OEPA 

United States Office of Air Quality EPA-450/3-82-024a 

Environmental Protection Plannrng and Standards December 1983 

Agency Research Triangle Park NC 27711 

Arr 

Equipment Leaks 

of VOC in 

Natural Gas 

Draft 

EIS 

Production Industry -

Background Information 

for Proposed Standards 
EPA-450/3-82-024a 

Equipment Leaks of VOC 

in Natural Gas Production IndustryBackground Information 

for Proposed Standards 

Emission Standards and Engineering Division 

U.S ENVIRONMENTAL PROTECTION AGENCY 

Office of Air, Noise, and Radiation 

Office of Air Quality Planning and Standards 

Research Triangle Park, North Carolina 27711 

December 1983 
Th1s report has been reviewed by the Emission Standards and Engineering Division of the Office of Air Quality ~~':lnri11g 

and Standards, EPA, and approved for publication. Mention of trade names or commercial products is not intender1 to 

constitute endorsement or recommendation for use. Copies of this report are available through the Ltbrar~J Serv1cus 

Office (MD-35), U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711; or, for a fee, f,·c.r. 

the National Technical Information Services, 5285 Port Royal Road, Springfield, Virginia 22161. 

II 
ENVIRONMENTAL PROTECTION AGENCY 

Background Information 

and Draft 

Environmental Impact Statement 

for Equipment Leaks of VOC in Natural 

Gas Production Industry Prepared by: 

c • armer 

I ?_lA-)~ ~ae} 

irector, Emission Standards and Engineering Division 

u.s. Environmental Protection Agency 

Research Triangle Park, North Carolina 27711 

1. The proposed standards of performance would limit emissions of VOC 

from equipment leaks at new, modified, and reconstructed affected 

facilities at natural gas plants. Section 111 of the Clean Air Act 

(42 U.S.C. 7411), as amended, directs the Administrator to establish 

standards.of performance for any category of new stationary source of 

air pollution that ..... causes or contributes significantly to air 

pollution which may reasonably be anticipated to endanger public health 

or welfare ... 

2. Copies of this doucment have been sent to the following Federal 

Departments: Labor, Health and Human Services, Defense, Transportation, Agriculture, Commerce, Interior, and Energy; the National 

Science Foundation; the Council on Environmental Qualtiy; members of 

the State and Territorial Air Pollution Program Administrators; the 

Association of Local Air Pollution Control Officials; EPA Regional Administrators; and other interested parties. 

3. For additional information contact: 

Mr. Gilbert H. Wood 

Standards Development Branch (MD-13) U.S. Environmental Protection Agency Research Triangle Park, North Carolina 27711 

Telephone: ( 919) 541-5578 

4. Copies of this document may be obtained from: 

U.S. EPA Library (MD-35) 

Research Triangle Park, North Carolina 27711 

National Technical Information Service 

5285 Port Royal Road 

Springfield, Virginia 22161 

iii 
METRIC CONVERSION TABLE 

EPA policy is to express all ~easurements 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 (em) 

meter (m) 

l iter ( 1 ) 

cubic meter (m 3) 

cubic f11eter (m3 ) 

cubic meter (m 3) 

k il og ram (kg) 

megagram (r~g) 

gigagram (Gg) 

gigagram (Gg) 

joule (J) 

Prefix 

tera 

gig a 

mega 

ki 10 

centi 

mi l1 i 

micro 

Multiply Sy 

Conversion Factor 

0.39 

3.28 

0.26 

254.2 

6. 29 

35 

2.2 

1.1 

2.2 

1102 

9.48 X 10-4 

PREFIXES 

Symbol 

T 

G 

M 

k 

c 

m 

J.l 

iv 

To Obtain 

English Unit 

inch (in.) 

feet (ft.) 

U.S. gallon (gal) 

U.S. gallon (gal) 

barrel (oil ) ( bb 1 ) 

cubic feet (ft3) 

pound ( 1 b) 

ton 

million pounds (10 6 lbs) 

ton 

British thermal unit (Btu) 

Multiplication 

Factor 

1012 

109 

106 

103 

10-2 

10-3 

10-6 
TABLE OF CONTENTS 

METRIC CONVERSION TABLE . . . . . . . . . . iv 

TABLE OF CONTENTS . . . . . . . . • • • • v 

LIST OF TABLES •••.• . . . . . . . . . . . . . . . . 

LIST OF FIGURES . . . . . . . . . 1.0 SUMMARY ..•••. . . . . . . . . 1.1 Regulatory Alternatives •• . . . . . . . . 1.2 Environmental Impact ••• . . . . . . . . . . . 1.3 Economic Impact ••• . . . . . . . . . . . . . . 

2.0 INTRODUCTION ••••. . . . . . . . . . . . . . . . . 2.1 Background and Authority for Standards ••••. 

2.2 Selection of Categories of Stationary Sources • 

2.3 Procedure for Development of Standards of 

Performance • • • . • • • • • • • • • • • 

• • • 

2.4 Consideration of Costs ••....... 

2.5 Consideration of Environmental Impacts. . . . . 2.6 

2.7 

Impact on Existing Sources •••••• 

Revision of Standards of Performance. 

3.0 SOURCES OF VOC Et~ISSIONS •• . . . . . . . . . 3.1 General .•.••..•••••••. 

3.2 Description of Fugitive Emission Sources. 

3.3 Baseline Fugitive VOC Emissions •.••. 

3.4 References •••....••••• 

v 

. . 

viii 

xi 

1-1 

1-1 

1-2 

1-3 

2-1 

2-1 

2-4 

2-6 

2-8 

2-9 

(-10 

2-11 

3-1 

3-1 

3-1 

3-8 

3-12 
TABLE OF CONTENTS (Continued) 

4.0 EMISSION CONTROL TECHNIQUES •••••• 

4.1 Introduction ••••••••••• 

4.2 Leak Detection and Repair Methods . 

4.3 

4.4 

Preventive Programs •• 

References. 

S.O MODIFICATION AND RECONSTRUCTION •. 

. . . . . . . . . 

5.1 Genera 1 Discussion of Modification and Reconstruction 

Provisions. . . . . . . . . . . . . . . . . . . . 5.2 Applicability of Modification and Reconstruction 

Provisions to Natural Gas/Gasoline Processing 

Plants. . . . . . . . . . . . . . . . . . 6.0 MODEL PLANTS AND REGULATORY ALTERNATIVES . 6.1 Introduction. . . . . . . . . . . . 6.2 t1odel Plants. . . . . . . 6.3 Regulatory Alternatives . 6.4 References. . . . . . . . . . . . . 

7.0 ENVIRONMENTAL IMPACTS. . . . . . . . . . . . 7.1 Introduction. . . . . . . . . 7.2 Emissions Impact. . . . . . . . . . 7.3 Water Qua 1 i ty Impact. . . . . 7.4 Solid Waste Impact. . . . . . 7.5 Energy Impacts. . . . . . . 7.6 Other Environmental Concerns. 

7.7 References. . . . . . 

8.0 COST ANALYSIS. . . . . . . 8.1 Cost Ana 1 ys is of Regulatory Alternatives. . . . . 8.2 Other Cost Considerations . . . . . 8.3 References. . . . . . . . . . . . . . 

vi 

Page 

4-1 

4-1 

4-1 

4-13 

4-20 

5-1 

5-1 

5-3 

6-1 

6-1 

6-1 

6-2 

6-10 

7-1 

7-1 

7-1 

7-3 

7-3 

7-9 

7-9 

7-12 

8-1 

8-1 

8-24 

8-26 
TABLE OF CONTENTS (Concluded) 

9.0 ECONOMIC ANALYSIS ..•....... 

9.1 Industry Profile ..... . 

9.2 Economic Impact Analysis .. 

Page 

9-1 

9-1 

9-21 

9.3 Potential socioeconomic and Inflationary Impacts. 9-30 

9.4 References. 

APPENDICES 

A 

B 

c 

C.1 

Evolution of the Background Information Document. 

Index to Environmental Considerations 

Emission Source Test Data ..... . 

Plant Description and Test Results. 

C.2 Industry Valve Maintenance Study ••.... 

C.3 References for Appendix C . • . . . . . ..• 

D Emission Measurement and Continuous Monitoring .• 

D.1 Emission Measurement Methods. . ...... . 

D.2 Continuous Monitoring Systems and Devices . 

0.3 Performance Test Method . . . . ...... . 

0.4 References. . . . . . . . . . . .. . 

E Model for Evaluating the Effects of Leak 

Detection and Repair on Fugitive Emissions from 

Pumps and Valves ..... . 

E.1 Introduction .. 

E.2 LDAR Model .. 

E.3 Model Outputs . 

E.4 References .. 

F Docket Entries on Correlation Between 

Cost-effectiveness and Throughput for 

G 

Small Gas Plants ..........• 

Revised Compressor Seal Emission Factors and Seal 

Vent System Control Costs . • . . . . . . . 

H Calculation of Emission Reductions and Cost 

Effectiveness for the Proposed Standards by 

9-32 

A-1 

B-1 

C-1 

C-2 

C-4 

C-8 

D-1 

D-1 

0-4 

D-4 

D-7 

E-1 

E-2 

E-2 

E-4 

E-6 

F-1 

G-1 

Source Type . . . . . . . . . . . . . . . . H-1 

I Revised Pump Seal Leak Detection and Repair 

Emission Reduction .... I-1 

vii 
LIST OF TABLES 

Number 

1-1 Environmental and Economic Impacts of Regulatory 

Alternatives ••.•.••..•..•.••.•.•.•• 1-4 

3-1 Baseline Fugitive Emission Factors for Gas Plants •..• 3-9 

3-2 Estimated Baseline Fugitive VOC Emissions From a 

Typical Gas Plant • • • . • • • . • • • . • . • • • • 3-11 

4-1 Percentage of Components Predicted to be Leaking In An 

Individual Component Survey . • • • . • • • . • • . 4-3 

4-2 Percent of Total VOC Emissions Affected at Various 

Leak Definitions. • • . • • • • . • • • • • • • . . • 4-8 

4-3 VOC Emission Correction Factors for Various Inspection 

Intervals, Allowable Repair Times, and Leak 

Definitions •••••.•••••••••• 

6-1 Example Types of Equipment Included and Excluded in 

• 4-12 

Vessel Inventories for Model Plant Development. • 6-3 

6-2 Number of Components in Hydrocarbon Service and Number 

of Vessels at Four Gas Plants •...•...•••.•• 6-4 

6-3 Ratios of Numbers of Components to Numbers of Vessels •• 6-5 

6-4 Fugitive VOC Emission Sources for Three Model Gas 

Processing Plants .....•..•••••• 

6-5 Fugitive VOC Regulatory Alternative Control 

Specifications ••. 

7-1 Controlled Emission Factors for Various Inspection 

Intervals .............. . 

7-2 Emissions for Regulatory Alternatives ••••• 

7-3 Total and Incremental Emission Reductions 

of the Regulatory Alternatives on a Model Plant 

Basis . . . . . . . . . . . . . . . . . . 

7-4 Projected Fugitive Emissions From Affected Model 

Plants for Regulatory Alternatives for 1983-1987. 

7-5 Energy Impacts of Emission Reductions for 

Regulatory Alternatives for 1983-1987 ••••••• 

viii 

6-6 

. 6-8 

• 7-2 

• 7-4 

7-7 

• 7-8 

. 7-10 
LIST OF TABLES (Continued) 

Number 

8-1 

8-2 

Capital Cost Data •••••••••••••••••••• 8-2 

Capita 1 Cost Estimates for ~lode 1 Plants • • • • . • • 8-7 

8-3 Leak Detection and Repair Labor-Hour Requirements • • 8-11 

8-4 Annual Leak Detection and Repair Labor Costs .•..••• 8-12 

8-5 Derivation of Annualized Labor, Administrative, 

Maintenance, and Capital Costs .....•••• 

8-6 Labor-Hour Requirements for Initial Leak Repair • 

8-7 Initial Leak Repair Costs . • ••• 

8-8 Recovery Credits ••• 

8-9 Annual Cost Estimates for Model Plant A 

8-10 Annual Cost Estimates for 1,1odel Plant B 

8-11 Annual Cost Estimates for Model Plant C 

8-12 Cost Effectiveness of Regulatory Alternatives • 

8-13 Fifth-Year Nationwide Costs of the 

Regulatory Alternatives .••.•.••.••• 

8-14 Statutes That May Be Applicable to the Natural Gas 

Processing Industry •••.•.••••••••••• 

9-1 Distribution of Gas Plants by Capacity (1980} ••. 

9-2 Distribution of Gas Plants by Process Method (1980} • 

9-3 Distribution of Gas Plants by Ownership (1980). 

9-4 Distribution of Gas Plants by State (1980) ••••• 

9-5 Production of Energy by Type, United States .•.. 

. • 8-14 

• • 8-15 

• 8-16 

• • 8-17 

• 8-18 

. . 8-19 

• 8-20 

• 8-21 

• 8-23 

• • 8-25 

. 9-3 

• • 9-5 

• 9-6 

• 9-7 

• 9-8 

9-6 Aggregate Retail Price Elasticities of Demand, U.S. . 9-9 

9-7 Natural Gas Gross Withdrawals and Marketed Onshore and 

Offshore Production .•......•.•..••.•.. 9-11 

9-8 Composite Financial Data for the Natural Gas Industry 

1976-1981 and 1983-1985 Estimates . • . . . . • . . . 9-14 

9-9 Projected Lower-48 States Conventional Natural Gas 

Production. . • . . . . . . . . . . • . . . . . . • 9-16 

9-10 Projections of Natural Gas Supply: Comparison of 1980 

Forecasts . . • • . . • . • • . . . . • 9-18 

9-11 Estimated Number of New Gas Plants, 1983-1987 • • • • 9-20 

9-12 Natural Gas Prices: History and Projections for 

1965-1995 • • • . • . • • • • •••••••••..• 9-22 

ix 
LIST OF TABLES (Concluded) 

Number Page 

9-13 Onshore Natural Gas Processing, Total and Cumulative 

Before-Tax Net Annualized Cost of VOC NSPS Regulatory Alternatives 1983-1987 •..•••.•••.••.•••• 9-27 

9-14 Onshore Natural Gas Processing Model Plants• Before-Tax 

Net Annualized Cost of VOC NSPS Regulatory Alternatives 

Per Plant ••.•.••••..•..•••.••.••• 9-28 

9-15 Onshore Natural Gas Processing Model Plants• After-Tax 

Net Annualized Cost of VOC NSPS Regulatory Alternatives 

Per Plant •..••••.....••.•.•••• . 9-29 

C-1 Gas Plants Tested for Fugitive Emissions . . . . . . • • C-3 

C-2 Instrument Screening Data for EPA-Tested Gas Plants • C-6 

C-3 Soap Screening Data for API-Tested and 

EPA-Tested Gas Plants . • • • . . . . . • . . . • • C-7 

E-1 Results of the LDAR Model Leak Detection and 

Repair Programs . . . • • . . • • • • • • . • . . • E-5 

X 
LIST OF FIGURES 

Number 

3-1 General schematic of natural gas-gasoline processing. 

