
1.9)
6.0)
49)
80)
17)
27)
180-Day
Estimate
10.
11.
1.
7.
30.
70.
15.
29.
8
6
5
4
0
5
6
0
95%
Confidence
Interval
(1.3,
(5.3,
(0.3,
(4.0,
(4.2,
(16,
(4.4,
(12,
30)
20)
3.8)
12)
74)
96)
32)
47)
Reference 11.
A leak from a source is defined as having occurred if it initially screened <10,000 ppmv and at
some later date screened >10,000 ppmv.
-------
TABLE C-9. VALVE LEAK RECURRENCE RATE ESTIMATES3'b
95% Confidence Limits on the
Recurrence Rate Estimate Recurrence Rate Estimate
30-day
90-day
180-day
17.2%
23.9%
32.9%
(5, 37)
(7, 48)
(10, 61)
Reference 11.
Data from 28 maintained valves were examined. Only those valves
that screened greater than or equal to 10,000 ppmv immediately
before maintenance and screened less than 10,000 ppmv immediately
after maintenance were considered having a potential to recur.
C-17
-------
TABLE C-10. SUMMARY OF VALVE MAINTENANCE
TEST RESULTS
Maintenance Number of Valve Number of Percent
Test Repairs Attempted Successful Repairs Repaired
Union3 133 67 50.4
Shell3
March 1979 161 105 65.2
April 1979 54 45 83.3
EPA-4 refineries
Directed0 . 9 8 88.9
Undirected0 23 13 56.5
Refinery 6
Directed and Undirected 46 29 63.0
EPA-ORDb
Directed 97 28 28.9
TOTAL 523 295 56.4
alnitial screening value of >5,300 ppmv at 1 cm was used to define the
population subject to repair. Repair was successful when a valve
screened <5,300 ppmv at 1 cm.
Before maintenance screening value of >10,000 ppmv at 0 cm was used
to define the population subject to repair. Repair was successful
when a valve screened <10,000 ppmv at 0 cm.
cDirected maintenance refers to a valve maintenance procedure whereby
the hydrocarbon detector is utilized during maintenance. The leak is
monitored with the instrument until no further reduction of leak is
observed or the valve stem rotation is restricted.
Undirected maintenance refers to action by plant personnel in which
an assigned worker tightens the valve packing gland with a wrench to
further compress the packing material around the valve stem and seat.
C-18
-------
The information presented in the tables of Appendix C has been
compiled with the objective of placing the data on as consistent a
basis as possible. However, some differences were unavoidable and
others may have gone unrecognized, due to the limited amount of information
concerning the details of methods used in each study. Therefore, care
should be exercised before attempting to draw specific quantitative
conclusions based on direct comparison of the results of these studies.
C-19
-------
C.3 REFERENCES
1. Wetherold, R.G., et al. Assessment of Atmospheric Emissions from
Petroleum Refining: Volume 3, Appendix B. Detailed Results.
U.S. Environmental Protection Agency. Research Triangle Park, NC.
EPA-600/2-80-075c. April 1980. Docket Reference Number II-A-19.*
2. Air Pollution Emission Test - Petroleum Refinery Fugitive Emissions
at ARCO Watson Refinery, Carson, California, and Newhall Refining
Company, Newhall, California. U.S. Environmental Protection
Agency. Research Triangle Park, NC. EMB Project No. 77-CAT-6.
December 1979. Docket Reference Number II-A-15.*
3. Hustvedt, K.C., et al. Control of Volatile Organic Compound Leaks
from Petroleum Refinery Equipment. U.S. Environmental Protection
Agency. Research Triangle Park, NC. EPA Report No. 450/2-78-036.
June 1978. Docket Reference Number II-A-6.*
4. Emission Test Report - Miscellaneous Refinery Equipment VOC Sources
at Refinery "E," Gulf Coast U.S. U.S. Environmental Protection
Agency. Research Triangle Park, NC. EMB Report 78-OCM-12F.
December 1979. Docket Reference Number II-A-14.*
5. Emission Test Report - Fugitive Emission Testing at Amoco Refining
Company. Texas City, TX. U.S. Environmental Protection Agency.
Research Triangle Park, NC. EMB Report No. 77-BEZ-2. April 1981.
Docket Reference Number II-A-22.*
6. Emission Test Report - Benzene Fugitive Emissions - Petroleum
Refineries. Sun Petroleum Products Company. Toledo, OH. U.S.
Environmental Protection Agency. Research Triangle Park, NC. EMB
Report No. 78-OCM-12B. October 1980. Docket Reference Number II-A-24.*
7. Air Pollution Emission Test Report. Phillips Petroleum Company.
Sweeny, TX. U.S. Environmental Protection Agency. Research
Triangle Park, NC. EMB Report No. 78-OCM-12E. December 1979.
Docket Reference Number II-A-13.*
8. Letter and attachments from Bottomley, F.R., Union Oil Company, to
Feldstein, M., Bay Area Air Quality Management District. April 10,
1979. 36 p. Docket Reference Number II-B-29.*
9. Letter and attachments from Thompson, R.M., Shell Oil Company, to
Feldstein, M., Bay Area Air Quality Management District. April 26,
1979. 46 p. Docket Reference Number II-B-30.*
10. Blacksmith, J.R., et al. Problem Oriented Report: Frequency of
Leak Occurrence for Fittings in Synthetic Organic Chemical Plant
Process Units. Research Triangle Park, NC. EPA Contract
No. 68-02-3171. September 1980. Docket Reference Number II-A-20.*
C-20
-------
11. Langley, G.J. and R.G. Wetherold. Evaluation of Maintenance for
Fugitive VOC Emissions Control. Final Contractor Report. Radian
Corporation. Austin, TX. Contract No. 68-03-2776-04. For U.S.
Environmental Protection Agency. Cincinnati, OH. February 1081.
Docket Reference Number II-A-21.*
*References can be located in Docket Number A-80-44 at the U.S.
Environmental Protection Agency Library, Waterside Mall, Washington, D.C
C-21
-------
APPENDIX D
EMISSION MEASUREMENT
AND CONTINUOUS MONITORING
D-l
-------
APPENDIX D - EMISSION MEASUREMENT AND CONTINUOUS MONITORING
D.I EMISSION MEASUREMENT METHODS
To develop data in support of standards for the control of fugitive
emissions, EPA conducted leak surveys at six petroleum refineries and
three organic chemical manufacturing plants. The resulting leak
determination procedures contained in Reference Method 21 were developed
during the course of this test program.
Prior to the first test, available methods for measurement of
fugitive leaks were reviewed, with emphasis on methods that would provide
data on emission rates from each source. To measure emission rates,
each individual piece of equipment must be enclosed in a temporary cover
for emission containment. After containment, the leak rate can be
determined using concentration change and flow measurements. This
1 2
procedure has been used in several studies, ' 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
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.
D-2
-------
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 that
conducted surveys at a distance of 5 cm from the components. This
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
5
techniques guideline document. Many commentors felt that a measurement
distance of 5 cm could not be accurately repeated during screening
tests. Since the concentration profile is rapidly changing between 0
and 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 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 concentrations at the interface surface, except in the
case of rotating shaft seals where measurements were made up to 1 cm
from the surface for safety reasons.
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
D-3
-------
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 avail-
able 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,
additional studies have begun to develop response factor data for two
instrument types. Based on preliminary results, it appears that methane
is a more representative reference calibration material at 10,000 ppmv
levels. Based on this conclusion, and the fact that methane standards
are readily available at the necessary calibration concentrations, the
recommended calibration material for this regulation was changed to
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. Based on
EPA test results, the number of concentration measurements in the range
where a variability of two or three would change the decision as to
whether or not a leak exists is small in comparison to the total number
of potential leak sources.
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
D-4
-------
the unit positioning the instrument probe within 1 meter of all valves
and pumps. The concentration readings were recorded on a portable strip
chart recorder. After completion of the walkthrough, the local wind
conditions were used with the chart data to locate the approximate
source of any increased ambient concentrations. This procedure was
found to yield mixed results. In some cases, the majority of leaks
located by individual component testing could be located by walkthrough
surveys. In other tests, prevailing dispersion conditions and local
elevated ambient concentrations complicated or prevented the interpre-
tation 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.
0.2 CONTINUOUS MONITORING SYSTEMS AND DEVICES
Since the leak determination procedure is not a typical emission
measurement technique, there are no continuous monitoring approaches
that are directly applicable. Continual surveillance is achieved by
repeated 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. EPA performed a
limited evaluation of fixed-point monitoring systems for their effective-
ness in leak detection. The systems consisted of both remote sensing
devices with a central readout and a central analyzer system (gas
chromatograph) with remotely collected samples. The results of these
tests indicated that fixed point systems were not capable of sensing all
leaks that were found by individual component testing. This is to be
expected since these systems are significantly affected by local dispersion
conditions and would require either many individual point locations, or
very low detection sensitivities in order to achieve similar results to
those obtained using an individual component survey.
D-5
-------
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 VOC fugitive emission detection procedure is
Reference Method 21. This method incorporates the use of a portable
analyzer to detect the presence of volatile organic vapors at the
surface of the interface where direct leakage to atmosphere could occur.
The approach of this technique assumes that if an organic leak exists,
there will 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
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 2 percent of the leak definition is observed, then a "no
detectable emissions" condition exists. The definition of 2 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. "No
detectable emissions" would exist when the observed concentration change
between local ambient and leak interface surface measurements is less
than 200 ppnv.
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 is recommended as the reference calibration basis for
VOC fugitive emission sources in the petroleum refining industry.
D-6
-------
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 known to be
available in Factory Mutual certified versions for use in hazardous
atmospheres.
The recommended test procedure includes a set of design and
operating specifications and evaluation procedures by which an analyzer's
performance can be evaluated. These parameters were selected based on
the allowable tolerances for data collection, and not on EPA evaluations
of the performance of individual instruments. Based on manufacturers'
literature specifications and reported test results, commercially
available analyzers can meet these requirements.
The estimated purchase cost for an analyzer ranges from about
$1,000 to $5,000 depending on the type and optional equipment. The cost
of an annual monitoring program per unit, including semiannual instrument
tests and reporting is estimated to be from $3,000 to $4,500. This
estimate is based on EPA contractor costs experienced during previous
test programs. Performance of monitoring by plant personnel nay result
in lower costs. The above estimates do not include any costs associated
with leak repair after detection.
D-7
-------
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. Docket Reference Numbers II-I-l,
II-I-2, II-I-3, II-I-4, and II-I-5.*
2. Wetherold, R. and L. Provost. Emission Factors and Frequency
of Leak Occurrence for Fittings in Refinery Process Units.
Radian Corporation. Austin, TX. For U.S. Environmental Protection,
Agency. Research Triangle Park, NC. Report Number EPA-600/2-79-044.
February 1979. Docket Reference Number II-A-10.*
3. Telecon. Harrison, P., Meteorology Research, Inc. with Hustvedt,
K.C., EPA, CPB. December 22, 1977. Docket Reference Number II-E-3.*
4. Miscellaneous Refinery Equipment VOC Sources at ARCO, Watson
Refinery, and Newhall Refining Company. U.S. Environmental
Protection Agency, Emission Standards and Engineering Division.
Research Triangle Park, NC. EMB Report Number 77-CAT-6.
December 1979. Docket Reference Number II-A-15.*
5. Hustvedt, K.C., R.A. Quaney, and W.E. Kelly. Control of Volatile
Organic Compound Leaks from Petroleum Refinery Equipment. U.S.
Environmental Protection Agency. Research Triangle Park, NC.
OAQPS Guideline Series. Report Number EPA-450/2-78-036. June 1978.
Docket Reference Number II-A-6.*
6. Response Factors of VOC Analyzers at a Meter Reading of
10,000 PPMV for Selected Organic Compounds. EPA/IERL. Research
Triangle Park, NC. Report No. EPA-600/2-81-051. March 1981.
Docket Reference Number II-A-25.*
7. Letter and Attachments from McClure, H.H., Texas Chemical Council,
to Barber, W., EPA, OAQPS. June 30, 1980. Docket Reference
Number II-D-69.*
*References can be located in Docket Number A-80-44 at the U.S.
Environmental Protection Agency Library, Waterside Mall, Washington, D.C.
D-8
-------
APPENDIX E
REFINERY CAPACITY AND MODEL
UNIT GROWTH PROJECTIONS
E-l
-------
E.I REFINERY CAPACITY
Table E-l provides a listing of total refinery capacity in the United
States and its territories as of January 1, 1980. For purposes of this
summary the refinery is defined as a system of process units, at least one
of which has the capability to process crude oil. The table notes for each
refinery its location, company, and calendar day crude oil distillation
capacity. It should be noted that one cubic meter (m^) is equivalent to
approximately 6.29 barrels.
E.2 MODEL UNIT GROWTH PROJECTIONS
As noted in Table E-2 it has been projected that up to and including the
year 1986, 100 new units and 182 modification/reconstructions of existing
process units will be subject to the implementation of a regulatory alternative.
The following discussion provides a brief review of the causes and nature of
growth in the refinery industry, and summarizes the method used to estimate
the number of units that may be affected by this standard.
Although the demand for petroleum products in many applications is pro-
jected to fall (see Section 9.1.3.1), the construction of new, and recon-
struction/modification of existing, refinery units will continue over the
forecast period (1981-1986). This apparent conflict is a direct result of
the need for existing refineries to cope with the shifting supply and demand
patterns present in the current market.
With regard to supply, the decreasing availability of light, low-sulfur
crude requires that refineries upgrade present capacity, providing the
flexibility needed to process a wider range of various quality crudes. In
particular, desulfurization capacity will be needed as fewer "sweet" crudes
are available. In addition, the need to meet higher octane demands of
unleaded gasoline, will require the upgrading of capacity to produce higher
octane blending stocks. In short, refinery modernization will continue
regardless of overall demand reductions.
The rapid expansion in small refinery construction, observed during the
1970's, is not anticipated to continue into the 1980's. This is true because
the decontrol of domestic crude production has eliminated the subsidies
extended to small refiners under the DOE Entitlements Program. Furthermore,
the small refiners may be more adversely impacted by the changes in crude
supplies noted above. This is so since small refineries, in general, do not
E-2
-------
Table E-l. CRUDE DISTILLATION CAPACITY BY REFINERY BY STATE
UNITED STATES AND UNITED STATES TERRITORIES
January 1, 1980a
Crude Capacity
Company and Refining Location m3/cd
ALABAMA
Hunt Oil Co. Tuscaloosa 5,556
Louisianna Land & Exploration Co. - Mobile 6,566
Marion Corp. - Theodore 3,291
Mobile Bay Refining Co. Chickasaw 4,467
Vulcan Asphalt Refining Co. - Cordova 1,556
Warrior Asphalt Co. of Alabama Inc. - Holt 1,556
ALASKA
Atlantic Richfield Co. - North Slope 2,258
Chevron U.S.A. Inc. - Kenai 3,498
Earth Resources Co. of Alaska - North Pole 5,028
Tesoro Petroleum Corp. - Kenai 7,711
ARIZONA
Arizona Fuels Corp. Fredonia 954
ARKANSAS
Berry Petroleum Co. - Stephens 636
Cross Oil & Refining Co. of Arkansas Smackover 1,463
MacMillan Ring-Free Oil Co. Inc. - Norphlet 700
Tosco Corp. - El Dorado 7,472
CALIFORNIA
Anchor Refining Co. - McKittrick 1,590
Atlantic Richfield Co. - Carson 28,617
Beacon Oil Co. - Hanford 1,876
Champlin Petroleum Co. - Wilmington 4,833
Chevron U.S.A. Inc. - Bakersfield 4,134
Chevron U.S.A. - El Segundo 62,003
2,385b
Chevron U.S.A. - Richmond 46,741
ll,288b
Coastal Petroleum Co. - Paloma 1,622
Conoco - Paramount 7,393
Conoco - Santa Maria 1,510
Demenno Resources Compton 2,385
ECO Petroleum Inc. - Long Beach 1,749
Edgington Oil Co. Inc. - Long Beach 4,690
Exxon Co. U.S.A. - Benecia 16,216
Fletcher Oil & Refining Co. - Carson 4,690
Getty Refining & Marketing Co. - Bakersfield 3,577
Gibson Oil & Refining Co. - Bakersfield 731
Golden Eagle Regining Co. Inc. - Carson , 2,571
Gulf Oil Co. U.S. - Santa Fe Springs 8,188
Huntway Refining Co. - Wilmington 859
Kern County Refinery Inc. - Bakersfield 3,339
Lunday-Thagard Oil Co. - South Gate 1,590
MacMillan Ring-Free Oil Co. Inc. - Long Beach 1,940
Marlex Oil & Refining Inc. - Long Beach 3,021
Mobil Oil Corp. - Torrance 19,634
Newhall Refining Co. Inc. Newhall 2,798
Oxnard Refinery - Oxnard 636
Pacific Refining Co. Inc. - Hercules 13,514
Powerline Oil Co. - Santa Fe Springs 7,014
Quad Refining Corp. - Bakersfield 1,113
Road Oil Sales Inc. Bakersfield 477
Sabre Refining Inc. - Bakersfield 1,192
San Joaquin Refining Co. Bakersfield 3,180
Shell Oil Co. Martinez 14,531
2,003b
Shell Oil Co. - Wilmington 14,785
Sunland Refining Corp. Bakersfield 1,272
318b
E-3
-------
Crude Capacity
Company and Refining Location m^/cd
Texaco Inc. - Wilmington 11,924
Tosco Corp. Avon 20,032
1.749&
Tosco Corp. Bakersfield 6,359
U.S.A. Petrochem Corp. - Ventura 3,816
Union Oil Co. of California - Aroyo Grande 6,518
Union Oil Co. of California - Rodeo 11,129
Union Oil Co. of California - Wilmington 17,170
West Coast Oil Co. - Oildale 3,021
Witco Chemical Corp. - Oildale 1,510
COLORADO
Asamera Oil Inc. - Commerce City 3,498
Conoco - Commerce City 1,606
Gary Refining Co. - Fruita 2,083
DELAWARE
Getty Refining & Marketing Co. - Delaware City 22,258
FLORIDA
Manatee Energy Co. - Manatee 4,515
Seminole Refining Inc. - St. Marks 2,067
GEORGIA
Amoco Oil Co. - Savannah 2,862
Young Refining Corp. - Douglasville 509
HAWAII
Chevron U.S.A. Inc. Honolulu 7,313
Hawaiian Independent Refining Inc. - Ewa Beach 10,795
ILLINOIS
Amoco Oil Co. - Wood River 17,170
Bi-Petro Inc. - Pana 986b
Clark Oil & Refining Corp. - Blue Island 10,572
Clark Oil & Refining Corp. - Hartford 10,111
Dillman Oil Recovery Inc. - Robinson 175
Energy Development Inc. - Crossville 111
Marathon Oil Co. - Robinson 31,002
Mobil Oil Corp. - Joliet 28,617
Shell Oil Co. - Wood River 44,992
Texaco Inc. - Lawrenceville 13,355
Texaco Inc. - Lockport 11,447
Union Oil Co. of California - Lemont 24,006
Wireback Oil Co. - Plymouth 286
Yetter Oil Co. - Colmar 159
INDIANA
Amoco Oil Co. - Whiting 60,413
Energy Cooperative Inc. - East Chicago 20,032
Gladieux Refinery Inc. - Fort Wayne 1,940
Indiana Farm Bureau Coop. Ass. Inc. - Mt. Vernon 3,275
Industrial Fuel & Asphalt of Ind. Inc. - Hammond 1,183
Kentucky Oil & Refining Co. - Troy 238
Laketon Asphalt Refining Co. - Laketon 1,351
Princeton Refining Inc. Princeton 795^
Rock Island Refining Corp. - Indianapolis 6,868
KANSAS
CRA, Inc. - Coffeyville 8,983
CRA, Inc. - Phillipsburg 4,197
Derby Refining Co. North Wichita 4,449
E-Z Serv Refining Inc. - Shallow Water 1,510
Getty Refining & Marketng Co. - El Dorado 12,810
Mid-America Refining Co. Inc. - Chanute 556
Mobil Oil Corp. - Augusta 7,949
E-4
-------
Company and Refining Location
Crude Capacity
KANSAS (Continued)
National Coop. Refinery Ass. - McPherson
Pester Refining Co. El Dorado
Phillips Petroleum Co. - Kansas City
Total Petroleum Inc. - Arkansas City
KENTUCKY
Ashland Oil Inc. - Catlettsburg
Ashland Oil Inc. - Louisville
Kentucky Oil & Refining Co. - Betsy Lane
Somerset Refinery Inc. - Somerset
LOUISIANA (Inland)
Atlas Processing Co. - Shreveport
Bayou State Oil Corp. - Hosston
Calumet Refining Co. - Princeton
Claiborne Gasoline Co. - Lisbon
Cotton Valley Solvents Co. - Cotton Valley
Kerr-McGee Corp. - Dubach
Port Petroleum Inc. - Stonewall
Schulze Processing Inc. - Tallulah
LOUISIANA (Gulf)
Bruin Refining Inc. - St. James
Calcasieu Refining Ltd. Lake Charles
Canal Refining Co. - Church Point
Cities Service Co. - Lake Charles
Conoco - Egan
Conoco Westlake
Evangeline Refining Co. Inc. - Jennings
Exxon Co. U.S.A. - Baton Rouge
Good Hope Industries Inc. - Good Hope
Gulf Oil Co. U.S. Belle Chasse
Gulf Oil Co. U.S. - Venice
Hill Petroleum Co. - Krotz Springs
International Processors - St. Rose
LaJet Inc. - St. James
Lake Charles Refining Co. - Lake Charles
Mallard Resources Inc. Gueydon
Marathon Oil Co. - Garyville
Mt. Airy Refining Co. - Mt. Airy
Murphy Oil Corp. Meraux
Placid Refining Co. Port Allen
Shell Oil Co. - Norco
Shepard Oil Co. Jennings
Slapco - Mermentau
Sooner Refining Co. - Darrow
TSS Refining Inc. - Jennings
Tenneco Oil Co. - Chalmette
Texaco Inc. Convent
MARYLAND
Amoco Oil Co.
Chevron U.S.A.
Bal tiniore
Inc. Baltimore
MICHIGAN
Consumers Power Co.
Crystal Refining Co.
Dow Chemical U.S.A.
Marysville
Carson City
Bay City
Lakeside Refining Co. Kalamazoo
Marathon Oil Co. Detroit
Texas American Petrochemicals Inc.