3-2 Diagram of a simple packed seal •..•.••.. 

Diagram of a basic single mechanical seal • 

Diagram of a gate valve .......•• 

Diagram of a spring-loaded relief valve •. 

Page 

3-2 

• 3-3 

3-4 

• 3-6 

• . 3-6 

3-3 

3-4 

3-5 

4-1 Rupture disk intallation upstream of a relief valve • • • 4-14 

4-2 Diagram of two closed-loop sampling systems . . •. 4-18 

9-1 Selected natural gas prices - three categories for the 

period 1955-1979 •••••••••••••.•..•.•• 9-13 

9-2 Projected new discovery onshore natural gas production •• 9-17 

E-1 Schematic diagram of the modeled leak detection 

and repair program •••••••••••••.•.•.•• E-3 

xi 
1.0 SUMMARY 

1.1 REGULATORY ALTERNATIVES 

Standards of performance for new stationary sources of volatile 

organic compounds (VOC) from fugitive emission sources in the onshore 

natural gas production industry are being developed under the authority 

of Section 111 of the Clean Air Act. These standards would reduce 

emissions caused by leaks from valves, relief valves, open-ended 

lines, compressor seals, pump seals, and sampling connections. Because 

VOC is emitted as a result of equipment leaks, the_emissions are 

referred to as fugitive emissions, and the process equipment are 

referred to as fugitive emission sources in this document. However, 

the title of this document has been changed from the title used for 

previous drafts (VOC Fugitive Emissions in On-Shore Natural Gas Production 

Industry - Background Information for Proposed Standards) to 11Equipment 

Leaks of VOC in Natural Gas Production Industry - Background Information 

for Proposed Standards .. to~clarify that the fugitive emissions are the 

result of equipment leaks. 

Four regulatory alternatives were considered. Regulatory Alternative I 

is the baseline alternative and represents the level of control that 

would exist in the absence of any standards of performance. Requirements 

of Alternative II are: 

o Quarterly instrument monitoring for leaks from valves, 

relief valves, and compressor seals; 

o Quarterly instrument and weekly visual nonitoring for leaks 

from pump seals; and 

o Installation of caps (including plugs, flanges, or second 

valves) on open-ended lines. 

Regulatory Alternative III is more restrictive than Alternative II. 

1-1 
The requirements are as follows: 

o Monthly monitoring of valves (if a particular valve is founa 

not to be leaking for 3 successive months, then 2 months may 

be skipped before the next time it is monitored with an 

instrument); 

o Monthly monitoring of relief valves and pump seals, and 

weekly visual inspection of pump seals; 

o Installation of a vent control system to control compressor 

seal emissions; 

o Installation of closed purge sampling systems on sampling 

connections; and 

o Installation of caps (including plugs, flanges, or second 

valves) on open-ended lines. 

Regulatory Alternative IV is the most stringent of the alternatives. 

Monthly instrument monitoring would be required for valves, relief 

valves would be equipped with a rupture disc, and pumps would be 

required to have dual mechanical seals. Other requirements would be 

the same as Alternative III. 

1.2 ENVIRONMENTAL IMPACT 

Fugitive emissions of VOC from affected gas production facilities 

under Regulatory Alternative I would be approximately 22,000 Mg/yr in 

1987, the fifth year of implementation. This is compared to 6,900, 

6,200, and 5,000 Mg/yr under Alternatives II, III, and IV, respectively. 

In addition to reducing emissions to the atmosphere, Alternatives II, 

III, and IV would reduce liquid leaks, thereby reducing wastewater 

treatment needs. Some solid waste would be generated by the replacement 

of existing equipment (e.g., replaced seal packing, rupture discs). 

However, this amount of solid waste would be very small in comparison 

to existing levels of solid waste generated by gas plants. 

Energy savings from VOC and non-VOC hydrocarbons would result 

under Regulatory Alternatives II-IV. Under Alternative II, hydrocarbons 

recovered during the fifth year of implementation would have an energy 

content of approximately 6,400 terajoules. This is equivalent to the 

heating valve of approximately 1,050 barrels of crude oil. Hydrocarbons 

recovered under Alternative III would result in slightly less energy 

savings than Alternative II, because emissions are not recovered from 

1-2 
compressor seal leaks. Alternative IV would result in energy savings 

of approximately 6,900 terajoules, which is approximately equivalent 

to the heating value of 1,120 barrels of crude oil. 

A more detailed analysis of environmental and energy impacts is 

presented in Chapter 7. A summary of the environmental impacts 

associated with the four regulatory alternatives is shown in Table 1-1. 

1.3 ECONOMIC IMPACT 

Costs incurred by the onshore natural gas production industry 

under Regulatory Alternative II would actually be a credit due to the 

value of the recovered hydrocarbons. In the fifth year of implementation 

of Alternative II, a net annual credit of $160,000 would result. Net 

annual costs incurred during the fifth year under Alternative III 

would be approximately $510,000; under Regulatory Alternative IV net 

annual costs of over $7 million are incurred. A more detailed analysis 

of costs is included in Chapter 8. Price impacts of the regulatory 

alternatives are expected to be slight regardless of the regulatory 

alternative. No plant closures or curtailments are expected, and 

effects on industry profitability, output, growth, and other factors 

would be negligible or zero. A more detailed economic analysis is 

presented in Chapter 9. A summary of environmental, energy, and 

economic impacts associated with the alternatives is shown in Table 1-1. 

1-3 
Table 1-1. ENVIRONMENTAL, ENERGY, AND ECONOMIC IMPACTS OF REGULATORY ALTERNATIVES 

Solid 

Administrative Air Water vias te Energy Noise Economic 

Action Impact Impact Impact Impact Impact Impact 

Regulatory 

Alternative I 

(No action) 0 0 0 0 0 0 

Regula tory 

Alternative II +2** +1** 0 +1* 0 +1* 

,_. 

I Regulatory .j::oo Alternative III +2** +1** 0 +1* 0 -1* 

Regulatory 

Alternative IV +2** +1** 0 +1* 0 -1 * 

KEY: + Beneficial impact 0 No impact * Short-term impact - Adverse impact 1 Negligible impact ** Long-term impact 2 Small impact *** Irreversible impact 

3 Moderate impact 

4 Large impact 
2.0 INTRODUCTION 

2.1 BACKGROUND AND AUTHORITY FOR STANDARDS 

Before standards of performance are proposed as a Federal regulation, 

air pollution control methods available to the affected industry and 

the associated costs of installing and maintaining the control equipment 

are examined in detail. Various levels of control based on different 

technologies and degrees of efficiency are expressed as regulatory 

alternatives. Each of these alternatives is studied by EPA as a 

prospective basis for a standard. The alternatives are investigated 

in terms of their impacts on the economics and well-being of the 

industry, the impacts on the national economy, and the impacts on the 

environment. This document summarizes the information obtained through 

these studies so that interested persons will be privy to the information 

considered by EPA in the development of the proposed standard. 

Standards of performance for new stationary sources are established 

under Section 111 of the Clean Air Act (42 U.S.C. 7411) as amended, 

hereinafter referred to as the Act. Section 111 directs the Administrator 

to establish standards of performance for any category of new stationary 

source of air pollution which 11 ••• causes, or contributes significantly 

to air pollution which may reasonably be anticipated to endanger 

public health or welfare. 11 

The Act requires that standards of performance for stationary 

sources reflect, 11 ••• the degree of emission reduction achievable 

which (taking into consideration the cost of achieving such emission 

reduction, and any nonair quality health and environmental impact and 

energy requirements) the Administrator determines has been adequately 

demonstrated for that category of sources ... The standards apply only 

to stationary sources, the construction or modification of which 

commences after regulations are proposed by publication in the Federal 

Register. 

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 review the standards of performance every 

4 years and, if appropriate, revise them. 

2. EPA is authorized to promulgate a standard based on design, 

equipment, work practice, or operational procedures when a standard 

based on emission levels is not feasible. 

3. The term 11Standards of performance .. is redefined, and a new 

term .. technological system of continuous emission reduction .. is defined. 

The new definitions clarify that the control system must be continuous 

and may include a low- or non-polluting process or operation. 

4. The time between the proposal and promulgation of a standard 

under section 111 of the Act may be extended to 6 months • 

. Standards of performance, by themselves, do not guarantee protection 

of health or welfare because they are not designed to achieve any 

specific air quality levels. Rather, they are designed to reflect the 

degree of emission limitation achievable through application of the 

best adequately demonstrated technological system of continuous emission 

reduction, taking into consideration the cost of achieving such emission 

reduction, any nonair-quality health and environmental impacts, and 

energy requirements. 

Congress had several reasons for including these requirements. 

First, standards with a degree of uniformity are needed to avoid 

situations where some States may attract industries by relaxing standards 

relative to other States. Second, stringent standards enhance the 

potential for long-term growth. Third, stringent standards may help 

achieve long-term cost savings by avoiding the need for more expensive 

retrofitting when pollution ceilings may be reduced in the future. 

Fourth, certain types of standards for coal-burning sources can adversely 

affect the coal market by driving up the price of low-sulfur coal or 

effectively excluding certain coals from the reserve base because 

their untreated pollution potentials are high. Congress does not 

intend that new source performance standards contribute to these 

problems. Fifth, the standard-setting process should create incentives for improved technology. 

2-2 
Promulgation of standards of performance does not prevent State 

or local agencies from adopting more stringent emission limitations 

for the same sources. States are free under Section 116 of the Act to 

establish even more stringent emission limits than those established 

under Section 111 or those necessary to attain or maintain the National 

Ambient Air Quality Standards (NAAQS) under Section 110. Thus, new 

sources may in some cases be subject to limitations more stringent 

than standards of performance under Section 111, and prospective 

owners and operators of new sources should be aware of this possibility 

in planning for such facilities. 

A similar situation may arise when a major emitting facility is 

to be constructed in a geographic area that falls under the prevention 

of significant deterioration of air quality provisions of Part C of 

the Act. These provisions require, among other things, that major 

emitting facilities to be constructed in such areas are to be subject 

to best available control technology. The term Best Available Control 

Technology (BACT), as defined in the Act, means 

••• an emission limitation based on the maximum degree of 

reduction of each pollutant subject to regulation under 

this Act emitted from, or which results from, any major 

emitting facility, which the permitting authority, on a 

case-by-case basis, taking into account energy, 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 

technology• result in emissions of any pollutants which 

will exceed the emissions allowed by any applicable standard 

established pursuant to Sections 111 or 112 of this Act. 

(Section 169{3)) 

Although standards of performance are normally structured in 

terms of numerical emission limits where feasible, alternative approaches 

are sometimes necessary. In some cases physical measurement of emissions 

from a new source may be impractical or exorbitantly expensive. 

Section lll(h) provides that the Administrator may promulgate a design 

or equipment standard in those cases where it is not feasible to 

prescribe or enforce a standard of performance. For example, emissions 

of hydrocarbons from storage vessels for petroleum liquids are greatest 

2-3 
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 

\'laivers of compliance to permit a source to use innovative continuous 

emission control technology. In order to grant the waiver, the Administrator must find: (1) a substantial likelihood that the technology 

will produce greater emission reductions than the standards require or 

an equivalent reduction at lower economic energy or environmental 

cost; (2) the proposed system has not been adequately demonstrated; 

(3) the technology will not cause or contribute to an unreasonable 

risk to the public health, welfare, or safety; (4) the governor of the 

State where the source is located consents; and (5) the waiver will 

not prevent the attainment or maintenance of any ambient standard. A 

waiver may have conditions attached to assure the source will not 

prevent attainment of any NAAQS. Any such condition will have the 

force of a performance standard. Finally, waivers have definite end 

dates and may be terminated earlier if the conditions are not met or 

if the system fails to perform as expected. In such a case, the 

source may be given up to 3 years to meet the standards with a mandatory 

progress schedule. 

2.2 SELECTION OF CATEGORIES OF STATIONARY SOURCES 

Section 111 of the Act directs the Adminstrator to list categories 

of stationary sources. The Administrator ..... shall include a 

category of sources in such list if in his judgement it causes, or 

contributes significantly to, air pollution which may reasonably be 

anticipated to endanger public health or welfare ... Proposal and 

promulgation of standards of performance are to follow. 

Since passage of the Clean Air Amendments of 1970, considerable 

attention has been given to the development of a system for assigning 

priorities to various source categories. The approach specifies areas 

of interest by considering the broad strategy of the Agency for implementing the Clean Air Act. Often, these 11 areas 11 are actually pollutants 

2-4 
emitted by stationary sources. Source categories that emit these 

pollutants are evaluated and ranked by a process i nvol vi ng 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 

nev1 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 

standard for a source category with a high priority. 

to develop a 

This might 

happen when a program of research is needed to develop control techniques 

or because techniques for sampling and measuring emissions may require 

refinement. In the developing of standards, differences in the time 

required to complete the necessary investigation for different source 

categories must also be considered. For example, substantially more 

time may be necessary if numerous pollutants must be investigated from 

a single source category. Further, even late in the development 

process the schedule for completion of a standard may change. For 

example, inablility to obtain emission data from well-controlled 

sources in time to pursue the development'process in a systematic 

fashion may force a change in scheduling. Nevertheless, priority 

ranking is, and will continue to be, used to establish the order in 

which projects are initiated and resources assigned. 

2-5 
After the source category has been chosen, the types of facilities 

within the source category to which the standard will apply must be 

determined. A source category may have several facilities that cause 

air pollution, and emissions from some of these facilities may vary 

from insignificant to very expensive to control. Economic studies of 

the source category and of applicable control technology may show that 

air pollution control is better served by applying standards to the 

more severe pollution sources. For this reason, and because there is 

no adequately demonstrated system for controlling emissions from 

certain facilities, standards often do not apply to all facilities at 

a source. For the same reasons, the standards may not apply to all air 

po'llutants 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 DEVELOP~1ENT OF STANDARDS OF PERFORMANCE 

Standards of performance must (1) realistically reflect best 

demonstrated control practice; {2) adequately consider the cost, the 

nonairquality health and environmental impacts, and the energy requirements 

of such control; (3) be applicable to existing sources that are modified 

or reconstructed as well as new installations; and {4) meet these 

conditions for all variations of operating conditions being considered 

anywhere in the country. 

The objective of a program for developing standards is to identify 

the best technological system of continuous emission reduction that 

has been adequately demonstrated. The standard-setting process involves 

three principal phases of activity: (1) information gathering, (2) analysis 

of the information, and (3) development of the standard of performance. 