Total Petroleum Inc. - Alma
8,609
4,054
12,719
6,757
33,927
4,006
477
795
7,154
795
143b
313
1,033
1,272
1,749
286
127
2,941
2,528
1,192
46,264
1,431
477°
13,831
509
79,491
13,052
31,145
4,563
1,590
4,547
3,180
4,769
1,192
40,541
3,657
14,706
5,723
36,566
,590
,305
859
,622
18,124
22,258
1,
2,385
5,986b
636
668
West Branch
890
10,890
1,828
6,359
E-5
-------
Crude Capacity
Company and Refining Location nr/ccl
MINNESOTA
Ashland Oil Inc. - St. Paul Park 10,675
Conoco - Wrenshall 3,736
Koch Refining Co. - Rosemount 20,238
MISSISSIPPI
Amerada Hess Corp. - Purvis 4,769
Chevron U.S.A. Inc. - Pascagoula 44,515
Ergon Refining Inc. - Vicksburg 1,876
Southland Oil Co. - Lumberton 922
Southland Oil Co. Sandersville 1,749
Southland Oil Co. Yazoo City 668
Vicksburg Refining Inc. - Vicksburg 1,256
MISSOURI
Amoco Oil Co. - Sugar Creek 16,534
MONTANA
Conoco - Billings 8,347
Exxon Co. U.S.A. Billings 7,154
Farmers Union Central Exchange Inc. - Laurel 6,622
Kenco Refining Inc. Wolf Point 747
Phillips Petroleum Co. - Great Falls 954
Westco Refining Co. - Cut Bank 843
NEBRASKA
CRA, Inc. - Scottsbluff 890
NEVADA
Nevada Refining Co. - Tonopah 715
NEW HAMPSHIRE
ATC Petroleum Inc. Newington 2,130
NEW JERSEY
Amerada Hess Corp. Port Reading 10,811b
Chevron U.S.A. Inc. - Perth Amboy 26,709
Exxon Co. U.S.A. - Linden 46,105
Mobil Oil Corp. - Paulsboro 15,580
Seaview Petroleum Co. - Paulsboro 7,059
Texaco Inc. - Westville 14,308
NEW MEXICO
Caribou-Four Corners Oil Co. - Farmington 397
Giant Industries Inc. - Farmington 2,146
Navajo Refining Co. - Artesia 4,758
Plateau Inc. - Bloornfield 2,671
Shell Oil Co. - Gallup 2,862
Southern Union Refining Co. Lovington 5,723
Southern Union Refining Co. - Monument 127
73lb
Thriftway Oil Co. - Bloomfield 970
NEW YORK
Ashland Oil Inc. - Buffalo 10,175
Cibro Petroleum Products Inc. - Albany 5^390
Mobil Oil Corp. Buffalo 6,836
NORTH CAROLINA
ATC Petroleum Inc. - Wilmington 1,892
NORTH DAKOTA
Amoco Oil Co. Mandan 8,903
Northland Oil and Refining Co. - Dickinson *795
Westland Oil Co. - Williston 741
E-6
-------
Company and Refining Location
OHIO
Ashland Oil Inc. - Canton
Ashland Oil Inc. - Findlay
Gulf Oil Co. U.S. - Cleves
Gulf Oil Co. U.S. - Toledo
Standard Oil Co. of Ohio - Lima
Standard Oil Co. of Ohio - Toledo
Sun Co. Inc. - Toledo
OKLAHOMA
Allied Materials Corp. - Stroud
Champlin Petroleum Co. - Enid
Conoco - Ponca City
Hudson Refining Co. Inc. - Cushing
Kerr-McGee Corp. - Wynnewood
OKC Corp. - Okmulgee
Oklahoma Refining Co. - Cyril
Sun Co. Inc. - Duncan
Sun Co. Inc. - Tulsa
Texaco Inc. - Tulsa
Tonkawa Refining Co. - Arnett
Vickers Petroleum Corp. - Ardmore
Crude Capacity
m-Vcd
10,493
3,243b
6,948
7,997
26,709
19,078
19,873
1,097
8,553
21,304
3,100
7,949
3,975
2,480
7,711
14,070
7,949
1,272
10,191
OREGON
Chevron U.S.A. Inc. Portland 2,385
PENNSYLVANIA
Ashland Oil Inc. - Freedom 1,081
Atlantic Richfield Co. - Philadelphia 29,412
,BP Oil Corp. - Marcus Hook 26,073
Gulf Oil Co. U.S. - Philadelphia 32,798
Pennzoil Co. - Rouseville 2,321
Quaker State Oil Refining Corp. - Emlenton 525
Quaker State Oil Refining Corp. - Smethport 1,033
Sun Co. Inc. - Marcus Hook 26,232
United Refining Co. - Warren 6,359
Witco Chemical Corp. - Bradford 1,145
TENNESSEE
Delta Refining Co. Memphis 6,757
TEXAS (Inland)
Adobe Refining Co. La Blanca 795
American Petrofina Co. of Texas - Big Spring 9,539
Chevron U.S.A. Inc. - El Paso 12,083
Diamond Shamrock Corp. - Sunray 11,566
Dorchester Refining Co. - Mount Pleasant 4,213
Flint Chemical Co. - San Antonio 191
Howell Hydrocarbons Inc. - San Antonio 954
La Gloria Oil & Gas Co. - Tyler 795
Longview Refining Co. - Longview 1,431
Petrolite Corp. Kilgore 159
Phillips Petroleum Co. - Borger 15,421
Pioneer Refining Ltd. Nixon 843
Pride Refining Inc. - Abilene 5,803
Quitman Refining Co. - Quitman 1,049
Rancho Refining Co. Inc. - Donna 556
Sector Refining Inc. - Palestine 636
954b
Shell Oil Co. - Odessa 5,087
Sigmore Refining Corp. Three Rivers 3,498
Tesoro Petroleum Corp. Carrizo Springs 4,149
Texaco Inc. Amarillo 3,180
Texaco Inc. El Paso 2,703
Texas Asphat fi Refining Co. - Euless 4,658
Thriftway Oil Co. - Graham 382
Wickett Refining Co. - Wickett l,272b
Winston Refining Co. Fort Worth 3,084
E-7
-------
Table E-l. (Continued)
Crude Capacity
Company and Refining Location nr/cd
TEXAS (Gulf)
American Petrofina Co. of Texas - Port Arthur 14,308
Amoco Oil Co. - Texas City 65,978
Atlantic Richfield Co. - Houston 54,849
Carbonit Refinery Inc. - Hearne 1,590
Champlin Petroleum Co. - Corpus Christi 24,642
Charter International Oil Co. - Houston 10,334
Coastal States Petroleum Co. - Corpus Christi 29,412
Copano Refining Co. - Ingleside 1,510
Crown Central Petroleum Corp. - Pasadena 15,898
Eddy Refining Co. - Houston 517
Erickson Refining Corp. - Port Neches 4,769
Exxon Co. U.S.A. - Baytown 101,749
Friendswood Refining Co. - Friendswood 1,987
Gulf Energy Refining Corp. - Brownsville 1,510
Gulf Oil Co. U.S. - Port Arthur 53,386
Gulf States Oil & Refining Co. - Corpus Christi 1,590
Independent Refining Corp. - Winnie 1,749
Marathon Oil Co. - Texas City 11,049
Mobil Oil Corp. - Beaumont 42,512
9,157b
Monsanto Co. - Alvin/Teas City 1,351
Nueces Petrochemical Co. - Corpus Christi 5,564
Petraco-Valley Oil & Refining Co. - Brownsville 1,955
Phillips Petroleum Co. - Sweeny 34,658
Placid Refining Co. - Mont Belvieu 1,971
Saber Refining Co. - Corpus Christi 3,577
Sentry Refining Inc. - Corpus Christi 1,590
Shell Oil Co. - Deer Park 45,310
South Hampton Co. - Silsbee 3,259
Southwestern Refining Co. Inc. - Corpus Christi 19,078
Sun Co. Inc. - Corpus Christi 9,134
Texaco Inc. - Port Arthur 58,029
Texaco Inc. - Port Neches 6,200
1.272&
Texas City Refining Inc. - Texas City 20,143
Tipperary Refining Co. - Ingleside 1,033
Uni Oil Co. - Ingleside 6,264
Union Oil Co. of California - Nederland 19,078
UTAH
Amoco Oil Co. - Salt Lake City 6,200
Caribou-Four Corners Oil Co. - Woods Cross 1,192
Chevron U.S.A. Inc. - Salt Lake City 7,154
Husky Oil Co. - North Salt Lake 3,975
Morrison Petroleum Co. - Woods Cross 1,035
Phillips Petroleum Co. - Woods Cross 3,816
Plateau Inc. - Roosevelt 1,192
Western Refining Co. - Woods Cross 1,987
VIRGINIA
Amoco Oil Co. - Yorktown 8,426
WASHINGTON
Atlantic Richfield Co. - Ferndale 17,488
Chevron U.S.A. Inc. Richmond Beach 874
Mobil Oil Corp. - Ferndale 11,367
Shell Oil Co. Anacortes 14^467
Sound Refining Inc. - Tacoma 1*227
Texaco Inc. - Anacortes 12^401
U.S. Oil & Refining Co. Tacoma 3,402
United Independent Oil Co. - Tacoma H6
WEST VIRGINIA
Elk Refining Co. - Falling Rock 890
Quaker State Oil Refining Corp. - Newell 1,542
Quaker State Oil Refining Corp. - St. Mary's *763
E-8
-------
Table E-l. (Continued)
Crude Capacity
Company and Refining Location m^/cd
WISCONSIN
Murphy Oil Corp. Superior 6,359
WYOMING
Amoco Oil Co. Casper 7,631
CfiH Refinery Inc. Lusk 30
Glacier Park Co. - Osage 638
Glenrock Refinery Inc. - Glenrock 511
Husky Oil Co. - Cheyenne 4,573
3,659b
Husky Oil Co. - Cody 1,828
Little America Refining Co. - Casper 3,895
Mountaineer Refining Co. Inc. La Barge 24
87 b
Sage Creek Refining Co. Inc. - Cowley 95
Silver Eagle Refining Co. - La Barge 318
Sinclair Oil Corp. - Sinclair 11,129
Southwestern Refining Co. - La Barge 175
Texaco Inc. - Casper 3,339
Wyoming Refining Co. - Newcastle 1,669
PUERTO RICO
Caribbean Gulf Refining Corp. - Bayamon 5,405
Commonwealth Oil Refining Co. Inc. - Penuelas 15,103
7.711&
Peerless Petrochemicals Inc. - Ponce 1,590
Sun Co. Inc. - Yabucoa 13,196
VIRGIN ISLANDS
Amerada Hess Corp. - St. Croix 111,288
GUAM
Guam Oil & Refining Corp. - Agana 6,979
TOTAL 3,031,863
aU.S. Department of Energy. Energy Information Administration.
Petroleum Refineries in the United States and U.S. Territories.
January 1, 1980. DOE/EIA-0111(80).
bCapacity shutdown but capable of being placed in operation within
90 days.
E-9
-------
Table E-2. REFINERY PROCESS UNIT GROWTH PROJECTIONS (1981-86)
(Number of Units)
Model " New Units Modifications/Reconstructions
' ~~"
Unit _ ____ Uni t_Type_ _____ "Number Total _______ Nu'mEer ____ Total
A Hydrotreating 34 35
Isomerization 1 2
Lube Oil 2 49 4 47
Asphalt 2 4
Hydrogen 10 2
B Alkylation 3 3
Reforming 13 27 38 79
Thermal Cracking 5 15
Vacuum Distillation 6 23
C Crude Distillation 17 24 37 56
Catalytic Cracking 7 _ 19 _
100 182
E-10
-------
have the downstream processing capabilities needed to maintain quality output
from heavier crudes. All of the conditions and factors noted above have been
considered in the projection of affected units as described below.
The projections have been made by counting, for each process unit type,
the number of new unit constructions and existing unit reconstructions and
modifications, known to have occurred over the five-year period 1976-1980.
This was accomplished through examination of the "Worldwide Construction"
issues of the Oil and Gas Journal for the appropriate years. Uhile new unit
construction is specifically noted in the reports reviewed, expansions in
output have been counted as unit modifications and reconstructions since
increases in unit capacity are often achieved by increasing the number of
equipment components (i.e., valves, pumps, etc.) comprising a unit. There-
fore, since such components are the sources of fugitive VOC emissions, unit
capacity increases could entail increased emissions and thus fall subject to
new source designation through modification.
The uncertainty of continued Federal support of small refiners requires
an adjustment to the projection method, thus recognizing that the recent
rapid growth of small refineries is unlikely to continue. This adjustment
has been accomplished by counting only those constructions and modifications
that have occured at existing refineries with crude distillation capacity in
excess of 2,226 m3 per calendar day. This cut-off point was chosen since
it represents the average size of those small refineries built during the
period 1974-1980 under protective regulations such as the entitlements
program.
The results of the model unit growth projections, made according to the
method described above, are summarized in Table E-2. These projections serve
as the basis for the projection of environmental and economic impacts pre-
sented in Chapters 7 and 9. respectively.
E-ll
-------
APPENDIX F
EVALUATION OF THE EFFECTS OF LEAK DETECTION AND
REPAIR ON FUGITIVE EMISSIONS USING THE LDAR MODEL
-------
F.O EVALUATION OF THE EFFECTS OF LEAK DETECTION
AND REPAIR ON FUGITIVE EMISSIONS USING THE LDAR MODEL
The purpose of Appendix F is to present a mathematical model for
evaluating leak detection and repair programs (LDAR model) and to
compare the impacts determined by this model with the results of the
impact analyses in Chapters 7, 8, and 9. The LDAR model is an empirical
approach which incorporates recently available leak occurrence and
recurrence data and emission reduction data regarding the effectiveness
of simple on-line repair of leaking sources. Whereas, the leak
detection and repair program impacts presented in Chapters 7, 8, and 9
are determined through derived controlled emission correction factors
(ABCD Model) which are based in part upon engineering judgment.
F.I LDAR MODEL
The LDAR model is based on the premise that all sources at any
given time are in one of four categories:
1) Non-leaking sources (sources screening, or found to be emitting
VOC, less than the action level of 10,000 ppmv);
2) Leaking sources (sources screening equal to or greater than the
action level);
3) Leaking sources which cannot be repaired on-line (screening equal
to or greater than the action level) that are awaiting a shutdown, or
process unit turnaround, for repair; and
4) Repaired sources with early leak recurrence.
There are also four basic components to the LDAR model:
1) Screening of all sources except those in Category 3, above;
2) Maintenance of screened sources in Categories 2 and 4, above, in
order to reduce emissions to less than 10,000 ppmv;
3) Rescreening of repaired sources;
4) Process unit turnaround during which maintenance is performed for
sources in Categories 2, 3, and 4, above. Figure F-l shows a schematic
diagram of the LDAR model.
F-2
-------
ta«ic«j» mot j«p«lt«4
I
CO
H*lBte0«itc* of
«hln| »uuf c«« I»clu4« all aour cca which l>«4 lc*fc tccuf ie(vc«,
rly l*llur*B, ot h«J l**k occ«ir*iic« «nJ rc^«lneJ l«ab*r*
Figure F-l. SCHEfATIC DIAGRAM OF THE LDAR MODEL
-------
Since there are only four categories of sources, only four "leak
rates" apply to all sources. In fact, there are only three distinct
leak rates, since the repaired sources experiencing early leak recurrence
are assumed to have the same leak rate as sources which were unsuccessfully
repaired. The LDAR model does not evaluate gradual changes in leak
rates over time but assumes that all sources in a given category have
the same average leak rate.
The LDAR model is implemented by the Statistical Analysis System
(SAS) computer program enabling investigation of several leak detection
and repair program scenarios. General inputs pertaining to the leak
detection and repair program may vary (for example, frequency of
inspection, repairs, and process unit 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 which 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 LDAR model are:
1) All repairs occur at the end of the repair period; the effects
associated with the time interval during which repairs occur are
negligible;
2) Unsuccessfully repaired sources instantaneously fall into the
unrepaired category;
3) Leaks other than unsuccessful maintenance and early recurrences
occur at a linear rate with time during a given inspection period;
4) A process unit turnaround essentially occurs instantaneously at
the end of a turnaround period and before the beginning of the next
monitoring period; and
5) The leak recurrence rate is equal to the leak occurrence rate;
sources that experience leak occurrence or leak recurrence immediately
leak at the rate of the "leaking sources" category.
F-4
-------
A limitation of the LDAR analysis is that the emission data used
to evaluate leak detection and repair program effectiveness in reducing
fugitive emissions of VOC were collected in the field over a very
short period of time in relation to the average operating time between
process unit turnarounds: the emission test data represent only several
minutes out of an average 2-year operation schedule between process
unit turnarounds. Further, all leaks do not occur simultaneously.
The quantity of leaking sources in a process unit accumulates over
time until a maximum number of sources leaking is achieved prior to
maintenance and repair activities at process unit trunaround.
Consequently, the fraction of sources found leaking and the leak
detection and repair program effectiveness for the population of
sources is dependent on the time at which field testing occurred in
relation to previous maintenance activities at process unit turnaround.