During the information-gathering phase, industries are queried 

through a telephone survey, letters of inquiry, and plant visits by 

EPA representatives. Information is also gathered from many other 

sources to provide reliable data that characterize the pollutant 

emissions from well-controlled existing facilities. 

In the second phase of a project, the information about the 

industry and the pollutants emitted is used in analytical studies. 

Hypothetical .. model plants 11 are defined to provide a common basis for 

analysis. The model plant definitions, national pollutant emission 

2-6 
data, and existing State regulations governing emissions from the 

source category are then used in establishing 11 regulatory alternatives." 

These regulatory alternatives are essentially different levels of 

emission control. 

EPA conducts studies to determine the impact of each regulatory 

alternative on the economics of the industry and on the national 

economy, on the environment, and on energy consumption. From several 

possibly applicable alternatives, EPA selects the single most plausible 

regulatory alternative as the basis for a standard of performance for 

the source category under study. 

In the third phase of a project, the selected regulatory alternative 

is translated into a standard of performance, which, in turn, is 

written in the form of a Federal regulation. The Federal regulation, 

when applied to newly constructed plants, will limit emissions to the 

levels indicated in the selected regulatory alternative. 

As early as is practical in each standard-setting project, EPA 

representatives discuss the possibilities of a standard and the form 

it might take with members of the National Air Pollution Control 

Techniques Advisory Committee. Industry representatives and other 

interested parties also participate in these meetings. 

The information acquired in the project is summarized in the 

Background Information Document (BID). The BID, the standard, and a 

preamble explaining the standard are widely circulated to the industry 

being considered for control, environmental groups, other government 

agencies, and offices within EPA. Through this extensive review 

process, the points of view of expert reviewers are taken into consideration 

as changes are made to the documentation. 

A 11 proposal package" is assembled and sent through the offices of 

EPA Assistant Administrators for concurrence before the proposed 

standard is officially endorsed by the EPA Administrator. After being 

approved by the EPA Administrator, the preamble and the proposed 

regulation are published in the Federal Register. 

As a part of the Federal Register announcement of the proposed 

regulation, the public is invited to participate in the standard-setting 

process. EPA invites written comments on the proposal and also holds 

a public hearing to discuss the proposed standard with interested 

2-7 
parties. All public comments are summarized and incorporated into a 

second volume of the BID. All information reviewed and generated in 

studies in support of the standard of performance is available to the 

public in a "docket" on file in Washington, D. C. 

Comments from the public are evaluated, and the standard of 

performance may be altered in response to the comments. 

The significant comments and EPA•s position on the issues raised 

are included in the "preamble" of a "promulgation package," which also 

contains the draft of the final regulation. The regulation is then 

subjected to another round of review and refinement until it is approved 

by the EPA Administrator. After the Administrator signs the regulation, 

it is published as a "final rule" in the Federal Register. 

2.4 CONSIDERATION OF COSTS 

Section 317 of the Act requires an economic impact assessment 

with respect to any standard of performance established under Section 111 

of the Act. The assessment is required to contain an analysis of: 

(1) the costs of compliance with the regulation, including the extent 

to which the cost of compliance varies depending on the effective date 

of the regulation and the development of less expensive or more efficient 

methods of compliance; (2) the potential inflationary or recessionary 

effects of the regulation; (3) the effects the regulation might have 

on small business with respect to competition; (4) the effects of the 

regulation on consumer costs; and (5) the effects of the regulation on 

energy use. Section 317 also requires that the economic impact assessment 

be as extensive as practicable. 

The economic impact of a proposed standard upon an industry is 

usually addressed both in absolute terms and in te~ns of the control 

costs that would be incurred as a result of compliance with typical, 

existing State control regulations. An incremental approach is necessary 

because both new and existing plants would be required to comply with 

State regulations in the absence of a Federal standard of performance. 

This approach requires a detailed analysis of the economic impact from 

the cost differential that would exist between a proposed standard of 

performance and the typical State standard. 

Air pollutant emissions may cause water pollution problems, and 

captured potential air pollutants may pose a solid waste disposal 

2-8 
problem. The total environmental impact of an emission source must, 

therefore, be analyzed and the costs determined whenever possible. 

A thorough study of the profitability and price-setting mechanisms 

of the industry is essential to the analysis so that an accurate 

estimate of potential adverse economic impacts can be made for proposed 

standards. It is also essential to know the capital requirements for 

pollution control systems already placed on plants so that the additional 

capital requirements necessitated by these Federal standards can be 

placed in proper perspective. Finally, it is necessary to assess the 

availability of capital to provide the additional control equipment 

needed to meet the standards of performance. 

2.5 CONSIDERATION OF ENVIRONMENTAL IMPACTS 

Section 102{2}{C) of the National Environmental Policy Act (NEPA) 

of 1969 requires Federal agencies to prepare detailed environmental 

impact statements on proposals for legislation and other major Federal 

actions significantly affecting the quality of the human environment. 

The objective of NEPA is to build into the decisionmaking process of 

Federal agencies a careful consideration of all environmental aspects 

of proposed actions. 

In a number of legal challenges to standards of performance for 

various industries, the United States Court of Appeals for the District 

of Columbia Circuit has held that environmental impact statements need 

not be prepared by the Agency for proposed actions under Section 111 

of the Clean Air Act. Essentially, the Court of Appeals has determined 

that the best system of emission reduction requires the Administrator 

to take into account counter-productive environmental effects of a 

proposed standard, as well as economic costs to the industry. On this 

basis, therefore, the Court established a narrow exemption from NEPA 

for EPA determination under Section 111. 

In addition to these judicial determinations, the Energy Supply 

and Environmental Coordination Act (ESECA) of 1974 (PL-93-319) specifically 

exempted proposed actions under the Clean Air Act from NEPA requirements. 

According to Section 7{c)(l), "No action taken under the Clean Air Act 

shall be deemed a major Federal action significantly affecting the 

quality of the human environment within the meaning of the National 

Environmental Policy Act of 1969" {15 U.S.C. 793{c){l)). 

2-9 
Nevertheless, the Agency has concluded that the preparation of 

environmental impact statements could have beneficial effects on 

certain regulatory actions. Consequently, although not legally required 

to do so by Section 102(2)(C) of NEPA, EPA has adopted a policy requiring 

that environmental impact statements be prepared for various regulatory 

actions, including standards of performance developed under Section 111 

of the Act. This voluntary preparation of environmental impact statements, 

however, in no way legally subjects the Agency to NEPA requirements. 

To implement this policy, a separate section in this document is 

devoted solely to an analysis of the potential environmental impacts 

associated with the proposed standards. Both adverse and beneficial 

impacts in such areas as air and water pollution, increased solid 

waste disposal, and increased energy consumption are discussed. 

2.6 IMPACT ON EXISTING SOURCES 

Section 111 of the Act defines a new source as 11 ••• 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 11modified 11 or 11 reconstructed 11 as defined 

in amendments to the general provisions of Subpart A of 40 CFR Part 

60, which were promulgated in the Federal Register on December 16, 

1975 (40 FR 58416). 

Promulgation of a standard of performance requires States to 

establish standards of performance for existing sources in the same 

industry under Section 111 (d) of the Act if the standard for new 

sources limits emissions of a designated pollutant (i.e., a pollutant 

for which air quality criteria have not been issued under Section 108 

or which has not been listed as a hazardous pollutant under Section 112). 

If a State does not act, EPA must establish such standards. General 

provisions outlining procedures for control of existing sources under 

Section lll(d) were promulgated on November 17, 1975, as Subpart B of 

40 CFR Part 60 (40 FR 53340). 

2.7 REVISION OF STANDARDS OF PERFORMANCE 

Congress was aware that the level of air pollution control achievable 

by any industry may improve with technological advances. 

section 111 of the Act provides that the Administrator 11 

2-10 

Accordingly, 

•• shall, 
at least every 4 years, review and, if appropriate, revise ..... the 

standards. Revisions are made to assure that the standards continue 

to reflect the best systems that become available in the future. Such 

revisions will not be retroactive, but will apply to stationary sources 

constructed or modified after the proposal of the revised standards. 

2-11 
3.0 SOURCES OF VOC EMISSIONS 

3.1 GENERAL 

Natural gas processing plants are a part of the oil and gas industry. 

Field gas is first gathered in the field directly from gas wells or from 

oil/gas separation equipment (see Figure 3-1). The gas may be compressed 

at field stations for the purpose of transporting it to treating or 

processing facilities. Treating is necessary in certain instances for 

removal of water, sulfur compounds, or carbon dioxide. Gas gathering, 

compression, and treating may or may not occur at a gas plant. For the 

purposes of this document, natural gas processing plants are defined as 

facilities engaged in the separation of natural gas liquids from field 

gas and/or fractionation of the liquids into natural gas products, such 

as ethane, propane, butane, and natural gasoline. Types of gas ·plants 

are: absorption, refrigerated absorption, refrigeration, compression, 

adsorption, cryogenic- Joule-Thomson, and cryogenic-expander. 1 

3.2 DESCRIPTION OF FUGITIVE EMISSION SOURCES 

In this document, fugitive emissions from gas plants are considered 

to be those volatile organic compound (VOC) emissions that result when 

process fluid (either gaseous or liquid) leaks from plant equipment. VOC 

emissions are defined as nonmethane-nonethane hydrocarbon emissions. 

There are many potential sources of fugitive emissions in a gas plant. 

The following sources are considered in this chapter: pumps, compressors, 

valves, relief valves, open-ended lines, sampling connections, flanges 

and connections, and gas-operated control valves. These source types are 

described below. 

3.2.1 Pumps 

Pumps are used in gas plants for the movement of natural gas liquids. 

The centrifugal pump is the most widely used pump. However, other types, 

such as the positive-displacement, reciprocating and rotary action, and 

special canned and diaphragm pumps, may also be used. Natural gas liquids 

3-1 
Sulfur 

Recovery 

Field Gas Gathering Systems 

Field Compression 

Gas Treating Sweetening and Dehydration (H2

S, co2, and H2

0 Removal) 

' 

Separation of Natural Gas 

Liquids from Field Gas 1----~ 

Fractionation of 

Natural Gas Liquids 

Sales Products 

Dry Gas 

to Sa 1 es 

(ethane, propane, iso-butane~ butane, natural gasoline, etc.) 

Figure 3-1. General Schematic of Natural Gas-Gasoline Processing. 

3-2 
transferred by pumps can leak at the point of contact between the ~oving 

shaft and stationary casing. Consequently, all pumps except the canned-motor 

and diaphragm type require a seal at the point where the shaft penetrates 

the housing in order to isolate the pump•s interior from the atmosphere. 

Two generic types of seals, packed and mechanical, are currently in 

use on pumps. Packed seals can be used on both reciprocating and rotary 

action types of pumps. As Figure 3-2 shows, a packed seal consists of a 

cavity ("stuffing box••) in the pump casing filled with special packing 

material that is compressed with a packing gland to form a seal around 

the shaft. Lubrication is required to prevent the buildup of frictional 

heat between the seal and shaft. The necessary lubrication is provided ~ 

by a lubricant that flows between the packing and the shaft.~ 

Figure 3-2. 

Stuffing 

Packing 

Atmosphere 

EM 

Possible 

LHk 

A~a 

2 Diagram of a simple packed seal. 

Mechanical seals are limited in application to pumps with rotating shafts 

and can further be categorized as single and dual mechanical seals. 

There are many variations to the basic design of mechanical seals, but 

all have a lapped seal face between a stationary element and a rotating 

seal ring. In a single mechanical seal application (Figure 3-3), the 

rotating-seal ring and stationary element faces are lapped to a very high 

degree of flatness to maintain contact throughout their entire mutual 

surface area. As with a packed seal, the seal faces must be lubricated 

3-3 
to remove frictional heat. However, because of its construction, much 

less lubricant is needed. 

PUMP 

STUFFING 

BOX 

GLAND 

A lNG 

AOT.AnNG 

U.AL lltiHG 

STATIONARY 

ELEMENT 

Figure 3-3. Diagram of a basic single mechanical seal. 2 

3.2.2 Compressors 

Three types of compressors can be used in the natural gas production 

industry: centrifugal, reciprocating, and rotary. The centrifugal 

compressor utilizes a rotating element or series of elements containing 

curved blades to increase the pressure of a gas by centrifugal force. 

Reciprocating and rotary compressors increase pressure by confining the 

gas in a cavity and progressively decreasing the volume of the cavity. 

Reciprocating compressors usually employ a piston and cylinder arrangement 

while rotary compressors utilize rotating elements such as lobed impellers 

or sliding vanes. About half of the compressors installed in new plants 

are likely to be centrifugal and half reciprocating. 

As with pumps, sealing devices are required to prevent leakage from 

compressors. Rotary shaft seals for compressors may be chosen from 

several different types: labyrinth, restrictive carbon rings, mechanical 

contact, and liquid film. All of these seal types are leak restriction 

devices; none of them completely eliminate leakage. Many compressors may 

be equipped with ports in the seal area to evacuate collected gases. 

~1echanical contact seals are a common type of seal for rotary compressor 

shafts, and are similar to the mechanical seals described for pumps. In 

this type of seal the clearance between the rotating and stationary 

elements is reduced to zero. Oil or another suitable lubricant is supplied 

to the seal faces. Mechanical seals can achieve the lowest leak rates of 

3-4 
the types identified above, but they are not suitable for all processing 

conditions. 3 

Packed seals are used for reciprocating compressor shafts. As with 

pumps, the packing in the stuffing box is compressed with a gland to form 

a seal. Packing used on reciprocating compressor shafts is often of the 11Chevron 11 or nested V type. 4 Because of safety considerations, the area 

between the compressor seals and the compressor motor (distance piece) is 

normally enclosed and vented outside of the compressor building. If 

hydrogen sulfide is present in the gas, then the vented vapors are normally 

flared. 10 

Reciprocating compressors may employ a metallic packing plate and 

nonmetallic partially compressible (i.e, GRAFFOIL,R TEFLONR) material or 

oil wiper rings to seal shaft leakage to the distance piece. Nevertheless, 

some leakage into the distance piece may occur. 

3.2.3 Process Valves 

One of the most common pieces of equipment in gas plants is the 

valve. The types of valves commonly used are globe, gate, plug, ball, 

butterfly, relief, and check valves. All except the relief valve (to be 

discussed below) and check valve are activated through a valve stem, 

which may have a rotational or linear motion, depending on the specific 

design. This stem requires a seal to isolate the process fluid inside 

the valve from the atmosphere as illustrated by the diagram of a gate 

valve in Figure 3-4. The possibility of a leak through this seal makes 

it a potential source of fugitive emissions. Since a check valve has no 

stem or subsequent packing gland, it is not considered to be a potential 

source of fugitive emissions. 

Sealing of the stem to prevent leakage can be achieved by packing 

inside a packing gland or 0-ring seals. Valves that require the stem to 

move in and out with or without rotation must utilize a packing gland. 

Conventional packing glands are suited for a wide variety of packing 

materials. The most common are various types of braided asbestos that 

contain lubricants. Other packing materials include graphite, graphiteimpregnated fibers, and tetrafluoroethylene polymer. The packing material 

used depends on the valve application and configuraton. 6 These conventional 

packing glands can be used over a wide range of operating temperatures. 

At high pressures these glands must be quite tight to attain a good 

seal. 7 

3-5 
PACKING 

GLAND 

Figure 3-4. Diagram of a gate valve. 2 

Process Side 

Figure 3-5. Diagram of a spring-loaded relief valve. 

3-6 
3.2.4 Pressure Relief Devices 

Engineering codes require that pressure-relieving devices or systems 

be used in applications where the process pressure may exceed the maximum 

allowable working pressure of the vessel. The most common type of pressurerelieving device used in process units is the pressure relief valve 

(Figure 3-5). Typically, relief valves ar~ spring-loaded and designed to 

open when the process pressure exceeds a set pressure, allowing the 

release of vapors or liquids until the system pressure is reduced to its 

normal operating level. When the normal pressure is reattained, the 

valve reseats, and a seal is again formed. 8 The seal is a disk on a 

seat, and the possibility of a leak through this seal makes the pressure 

relief valve a potential source of VOC fugitive emissions. A seal leak 

can result from corrosion or from improper reseating of the valve after a 

relieving operation. 2 

Rupture disks may also be used in process units. These disks are 

made of a material that ruptures when a set pressure is exceeded, thus 

allowing the system to depressurize. The advantage of a rupture disk is 

that the disk seals tightly and does not allow any VOC to escape from the 

system under normal operation. However, when the disk does rupture, the 

system depressurizes until atmospheric conditions are obta·ined, unless 

the disk is used in series with a pressure relief valve. 

3.2.5 Open-Ended Lines 

Some valves are installed in a system so that they function with the 

downstream line open to the atmosphere. Open-ended lines are used mainly 

in intermittent service for sampling and venting. Examples are purge, 

drain, and sampling lines. Some open-ended lines are needed to preserve 

product purity. These are normally installed between multi-use product 

lines to prevent products from collecting in cross-tie lines due to valve 

seat leakage. In addition to valve seat leakage, an incompletely closed 

valve could result in VOC emissions to the atmosphere. 

3.2.6 Flanges and Connections 

Flanges are bolted, gasket-sealed junctions used wherever pipe or 

other equipment such as vessels, pumps, valves, and heat exchangers may 

require isolation or removal. Connections are all other nonwelded fittings 

that serve a similar purpose to flanges, that also allow bends in pipes 

(ells), joining two pipes (couplings), or joining three or four pipes 

(tees or crosses). The connections are typically threaded. ~7 
Flanges may become fugitive emission sources when leakage occurs due 

to improperly chosen gaskets or poorly assembled flanges. The primary 

cause of flange leakage is due to thermal stress that piping or flanges 

in so~ services undergo; this results in the deformation of the seal 

between the flange faces. 9 Threaded connections may leak if the threads 

become damaged or corroded, or if tightened without sufficient lubrication 

or torque. 

3.2.7 Gas-Operated Control Valves 

Pneumatic control valves are used widely in process control at gas 

plants. Typically, compressed air is used as the operating medium for 

these control valves. In certain instances, however, field gas or flash 

gas is used to supply pressure. 5 Since gas is either continuously bled 

to the atmosphere or is bled each time the valve is activated, this can 

potentially be a large source of fugitive emissions. There are also some 

instances where highly pressurized field gas is used as the operating 

medium for emergency control valves. However, these valves are seldom 

activated and, therefore, have a much lower emissions potential than 

control valves in routine service. 

3.2.8 Sampling Connections 

The operation of a gas plant is checked periodically by routine 

analyses of process fluids. To obtain representative samples for these 

analyses, sampling lines must first be purged prior to saMpling. The 

purged liquid is sometimes d~ained onto the ground or into a drain, where 

it can evaporate and release VOC emissions to the atmosphere. 

Purged vapor is typically released directly to the atmosphere. 

3.3 BASELINE FUGITIVE VOC EMISSIONS 

Baseline fugitive emission data have been obtained at six natural 

gas/gasoline processing plants. Two of the plants were tested by Rockwell 

International under contract to the American Petroleum Institute,11 and 

four plants were tested by Radian Corporation under contract to EPA. 12 

Baseline fugitive emission factors for six of the seven component types 

12 

were developed from these data. The emission factors are presented in 

Table 3-1. The factors represent the average baseline emission rate from 

each of the components of a specific type in a gas plant. Baseline 

emissions for sampling connections were determined based on purge volume 

calculations for both gas and liquid streams. 13 ,

14 The compressor seal 

3-8 
Table 3-1. BASELINE FUGITIVE EMISSION FACTORS FOR 

GAS PLANTS, kg/day 

Component Emission factor 95% Confidence interval 

·Valvesa 0.18 (0.48) 0.1-0.3 (0.2-1) 

Relief valvesa 0.33 (4.5) 0.007-8 (0.1-100) 

Open-ended linesa 0.34 (0.53) 0.1-0.7 (0.2-1) 

Compressor sealsa,c 1.0 (4.9) 0.1-5 (0.7-30) 

Pump sealsa 1.2 ( 1.5) 0.5-3 (0.5-4) 

Sampling connectionsb 

Gas 0.016 (0.32) 

Liquid 0.085 (0.085) 

Flanges anda 0.011 (0.026) 0.006-0.02 (0.01-0.05) 

connections 

xx = VOC emission values. 

(xx)= Total hydrocarbon emission values. 

aReference 12. 

bReferences 13 and 14. Liquid streams are assumed to be 100 percent 

VOC, sampled twice per month with a 1.96 liter purge. Gas streams 

are assumed to be sampled twice per shift with a 1 sec purge through 

a 6.4 mm ID sample tube 15 em long; 80% methane, 15% ethane, 5% VOC. 

cEmission factors for compressors are based on EPA and API testing of emissions 

into the distance piece area from open frame compressors. The factors 

do not include emissions into the seal packing vent or into enclosed 

distance pieces. Therefory8 the emission factors given are probably 

understated substantially. 

3-9 
emissions factor represents only the emissions measured in the distance 

piece area from open frame compressors. Therefore, the emissions from 

the seal packing vent and from enclosed distance pieces are not included. 

This probably results in a significant understatement of total compressor 

emissions because the majority of the compressor emissions will come from 

the seal vents. 16 The total daily and annual emissions from fugitive 

sources at a model gas plant are shown in Table 3-2. Total daily emissions 

are calculated by multiplying the number of pieces of each type of equipment 

by the corresponding daily emission factor. The average percent of total 

emissions attributed to each component type is also presented in Table 3-2. 

3-10 
Table 3-2. ESTIMATED BASELINE FUGITIVE VOC EMISSIONS FROM 

A TYPICAL GAS PLANT 

Component Number of Ba~el~ne a Percentage of 

type components emlSSlOnS, total emissions 

kg/day 

Valves 750 140 (360) 58 (59) 

Relief valves 12 4.0 ( 54) 2 ( 9) 

Open-ended lines 150 51 ( 80) 21 (13) 

Compressor sealsb 6 6.0 ( 29) 2 ( 5) 

Pump seals 6 7.2 ( 9.0) 3 ( 1) 

Sampling connections 

Inlet Gas 6 0.1 ( 1. 9) 1 ( 1) 

Liquids 6 0.5 (0.5) 1 ( 1) 

Flanges and 3,000 33 ( 78) 14 (13) 

connections 

Total baseline emissions 242 (612) 

xx = VOC emission values. 

(xx) = Total hydrocarbon emissions values. 

aFrom Table 3-1. 

bAs discussed in Table 3-1, the compressor seal emission factor and thus 

the percentage of total emissions from compressors may be substantially 

understated. 

3-11 
3.4 REFERENCES 

1. Cantrell, A. Worldwide Gas Processing. Oil and Gas Journal, 

July 14, 1980. p. 88. Docket Reference Number II-I-23.* 

2. Organic Chemical t1anufacturing, Volume 3: Storage, Fugitive, and 

Secondary Sources. Report 2, Fugitive Emissions. U.S. Environmental 

Protection Agency. Office of Air Quality Planning and Standards. 

Emission Standards and Engineering Division. Research Triangle 

Park, North Carolina. EPA-450/3-80-025. December 1980. Docket 

Reference Number II-A-22.* 

3. Nelson, W.E. Compressor Seal Fundamentals. Hydrocarbon Processing, ~(12):91-95. 1977. Docket Reference Number II-I-12.* 

4. Telecon. R.A. McAllister, TRW, to G.H. Holliday, Shell Oil, Houston, 

Texas. March 10, 1981. Compressors and seals at gas plants. Docket Reference Number II-E-7.* 

5. Letter from Hennings, T.J., TRW to K.C. Hustvedt, EPA. Hay 13, 1981. 

Results of a telephone survey concerning the use of pneumatic 

control valves at gas plants. Docket Reference Number II-B-6.* 

6. Lyons, J.D., and C.L. Ashland, Jr. Lyons• Encyclopedia of Valves. 

New York, Van Nostrand Reinhold Co., 1975. 290 p. Docket Reference 

Number II-I-9.* 

7. Templeton, H.C. Valve Installation, Operation and Maintenance. 

Chern. E., .z5l(23)141-149, 1971. Docket Reference Number II-I-4.* 

8. Steigerwald, B.J. Emissions of Hydrocarbons to the Atmosphere from 

Seals on Pumps and Compressors. Report No. 6, PB 216 582, Joint 

District, Federal and State Project for the Evaluation of Refinery 

Emissions. Air Pollution Control District, County of Los Angeles, California. April 1958. 37 p. Docket Reference Number II-I-1.* 

9. McFarland, I. Preventing Flange Fires. Chemical Engineering 

Progress, ~{8):59-61. 1969. Docket Reference Number II-I-3.* 

10. Letter from Hennings, T.J., TRW to K.C. Hustvedt, EPA. July 7, 1981. 

Results of a telephone survey concerning control of fugitive emissions 

from gas plant compressor seals. Docket Reference Number II-B-7.* 

11. Eaton, W.S., et al. Fugitive Hydrocarbon Emissions from Petroleum 

Production Operations. API Publication No. 4322. March 1980. Docket 

Reference Number II-I-20.* 

12. DuBose, D.A., J.I. Steinmetz, and G.E. Harris. Frequency of Leak 

Occurrence and Emission Factors for Natural Gas Liquid Plants. 

Final Report. Radian Corp., Austin, Texas. Prepared for U.S. 

Environmental Protection Agency, Emissions t1easurement Branch, 

Research Triangle Park, North Carolina. EMB Report No. 80-FOL-1. 

July 1982. Docket Reference Number II-A-36.* 

3-12 
13. Memo from Norwood, T.L., PES to Docket. Gas sampling connection 

purge emission factor and control cost effectiveness. October 28, 

1982. Docket Reference Number II-B-15.* 

14. Memo from Norwood, T.L., PES to Docket, Liquid sampling connection 

purge emission factor and control cost effectiveness. October 27, 

1982. Docket Reference Number II-B-14.* 

15. Letter and Attachments. Norwood, Tom, Pacific Environmental Services, 

Inc. to Gibson, Jim, Seagull Products Company. Draft Trip Report 

to Palacios Gas Plant. December 9, 1982. Docket Reference Number 

II-C-18.* 

16. 11 National Air Pollution Control Techniques Advisory Committee 

Minutes of Meeting July 21 and 22, 1982, 11 U.S. EPA:OAQPS, RTP, NC. 

August 23, 1982. Page III-43. Docket Reference Number II-A-24.* 

*References can be located in Docket Number A-80-20-B at U.S. Environmental 

Protection Agency Library, Waterside Mall, Washington, D.C. 

3-13 
4.0 EMISSION CONTROL TECHNIQUES 

4.1 INTRODUCTION 

Sources of fugitive VOC emissions from gas plant equipment were 

identified in Chapter 3 of this document. This chapter discusses the 

emission control techniques that can be applied to reduce fugitive VOC 

emissions from these sources. These techniques include leak detection 

and repair programs and equipment specifications. The estimated 

control effectiveness of the techniques is also presented. In some 

cases, the techniques for reducing gas plant fugitive emissions are 

based on transfer of control technology as applied to related industries. 

This approach is possible because the related industries (e.g., refineries) 

use similar types of equipment, such as valves, pumps, and compressors. 

There may be differences between gas plants and related industries in 

average line temperatures, product composition, or other parameters. 

However, these differences do not influence the applicability of the 

techniques used in controlling fugitive emissions. 

Chapter 4 also presents other control strategies applicable to 

control of fugitive emissions from gas plants. However, the control 

effectiveness of these alternative strategies has not been estimated. 

4.2 LEAK DETECTION AND REPAIR METHODS 

Leak detection and repair methods can be applied in order to 

reduce fugitive emissions from gas plant sources. Leak detection 

methods are used to identify equipment components that are emitting 

significant amounts of VOC. Emissions from leaking sources may be 

reduced by three general methods: repair, modification, or replacement 

of the source. 

4.2.1 Leak Detection Techniques 

Various monitoring techniques that can be used in a leak detection 

program include individual component surveys, unit area (walk-through) 

4-1 
surveys, and fixed-point monitoring systems. These emission detection 

methods would yield qualitative indications of leaks. 

4.2.1.1 Individual Component Survey. Each fugitive emission 

source (pump, valve, compressor, etc.) is checked for VOC leakage in 

an individual component survey. The source may be checked for leakage 

by visual, audible, olfactory, soap solution, or instrument techniques. 

Visual methods are good for locating liquid leaks, especially pump 

seal failures. High pressure vapor leaks may be detected by hearing 

the escaping vapors, and leaks of odorous materials may be detected by 

smell. Predominant industry practices are leak detection by visual, 

audible, and olfactory methods. However, in many instances, even very 

large VOC leaks are not detected by these methods. 

Applying a soap solution on equipment components is one individual 

survey method. If bubbles are seen in the soap solution, a leak from 

the component is indicated. The method requires that the observer 

subjectively determine the rate of leakage based on the rate of for~tion 

of soap bubbles over a specified time period •. The method is not 

appropriate for very hot sources, although ethylene glycol can be 

added to the soap solution to extend the temperature range. This 

method is also not suited for moving shafts on pumps or compressors, 

since the motion of the shaft may cause entrainment of air in the soap 

solution and indicate a leak when none is present. In addition, the 

method cannot generally be applied to open sources such as relief 

valves or vents without additional equipment. 

The use of portable hydrocarbon detection instruments is the best 

known individual survey method for identifying leaks of VOC from 

equipment components because it is applicable to all types of sources. 