For example, if the field test was performed immediately before process
unit turnaround, the degree of emission reduction attributable to the
leak detection and repair program would approach the maximum emission
reduction attainable. Alternately, if field testing is performed
shortly after process unit turnaround, the effectiveness of the leak
detection and repair program will be minimal and the actual emission
reduction may be underpredicted. The cyclical nature of the number of
leaking sources accumulating between process unit turnarounds and the
effect this cycle has on predicting emission reductions by leak detection
and repair programs are illustrated in Figure F-2.
Generally, there is no indication of where in the repair cycle
field testing occurred. Thus, there is some uncertainty in emission
reduction estimates associated with leak detection and repair programs.
Even though the phase on the repair cycle at which field test data
collection occurred is unknown, it is known that the maximum number of
leaking sources occurs near the end of each repair cycle. It is
probable that for any randomly selected time, the number of sources
tested and found leaking will be less than the maximum number and
emission reductions will be less than the maximum attainable. Therefore,
the LDAR model probably predicts emission reductions that are less
than the maximum actually attainable. That is, the LDAR model emission
reduction estimates probably are conservative.
F-5
-------
Initial
Leak
Frequency t
(Maximum "
Leak
Occurrence)
Fraction
of
Sources
Leaking
(Percent)
Practical
Minimum
Leak
Frequency
Time
Process Unit
Turnaround
Process Unit
Turnaround
(?) LORP emission reduction effectiveness approaching maximum attainable
value if field data collected at this point in the leak repair cycle
is used in LDAR model.
(D LDRP emission reduction effectiveness underpredicted if field data
collected at this point in the leak repair cycle is used in LDAR model
This figure is presented for illustrative purposes only and should not
be used to determine the fraction of sources leaking at any particular
phase in the leak repair cycle.
Figure F-2.
Effect Of Leak Repair Cycles On Field Emission Test Results
And Leak Detection And Repair Program (LDRP) Effectiveness.
F-6
-------
F.2 LDAR MODEL IMPACTS
The LDAR model is used to determine emission reductions, fraction
of sources monitored (screened), and fraction of sources repaired
(operated on) for valves and pumps that are subject to leak detection
and repair activities. The values determined for fraction of sources
screened and fraction of sources operated on then are used to establish
monitoring and repair labor requirements. Monthly, monthly/quarterly,
quarterly, and annual leak detection and repair program scenarios for
valves in gas/vapor service and valves in light liquid service are
evaluated. Monthly, quarterly, and annual leak detection and repair
program scenarios for pumps in light liquid service also are examined.
In addition, safety/relief valve LDAR model impacts are estimated.
The LDAR model input and output data used to evaluate these leak
detection and repair program scenarios are presented in Tables F-l
through F-6.
F.2.1. Environmental Impacts
The resultant LDAR model outputs are used to generate emission
reduction and energy impacts associated with Regulatory Alternatives II
through V. These environmental impacts, presented in Tables F-7
through F-ll, are analogous to the impact tables presented in Chapter 7.
Most bases for calculating the impacts (such as component counts and
model unit counts) are unchanged. However, the LDAR model impacts for
gas/vapor service valves, light liquid service valves, light liquid
service pumps, and gas/vapor service safety/relief valves are substituted
for their respective ABCD model impacts.
F.2.2 Cost Impacts
The LDAR model outputs also are used to determine costs corresponding
to the leak detection and repair programs required by the regulatory
alternatives. The cost impacts, presented in Tables F-12 through
F-23, are developed by substituting LDAR model leak detection/repair
costs and emission reductions for ABCD model leak detection/repair
costs and emission reductions. All other cost bases presented in
Chapter 8 (including capital costs) are unchanged.
F.2.3. Economic Impacts
Economic impacts of implementing the regulatory alternatives are
determined using the LDAR model cost impacts developed in Tables F-12
F-7
-------
TABLE F-l. INPUT DATA FOR EXAMINING THE REDUCTION IN AVERAGE LEAK RATE
DUE TO A VALVE MAINTENANCE PROGRAM
TYPE OF
SOURCE/UNIT
El
MEAN (95% CD
FF
MEAN<95% CD
IFL
MEAN <8F. >
Fl
MEAN (Sfi)
F2
MEAN ) (
0.038
r
0.038
9
0.038
r
0.038
r
0.03B
r
0.038
f
0.038
>
0.038
f
0.1
) ( ) (
0.11
) ( ) <
0.1
) ( ) (
0.11
) ( ) (
0.1
> ( ) (
0.11
\ / J (
0.1
> ( ) (
0.11
> ( ) (
MONTHS -- FRACTION OF SOURCES UNREPAIRED (FED
(KG/HR/SOURCE)
FF = FRACTION OF NON-LEAKING SOURCES
FOR Al L
AT THE
SOURCES INITIALLY
BEGINNING THAT BECOME I.
0.
0.
0.
0.
0.
0.
0.
0.
IS
374
)
374
)
374
>
374
)
374
>
374
\
374
)
374
)
0 AT
0
(
0
(
0
(
0
(
0
<
0
I
0
(
0
(
.023
)
.023
)
.023
)
.023
)
.023
)
.023
\
.023
)
.023
)
0.
<
0.
(
0.
(
0.
(
0.
(
0.
/ '
0.
(
0.
(
1
)
1
)
1
)
1
)
1
)
1
\
1
)
1
>
0.
(
0.
(
0.
(
0.
(
0.
(
0.
/
0.
(
0.
(
14
14
14
14
14
14
14
14
THE TURNAROUNDS
EAKERS
(SCREENING VALUE GREATER THAN OR EQUAL TO 10.000 PFHV) DURING A 12 MONTH PERIOD (LEAK OCCURRENCE)
IFL = FRACTION OF SOURCES LEAKING INITIALLY
Fl = ONE MINUS EMISSIONS REDUCTION FROM AN UNSUCCESSFUL RF.FAIR. DEFINED BY EE-FISFL WHEREr
EL = AVERA(iE EMISSION FACTOR FOR SOURCES LEAKING AT OR ABOVE THE ACTION LEVELf AND
EE=AVERAGE EMISSION FACTOR FOR SOURCES WHICH EXPERIENCE EARLY LEAK RECURRENCES
F2 = ONE MINUS EMISSIONS REDUCTION FROM A SUCCESSFUL REPAIRi DEFINED BY EP==F2*EL WHERE EL IS AS DEFINFD AUPVF., AMD
EP=AVERAGE EMISSION FACTOR FOR SOURCES LEAKING BELOW THE ACTION LEVEL
FE1 = FRACTION OF SOURCES THAT ARE LEAKING AND FOR WHICH ATTEMPTS Al REPAIR HAVE FAILED
FE2 - FRACTION OF REPAIRED SOURCES THAT EXPERIENCE EARLY FAILURES
-------
INPUT DATA
Table F-2. FOR EXAMINING THE REDUCTION IN AVERAGE LEAK RATE DUE TO A PUMP MAINTENANCE PROGRAM
TYPE OF
SOURCE/UNIT
El
MEAN (95% CD
FF
MEAN(95% CD
IFL Fl F2 FE1 FE2
MEAN (SE) MEAN (SE) MEAN (SE) MEAN (SE) MEAN (SE)
PUMPS
MONTHLY UNITS
VOC
QUART/MONTH UNITS
VOC
QUARTERLY UNITS
VOC
0.113
0.113
0.113
0.102
0.102
0. 102
0.24
0.24
0.24
0.027
0.027
0.027
YEARLY UNITS
VOC 0.113 0.102 0.24 1 0.027 0 0
( , ) ( , ) ( ) ( ) ( ) ( ) ( )
TURNAROUND EVERY 24 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 BECOME LEAKERS
(SCREENING VALUE GREATER THAN OR EQUAL TO 10,000 FPMV) DURING A 12 MONTH PERIOD (LEAK OCCURRENCE)
IFL = FRACTION OF SOURCES LEAKING INITIALLY
Fl = ONE MINUS EMISSIONS REDUCTION FROM AN UNSUCCESSFUL REPAIR, DEFINED BY EE=F1*EL WHERE,
EL=AVERAGE EMISSION FACTOR FOR SOURCES LEAKING AT OR ABOVE THE ACTION LEVEL, AND
EE=AVERAGE EMISSION FACTOR FOR SOURCES WHICH EXPERIENCE EARLY LEAK RECURRENCES
F2 = ONE MINUS EMISSIONS REDUCTION FROM A SUCCESSFUL REPAIR, DEFINED BY EP=F2*EL WHERE EL IS AS DCFINED ABOVE, AND
EF=AVERAGE EMISSION FACTOR FOR SOURCES LEAKING BELOW THE ACTION LEVEL
FE1 = FRACTION OF SOURCES THAT ARE LEAKING AND FOR WHICH ATTEMPTS AT REPAIR HAVE FAILED
FE2 = FRACTION OF REPAIRED SOURCES THAT EXPERIENCE EARLY FAILURES
-------
Table F-3. VALVE EMISSION FACTORS AND MASS EMISSION REDUCTIONS
TURNAROUND
SUMMARY OF ESTIMATED EMISSION FACTORS (KG/HR) AMD FRACTIONAL REDUCTION
IN MASS EMISSIONS FOR VALVES BY rURNAROIINfi - MONTHLY UNITS
GAS SEKVICE
MEAN EMISSIOM-KG/HR
Linuin SERVICE
REDUCTION
MEAN EMISSIOK'-KO/HR
RE DUCT I ON
0.0088
0.0080
0.673
0.703
0.0034
0.0030
0.69J.
0.7?5
SUhHARY OF ESTIMATED EMISSION FACTORS
-------
Table F- 4. FRACTION OF VALVES SCREENED AND OPERATED ON
SUMMARY OF TOTAL FRACTION OF SOURCES SCREENED AND OPERATED ON FOP VALVES BY YFAR
MONTHI Y UNITS
GAS SERVICE
LIGHT i rniirn
fEAR
1
t
3
4
5
TOTAL FRACTION OF
SOURCES SCREENED
12.7729
11 .5686
11 .8971
11 .6917
1 1 .8991
TOTAL FRACTION OF
SOURCES OPERATED ON
0.2325
0.2110
0 . 1792
0,2026
0 , 1776
SUMMARY OF TOTAL FRACTION OF SOURCES SCREENED AND
QUART/MONTH UNITS
YEAR
1
n
3
4
3
GAS
TOTAL FRACTION OF
SOURCES SCREENED
5.2994
4. 1169
4 .3130
4. 1595
4.2971
SERVICE
TOTAL FRACTION OF
SOURCES OPERATED ON
0.2776
0,2063
0.1771
0. 1983
0. 175*
SUMMARY OF TOTAL FRACTION OF SOURCES SCREENED AND
QUARTERLY UNITS
YEAR
1
-i
3
4
5
GAS
TOTAL FRACTION OF
SOURCES SCREENED
4 , 9324
3.8648
3.9726
3.9014
3.9730
SFRU rr.F
TOTAL FRACTION OF
SOURCES OPERATED ON
0 ,2760
0.2051
0. 1762
0. 1970
0. 1748
SUMMARY PIF TOTAL FRACTION OF SOURCES SCREENED ANI.I
YEARLY UHITS
^EAR
1
n
3
4
f
J
GAS
TOTAL FRACTION OF
SOURCES SCREENED
1 .9900
0.9749
1 .0000
0 . 9037
1 . 0000
SERVICE
TOTAL FRACTION OF
SOURCES OPERATED ON
0.2312
0. 1798
0.1634
0. 1735
0. 1627 r , ..
TOTAL FRACTION OF
SOURCES SCREENED
12.7594
11 .3333
11 .997?
1 1 . 6915
1 I .8991
TOIi".l FRACT1PI! OF
SOURCES OPERATED ON
0 . 2937
0.2119
0. 1793
0.2026
0. 1776
OPERATE!' HN ^ OR VALUES PY YEAR
LIGHT
TOTAL FRACTION OF
SOURCES SCRKENFD
5.3121
4.1121
4 .3170
4 . 1394
4.2971
LIGUin SERVICE
TOTAL FRACTION OF
SOURCES OPERATED ON
0 .2388
0.2074
0. 1773
0. 1983
0.1756
OPERATED ON FOR VALVES BY YEAR
LIGHT
TOTAL FRACTION OF
SOURCES SCREENED
4.9231
3.3603
3.9723
3.9043
3.9730
inillD SKR'MCE
TOTAL FRACTION OF
SOURCES OPERATED ON
0.287?