The instrument is used to sample and analyze the air in close proximity 

to the potential leak surface by traversing the sampling probe tip 

over the entire area where leaks may occur. This sampling traverse is 

called 11monitoring 11 in subsequent descriptions. A measure of the 

hydrocarbon concentration of the sampled air is displayed in the 

instrument meter. The performance criteria for monitoring instruments 

and a description of instrument survey methods are included in Appendix D. 

Table 4-1 presents data on the percentage of components that are 

4-2 
Component type 

Valves a 

Relief valvesb 

Compressor seals3 

~ 

Pur:1p sealsa I 

w 

aReference 1. 

bReference ? 

~. 

Table 4-1. PERCENTAGE OF COMPONENTS PREDICTED TO BE LEAKING 

IN AN INDIVIDUAL COMPONENT SURVEY 

Predicted percent of sources leaking 

100,000 ppmv 50,000 ppmv 20,000 ppmv 10,000 ppmv 

9 11 14 18 

8 11 15 19 

20 27 35 43 

10 22 26 33 

1,000 ppmv 

28 

34 

60 

53 
predicted to have instrument readings greater than or equal to various 

concentrations during an individual component survey. 

4.2.1.2 Unit Area Survey. A unit area or walk-through survey 

entails measuring the ambient VOC concentration within a given distance, 

for example, one meter, of all equipment located at ground level and 

other accessible levels within a processing area. These measurements 

are performed with a portable VOC detection instrument utilizing a 

strip chart recorder. 

The instrument operator·walks a predetermined path to assure 

total coverage of a unit on both the upwind and downwind sides of the 

equipment, noting on the chart record the location in a unit where any 

elevated VOC concentrations are detected. If an elevated VOC concentration 

is recorded, the components in that area can be screened individually 

to locate the specific leaking equipment. 

It is estimated that 50 percent of all significant leaks in a 

unit are detected by the walk-through survey, provided that there are 

only a few pieces of leaking equipment, thus reducing the VOC background 

concentration sufficiently to allow for reliable detection. 3 

The major advantages of the unit area survey are that leaks from 

accessible leak sources near the ground can be located quickly and 

that the leak detection manpower requirements can be lower than those 

for the individual component survey. Some of the shortcomings of this 

method are that VOC emissions from adjacent units can cause false leak 

indications; high or intermittent winds (local meteorological conditions) 

can increase dispersion of VOC, causing leaks to be undetected; elevated 

equipment leaks may not be detected; and additional effort is necessary 

to locate the specific leaking equipment, i.e., individual checks in 

areas where high concentrations are found. 

4.2.1.3 Fixed-Point Monitors. This method consists of placing 

several automatic hydrocarbon sampling and analysis instruments at 

various locations in the process unit. The instruments may sample the 

ambient air intermittently or continuously. Hydrocarbon concentrations 

above a background level indicate a leaking component. As in the 

walk-through method, an individual component survey is required to 

identify the specific leaking component in the area. Leaks from 

4-4 
adjacent units and meteorological conditions may affect the results 

obtained. The efficiency of this method is not well established, but 

it has been estimated that 33 percent of the number of leaks identified 

by a complete individual component survey could be located by fixed-point 

monitors. 4 These leaks would be detected sooner by fixed-point monitors 

than by use of portable monitors, because the fixed-point monitors 

operate semi continuously. Fixed-point monitors are more expensive; 

multiple fixed point monitors may be required; and use of the portable 

instrument is still required to locate the specific leaking component. 

Calibration and maintenance costs may be higher. Fixed-point monitors 

have been used to detect emissions of hazardous or toxic substances 

(such as vinyl chloride) as well as potentially explosive conditions. 

Fixed-point monitors have an advantage in these cases, since a particular 

compound can be selected as the sampling criterion. 

4.2.1.4 Visual Inspections. Visual inspections can be performed 

for any of the leak detection techniques discussed above to detect 

evidence of liquid leakage from plant equipment. When such evidence 

is observed, the operator can use a portable VOC detection instrument 

to measure the VOC concentration of the source. In a specific application, 

visual inspections can be used to detect the failure of the outer seal 

of a pump•s dual mechanical seal system. Observation of liquid leaking 

along the shaft indicates an outer seal failure and signals the need 

for seal repair. 5 

4.2.2 Repair Methods 

The following descriptions of repair methods include only those 

features of each fugitive emission source (pump, valve, etc.) that 

should be considered in assessing the applicability and effectiveness 

of each method. 

4.2.2.1 Valves. Most valves have a packing gland that can be 

tightened while in service. Although this procedure should decrease 

the emissions from the valve, in some cases it may actually increase 

the emission rate if the packing is old and brittle or has been 

overtightened. Unbalanced tightening of the packing gland may also 

cause the packing material to be positioned improperly in the valve 

and allow leakage. Valves that are not often used can build up a 

4-5 
"static" seal of paint or hardened lubricant that could be broken by 

tightening the packing gland. Plug-type valves can be lubricated with 

grease to reduce emissions around the plug. 

Some types of valves have no means of in-service repair and must 

be isolated from the process and removed for repair or replacement. 

Other valves, such as control valves, may be excluded from in-service 

repair by operating procedures or safety procedures. In many cases, 

valves cannot be isolated from the process for removal. If a line 

must be shut down in order to isolate a leaking valve, the emissions 

resulting from the shutdown may possibly be greater than the emissions 

from the valve if it were allowed to leak until the next process 

change that permits isolation for repair. Depending on site-specific 

factors, it may also be possible to repair leaking process valves by 

injection of a sealing fluid into the source of the leak. 6 

4.2.2.2 Pressure Relief Valves. In general, pressure relief 

valves that leak must be removed in order to repair the leak. In some 

cases of improper reseating, manual release of the valve may improve 

the seat seal. In order to remove the pressure relief valve for 

repair without shutting down the process, the process must be kept 

isolated from atmosphere. The safest way to isolate the process is to 

install a three-way valve with parallel relief systems so that one of 

the two relief systems is always open.

7'8 

4.2.2.3 Compressor Seals. Leaks from centrifugal and reciprocating 

compressor seals may be reduced by replacing the seal or tightening or 

replacing the packing. If the leak is small, temporary emissions 

resulting from a shutdown may be greater than the emissions from the 

leaking seal. It is anticipated that for many reciprocating compressor 

seals it will not be possible to bring leaks under the designated 

action level. In addition, there will not often be a spare compressor 

to allow shutdown for repair of the leaking compressor seal. In these 

instances it would be more appropriate to vent leaks from compressor 

seals to a control device. This approach is described in Section 4.3.2. 

4.2.2.4 Pumps. In some cases, it is possible to operate a spare 

pump while the leaking pump is being repaired. Leaks from packed 

seals may be reduced by tightening the packing gland. At some point, 

the packing may deteriorate to the point where further tightening 

4-6 
would have no effect or possibly even increase fugitive emissions from 

the seal. The packing can be replaced with the pump out of service. 

When mechanical seals are utilized, the pump must be dismantled so the 

leaking seal can be repaired or replaced. Dismantling pumps may 

result in spillage of some process fluid causing emissions of VOC. 

These temporary emissions have the potential of being greater than the 

continued leak from the seal. Therefore, the pump should be isolated 

from the process and flushed of VOC as much as possible prior to 

repacking or seal replacement. 

4.2.2.5 Flanges and Connections. In some cases, leaks from 

flanges can be reduced by replacing the flange gaskets. Leaks from 

small threaded connections can be reduced by placing synthetic (e.g., 

Tefl6n) tape or "pipe dope•• on the male threads before the connection 

is made. Most flanges and connections cannot be isolated to permit 

repair of leaks. Data show that flanges and connections emit relatively 

small amounts of VOC (Table 3-1). 

4.2.3 Emission Control Effectiveness of Leak Detection and Repair 

The control efficiency achieved by a leak detection and repair 

program is dependent on several factors, including the leak definition, 

inspection interval, and the allowable repair time. 

4.2.3.1 Definition of a Leak. The first step in developing a 

monitoring plan for fugitive VOC emissions is to define an instrument 

meter reading that is indicative of an equipment leak. The choice of 

the meter reading for defining a leak is influenced by several considerations. The percent of total mass emissions that can potentially 

be controlled by the leak detection and repair program can be affected 

by varying the leak definition. Table 4-2 gives the percent of total 

mass emissions affected at various leak definitions for a number of 

component types. From the table, it can be seen that, in general, a 

low leak definition results in larger potential emission reductions. 

Other considerations are more source specific. For valves, the 

selection of an action level for defining a leak is a tradeoff between 

the desire to locate all significant leaks and to ensure that emission 

reductions are possible through maintenance. Although test data show 

that some valves with meter readings less than 10,000 ppm have significant 

emission rates, most of the major emitters have meter readings greater 

4-7 
~ 

I 

co 

Table 4-2. PERCENT OF TOTAL EtHSSIONS AFFECTED AT VARIOUS 

LEAK DEFINITIONS 

Percent of PlaSS emissions affected at this leak definitiona 

Component type 100,000 ppmv 50,000 ppmv 20,000 ppmv 10,000 ppmv 1,000 ppmv 

b Valves 54 (59) 64 (70) 78 (83) 86 (87) 97 (98) 

Relief valvesc 41 (42) 53 (56) 67 (69) 77 ( 77) 96 (96) 

Compressor seals b 63 (64) 75 (76) 87 (88) 92 (93) 99 (99) 

Pump sealsb 46 ( 47) 63 (63) 72 ( 71) 79 (79) 94 (94) 

XX = VOC emission values. 

(xx) =Total hydrocarbon emission values. 

aThese figures relate the leak definition to the percentage of total mass emissions that can 

be expected from sources with concentrations at the source greater than the leak definition. 

If these sources were instantaneously repaired to a zero leak rate and no new leaks occurred, 

then emissions could be expected to be reduced by this maximum theoretical efficiency. 

bReference 1. 

cReference 2. 
than 10,000 ppm. Maintenance programs on valves have shown that 

emission reductions are possible through on-line repair for essentially 

all valves with nonzero meter readings. There are, however, cases 

where on-line repair attempts result in an increased emission rate. 

The increased emissions from such a source could be greater than the 

emission reduction if maintenance is attempted on low leak valves. 

These valves should, however, be able to achieve essentially 100 percent 

emission reduction through off-line repair. Generally, the emission 

rates from valves with meter readings greater than or equal to 10,000 ppm 

are significant enough so that an overall emission reduction is likely 

for a leak detection and repair program with a 10,000 ppm leak definition. 

In addition, testing by EPA and industry has shown that meter readings 

will generally be either much less than 10,000 ppm or much greater 

than 10,000 ppm. 1'

9'10 Therefore, 10,000 ppm was deter~ined to be the 

most reasonable leak definition to initiate valve maintenance efforts 

while still having confidence that an overall emission reduction will 

result. 

For pump and compressor seals, the rationale for selection of an 

action level is different because the cause of leakage is different. 

As opposed to valves, which generally have zero leakage, most pump and 

compressor seals leak to a certain extent while operating normally. 

These seals would tend to have low instrument meter readings. With 

time, however, as the seal begins to wear, the concentration and 

emission rate are likely to increase. At any time, catastrophic seal 

failure can occur with a large increase in the instrument meter reading 

and emission rate. As shown in Table 4-2, over 90 percent of the 

emissions from compressor seals and 80 percent of the emissions from 

pump seals are from sources with instrument meter readings greater 

than or equal to 10,000 ppm. Since properly designed, installed, and 

operated seals should have low instrument meter readings, and, since 

the bulk of the pump and compressor seal emissions are from seals that 

have worn out or failed such that they have a concentration equal to 

or greater than 10,000 ppm, this level was chosen as a reasonable 

action level. 

4.2.3.2 ~ection Interval. The length of time between inspections 

should depend on the expected occurrence and recurrence of leaks after 

4-9 
a piece of equipment has been checked and/or repaired. This interval 

can be related to the type of equipment and service conditions, and 

different intervals can be specified for different pieces of equipment. 

Monitoring may be scheduled on an annual, quarterly, monthly, or 

weekly basis. The choice of the interval affects the emission reduction 

achievable, since more frequent inspection intervals will result in 

earlier detection and repair of leaking sources. 

4.2.3.3 Allowable Repair Time. If a leak is detected, the 

equipment should be repaired within a certain time period. The allowable 

repair time should allow the plant operator sufficient time to obtain 

necessary repair parts and maintain some degree of flexibility in 

overall plant maintenance scheduling. The determination of this 

allowable repair time will affect emission reductions by influencing 

the length of time that leaking sources are allowed to continue to 

emit VOC. 

4.2.3.4 Estimation of Reduction Efficiency. Data are presented 

in Table 4-2 that show the expected percent of total emissions from 

each type of source contributed by those sources with VOC concentrations 

greater than given leak definitions. If a leak detection and repair 

program resulted in repair of all such sources to 0 ppmv, elimination 

of all sources over the leak definition between inspections, and 

instantaneous repair of those sources found at each inspection, then 

emissions could be expected to be reduced by the amount reported in 

Table 4-2. However, since these conditions are not met in practice, 

the fraction of emissions from sources with VOC concentrations over 

the leak definition represents the theoretical maximum reduction 

efficiency. The approach used to estimate emission reductions 

presented here is to reduce this theoretical maximum control efficiency 

by accounting quantitatively for those factors outlined above. 

There are two models available for estimation of emission reduction 

efficiency from leak detection and repair programs. Both models are 

used in this BID. The first model (the computer leak detection and 

repair (LDAR) model) is described in Appendix E and is applied to 

valves and pumps. It is the preferred model, because it incorporates 

recently available data on leak occurrence and recurrence and data on 

the effectiveness of simple in-line repair. These data are not available 

4-10 
for relief valves and compressors. Therefore, a second model (the 

ABCD model) is applied to these sources. The ABCD model can be expressed 

mathematically by the following equation: 11 

Reduction efficiency = A x B x C x D 

Where: 

A = Theoretical Maximum Control Efficiency = fraction of total 

mass emissions from sources with VOC concentrations greater 

than the leak definition (from Table 4-2). 

B = Leak Occurrence and Recurrence Correction Factor = correction 

factor to account for sources which start to leak between 

inspections (occurrence), for sources which are found to be 

leaking, are repaired and start to leak again before the next 

inspection (recurrence), and for known leaks that could not be 

repaired. 

C = Noninstantaneous Repair Correction Factor = correction factor 

to account for emissions which occur between detection of a 

leak and subsequent repair, since repair is not instantaneous. 

D = Imperfect Repair Correction Factor = correction factor to 

account for the fact that some sources which are repaired are 

not reduced to zero. For computational purposes, all sources 

which are repaired are assumed to be reduced to an emission 

level equivalent to a concentration of 1,000 ppmv. 

As an example of this technique, Table 4-3 gives values for the 11 8, 11 

11 C, 11 and 11 011 correction factors for various possible inspection intervals, 

allowable repair times, and leak definitions. These values are given 

only for relief valves and compressors seals, because the reduction 

efficiency for valves and pump seals is estimated according to the 

LDAR model presented in Appendix E. 

The ABCD model control efficiencies for compressors and pressure 

relief valves, however, have been modified to correct for the accuracy 

of the engineering judgment employed to derive one of the model inputs. 

The accuracy of the judgment was approximated by the comparison of the 

LDAR model and ABCD model control efficiencies for valves. The control 

efficiency for compressors and pressure relief valves was derived by 

weighting the ABCD model results by this relationship. 18 This technique 

is used to determine emission reductions for control alternatives in 

Table 7-1. 

4-11 
.t:-

I 

........ 

"' 

Table 4-3. VOC EMISSION CORRECTION FACTORS FOR VARIOUS INSPECTION INTERVALS, 

ALLOWABLE REPAIR TIMES, AND LEAK DEFINITIONS FOR ABCD MODEL 

Leak occurence and Non-instantaneous 

recurrence coarection 

factor repair corrsction 

factor Imperfect repair correction factorc 

Inspection interval 

Allowable repair 

time (days) Leak definition (ppmv) 

Component type Quarterly Monthly 15 5 100,000 50,000 10,000 1,000 

Relief valves 0.90 0.95 0.98 0.99 0.92 0.91 0.89 0.85 

(0.99) (0.99) (0.99) (0.99) 

Compressor seals 0.90 0.95 0.98 0.99 0.98 0.98 0.97 0.97 

( 0. 97) {0.96) (0.95) (0.94) 

xx = VOC emission values. 

(xx) = Total hydrocarbon emission values. 

aFactor accounts for sources that start to leak between inspections (occurrence), for sources that are found 

to be leaking, are repaired, and start to leak again before the next inspection (recurrence), and for 

leaking sources that cannot be repaired. Reference 11. 

bFactor accounts for emissions that occur between detection of a leak and subsequent repair. Reference 11. 

cFactors accounts for the fact that some sources that are repaired are not reduced to zero. Repaired 

sources are assumed to be reduced to a 1,000 ppmv concentration level. From Tables 3-1, 4-1, 4-2, and 

References 1 and 2. 
4.3 PREVENTIVE PROGRAMS 

An alternative approach to controlling fugitive VOC emissions 

from gas plant operations is to replace components with leakless 

equipment. This approach is referred to as a preventive program. 

This section will discuss the kinds of equipment that could be applied 

in such a program and the advantages and disadvantages of this equipment. 

4.3.1 Pressure Relief Valves 

As discussed in Chapter 3, pressure relief valves can be sources 

of fugitive VOC emissions because of leakage through the valve seat. 

This type of leakage can be prevented by installing a rupture disk 

upstream of the valve, by connecting the discharge port of the valve 

to a closed-vent system, or by use of soft seat technology such as 

elastomer "0-rings." A rupture disk can be used upstream of a pressure 

relief valve so that under normal conditions it seals the system 

tightly but will break when its set pressure is exceeded, at which 

time the pressure relief valve will relieve the pressure. Figure 4-1 

is a diagram of a rupture disk and pressure relief valve installation. 

The installation is arranged to prevent disk fragments from lodging in 

the valve and preventing the valve from being reseated if the disk 

ruptures. It is important that no pressure be allowed to build in the 

pocket between the disk and the pressure relief valve; otherwise, the 

disk will not function properly. A pressure gauge and bleed valve can 

be used to prevent pressure buildup. With the use of a pressure 

gauge, it can be determined whether the disk is properly sealing the 

system against leaks. 

It may be necessary to install a 2-port valve and parallel relief 

valve when using a rupture disk upstream of a relief valve. Such a 

system may be required to isolate the relief valve/rupture disk system 

for repair in case of an overpressure discharge. The parallel system 

would provide a backup relief valve during repair. However, a block 

valve upstream of the rupture disk/relief valve system will accomplish 

the same purpose where safety codes allow the use of a block valve for 

this purpose. 

An alternative method for controlling pressure relief valve 

emissions due to improper reseating is the use of a soft elastomer 

seat in the valve. An elastomer "0-ring" can be installed so that the 

4-13 
To 

atmospheric 

vent 

---Tension-adjustment 

thimble 

---- Spnng 

Figure 4-1. Rupture disk installation upstream of a relief valve. 3 

~·-14 
valve always forms a tight seal after an overpressure discharge. 

However, this approach will not prevent leakage due to 11 Simmering, 11 a 

condition due to the system pressure being too close to the set pressure 

of the valve. 

4.3.2 Compressor Seals 

As discussed in Chapter 3, there are three types of compressors 

used in natural gas plants: centrifugal, rotary, and reciprocating. 

Centrifugal and rotary compressors are driven by rotating shafts while 

reciprocating compressors are driven by shafts having a linear reciprocating motion. In either case, fugitive emissions occur at the junction 

of the moving shafts and the stationary casing, but the kinds of 

controls that can be effectively applied depend on the type of shaft 

motion involved. 

4.3.2.1 Centrifugal and Rotary Compressors. Centrifugal and · 

rotary compressors are both driven by rotating shafts. Emissions fran 

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 c~se of 

pumps, seal fluid degassing vents must be controlled with a closed 

vent system to prevent process gas from escaping from the vent. 

4.3.2.2 Reciprocating Compressors. This type of compressor 

usually involves a piston, cylinder, and drive-shaft arrangement. 

Since the shaft motion is linear, a packing gland arrangement is 

normally employed to prevent leakage around the moving shaft. This 

type of seal can be improved by inserting one or more spacer rings 

into the packing and connecting the void area or areas thus produced 

to a collection system through vents in the housing. This is referred 

to as a 11 Scavenger 11 system. As with other fugitive emission collection 

systems, these vents must be controlled to prevent fugitive emissions 

from entering the atmosphere. However, venting the seal does not 

eliminate emissions from reciprocating compressors entirely, because 

emissions can still occur into the distance piece area. These leaks 

4-15 
can be controlled by enclosing the distance piece area and installing . 

suitable piping to vent the emissions either to a flare, a plant 

process heater, or back into a low pressure point in the process. For 

the latter two cases, an auxilliary compressor may be required to 

compress the vent stream to a usable pressure. Purging the distance 

piece with natural gas could be performed to keep the enclosure above 

the upper explosive limit and to ensure a nonexplosive atmosphere 

(Figure 4-2). 

As shown in Figure 4-2, the distance piece enclosure could be 

maintained slightly above atmospheric pressure by purging the enclosure 

with residue or sales gas through a regulator. To ensure safety, 

either double distance pieces13 or more sophisticated piston rod 

seals12 should be employed. Additionally, a high pressure sensor in 

the purge gas line should be used to shut off the gas supply in the 

event of regulator failure. In order to provide for draining of seal 

oil leaks, the atmospheric pressure oil drain line should be connected 

through a 11 U11 tube trap as shown to prevent loss of the purge gas 

while allowing uninterrupted oil flow. A second water filled trap in' 

the outlet serves to maintain the pressure in the enclosure, while 

allowing free flow of emissions (or seal failure gases) to the control 

device by displacement of the water into the knockout drum when the 

pressure in the system exceeds the water column height set pressure. 

Obtaining a good seal at the distance piece door and at the point 

where emissions are vented from the distance piece or seal area is 

necessary for maintaining a sufficient pressure (e.g., 2 to 5 psig). 

Block valves should also be installed in order to close vent lines 

during compressor shutdown periods. This will prevent hydrocarbon 

vapors from entering the work place and air from entering the vent 

system during compressor maintenance. 14 There may be instances where 

retrofitting of such a vent control system to a compressor distance 

piece may be infeasible for safety reasons. 15 Therefore, the application 

of this preventive program as a retrofit will have to be evaluated on 

a case-by-case basis. 

4.3.3 Pump Seals 

Pumps can be potential fugitive VOC emission sources because of 

leakage through the drive-shaft sealing mechanism. This kind of 

4-16 
·- _._.. ... ,. ....... 

To Flare or ..-------:J~or>rocess Heater 

2" (Scm) Header) 

Check 

Valve -+ 

Distance 

Piece Vent _, 

Block Valve ..., 

Pressure Alarm ~ 

Water 

_..-Filled 

Trap 

Waste 011 - ~t:=:==~l==::;;::==~ F=====111===«========:s. 

Drain l fne 

to Tank or 

Recovery Oil 

Cap 

Figure 4-2. COMPRESSOR DISTANCE PIECE PURGE SYSTEM 

..... "_ 

Trap J 

Detail 
leakage can be reduced to a negligible level through the installation 

of improved shaft sealing mechanisms, such as dual mechanical seals. 

Dual mechanical seals consist of two mechnical sealing elements 

usually arranged in either a back-to-back or a tandem configuration. 

In both configurations a barrier fluid circulates between the seals. 

The barrier fluid system may be circulating system, or it may rely on 

convection to circulate fluid within the system. While the barrier 

fluid's main function is to keep the pumped fluid away from the environment, it can serve other functions as well. A barrier fluid can 

provide temperature control in the stuffing box. It can also protect 

the pump seals from the atmosphere, as in the case of pumping easily 

oxidizable materials that form abrasive oxides or polymers upon exposure 

to air. A wide variety of fluids can be used as barrier fluids. Some 

of the more common ones that have been used are water (or steam), 

glycols, methanol, oil, and heat transfer fluid. In cases in which 

product contamination cannot be tolerated, it may also be possible to 

use clean product, a product additive, or a product diluent. 

Emissions of VOC from barrier fluid degassing vents can be controlled 

by a closed vent system, which consists of piping and, if necessary, 

flow inducing devices to transport the degassing emissions to a control . device, such as a process heater, or vapor recovery system. Control 

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. 3 In addition, visual inspection of 

the seal area also can be effective for detecting failure of the outer 

seals. Upon seal failure, the leaking pump would have to be shut down 

for repair. 

4.3.4 Open-Ended Lines 

Caps, plugs, and double block and bleed valve are devices for 

closing off open-ended lines. When installed downstream of an open-ended 

line, they are effective in preventing leaks through the seat of the 

valve from reaching atmosphere. In the double block and bleed system, 

it is important that the upstream valve be closed first. Otherwise, 

4-18 
product will remain in the line between the valves, and expansion of 

this product can cause leakage through the valve stem seals. 

The control efficiency will depend on such factors as frequency 

of valve use, valve seat leakage, and material that may be trapped in 

the cap or plug. Annual VOC emissions from a leaking open-ended valve 

are approximately 100 kg. 16 Assuming that open-ended lines are used 

an average of 10 times per year, that 0.1 kg of trapped organic material 

is released when the valve is used, and that all of the trapped organics 

released are emitted to atmosphere, the annual emissions from closed 

off open-ended lines would be 1 kg. This would be a 99 percent reduction 

in emissions. Oue to the conservative nature of these assu~ptions, a 

100 percent control efficiency has been used to estimate the emission 

reductions of closing off open-ended lines. 

4.3.5 Closed-Purge Sampling 

VOC emissions from purging sampling lines can be controlled by a 

closed-purge sampling system, which is designed so that the purged VOC 

is returned to the system or sent to a closed disposal syster.t so that 

the handling losses are minimized. Figure 4-2 gives two examples of 

closed-purge sampling systems where the purged VOC is flushed from a 

point of higher pressure to one of lower pressure in the syster.t and 

where sample-line dead space is minimized. Other sampling systems are 

available that utilize partially evacuated sampling containers and 

require no line pressure drop. 17 

Reduction of emissions for closed-purge sampling is dependent on 

many highly variable factors, such as frequency of sampling and amount 

of purge required. For emission calculations, it has been assumed 

that closed-purge sampling systems will provide 100 percent control 

efficiency for the sample purge. 

4.3.6 Gas-Operated Control Valves 

VOC emissions from pneumatic control valves result when field gas 

or flash gas is used as the operating medium. These emissions can be 

eliminated by the use of compressed air. This will require installation 

of an air compression system and connection of the appropriate pressure 

supply lines. 

4-19 
4.4 REFERENCES 

1. DuBose, D.A., J.I. Steinmetz, and G.E. Harris. Frequency of Leak 

Occurrence and Emission Factors for Natural Gas Liquid Plants. 

Final Report. Radian Corporation. Austin, Texas. Prepared for 

U.S. Environmental Protection Agency. Emissions Heasurement Branch. 

Research Triangle Park, North Carolina. EMB Report No. 80-FOL-1. 

July 1982. Docket Reference Number II-A-36.* 

2. Hennings, T. J., TRW to VOC/Onshore Production Docket. April 2, 

1982. Cumulative distribution of mass emissions and percent sources 

with respect to screening value for relief valves. Docket Reference 

Number II-B-12.* 

3. Erikson, D.G. and V. Kalcevic. Organic Chemical Manufacturing, Volume 3: Storage, Fugitive, and Secondary Sources. Report 2. 

Fugitive Emissions. U.S. Environmental Protection Agency. Research 

Triangle Park, NC. Report Number EPA-450/3-80-025. December 1980. 

Docket Reference Number II-I-15.* 

4. Hustvedt, K.C. and R.C. Weber. Detection of Volatile Organic 

Compound Emissions from Equipment Leaks. Paper presented at 71st 

Annual Air Pollution Control Association t1eeting. Houston, TX. 

June 25-30, 1978. Docket Reference Number II-A-2.* 

5. Hustvedt, K.C., R.A. Quaney, and W.E. Kelly. Control of Volatile 

Organic Compound Leaks from Petroleum Refinery Equipment. U.S. 

Environmental Protection Agency. Research Triangle Park, NC. 

Report Number EPA-450/2-78-036. June 1978. Docket Reference 

Number II-A-3.* 

6. Teller, James H. Advantages Found in On-Line Leak Sealing. Oil 

and Gas Journal, 1L(29):54-59, 1979. Docket Reference Number II-I-16.*. 

7. Letter from Naughton, D. A., Hartford Steam Boiler 

Insurance Company, to M. Cappers, Allied Chemical. 

P·roposed EPA regulations requiring isolation valve 

relief valves and rupture discs. Docket Reference 

Inspection and 

May 28, 1981. 

upstream of 

Number II-I-29.* 

8. Letter from Lambert, J. A., Jr., Industrial Risk Insurers, to 

t1. A. Cappers, Allied Chemical. t~ay 28, 1981. Propose9 EPA regulations 

requiring isolation valve upstream of relief valves and rupture 

discs. Docket Reference Number II-I-28.* 

9. Letter with attachments from H. H. ~1cClure, Texas Chemical Council, 

to W. Barber, EPA. June 30, 1980. Appendix 8, page 11. Docket 

Reference Number II-D-4.* 

10. "A Fugitive Emissions Study in Petrochemical Manufacturing Unit" 

Kun-Chieh Lee, et. al., Union Carbide Corporation, South Charleston, 

West Virginia, presented to annual meeting of the Air Pollution 

Control Association, Montreal, Quebec, June 22-27, 1980. page 2. 