0. 2060
0. 1764
0 . 1970
0 . 1748
OPERATED ON FOR VAl VFS BY YEAR
LIGHT
TOTAL FRACTION OF
SOURCES SCREENED
1 .9890
0. 9738
1 .0000
0 . 9836
1 .0000
LIC1UIJ.I SERVICE
TOTAL FRACTION OF
SOURCES OPERATED ON
0.2622
0 . 1808
0 . 1636
0. 1736
0. 1627
-------
Table F- 5. PUMP EMISSION FACTORS AND MASS EMISSION REDUCTIONS
ro
SUMMARY OF ESTIMATED EMISSION FACTORS (KG/HR) AND FRACTIONAL REDUCTION
IN MASS EMISSIONS FOR PUMPS BY TURNAROUND - MONTHLY UNITS
VOC SERVICE
TURNAROUND MEAN EMISSION-KG/HR REDUCTION
1 0.0189 0.833
2 0.0189 0.833
SUMMARY OF ESTIMATED EMISSION FACTORS (KG/HR) AND FRACTIONAL REDUCTION
IN MASS E1ISSIONS FOR PUMPS BY TURNAROUND - QUARTERLY UNITS
VOC SERVICE
TURNAROUND MEAN EMISSION-KO/HR REDUCTION
1 0.0328 0.709
2 0.0328 0.709
SUMMARY OF ESTIMATED EMISSION FACTORS (KG/HR) AND FRACTIONAL REDUCTION
IN MASS EMISSIONS FOR PUMPS BY TURNAROUND YEARLY UNITS
VOC SERVICE
TURNAROUND MEAN EMISSION-KG/HR REDUCTION
1 0.0883 0.218
2 0.0883 0.218
-------
Table F-6. FRACTION OF PUMPS SCREENED AND OPERATED ON
3UMMARY OF TOTAL FRACTION OF SOURCES SCREENED AND OPERATED ON FOR PUMPS BY YEAR
MONTHLY UNITS
VOC SERVICE
TOTAL FRACTION OF TOTAL FRACTION OF
YEAR SOURCES SCREENED SOURCES OPERATED ON
1 13.0000 0.6480
2 12.0000 0.4080
3 12.0000 0.4080
4 12.0000 0.4080
3 12.0000 0.4080
SUMMARY OF TOTAL FRACTION OF SOURCES SCREENED AND OPERATED ON FOR PUMPS BY YEAR
QUARTERLY UNITS
VOC SERVICE
TOTAL FRACTION OF
YEAR SOURCES SCREENED
1 5.0000
2 4.0000
3 4.0000
4 4.0000
S 4.0000
TOTAL FRACTION
SOURCES OPERATED
0.6343
0.3943
0.3943
0.3943
0.3943
OF
ON
SUMMARY OF TOTAL FRACTION OF SOURCES SCREENED AND OPERATED ON FOR PUMPS 31 "EAR
YEARLY UNITS
VOC SERVICE
TOTAL FRACTION OF
YEAR SOURCES SCREENED
1 2.0000
2 1.0000
3 1.0000
4 1.0000
3 1.0000
TOTAL FRACTION
SOURCES OPERATED
0.3797
0.3397
0.3397
0.3397
0.3397
OF
ON
F-13
-------
Table F-7. CONTROLLED VOC EMISSION FACTORS FOR VARIOUS
INSPECTION INTERVALS USING THE LDAR MODEL3
Source
Type
Valves
Gas/vapor
Light Liquid
Pump Seals
Light Liquid
Safety/Relief
Valves
Gas /Vapor
Inspection
Interval'
Quarterly0'0'0
Monthly6^
Annual b
Quarter! yc>a
Monthly8
K
Annual
Monthly
b f
Quarterly '
Control
Efficiency
(percent)
59.7
70.3
21.2
62.7
72.5
21.8
83.3
44
Controlled
Emission
Factors (kg/day)
0.262
0.192
0.209
0,098
0.072
2.12
0.45
2.18
aTable F-7 presents information based upon the LDAR model which is
analogous to ABCD model information presented in Table 7-1.
Required in Regulatory Alternative II.
cRequired 1n Regulatory Alternative III.
dRequired in Regulatory Alternative IV.
eRequired in Regulatory Alternative V.
Safety/relief valve LDAR model outputs were estimated by weighting the
safety/relief valve ABCD model control effectiveness by the ratio of the
quarterly inspection for gas/vapor valve ABCD model estimate to the gas/vapor
valve LDAR model estimate. Calculated as:
Safety/Relief Valve
LDAR Control
Effectiveness
/ Valve LDAR Model
(Safety/Relief Valve \ Control
ABCD Model UEffectiveness Table F-
Control Effectiveness] / Valve ABCD Model \
Table 7-1 / / Control \
\ Effectiveness )
(0.64) (0.597) = 0.44 \ Table 7-1 /
(0.86)
The estimated LDAR model control emission factor for quarterly leak detection
and repair for safety/relief valves is calculated as:
/ Uncontrolled
Safety/Relief Valve 1
Emission Factor
i Table 7-1
Estimated LDAR
Model Emission
Reduction for
Safety/Relief
Valves
(3.9 kg/day)(l-0.44)
= 2.18 kg/day
F-14
-------
Table 8.
VOC EMISSIONS FOR REGULATORY ALTERNATIVES BASED ON LDAR MODEL9
(Model Unit A}
I
Uncontrolled
. . b
emissions
TI
i
i—1
en
Source type
Valves
gas/vapor
1 ight liquid
heavy liquid
Open-Ended Lines
Sampling
connections
Pump Seals
light liquid
heavy liquid
Flanges
Relief Valves
gas/vapor
Compressor Seals
Total
(kg/day)
83
65
0.80
3.9
3.6
19
2.0
13
12
15
217
Percent
of
total
38
30
<1
2
2
9
1
6
5
7
II
Control 1 ed
emissions0
(kg/day)
34
52
0.80
0
3.6
15
2.0
13
6.5
3.2
130
Percent
of
total
26
40
<1
0
3
12
2
10
5
2
III
Controlled
emissions0
(kg/day)
34
24
0.80
0
0
3.2
2.0
13
0
0
77
Regulatory Alternatives
IV
Percent
of
total
44
31
1
0
0
4
3
17
0
0
Controlled
emissions0
(kg/day)
34
24
0.80
0
0
0
2.0
13
0
0
74
Percent
of
total
46
32
1
0
0
0
3
18
0
0
V
Controlled
emissions0
(kg/day)
25
18
0.80
0
0
0
2.0
13
0
0
59
Percent
of
total
43
31
1
0
0
0
3
22
0
0
VI
Control led
emissions0
(kg/day)
0
0
0.80
0
0
0
2.0
13
0
0
16
Percent
of
total
0
0
5
0
0
0
13
82
0
0
Table F-8 is analogous to Table 7-2 which is based on the ABCD model.
Uncontrolled anissions are obtained by multiplying the uncontrolled emission factors for each source (Table 3-1) by their respective model unit
component counts (Table 6-1).
""Controlled anissions from gas/vapor valves, light liquid valves, light liquid pumps, and gas vapor safety/relief valves are obtained by multiplying
the controlled emission factors for these sources (Table F-7) by their respective model unit component counts (Table 6-1). Other source emission
estimates are taken from Table 7-2.
-------
Table 8. VOC EMISSIONS FOR REGULATORY ALTERNATIVES BASED ON LDAR MODELa (Continued)
(Model Unit B)
I
Uncontrolled Percent
emissions of
Source type
Valves
gas/vapor
1 ight liquid
heavy liquid
Open-Ended Lines
Sampl ing
connections
Pump Seals
light liquid
heavy liquid
Flanges
Relief Valves
gas/vapor
Compressor Seals
Total
(kg/day) total
170 37
130 28
2 <1
7 2
7.2 2
38 8
3 <1
27 6
27 6
45 10
456
II
Controlled
emissions0
(kg/day)
68
100
2
0
7.2
30
3
27
15
y.6
262
Percent
of
total
26
38
0
3
12
1
10
6
4
III
Controlled
emissions0
(kg/day)
68
49
2
0
0
6.3
3
27
0
0
155
Regulatory Alternatives
IV
Percent
of
total
44
32
1
0
0
4
2
17
0
0
Controlled
emissions0
(kg/day)
68
49
2
0
0
0
3
27
0
0
149
Percent
of
total
46
33
1
0
0
0
2
18
0
0
V
Controlled
emissions
(kg/day)
50
36
2
0
0
0
3
27
0
0
118
Percent
of
total
42
31
2
0
0
0
2
23
0
0
VI
Controlled
emissions0
(kg/day)
0
0
2
0
0
0
3
27
0
0
32
Percent
of
total
0
0
6
0
0
0
9
85
0
0
Table F-8 is analogous to Table 7-2 which is based on the ABCD model.
Uncontrolled emissions are obtained by multiplying the uncontrolled emission factors for each source (Table 3-1) by their respective model unit
component counts (Table 6-1).
Controlled emissions from gas/vapor valves, light liquid valves, light liquid pumps, and gas vapor safety/relief valves are obtained by multiplying
the controlled emission factors for these sources (Table F-7) by their respective model unit component counts (Table 6-1). Other source emission
estimates are taken from Table 7-2.
-------
Table 8. VOC EMISSIONS FOR REGULATORY ALTERNATIVES BASED ON LDAR MODELa (Concluded)
(Model Unit C)
I
Uncontrolled Percent
emissions of
Source type
Valves
gas/vapor
1 ight liquid
heavy liquid
Open-Ended Lines
Sampl ing
connections
Pump Seals
1 ight liquid
heavy liquid
Flanges
Relief Valves
gas/vapor
Compressor Seals
Total
(kg/day) total
500 38
390 29
4 >1
20 2
22 2
110 8
10 >1
77 6
78 6
120 9
1331
II
Controlled
emissions0
(kg/day)
200
310
4
0
22
85
10
77
44
26
778
Percent
of
total
26
40
1
0
3
11
1
10
6
3
III
Controlled
emissions0
(kg/day)
200
150
4
0
0
18
10
77
0
0
459
Regulatory Alternatives
IV
Percent
of
total
43
33
1
0
0
4
2
17
0
0
Controlled
emissions0
(kg/day)
200
150
4
0
0
0
10
77
0
0
441
Percent
of
total
45
34
1
0
0
0
2
18
0
0
V
Controlled
emissions0
(kg/day)
150
110
4
0
0
0
10
77
0
0
351
Percent
of
total
43
31
1
0
0
0
3
22
0
0
VI
Controlled
emissions0
(kg/day)
0
0
4
0
0
0
10
77
0
0
91
Percent
of
total
0
0
4
0
0
0
11
85
0
0
Table F-8 is analogous to Table 7-2 which is based on the ABCD model.
by multiplying the uncontrolled emission factors for each source (Table 3-1) by their respective model unit
Uncontrolled missions are obtained
component counts (Table 6-1).
cControlled emissions from gas/vapor
the controlled emission factors for
estimates are taken from Table 7-2.
valves, light liquid valves, light liquid pumps, and gas vapor safety/relief valves are obtained by multiplying
these sources (Table F-7) by their respective model unit component counts (Table 6-1). Other source emission
-------
I
I—'
co
Table F-9. ANNUAL MODEL UNIT EMISSIONS AND AVERAGE PERCENT EMISSION
REDUCTION FROM REGULATORY ALTERNATIVE I BASED ON LDAR MODEL RESULTS3
Regulatory
Alternative
Ic
II
III
IV
V
VI
Model unit emissions
(Mq/year)b
A
79
47
28
27
22
6
B
166
95
57
55
43
12
C
486
284
167
161
128
33
Average percent
From Regulatory
Alternative I
—
42
65
67
74
93
emission reduction
Incremental
._
42
41
4
20
73
aTable F-9 is analogous to Table 7-3 which is based on the ABCD model.
From Table F-8. Based on 365 days per year.
°Regulatory Alternative I represents "uncontrolled" emissions.
-------
Table 10. PROJECTED VOC FUGITIVE EMISSIONS FROM AFFECTED MODEL UNITS
FOR REGULATORY ALTERNATIVES FOR 1982-1986 BASED ON LDAR MODEL RESULTS3
Model Unitsb
New Units
Modified/
Reconstructed
Units
Year
1982
1983
1984
1985
1986
1982
1983
1984
1985
1986
A
9
19
29
39
49
9
18
27
37
47
B
5
10
15
21
27
15
31
47
67
79
C
4
9
14
19
24
11
22
33
44
56
Total Fugitive Emissions Projected under Regulatory
I
3.5
7.5
11.6
15.8
20.0
8.5
17.3
26.0
35.4
44.0
Baseline
2.7
5.8
8.8
12.0
15.3
6.5
13.2
19.8
27.0
33.6
II
2.0
4.4
6.7
9.1
11.6
4.9
10.0
15.0
20.4
25.4
III
1.2
2.6
4.1
5.5
7.0
3.0
6.0
9.1
12.4
15.4
IV
1.1
2.5
3.8
5.2
6.6
2.8
5.7
8.6
11.7
14.6
Alternative (Gq/yr)c
V
0.9
2.0
3.1
4.2
5.4
2.3
4.6
7.0
9.5
11.8
VI
0.2
0.5
0.8
1.1
1.4
0.6
1.2
1.8
2.5
3.1
,
Table F-10 is analogous to Table 7-4 which is based on the ABCD model.
The numbers of affected model units projected through 1986 are cumulative and distinguished between new unit construction and
modification/reconstruction. Units in existence prior to 1982 are otherwise excluded. A discussion of the growth projections
is in Appendix E.
GThe total fugitive anissions from Model Units A, B, and C are derived from the emissions per model unit in Table F-9. The sum
of anissions in any one year is the sum of the products of the number of affected facilities per model unit times the emissions
per model unit.
The baseline emissions level is the weighted sum of the emissions in Regulatory Alternative I (uncontrolled) and II (CTG Controls)
and is based on the proportion of refineries in nonattainment (169/302 = 56 percent) and attainment (133/302 = 44 percent)
areas. Reference 4.