Docket Reference Number II-D-4.* 

4-20 
11. Tichenor, B.A., K.C. Hustvedt, and R.C. Weber. Controlling Petroleum 

Refinery Fugitive Emissions Via Leak Detection and Repair. Symposium 

on Atmospheric Emissions from Petroleum Refineries. Austin, TX. 

Report Number EPA-600/9-80-013. November 6, 1979. Docket Reference 

Number I I-A-7. * 

12. Letter from Sheppard, R.W., Ingersoll Rand to Ajax, R.L., EPA. 

October 29, 1982. Docket Reference Number II-D-43.* 

13 ... Reciprocating Compressors for General Refinery Service, .. American 

Petroleum Institute, API Standard 618, July 1974, pp. 6-8. 

Docket Reference Number II-I-35.* 

14. Letter and attachment from Hennings, T.J., TRW to K.C. Hustvedt, 

EPA. July 7, 1981. Results of a telephone survey concerning 

control of fugitive emissions from gas plant compressor seals. 

Docket Reference Number II-B-7.* 

15. Letter and attachment from Hennings, T. J., TRW to K. C. Hustvedt, 

EPA. February 22, 1982. Results of a telephone survey on safety 

issues concerning compressor vent control systems. Docket Reference 

Number II-B-16.* 

16. Fugitive Emission Sources of Organic Compounds. Additional Information 

on Emissions, Emission Reduction, and Costs. U.S. Environmental 

Protection Agency. EPA-450/3-82-010. April 1982. Docket Reference 

Number II-A-25.* 

17. Letter and attachments from McClure, H.H., Texas Chemical Council, 

to Patrick, D.R., EPA. May 17, 1979. Docket Reference Number II-D-3.* 

18. Memorandum from Rhoads, T.W., PES, Inc., to Docket Number A-80-20. 

Calculation of Controlled Emission Factors for Pressure Relief 

Valves and Compressor Seals. November 1, 1982. Docket Reference 

Number I I-B-17. * 

*References can be located in Docket Number A-80-20-B at U.S. Environmental 

Protection Agency Library, Waterside Mall, Washington, D.C. 

4-21 
5. MODIFICATION AND RECONSTRUCTION 

In accordance with the provisions of Title 40 of the Code of Federal 

Regulation (CFR), Sections 60.14 and 60.15, an existing facility can 

become an affected facility and, consequently, subject to the standards 

of perfonnance 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 perform~nce is promulgated and the construction or n~dification of 

which was commenced prior to the proposal date of the applicable standards. 

The following discussion examines the applicability of modification/ 

reconstruction provisions to natural gas/gasoline processing plants that 

involve fugitive VOC emissions. 

5.1 GENERAL DISCUSSION OF MODIFICATION AND RECONSTRUCTION PROVISIONS 

5.1.1 Modification 

Modification is defined in Section 60.14 as any physical or operational 

change to an existing facility that results in an increase in the emission 

rate of the pollutant(s) to which the standard applies. Paragraph (e) 

of Section 60.14 lists exceptions to this definition which are not 

considered modifications, irrespective of any changes in the emission 

rate. These changes include: 

1. Routine maintenance, repair, and replacement; 

2. An increase in the production rate not requiring a capital 

expenditure as defined in Section 60.2(bb); 

3. An increase in the hours of operation; 

4. Use of an alternative fuel or raw material if, prior to the 

standard, the existing facility was designed to accommodate that alternative 

fuel or raw material; 

5. The addition or use of any system or device whose primary 

function is the reduction of air pollutants, except when an emission 

5-1 
control system is removed or replaced by a system considered to be less 

environmentally beneficial. 

As stated in paragraph (b), emission factors, material balances, 

continuous monitoring systems, and manual emission tests are to be used 

to determine emission rates expressed as kg/day of pollutant. Paragraph 

(c) affirms that the addition of an affected facility to a stationary 

source through any mechanism -- new construction, modification, or 

reconstruction -- does not make any other facility within the stationary 

source subject to standards of performance. Paragraph (f) provides for 

superseding any conflicting provisions. And, (g) stipulates that 

compliance be achieved within 180 days of the completion of any 

modification. 

5.1.2 Reconstruction 

Under the provisions of Section 60.15, an existing facility becomes 

an affected facility upon reconstruction, irrespective of any change in 

emission rate. A source is identified for consideration as a reconstructed 

source when: (1) the fixed capital costs of the new components exceed 

50 percent of the fixed capital costs that would be required to construct 

a comparable entirely new facility, and (2) it is technologically and 

economically feasible to meet the applicable standards set forth in this 

part. The final judgment on whether a replacement constitutes 

reconstruction will be made by the Administrator•s determination of 

reconstruction will be based on: 

(1) The fixed capital cost that would be required to construct 

a comparable new facility; (2) the estimated life of the 

facility after the replacements compared to the life of a 

comparable entirely new facility; (3) the extent to which the 

components being replaced cause or contribute to the emissions 

from the facility; and (4) any economic or technical li~itations in compliance with applicable standards of performance which are inherent in the proposed replacements. 

The purpose of the reconstruction provision is to ensure that an 

owner or operator does not perpetuate an existing facility by replacing 

all but minor components, support structures, frames, housing, etc., 

rather than totally replacing it in order to avoid being subject to 

applicable performance standards. In accordance with Section 60.5, EPA 

5-2 
will, upon request, determine if an action taken constitutes construction 

(including reconstruction). 

5.2 APPLICABILITY OF MODIFICATION AND RECONSTRUCTION PROVISIONS TO 

NATURAL GAS/GASOLINE PROCESSING PLANTS 

As a result of cost and energy considerations, as well as changes 

in product demand and feedstock supply, there are expected to be a 

number of modernization projects at existing gas plants in the near 

future. Some of these projects could result in existing gas plants 

becoming subject to the provisions of Sections 60.14 and 60.15. 

For example, a company may decide to add process trains at an 

existing facility in order to increase the plant capacity or efficiency. 

The additional process equipment would include additional sources of 

potential fugitive emissions, such as valves or compressors. Routine 

changes are also made to gas plants, such as those made to increase ease 

of maintenance, to increase productivity, to improve plant safety, or 

correct minor design flaws. These types of changes may also result in 

an increase of fugitive emissions. However, measures could be taken to 

reduce fugitive emissions from other sources to compensate for the 

increase. The capital expenditure for any of the above additions, 

replacements, or changes may exceed the level of capital expenditure as 

defined in Section 60.2(bb). Some changes may involve only the replacement of a potential fugitive emission source such as a valve. If the 

source is replaced with an equivalent source the level of fugitive 

emissions would be expected to remain unchanged. 

It may be advantageous for certain plants to convert to an entirely 

different processing method. Most new gas plants use the cryogenic 

processing method because it is less costly to operate and because it is 

more efficient. For the same reasons, owners of existing plants may 

decide to convert to the cryogenic method. Depending on the process 

method that is presently being used, this may involve a substantial 

amount of new equipment. It is possible that the cost of the conversion 

would exceed 50 percent of the cost of a new plant. 

5-3 
6.0. MODEL PLANTS AND REGULATORY ALTERNATIVES 

6.1 INTRODUCTION 

This chapter presents model plants and regulatory alternatives for 

reducing fugitive VOC emissions from natural gas/gasoline processing 

plants. The model plants were selected to represent the range of processing complexity in the industry. They provide a basis for determining 

environmental and cost impacts of the regulatory alternatives. The 

regulatory alternatives consist of various combinations of the available 

control techniques and provide incremental levels of emission control. 

6.2 MODEL PLANTS 

There are a number of different process methods used at gas plants: 

absorption, refrigerated absorption, refrigeration, compression, adsorption, cryogenic- Joule-Thomson, and cryogenic-expander. 1 Process 

conditions are expected to vary widely between plants using these different 

methods. However, available data show that fugitive emissions are 

proportional to the number of potential sources, and are not related to 

capacity, throughput, age, temperature, or pressure. 2 Therefore, model 

plants defined for this analysis represent different levels of process 

complexity (number of fugitive emission sources), rather than different 

process methods. 

In order to estimate emissions, control costs, and environmental 

impacts on a plant specific basis, three model plants were developed. 

With the exception of sampling connections, the number of components for 

each model plant is derived from actual component inventories performed 

at four gas plants. Two of the plants were inventoried during EPA 

testing, 3 and two were inventoried during testing by Rockwell International 

under contract to the American Petroleum Institute. 4 The number of 

sampling connections is based on one liquid sampling connection at 

each pump and one gas sampling connection at each compressor. 

6-1 
Complexity of gas plants can be indexed by means of calculating 

ratios of component populations to a more easily counted population. 

For gas plants, the number of vessels appears to be best suited to this 

need. Equipment included and excluded in vessel inventories are listed 

in Table 6-1. The vessel inventories for the industry-tested gas plants 

are taken from the site diagrams and descriptions provided in the 

API/Rockwell report, 6 and the vessel inventories from the EPA-tested 

plants were performed during the testing. These vessel inventories and 

the component inventories are shown in Table 6-2. Table 6-3 shows the 

ratios of numbers of components to numbers of vessels at the four gas 

plants. The mean and standard deviation of the four ratios are also 

shown in Table 6-3. 

Three model plants have been developed using the average ratios of 

components to vessels. The number of vessels in the model gas plants 

are 10, 30, and 100. This range in number of vessels is based on the 

vessel inventories shown in Table 6-2. The low end of the range, 10 

vessels, is approximately equivalent to the number of vessels that are 

accounted for in one of the three process trains at the EPA-tested 

plant A. It is assumed that there are existing gas plants with a similar 

configuration to the EPA-tested plant A, that have only one process 

train. The high end of the range, 100 vessels, is slightly larger than 

the number of vessels at the industry-tested plant C. Since this was 

the largest of the plants tested, it appears reasonable to use this as a 

guide in calculating the number of components at the largest Model 

plant. The middle-sized model plant has 30 vessels. This is approximately 

the same number of vessels as at three of the four plants tested and may 

be representative of a common gas plant size. The three model plants 

and their respective number of components are shown in Table 6-4. 

6.3 REGULATORY ALTERNATIVES 

This section presents four regulatory alternatives for controlling 

fugitive VOC emissions from natural gas/gasoline processing plants. The 

alternatives define feasible programs for achieving varying levels of 

6-2 
1. 

2. 

3. 

0"1 

I 

w 4. 

5. 

Table 6-1. EXAMPLE TYPES OF EQUIPMENT INCLUDED AND EXCLUDED IN 

VESSEL INVENTORIES FOR MODEL PLANT DEVELOPMENT 

Included Excluded 

Absorption/Desorption Units 1. Compressors, Pumps 

a. Absorbers 2. Piping Systems 

b. Scrubbers 

c. De hydra tors 

d. Stabilizer 

e. Stripper 

a. Manifold/header systems 

b. Valves, flanges, connections, etc. 

c. Meters, gauges, control equipment 

Adsorption Units 3. Glycol, lube oil, water storage 

Distillation/Fractionation Units 4. Any equipment associated with sweetening 

a. Demethanizer 

b. Deethanizer 

c. Depropanizer 

d. Splitter 

e. Flash Drum/Tank 

f. St i 11 s 

Heating/Cooling Units 

a. Heaters 

b. Chillers 

c. Heat Exchangers 

d. Reboilers 

e. Condensers 

f. Coolers 

Drums/Tanks 

a. Separator 

b. Surge 

c. Gas 

d. Oil 

e. Accumulator 

f. Knockout 
0"1 

I 

+::> 

Vessels 

Va 1 ves 

Relief valves 

Open-ended lines 

Compressor seals 

Pump seals 

Table 6-2. NUMBER OF COMPONENTS IN HYDROCARBON SERVICE AND NUMBER OF 

VESSELS AT FOUR GAS PLANTS 

EPA tested ~lantsa Industri: tested 

A B c 

31 30 90 

508c 541 3,330 

16c 11 20 

62c 64 669 

0 8 35 

lc 12 32 

Flanges and connections 1 , 530c 1,440 15,370 

aReference 3. 

bReference 4. 

~lantsb 

D 

25 

762 

7 

173 

0 

3 

3,030 

COnly two of the three adsorption units at the plant were tested and inventoried. Estimated total 

number of components is therefore based on the sum of the number of components counted in the 

larger unit plus twice the number of components counted in the smaller unit. 
"" I 

(Jl 

Table 6-3. RATIOS OF NUMBERS OF COMPONENTS TO NUMBERS OF VESSELSa 

EPA tested plants 

A B 

Valves 16.4 18.0 

Re 1 i ef va 1 ve s 0.5 0.4 

Open-ended lines 2.0 2. 1 

Compressor seals 0.0 0.3 

Pump seals 0.0 0.4 

Flanges and 49.4 48.0 

connections 

aBased on data presented in Table 6-2. 

Industry tested plants 

c D 

37.0 30.5 

0.2 0.3 

7.4 6.9 

0.4 0.0 

0.4 0.1 

170.8 121 • 2 

Average 

ratio 

25.5 

0.4 

4.6 

0.2 

0.2 

97.4 

Standard 

deviation 

of ratio 

9.9 

0.1 

3.0 

0.2 

0.2 

59.7 
Table 6-4. FUGITIVE VOC EMISSION SOURCES FOR THREE MODEL 

GAS PROCESSING PLANTS 

Number of components 

Model plant Mode 1 plant Model plant 

Component type 

Valvesa 

Relief valvesa 

Open-ended linesa 

Compressor sealsa 

Pump sea 1 sa 

Sampling connectionsb 

Liquid 

Gas 

Fl d t . a 

anges an connec 1ons 

(10 

A 

vessels) (30 

250 

4 

50 

2 

2 

2 

2 

1,000 

B c 

vessels) (100 vessels) 

750 2,500 

12 40 

150 500 

6 20 

6 20 

6 20 

6 20 

3,000 10,000 

aNumber of components based on average ratios presented in Table 6-3. 

bBased on one liquid connection at each pump and one gas connection at 

each compressor. 

6-6 
emission reduction. The first alternative represents a baseline level 

of fugitive emissions in which case the impact analysis is based on no 

additional controls. The remaining regulatory alternatives require 

increasingly restrictive controls comprised of the techniques discussed 

in Chapter 4. Table 6-5 summarizes the requirements of the regulatory 

alternatives. 

6.3.1 Regulatory Alternative I 

Regulatory Alternative I reflects normal existing gas plant operations 

with no additional regulatory requirements. This baseline regulatory 

alternative provides the basis for incremental comparison of the impacts 

of the other regulatory alternatives. 

6.3.2 Regulatory Alternative II 

Regulatory Alternative II provides a higher level of emission 

control than the baseline alternative through leak detection and repair 

methods as well as equipment specifications. 

This regulatory alternative requires quarterly instrument monitoring 

of valves, relief valves, compressor seals, and pump seals for leaks. 