-------
TABLE F-ll. PROJECTED ENERGY IMPACTS OF REGULATORY ALTERNATIVES FOR 1982-1986 BASED ON LDAR MODEL RESULTS
New
Units
Modified/
Reconstructed
Units
Regulatory
Alternative
II
III
IV
V
VI
II
III
IV
V
VI
Five-year
total reduction from
baseline (Gg)a
10.8
24.2
25.4
29.0
40.6
24.4
54.2
56.7
64.9
90.9
Energy value
of emission reduction
(terajoules)
529
1,190
1,240
1,420
1,990
1,200
2,660
2,780
3,180
4,450
Crude oil equivalent
of emission reduction
(103m3)c
14
31
32
37
52
31
69
72
82
116
Estimated total fugitive VOC emission reduction from Model Units A, B, and C, from Table F-10.
Based on 49 TJ/Gg, these values represent energy credits. Reference 5.
cBased on 38.5 TJ/Mm3 (6.12 x 109 J/bbl) crude oil. Reference 6.
-------
Table F-12. MONITORING AND MAINTENANCE LABOR-HOUR REQUIREMENTS
BASED ON LDAR MODEL RESULTS3
Components
Per
Model Unit
Source lype ABC
Valves
Gas/Vapor 130 260 780
1 ight liquid 250 500 1500
Pump Seals
lignt liquid 7 14 40
Type of b
Monitoring
Instrument
Instrument
Instrument
Instrument
Instrument
Instrument
Instrument
Visual
LEAK DETECTION
Fraction of
Sources
Screened
3-94h,i,j
11.80k
0.99h
3.941>J
11.80k
lh
121
52h>1>J'k'1
LEAK REPAIR
Monitoring
Labor-Hours
Required
A
17
51
8.3
33
98
1.2
14
1 3
B
34
102
17
66
197
2.3
28
6.1
,u
C
102
307
50
197
590
6.7
80
17
Fraction of
Sources
Operated on
0.
0.
0.
0.
0.
0.
0.
,186
190
168
186
190
340
394
Maintenance ,;
Labor-Hours
A
27
28
47
52
54
190
221
B
55
56
95
105
107
381
441
C
164
167
285
315
322
1,088
1,261
Relief Valves
Gas/Vapor 3
20
Instrument
3.94"
3.2
7.4 21.0
0.186
Compressor Seals
Gas/Vapor 1
Instrument
5.3
0.149
17
45
Table F-12 is analogous to the ABCD analysis presented in Table 8-3.
Assumes that instrument monitoring requires a two-person team and visual monitoring one person.
cFrum Table F-4 and F-6.
Monitoring time per person: valves 1 min., pumps-instrument 5 min., visual 1/2 min.; compressors 5 min.; and
safety/relief valves 8 m1n. Monitoring labor-hours number of workers x number of components x time to monitor x
fraction of sources screened.
eFrom Table F-4 and F-6
Maintenance labor-hours = number of components x repair time x fraction of sources operated on. Labor-hours: Repair
time per component: pumps - 80 hrs., compressors - 40 hrs., valves - 1.13 hrs. (Basis: weighted average on 75 percent
of the leaks repaired on-line requiring 10 minutes per repair, and on 25 percent of the leaks repaired off-line requiring
4 hrs. per repair, safety relief valves - 0 hrs. (It is assumed that these leaks are corrected by routine maintenance at
no additional labor requirement). (,4)(.35) = 0.14.
^From Table 8-3. (Fraction of Compressors operated on quarterly percent recurrence) (Percent of sources leaking)
(0.4)(0.35) 0.14.
Required in Regulatory Alternative II.
Required in Regulatory Alternative III.
^Required in Regulatory Alternative IV.
L
Required in Regulatory Alternative V.
Required in Regulatory Alternative VI.
F-21
-------
Table F-13. LEAK DETECTION AND REPAIR COSTS BASED ON
LDAR MODEL RESULTSa'b
(May 1980 Dollars)
Regulatory
Alternatives
II
III
IV
V
Leak Detection Cost
Model Units
A
610
1,210
950
2,740
B
1,240
2,410
1,910
5,490
C
3,640
7,130
5,690
16,500
A
4,860
5,400
1,420
1,480
Repair Cost
Model Units
B
9,860
10,800
2,880
2,930
C
28,500
31,300
8,620
8,800
aTable F-13 is analogous to Table 8-4.
bCost = Hours (From Table F-3) x $18.00 per hour.
cRegulatory Alternative I has zero costs. Regulatory Alternative VI
has negligible costs incurred by weekly visual inspection.
F-22
-------
Table 14. RECOVERY CREDITS0
I
r-o
CO
Regulatory
Alternative
I
11
III
IV
V
VI
VOC
Emissions
Mg/yr
79
47
28
27
22
6
Model Unit A
Emission
Reduction
from
Reg ill atory
Alternative I
Mg/yr
__
32
51
52
57
73
k
Recovered
Product
Value
$/yr
__
6,900
11,000
11,200
12,300
15,700
VOC
Emissions
Mg/yr
166
95
57
55
43
12
Model Unit B
Emission
Reduction
from
Regulatory
Alternative I
Mg/yr
_„
71
109
111
123
154
k
Recovered
Product
Value
$/yr
__
15,300
23,400
23,900
26,400
33,100
VOC
Emissions
Mg/yr
486
284
167
161
128
33
Model Unit C
Emission
Reduction
from
Regulatory
Alternative I
Mg/yr
202
319
325
358
453
K
Recovered
Product
Value
$/yr
__
43,400
68,600
69,900
77,000
97,400
Table F-14 is analogous to Table 8-8.
This value is obtained by multiplying the recovery credit in Mg per year (Table F-16) by $215 per Mg (May 1980 value of 60:40 LPG to
Gasoline Price Ratio). References 7, 8.
-------
Table F-15. ANNUALIZED CONTROL COST ESTIMATES FOR NEW
FACILITIES FOR MODEL UNIT A BASED ON THE LUAR MODEL3
(Thousands of May 1980 Dollars)
Regulatory Alternatives
Cost Item II
Annual! zed Capital Costs
A. Control Equipment
1. Monitoring Instrument 2.1
2. Caps for Open-Ended Lines 0.60
3. Dual Mechanical Seals
o Seals
o Installation
4. Barrier Fluid System for
Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk System
o Disks
o Assembly and Installation
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
B. Initial Leak Repair 1.0
Operating Costs
A. Maintenance Charges
1. Monitoring Instrument 3.0
2. Caps for Open-Ended Lines 0.19
3. Dual Mechanical Seals
4. Barrier Fluid System
for Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir Vents
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk Systems
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
B. Miscellaneous Charges (taxes,
insurance, administration)
1. Monitoring Instrument 0.37
2. Caps for Open-Ended Lines 0.15
3. Dual Mechanical Seals
4. Barrier Fluid System for
Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk System
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
C. Labor Charges
1. Monitoring Labor 0.61
2. Leak Repair Labor 4.9
3. Administrative and Support 2.2
Total Before Credit 15
Recovery Credits (6.9)
Net Annual ized Cost 8.1
III
2.1
0.60
1.3
0.40
1.4
0.86
0.84
3.0
0.19
0.40
0.46
0.27
0.37
0.15
0.32
0.37
0.21
1.2
5.4
2.6
22
(H)
11
IV
2.1
0.60
3.9
0.33
2.1
4.6
1.3
0.40
1.4
0.86
0.18
3.0
0.19
0.44
0.65
1.4
0.40
0.46
0.27
0.37
0.15
0.35
0.52
1.1
0.32
0.37
0.21
0.95
1.4
0.94
31
(ID
20
V
2.1
0.60
3.9
0.33
2.1
4.6
1.3
0.40
1.4
0.86
0.18
3.0
0.19
0.44
0.65
1.4
0.40
0.46
0.27
0.37
0.15
0.35
0.52
1.1
0.32
0.37
0.21
2.7
1.5
1.7
34
(12)
22
VI
2.1
0.60
3.9
0.33
2.1
4.6
1.3
0.40
1.4
0.86
169
3.0
0.19
0.44
0.65
1.4
0.40
0.46
0.27
52
0.37
0.15
0.35
0.52
1.1
0.32
0.37
0.21
42
0.055
0.0
0.022
291
(16)
275
Values presented in this table are analagous to the ABCD model values presented
in Table 8-9.
From Tables 6-1 and 8-1.
cFrom Table F-13.
F-24
-------
Table F-16. ANNUALIZED CONTROL COST ESTIMATES FOR NEW
FACILITIES FOR MODEL UNIT B BASED ON THE LDAR MODEL3
(Thousands of May 1980 Dollars)
Regulatory Alternatives
Cost Item II
Annual ized Capital Cost
A. Control Equipment
1. Monitoring Instrument 2.1
2. Caps for Open-Ended Lines 1.2
3. Dual Mechanical Seals
o Seals
o Installation
4. Barrier Fluid System for
Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk System
o Disks
o Assembly and Installation
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
B. Initial Leak Repair 1.5
Operating Costs
A. Maintenance Charges
1. Monitoring Instrument 3.0
2. Caps for Open-Ended Lines 0.37
3. Dual Mechanical Seals
4. Barrier Fluid System
for Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir Vents
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk Systems
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
B. Miscellaneous Charges (taxes,
insurance, administration)
1. Monitoring Instrument 0.37
2. Caps for Open-Ended Lines 0.30
3. Dual Mechanical Seals
4. Barrier Fluid System for
Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir Vents
6. Compressor Degassing
Reservoir Vents .
7. Rupture Disk System
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
C. Labor Charges
1. Monitoring Labor 1.2
2. Leak Repair Labor 9.9
3. Administrative and Support 4.4
Total Before Credit 24
Recovery Credits (15)
Net Annual 1 zed Cost 9
III
2.1
1.2
3.9
0.93
3.3
1.7
1.4
3.0
0.37
1.2
1.1
0.53
0.37
0.30
0.96
0.86
0.42
2.4
10.8
5.3
42
(23)
19
IV
2.1
1.2
7.9
0.65
4.2
9.1
3.9
0.93
3.3
1.7
.25
3.0
0.37
0.88
1.3
2.8
1.2
1.1
0.53
0.37
0.30
0.70
1.0
2.2
0.96
0.86
0.42
1.9
2.9
1.9
60
(24)
36
V
2.1
1.2
7.9
0.65
4.2
9.1
3.9
0.93
3.3
1.7
.25
3.0
0.37
0.88
1.3
2.8
1.2
1.1
0.53
0.37
0.30
0.70
1.0
2.2
0.96
0.86
0.42
5.5
2.9
3.4
65
(26)
39
VI
2.1
1.2
7.9
0.65
4.2
9.1
3.9
0.93
3.3
1.7
338
3.0
0.37
0.88
1.3
2.8
1.2
1.1
0.53
100
0.37
0.30
0.70
1.0
2.2
0.96
0.36
0.42
83
0.11
0.0
0.04
570
(33)
537
aValues presented in this table are analagous to the ABCD model values presented
in Table 8-10.
bFrom Tables 6-1 and 8-1.
cFrom Table F-13.
F-25
-------
Table F-17. ANNUALIZED CONTROL COST ESTIMATES FOR NEW
FACILITIES FOR MODEL UNIT C BASED ON THE LDAR MODEL9
(Thousands of May 1980 Dollars)
Regulatory Alternatives
Cost Item II
Annual ized Capital Costs
A. Control Equipment
1. Monitoring Instrument 2.1
2. Caps for Open-Ended Lines 3.6
3. Dual Mechanical Seals
o Seals
o Installation
4. Barrier Fluid System for
Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk System
o Disks
o Assembly and Installation
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
B. Initial Leak Repair 4.8
Operating Costs
A. Maintenance Charges
1. Monitoring Instrument 3.0
2. Caps for Open-Ended Lines 1.1
3. Dual Mechanical Seals
4. Barrier Fluid System
for Dual Mechanical Seals
5. Punp Seal Barrier Fluid
Degassing Reservoir Vents
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk Systems
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
B. Miscellaneous Charges (taxes,
insurance, administration)
1. Monitoring Instrument 0.37
2. Caps for Open-Ended Lines 0.89
3. Dual Mechanical Seals
4. Barrier Fluid System for
Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir Vents
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk System
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
C. Labor Charges
1. Monitoring Labor 3.6
2. Leak Repair Labor 28.5
3. Administrative and Support 12.8
Total Before Credit 61
Recovery Credits (43)
Net Annual ized Cost 18
III
2.1
3.6
10
2.7
9.1
5.2
4.3
3.0
1.1
3.2
3.0
1.6
0.37
0.89
2.6
2.4
1.3
7.1
31.3
15.4
110
(69)
41
IV
2.1
3.6
23
1.9
12
26
10
2.7
9.1
5.2
1.1
3.0
1.1
2.5
3.7
8.0
3.2
3.0
1.6
0.37
0.89
2.0
2.9
6.4
2.6
2.4
1.3
5.7
8.6
5.7
161
(70)
91
V
2.1
3.6
23
1.9
12
26
10
2.7
9.1
5.2
1.1
3.0
1.1
2.5
3.7
8.0
3.2
3.0
1.6
0.37
0.89
2.C
2.9
6.4
2.6
2.4
1.3
16.5
8.8
10.1
177
(77)
100
VI
2.1
3.6
23
1.9
12
26
10
2.7
9.1
5.2
1,000
3.0
1.1
2.5
3.7
8.0
3.2
3.0
1.6
310
0.37
0.89
2.0
2.9
6.4
2.6
2.4
1.3
250
0.31
0.0
0.12
1,700
(97)
1,600
Values presented 1n this table are analagous to the ABCD model values presented
in Table 8-11.
bFrom Tables 6-1 and 8-1.
"•From Table F-13.
F-26
-------
Table F-18. COST EFFECTIVENESS FOR MODEL UNITS FOR NEW
FACILITIES BASED ON THE LDAR MODEL*
(May 1980 Dollars)
Regulatory Alternative
II III
Model Unit A
Total Capital
Cost ($1,000)
Total Annual ized
Cost ($1,000)
Net Annual 1zed
Cost ($1,000)
Total VOC
Reduction (Mg/yr)
Cost Effectiveness
($/Mg VOC)
Model Unit B
Total Capital
Cost ($1,000)
Total Annual ized
Cost ($1,000)
Net Annual 1zed
Cost ($1,000)
Total VOC
Reduction (Mg/yr)
Cost Effectiveness
($/Mg VOC)
Model Unit C
Total Capital
Cost ($1,000)
Total Annual ized
Cost ($1,000)
Net Annual ized
Cost ($1,000)
Total VOC
Reduction (Mg/yr)
Cost Effectiveness
($/Mg VOC)
*Values presented in this
13
15
8
32
250
17
24
9
71
130
31
61
18
202
89
table are
35
22
.1 11
51
220
73
42
19
109
170
190
110
41
319
130
analagous to
IV
85
31
20
52
380
168
60
36
111
320
470
161
91
325
280
the ABCD model
V
85
34
22
57
390
168
65
39
123
320
470
177
100
358
280
values
VI
1,100
291
275
73
3,800
2,300
570
537
154
3,500
6,600
1,700
1,600
453
3,500
presented
in Table 8-12.
F-27
-------
Table F-19. ANIMUALIZED CONTROL COST ESTIMATES FOR
MODIFIED/RECONSTRUCTED FACILITIES FOR MODEL UNIT A
BASED ON THE LDAR MODEL3
(Thousands of May 1930 Dollars)
Regulatory Alternatives
Cost Item
Annual ized Capital Costsc
A. Control Equipment
1. Monitoring Instrument
2. Caps for Open-Ended Lines
3. Dual Mechanical Seals
o Seals
o Installation
4. Barrier Fluid System for
Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk System
o Disks
o Assembly and Installation
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
B. Initial Leak Repair
Operating Costs
A. Maintenance Charges
1. Monitoring Instrument
2. Caps for Open-Ended Lines
3. Dual Mechanical Seals
4. Barrier Fluid System
for Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir Vents
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk Systems
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
B. Miscellaneous Charges (taxes,
Insurance, administration)
1. Monitoring Instrument
2. Caps for Open-Ended Lines
3. Dual Mechanical Seals
4. Barrier Fluid System for
Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk System
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
C. Labor Charges
1. Monitoring Labor
2. Leak Repair Labor
3. Administrative and Support
Total Before Credit
Recovery Credits
Net Annual 1zed Cost
Total VOC Reduction (Mg/yr)
Cost Effectiveness ($/Mg)
III
2.1
0.60
1.3
0.4
2.0
0.86
0.84
3.0
0.19
0.40
0.64
0.27
0.37
0.15
0.32
0.51
0.21
1.2
5.4
2.6
23
(11)
12
51
240
IV
2.1
0.60
5.1
0.39
2.1
4.6
1.3
0.4
2.0
0.86
0.18
3.0
0.19
0.56
0.65
1.4
0.40
0.64
0.27
0.37
0.15
0.44
0.52
1.1
0.32
0.51
0.21
0.95
1.4
0.94
34
(ID
23
52
440
V
2.1
0.60
5.1
0.39
2.1
4.6
1.3
0.4
2.0
0.86
0.18
3.0
0.19
0.56
0.65
1.4
0.40
0.64
0.27
0.37
0.15
0.44
0.52
1.1
0.32
0.51
0.21
2.7
1.5
1.7
36
(12)
24
57
420
VI
2.1
0.60
5.1
0.39
2.1
4.6
1.3
0.4
2.0
0.86
169
3.0
0.19
0.56
0.65
1.4
0.40
0.64
0.27
52
0.37
0.15
0.44
0.52
1.1
0.32
0.51
0.21
42
0.055
0.0
0.022
300
(16)
284
73
3,900
Values presented in this table are analagous to the ABCD model values presented
in Table 8-14.
For Regulatory Alternatives I and II the annualized costs for modified/
reconstructed facilities are the same as for new units (Table F-12).
cFrom Tables 6-1 and 8-1.
dFrom Table F-13.
F-28
-------
Table F-20. ANNUALIZED CONTROL COST ESTIMATES FOR
MODIFIED/RECONSTRUCTED FACILITIES FOR MODEL UNIT B
BASED ON THE LDAR MODEL3
(Thousands of May 1980 Dollars)
Regulatory Alternatives
Cost Item
Annual ized Capital Costs
A. Control Equipment
1. Monitoring Instrument
2. Caps for Open-Ended Lines
3. Dual Mechanical Seals
o Seals
o Installation
4. Barrier Fluid System for
Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk System
o Disks
o Assembly and Installation
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
B. Initial Leak Repair
Operating Costs
A. Maintenance Charges
1. Monitoring Instrument
2. Caps for Open-Ended Lines
3. Dual Mechanical Seals
4. Barrier Fluid System
for Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir Vents
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk Systems
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
B. Miscellaneous Charges (taxes,
Insurance, administration)
1. Monitoring Instrument
2. Caps for Open-Ended Lines
3. Dual Mechanical Seals
4. Barrier Fluid System for
Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir Vents
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk System
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
C. Labor Charges
1. Monitoring Labor
2. Leak Repair Labor
3. Administrative and Support
Total Before Credit
Recovery Credits
Net Annual 1zed Cost
Total VOC Reduction (Mg/yr)
Cost Effectiveness ($/Mg)
III
2.1
1.2
3.9
0.9
4.6
1.7
1.4
3.0
0.37
1.2
1.5
0.53
0.37
0.30
0.96
1.2
0.45
2.4
10.8
5.3
44
(23)
21
109
190
IV
2.1
1.2
10
0.78
4.2
9.1
3.9
0.9
4.6
1.7
0.25
3.0
0.37
1.1
1.3
2.8
1.2
1.5
0.53
0.37
0.30
0.91
1.0
2.2
0.96
1.2
0.45
1.9
2.9
1.9
65
(24)
40
111
360
V
2.1
1.2
10
0.78
4.2
9.1
3.9
0.9
4.6
1.7
0.25
3.0
0.37
1.1
1.3
2.8
1.2
1.5
0.53
0.37
0.30
0.91
1.0
2.2
0.96
1.2
0.45
5.5
2.9
3.3
70
(26)
43
123
350
VI
2.1
1.2
10
0.78
4.2
9.1
3.9
0.9
4.6
1.7
338
3.0
0.37
1.1
1.3
2.8
1.2
1.5
0.53
100
0.37
0.30
0.91
1.0
2.2
0.96
1.2
0.45
83
0.11
C.O
0.04
580
(33)
546
154
3,500
aValues presented 1n this table are analagous to the ABCD model values presented
in Table 8-15.
bFor Regulatory Alternatives I and II the annualized costs for modified/
reconstructed facilities are the same as for new units (Table F-13).
cFrom Tables 6-1 and 8-1.
dFrom Tables F-13.
F-29
-------
Table F-21. ANNUALIZED CONTROL COST ESTIMATES FOR
MODIFIED/RECONSTRUCTED FACILITIES FOR MODEL UNIT C
BASED ON THE LDAR MODELa
(Thousands of May 1980 Dollars)
Regulatory Alternatives
Cost Item
Annual ized Capital Costs0
A. Control Equipment
1. Monitoring Instrument
2. Caps for Open-Ended Lines
3. Dual Mechanical Seals
o Seals
o Installation
4. Barrier Fluid System for
Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk System
o Disks
o Assembly and Installation
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
B. Initial Leak Repair
Operating Costs
A. Maintenance Charges
1. Monitoring Instrument
2. Caps for Open-Ended- Lines
3. Dual Mechanical Seals
4. Barrier Fluid System
for Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir Vents
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk Systems
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
8. Miscellaneous Charges (taxes,
Insurance, administration)
1. Monitoring Instrument
2. Caps for Open-Ended Lines
3. Dual Mechanical Seals
4. Barrier Fluid System for
Dual Mechanical Seals
5. Pump Seal Barrier Fluid
Degassing Reservoir Vents
6. Compressor Degassing
Reservoir Vents
7. Rupture Disk System
8. Closed-Loop Sampling
Connections
9. Sealed Bellows Valves
C. Labor Charges
1. Monitoring Labor
2. Leak Repair Labor
3. Administrative and Support
Total Before Credit
Recovery Credits
Net Annual ized Cost
Total VOC Reduction (Mg/yr)
Cost Effectiveness ($Mg)
III
2.1
3.6
10
2.7
13
5.2
4.3
3.0
1.1
3.2
4.2
1.6
0.37
0.89
2.6
3.4
1.3
7.1
31.3
15.4
116
(69)
47
319
150
IV
2.1
3.6
29
2.3
12.0
26
10
2.7
13
5.2
1.1
3.0
1.1
3.2
3.7
8.0
3.2
4.2
1.6
0.37
0.89
2.6
2.9
6.4
2.6
3,4
1.3
5.7
8.6
5.7
175
(70)
105
325
320
V
2.1
3.6
29
2.3
12.0
26
10
2.7
13
5.2
1.1
3.0
1.1
3.2
3.7
8.0
3.2
4.2
1.6
0.37
0.89
2.6
2.9
6.4
2.6
3.4
1.3
16.5
8.8
10.1
191
(77)
114
358
320
VI
2.1
3.6
29
2.3
12.0
26
10
2.7
13
5.2
1,000
3.0
1.1
3.2
3.7
8.0
3.2
4.2
1.6
310
0.37
0.89
2.6
2.9
6.4
2.6
3.4
1.3
250
0.31
0.0
0.12
1,700
(97)
1,600
453
3,500
aValues presented in this table are analagous to the ABCD model values presented
in Table 8-16.
For Regulatory Alternatives I and II the annuallzed costs for modified/
reconstructed facilities are the same as for new units (Table F-14).
°From Tables 6-1 and 8-1.
dFrom Table F-13.
F-30
-------
Table F-22. FIFTH-YEAR NATIONWIDE COSTS
OF THE REGULATORY ALTERNATIVES
ABOVE REGULATORY ALTERNATIVE I, COSTS
BASED ON THE LDAR MODEL3'0
(Thousands of May 1980 Dollars)
Cost Item
New Units
Total Capital Cost0
Total Annual ized Cost
Total Recovery Credit6
Net Annual ized Cost
Modified/ Reconstructed Units
Total Capital Cost0
Total Annual ized Cost
Total Recovery Credit6
Net Annual ized Cost
II
1,800
2,800
1,800
1,000
3,700
6,100
4,000
2,100
Regulatory Alternatives
III IV V
8,200
4,900
2,800
2,100
19,000
11,000
6,200
4,800
20,000
7,000
2,900
4,100
47,000
16,500
6,300
10,200
20,000
7,700
3,200
4,500
47,000
17,900
7,000
19,900
VI
274,000
70,400
4,000
66,400
610,000
155,100
8,800
146,300
a
Values presented in this table are analagous to the ABCD model values presented
in Table 8-17.
Regulatory Alternative I assumes that no control costs are incurred; therefore,
costs for Regulatory Alternatives II through VI are compared to zero.
°Total cumulative capital costs in 1986.
dAnnualized costs for model units subject to each regulatory alternative in the
fifth year are calculated by multiplying cost estimates for each model unit
under each regulatory alternative by the number of affected model units (from
Table 7-4).
6From Table F-14.
F-31
-------
Table F-23. FIFTH-YEAR NATIONWIDE COSTS FOR
;UM REFINING INDUSTRY ABOVE BASEl
BASED ON THE LDAR MODEL3)D
(Thousands of May 1980 Dollars)
THE PETROLEUM REFINING INDUSTRY ABOVE BASELINE COSTS
BASED ON THE LDAR MODEL3)D
Cost Item
New Units
Total Capital Costc
Total Annual i zed Cost
Total Recovery Credit6
Net Annual ized Cost
Modified/Reconstructed Units
Total Capital Cost
Total Annual ized Cost
Total Recovery Credit
Net Annual ized Cost
II
790
1,230
790
440
1,630
2,680
1,760
920
Regulatory Alternative
III IV V
7,190
3,280
1,790
1,490
16,900
7,580
3,900
3,680
19,000
5,380
1,890
3,490
44,900
13,080
4,060
9,020
19,000
6,080
2,190
3,890
44,900
14,480
4,760
9,720
VI
273,000
68,780
2,990
65,790
607,000
151,700
6,560
145,140
aValues presented in this table are analagous to the ABCD model values presented
in Table 8-18.
Baseline costs are calculated from baseline emission levels. As discussed in
Chapter 7, the baseline VOC emission level represents a weighted average of
emissions from refineries operating in National Ambient Air Quality Standard
(NAAQS) for ozone attainment areas (no control) and refineries operating in
NAAQS for ozone non-attainment areas (CTG controls). Approximately 44 percent
of existing refineries are expected to be operating in ozone attainment areas,
and 56 percent are expected to be operating in ozone non-attainment areas.
cTotal cumulative capital cost above baseline cost in 1986 = total cumulative
capital cost in 1986 for each regulatory alternative - total cumulative capital
cost in 1986 for baseline (for example, at new units: 0.56 x $1,800 = $1,008).
Total annualized cost above baseline cost = total annualized cost for each
regulatory alternative - annualized cost for baseline (for example, at new
units: 0.56 x $2,900 = $1,624).
eTotal recovery credit above baseline credit = total recovery credit for each
regulatory alternative - total baseline recovery credit (for example, at new
units: 0.56 x $1,800 = $1,008).
F-32
-------
through F-23. The price increase under full cost pricing and profit
margin decrease under full cost absorption are presented for each
model unit and regulatory alternative in Tables F-24 and F-25,
respectively. Table F-26 presents a summary of fifth-year net annualized
costs above baseline costs based upon the LDAR model analysis.
F.2.4. Comparative Analysis
A comparison of the results of the LDAR model and ABCD models are
given in Tables F-27 and F-28. Table F-27 compares the estimated
effects of the leak detection and repair scenarios for the individual
emission sources. The overall emission and cost impacts determined
using the LDAR model values are compared with the ABCD model analysis
impacts in Table F-28. The data generated from the LDAR model
(Table F-27) have been substituted into the ABCD Model analyses in
Chapter 7 and 8 for Model Unit B. The impacts resulting from the
control of emission sources other than gas/vapor service valves, and
safety/relief valves, light liquid service valves, and light liquid
service pumps were kept consistent with ABCD model analysis values
reported in Chapters 7 and 8.
This comparison found the LDAR model program emission reductions
to be lower than ABCD model (Chapter 7) emission reductions under all
leak detection and repair scenarios, except the monthly leak detection
and repair scenario for pumps in light liquid service. This comparison
also found the LDAR model costs of implementing the leak detection and
repair programs to be higher than the ABCD model (Chapter 8) analysis
estimates. Higher costs are estimated under the LDAR model due to a
higher percentage of valves requiring repair.
The monthly/quarterly leak detection and repair program scenario
would require monthly leak detection of all gas/vapor and light liquid
service valves. However, valves which do not leak during two consecutive
months would then be inspected on a quarterly basis until a leak is
detected. Although there is no monthly/quarterly leak detection and
repair program in the regulatory alternatives (Chapter 6), the scenario
was included to demonstrate the impacts of such a program in relation
to straight monthly or quarterly leak detection and repair programs.
The LDAR model data output, summarized in Table F-27, indicates that
emission reductions under the monthly/quarterly leak detection and
F-33
-------
Table F-24. PERCENT INCREASES IN PRICE UNDER FULL
COST PRICING BY MODEL UNIT BASED ON LDAR MODEL RESULTS9
.Regulatory Alternative
Unit Type
New Units
A
B
C
II
0.05
0.02
0.03
III
0.08
0.04
0.08
IV
0.13
0.07
0.16
V
0.15
0.08
0.18
VI
0.85
1.15
2.87
Modified/Reconstructed Units
A
B
C
0.05
0.02
0.03
0.09
0.05
0.09
0.15
0.09
0.19
0.16
0.09
0.21
1.91
1.17
2.87
aTable F-24 is analogous to Table 9-23 which is based on the ABCD
model.
F-34
-------
Table F-25. PROFIT MARGINS UNDER FULL COST
ABSORPTION BY MODEL UNIT BASED ON LDAR MODEL RESULTS'
(Baseline Profit Margin = 5.12 Percent)
Regulatory Alternative
Unit Type
New Units
A
B
C
II
5.09
5.11
5.10
III
5.07
5.10
5.08
IV
5.04
5.08
5.03
V
5.04
5.08
5.02
VI
4.12
4.50
3.57
Modified/Reconstructed Units
A
B
C
5.09
5.11
5.10
5.07
5.10
5.07
5.03
5.07
5.02
5.03
5.07
5.01
4.08
4.49
3.57
Table F-25 is analogous to Table 9-24 which is based on the ABCD
model.
Table F-26. SUMMARY OF FIFTH-YEAR NET ANNUALIZED COSTS
BASED ON LDAR MODEL RESULTS3
(Thousands of May 1980 Dollars)
Regulatory Alternative
Unit Type
New Units
Modified/Recon-
structed Units
II
440b
920°
III
1,490
3,680
IV V VI
3,490 3,890 65,790
9,020 9,720 145,140
Total
1,360° 5,170 12,510 13,610 210,930
aCosts are above "baseline" costs as explained in Section 3.3. Table
F-26 is analogous to Table 9-25 which presents fifth-year net annualized
costs based on the ABCD model.
DValues in parentheses denote net annualized credits.
F-35
-------
Table F-27. COMPARISON OF RESULTS FROM THE LDAR MODEL
WITH THE ABCD MODEL ANALYSIS
Results of ABCD Model Analysis3
(LDAR Model Program Output)b
Emission Source
and LDR
Scenario
Emission Percent
Factors'" Emission
(kg/day) Reduction11
Total Fraction of
Sources Screened In
The Second Turnaround-
Annual Average6
Fraction of Sources
Operated on in the
Second Turnaround-
Annual Average
Gas/Vapor Service Valves
Quarterly LDR
0.090
(0.262)
Monthly/Quarterly —
LDR9 (0.252)
Monthly LDR
0.058
(0.192)
Light Liquid Service Valves
Annual LDR
Quarterly LDR
Monthly/Quarterly
LDR9
Monthly LDR
0.091
(0.209)
0.070
(0.098)
(0.096)
0.060
(0.072)
Light Liquid Service Pumps
Annual LDR
0.86
(2.12)
(0.79)
0.54
(0.45)
86
(60)
(61)
91
(70)
65
(21)
73
(63)
(64)
77
(73)
68
(22)
Quarterly LDR
Monthly LDR
Gas/Vapor Service Safety/Relief Valves
Quarterly LDR1
(71)
80
(83)
4
(3.94)
(4.23)
12
(11.
1
(0.99)
4
(3.94)
(4.23)
12
(11.80)
1
(1.00)
4
(4.00)
12
(12.00)
1.4
(2.18)
64
(44)
0.040
(0.186)
(0.187)
0.060
(0.190)
0.022
(0.168)
0.044
(0.186)
(0.187)
0.066
(0.190)
0.048
(0.340)
0.096
(0.394)
0.144
(0.408)
0.028
aThe ABCD model analysis leak detection and repair (LDR) program data were obtained from Chapters 6
through 8.
LDAR model values are indicated in parentheses. The LDAR model program data were obtained from
Tables F-3 through F-6.
CABCD model emission factor values were obtained from Table 7-1; the LDAR model values were the
reported values for the second turnaround in Tables F-3 and F-5. (The emission factors are reported
1n kg per hour 1n Tables F-3 and F-5.)
Percent emission reduction values for the ABCD model analysis were calculated from the data in
Table 7-2; the corresponding values for the ABCD model were the values for the second turnaround in
Tables F-3 and F-5.
eValues for total fraction of sources screened were obtained for the ABCD model analysis from Table 8-3.
Corresponding values for the LDAR model were the averages of fourth- and fifth-year values reported
in Tables F-4 and F-6.
Values for fraction of sources operated on were obtained for the ABCD model analysis from the
equation, (initial leak frequency) x (times operated on per year) x (leak recurrence factor); these
values are presented in Table 8-3. The corresponding values for the modeled emission program
represent the averages of the fourth- and fifth-year values reported in Tables F-4 and F-6.
9There is no ABCD model analysis equivalent to the monthly/quarterly LDR scenario for valves.
There is no ABCD model analysis equivalent to the quarterly LDR scenario for pumps.
There is no LDAR model output equivalent to the quarterly LDR scenario. However, the LDAR model
output emission factor and emission reduction can be estimated as shown in Table F-7.
F-36
-------
Table F-28. COMPARISON OF OVERALL EMISSION AND COST IMPACTS
USING LDAR MODEL PROGRAM VALUES WITH ABCD MODEL ANALYSIS IMPACTS
All Sources
Regulatory Alternatives
II III IV V
Emissions From Model Unit B
ABCD Model Emiss1onsa(kg/day)
LDAR Model Emissionsb(kg/day)
Emissions (kg/day)
140
262C
122
98
155
57
90
149
59
77
118
41
Annualized Costs For Model Unit B-New Units
ABCD Model Net Annualized Costs
($1000/yr)d'e
LDAR Model Net Annualized Costs6'9
($1000/year)
Annualized Costs ($1000/yr)
(12)T
9
21
1
19
18
28
36
31
39
"From Table 7-2.
bObtained by substituting LDAR model emissions values and safety/relief for valves in gas/ vapor
service, valves in light liquid service, and pumps in light liquid service for ABCD model analysis
emission values (Table 7-2). Emission rates for other sources are unchanged.
cFrom Table F-8.
dFrom Table 8-10.
eObtained by substituting LDAR model costs and emission credits for analogous ABCD model costs and
emission credits; model unit costs for control of sources other than valves and pumps are the same
as In Chapter 8.
fParentheses denote credit,
9From Table F-16.
F-37
-------
repair program scenario are similar to emission reductions achieved
under the straight quarterly leak detection and repair program scenario.
The total fraction of sources screened and fraction of sources operated
on under the monthly/quarterly leak detection and repair program
scenario are also similar to corresponding quarterly leak detection
and repair program scenario values.
F-38
-------
F.4 REFERENCES
1. Fugitive Emission Sources of Organic Compounds—Additional Information
on Emissions, Emission Reductions, and Costs. U.S. Environmental
Protection Agency. Office of Air Quality Planning and Standards.
Research Triangle Park, N.C. EPA-450/3-82-010. April 1982.
Docket Reference Number II-A-39.*
2. Williamson, H.J., L.P. Provost, J.I. Steinmetz. Model for Evaluating
the Effects of Leak Detection and Repair Programs on Fugitive
Emissions. Radian Corporation. September 1981. Docket Reference
Number II-I-61.*
3. Memorandum from T.W. Rhoads, Pacific Environmental Services,
Inc., to Docket No. A-80-44. Evaluation of the Effects of Leak
Detection and Repair on Fugitive Emissions using the LDAR Model.
August 4, 1982. Docket Reference Number II-B-45.*
4. Carruthers, J.E., and J.L. McClure, Jr. Overview Survey of
Status of Refineries in the U.S. with RACT Requirements (Draft
Report). Prepared for U.S. Environmental Protection Agency.
Division of Stationary Source Enforcement. Washington, D.C.
October 1979. p. A-2. Docket Reference Number II-A-30.*
5. Wetherold, R.G., C.P. Provost, and C.O. Smith. Assessment of
Atmospheric Emissions from Petroleum Refining. Volume 3, Appendix B.
Prepared for U.S. Environmental Protection Agency. EPA-600/2-80-075c.
April 1980. Docket Reference Number II-A-19.*
6. Perry, R.H. and C.H. Chilton. Chemical Engineer's Handbook.
Fifth Edition. McGraw-Hill Book Company. New York. 1973.
Docket Reference Number II-I-15.*
7. Chemical Engineering. Gasoline in Olefins from an Alcohol Feed.
a7(8):86. April 21, 1980. Docket Reference Number II-I-46.*
8. Oil and Gas Journal. OGJ. Production Report. ^8(22):194.
June 2, 1980. Docket Reference Number 11-1-48.*
*References can be located in Docket Number A-80-44 at the U.S.
Environmental Protection Agency Library, Waterside Mall, Washington,
D.C.
F-39
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-450/3-81-015a
4. TITLE AND SUBTITLE
VOC Fugitive Emissions in the Petroleum Refining
Industry—Background Information for Proposed Standard
3. RECIPIENT'S ACCESSION NO.
5. REPORT DATF
iioyember
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Office of Air Quality Planning and Standards
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-3060
12. SPONSORING AGENCY NAME AND ADDRESS
Director for Air Quality Planning and Standards
Office of Air, Noise, and Radiation
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
13. TYPE OF REPORT AND PERIOD COVERED
14. SPONSORING AGENCY CODE
EPA/200/04
15. SUPPLEMENTARY NOTES This report discusses the regulatory alternatives considered during
development of the proposed new source performance standards and the environmental
and economic impacts associated with each regulatory alternative.
16. ABSTRACT
Standards of performance for the control of volatile organic compound (VOC)
fugitive emissions from the petroleum refining industry are being proposed under
Section 111 of the Clean Air Act. These standards would apply to fugitive emission
sources of VOC within new, modified, and reconstructed petroleum refinery compressors
and process units. This document contains background information and environmental
: and economic impact assessments of the regulatory alternatives considered in
developing the proposed standards.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
Air Pollution
Petroleum Refining
Pollution Control
Standards of Performance
Volatile Organic Compounds (VOC)
b.lDENTIFIERS/OPEN ENDED TERMS c. COSATI Held/Group
Air Pollution Control
13b
18. DISTRIBUTION STATEMENT
19. SECURITY CLASS (Tliii Report)
Unclassified
21. NO, OF PAGES
280
Unlimited
20. SECURITY CLASS (This page}
Unclassified
22. PRICE
EPA Form 2220-1 (Rev. 4-77) PREVIOUS EDITION is OBSOLETE
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