Leaks that are found to be in excess of a prescribed hydrocarbon concentration (as indicated by a hydrocarbon detection instrument) would be 

repaired within a prescribed time period. Pump seals would additionally 

receive weekly visual inspections for leaks. Leaks found to be in 

excess of the prescribed concentration would be repaired within the 

prescribed time period. 

The regulatory alternative also requires that caps (including 

plugs, flanges, or second valves) be installed on open-ended lines. 

6.3.3 Regulatory Alternative III 

Regulatory Alternative III achieves a greater emission reduction 

than Alternative II by requiring monthly instrument monitoring of valves, 

relief valves, and pump seals. If a particular valve is found not to be 

leaking for 3 successive months, then 2 months may be skipped before the 

next time it is monitored with an instrument. A compressor vent control 

system would be installed to control compressor seal emissions. Sampling 

connections would be equipped with a closed purge sampling system. 

Other requirements (caps on open-ended lines, weekly inspection of 

pumps) remain the same as Alternative II. 

6-7 
Table 6-5. FUGITIVE VOC REGULATORY ALTERNATIVE CONTROL SPECIFICATIONS 

Regulatory Alternative 

I I III IV 

~1on it or i ng Equipment !1on itori ng Equipment Monitoring Equipment 

Component type interval specification interval specification interval specification 

Valves baseline quarterly monthly/ monthly 

control quarterly 

(no NSPS) 

Relief valves quarterly monthly rupture disc 

Open-ended lines cap cap cap 

0) 

none closed purge closed purge 

sampling sampling ~ Sampling connections 

Compressor seals quarterl/ compressor vent compressor vent 

control control 

quarterly, b monthly, b dual seals 

weekly visual weekly visual 

Pump seals 

aQuarterly monitoring and repair is not an effective control technique for all compressors. In some instances, reduction in emissions 

from compressors through seal repair may necessitate a process unit turnaround because compressors generally are not spared. In addition, 

it may not be possible to repair a compressor seal to below a prescribed leak definition because the seals can normally operate with 

concentrations above the action level. In these instances a coo1pressor vent control system should be substituted for monitoring. 

binstrument monitoring of pumps would be supplemented with weekly visual inspections for liquid leakage. If liquid is noted to be leaking 

from the pump seal, the seal would be repaired. 
6.3.4 Regulatory Alternative IV 

Regulatory Alternative IV increases emission control by requ1r1ng 

monthly instrument monitoring of valves. Relief valves should be equipped 

with a rupture disc, and pumps are required to have dual mechanical 

seals. Other requirements are the same as Alternative III. 

6-9 
6.4 REFERENCES 

1. Cantrell, A. Worldwide Gas Processing. Oil and Gas Journal, July 

14, 1980. p. 88. Docket Reference Number 11-I-23.* 

2. Assessment of Atmospheric Emissions from Petroleum Refining, Volume 

3, Appendix B. EPA 600/2-80-075c, April 1980. Pages 266 and 280. 

Docket Reference Number II-A-8.* 

3. Hustvedt, K.C., memo to James F. Durham, Chief, Petroleum Section, 

OAQPS, U.S. EPA. Preliminary Test Data Summaries of EPA testing at 

Houston Oil and Minerals Smith Point gas plant and Amoco Production 

Hastings gas plant. March 19, 1981. Docket Reference Number 

II-B-19*. 

4. Eaton, W.S., Rockwell International, letter to D. Markwardt, OAQPS, U.S. EPA. Component Inventory Data from Two API-Tested Gas Plants. 

September 11, 1980. Docket Reference Number II-D-5.* 

5. VOC Fugitive Emissions in Petroleum Refining Industry- Background 

Information for Proposed Standards. U.S. EPA, OAQPS. April 1981. 

Docket Reference Number 11-A-10.* 

6. Eaton, W.S., et al. Fugitive Hydrocarbon Emissions from Petroleum 

Production Operations. API Publication No. 4322. March 1980. Docket 

Reference Number II-I-20, Vol. 1.1* and Docket Reference 

Number II-I-21, Vol. 1.2* 

*References can be located in Docket Number A-80-20-B at the U.S. 

Environmental Protection Agency Library, Waterside Mall, Washington, D.C. 

6-10 
7.0 ENVIRONMENTAL IMPACTS 

7.1 INTRODUCTION 

This chapter discusses the environmental impacts from implementing 

the regulatory alternatives presented in Chapter 6. The primary emphasis 

is a quantitative assessment of the fugitive emissions that would result 

from each of the alternatives. The impacts on water quality, solid 

waste, energy and other environmental concerns are also addressed. 

7.2 EMISSIONS IMPACT 

7.2.1 Emission Source Characterization 

As discussed in Chapter 6, the model plants consist of several 

types of components (e.g., valves, pumps) that comprise the major fugitive 

emission sources within natural gas/gasoline processing plants. The 

emission factors presented in Table 3-1 are characteristic of existing 

gas plant components. These emissions are referred to as 11 baseline 11 and 

represent emissions under Regulatory Alternative I. The control technology· discussed in Chapter 4 is applied in progressive increments in 

Alternatives II, III, and IV in reducing emissions below baseline levels. 

7.2.2 Development of Emission Levels 

In order to estimate the impacts of the regulatory alternatives on 

fugitive VOC emission levels, emission factors for the model plants were 

determined for each regulatory alternative. Controlled emission factors 

were developed for those component types that would be controlled by the 

implementation of a leak detection and repair program and are given in 

Table 7-1. Controlled emission factors for pressure relief valves and 

compressor seals were derived based upon the ABCD model correction 

factors and the leak detection and repair (LDAR) model as discussed in 

Chapter 4. 5 Controlled emission factors for valves and pump seals were 

derived directly from the LDAR model as described in Chapter 4 and 

Appendix E. 

7-1 
Table 7-1. CONTROLLED EMISSION FACTORS FOR VARIOUS 

INSPECTION INTERVALS 

Baseline Controlled 

Source Inspection Emission Factora Control Emission Factorb 

Type Interval (kg/day) Efficiency (kg/day) 

Valves Quarterly 0.18 (0.48) o. 77 (0.77)c 0.041 ( 0.11) 

Monthly/ 

Quarterly 0.78 (0.78) 0.041 (0.11) ~1onthly 0.84 (0.84) 0.029 (0.077) 

Relief Quarterly 0.33 (4.5) 0.63 ~0.69?d 0.12 ~ 1.4? valves Monthly 0.70 0.76 0.10 1.1 

Compressor Quarterly 1.0 (4.9) 0.82 (0.78)d 0.18 ( 1.1) 

seals 

Pump Quarterly 1.2 ( 1. 5) 0.58 (0.58)c 0.50 (0.63) 

seals Monthly 0.65 (0.65) 0.42 (0.53) 

xx = VOC emission values 

(xx) = THC emission values 

aFrom Table 3-1. 

bcontrolled emission factor= baseline emission factor x (!-control efficiency). 

cFrom Table E-1. 

dReferences 4, 5. 

7-2 
Where the regulatory alternatives require an equipment specification, 

it is assumed that there are no subsequent emissions from the controlled 

source. Table 7-2 presents the total fugitive VOC emissions from Model 

Plants A, B, and C under each regulatory alternative by component type 

and the component percent of the total emissions. Table 7-3 compares 

the control effectiveness ot Regulatory Alternatives II through IV over 

Alternative I (baseline emissions) and the incremental cost effectiveness 

between each regulatory alternative and the previous alternative. 

7.2.3 Future Impact on Fugitive VOC Emissions 

Future impacts of the regulatory alternatives were estimated for 

the 5-year period, 1983 to 1987 as shown in Table 7-4. The number of 

affected model plants (detailed in Section 9.1.2.2) projected for each 

year was multiplied by the estimated total fugitive emissions per model 

plant for each of the alternatives (from Table 7-3). 

Over the 5-year period, the total fugitive VOC emissions for new 

plants under baseline control (Regulatory Alternative I) are projected 

at 52 gigagrams. These baseline emissions may reach an additional 

19 gigagrams from existing plants through modification/reconstruction. 

Implementation of Regulatory Alternatives II through IV would reduce the 

total new plant emissions to 16, 14, and 11 gigagrams, respectively. 

Modification/reconstruction may add up to 5.6, 5.0, and 4.1 gigagrams, 

respectively, to the new plant projections. 

7.3 WATER QUALITY IMPACT 

Although fugitive emissions from gas plant equipment primarily 

impact air quality, they also adversely impact water quality. In particular, 

leaking components handling liquid hydrocarbon streams increase the 

waste load entering wastewater treatment systems. Leaks from equipment 

contribute to the waste load by entering drains via run-off. Implementation 

of Regulatory Alternatives II through IV would reduce the waste load on 

wastewater treatment systems by preventing leakage from process equipment 

from entering the wastewater system. 

7.4 SOLID WASTE IMPACT 

Solid wastes that are generated by the natural gas/gasoline processing 

industry and that are associated with the regulatory alternatives include 

replaced mechanical seals, seal packing, rupture disks, and valves. 

7-3 
Table 7-2. EMISSIONS FOR REGULATORY ALTERNATIVES (MODEL PLANT A) 

Regulatory Alternative* 

II III IV 

Baseline Percent Controlled Percent Controlled Percent Controlled Percent 

Component emissions, total emissions, total emissions, total emissions, total 

type kg/day emissions kg/day emissions kg/day emissions kg/day emissions 

Valves 45 (120) 57 (59) 10 (28) 43 ( 44) 10 ( 28) 45 (47) 7.3 (20) 40 (43) 

Relief valves 1.3 (18) 2 (9) 0.4B (5.6) 2 (9) 0.40 (4.4) 2 (7) 0.0 (0.0) 0 (0) 

Open-ended 17 (27) 22 (13) 0.0 (0.0) 0 (0) o.o (0.0) 0 (0) 0.0 (0.0) 0 (0) 

lines 

Compressor 2.0 (9.8) 3 (5) 0.36 (2.2) 2 (3) o.o (0.0) 0 (0) 0.0 (0.0) 0 (0) 

seals 

Pump seals 2.4 (3.0) 3 (1) 1.0 ( 1.3) 4 (2) 0.84 ( 1.1) 4 (2) o.o (0.0) 0 (O) '-I 

I 

~ Samplinga G .03 ( .64) <1 (<1) 0.3 ( .64) <1 (<1) 0.0 (0.0) 0 (0) 0.0 ~0.0~ 0 

connections L .17 ( .17) <1 (<1) .17 ( .17) <1 (<1) o.o (0.0) 0 (0) 0.0 0.0 0 ~g~ 

Flanges and 11 (26) 14 (13) 11 (26) 48 (41) 11 ( 26) 49 ( 44) 11 (26) 60 (57) connections 

Total 79 (205) 23 (64) 22 (60) 18 (46) 

* From Chapter 6 

xx = VOC emission values 

(xx) = THC emission values 

aG = Gas Service 

L =Liquid Service 
Table 7-2. EMISSIONS FOR REGULATORY ALTERNATIVES (MODEl PlANT B) Continued 

Regulatory Alternative* 

II III IV 

Baseline Percent Controlled Percent Controlled Percent Controlled Percent 

-Component emissions, total emissions, total emissions, total emissions, total 

type kg/day emissions kg/day emissions kg/day emissions kg/day emissions 

Valves 140 (360) 57 (59) 31 (83) 43 ( 44) 31 (83) 46 ( 47) 22 (59) 40 (43) 

Re 1 i ef va 1 ve s 4.0 (54) 2 (9) 1.4 (17) 2 (9) 1.2 {13) 2 {7) 0.0 {0.0) 0 {0) 

Open-ended 51 {80) 22 {13) 0.0 {0.0) 0 {0) 0.0 (0.0) 0 {0) 0.0 (0.0) 0 {0) lines 

Compressor seals 

6.0 (29) 3 (5) 1.1 (6.6) 2 (3) 0.0 (0.0) 0 {0) o.o (0.0) 0 (0) 

Pump seals 7.2 (9.0) 3 {1) 3.0 (3.8) 4 (2) 2.5 (3.2) 4 (2) o.o (0.0) 0 (0) ....... Sampl inga I G. .09 {1.9) <1 (<1) 0.9 {1.9) <1 ( <1) 0.0 {0.0) 0 {0) 0.0 (0.0) 0 {0) U1 connect 1 ons L. .51 .51 <1 (<1) .51 .51 <1 {<1) 0.0 (0.0) 0 (0) o.o {0.0) 0 {0) 

Flanges and 33 (78) 14 (13) 33 {78) 48 {41) 33 {78) 49 { 44) 33 {78) 60 {57) 

connections 

Total 242 (612) 71 (191) 68 ( 177) 55 (140) 

* From Chapter 6 

xx = VOC emission values 

(xx) = THC emission values 

aG = Gas Service 

L =Liquid Service 
Table 7-2. EMISSIONS FOR REGULATORY ALTERNATIVES (MODEL PLANT C) Concluded 

Regulatory Alternative 

.II III IV 

Baseline Percent Controlled Percent Controlled Percent Controlled Percent 

Component emissions, total emissions, total emissions, total emissions, total 

type kg/day emissions kg/day emissions kg/day emissions kg/day emissions 

Valves 450 (1,200) 57 (59) 100 (280) 39 (43) 100 (280) 45 (47) 73 (200) 40 (43) 

Relief valves 13 (180) 2 (9) 4.8 (56) 2 (9) 4.0 (44) 2 (7) o.o (0.0) 0 (0) 

Open-ended 

1 ines 170 (265) 22 ( 13) o.o (0.0) 0 (0) 0.0 (0.0) 0 (0) o.o (0.0) 0 (0) 

Compressor 

seals 20 (98) 3 (5) 0.36 (22) 1 (3) 0.0 (0.0) 0 (0) o.o (0.0) 0 (0) 

Pump seals 24 ( 30) 3 (1) 10 (13) 4 (2) 8.4 ( 11) 4 (2) 0.0 (0.0) 0 (0) "'-.! 

Samplinga I 

0'1 connections G. 0.3 ~6.4) <1 ~<1) 0.3 (6.4) <1 ~<1 ~ o.o ~0.0~ 0 ~g~ 0.0 ~0.0~ 0 (0) 

L. 1.7 1.7) <1 <1) 1.7 1.7 ' <1 <1 o.o 0.0 0 0.0 o.o 0 (0) Flanges and 

connections 110 (260) 14 (13) 110 (260) 43 (40) 110 (260) 49 (44) 110 (260} 60 (57} 

Total 789 (2,041) 227 (643) 220 (600) 180 (460) 

XX = VOC emission values. 

(xx) = Total hydrocarbon emission values. 

aG = Gas Service 

l =liquid Service 
....... 

I 

....... 

Table 7-3. TOTAL AND INCREMENTAL EMISSION REDUCTIONS OF THE 

REGULATORY ALTERNATIVES ON A MODEL PLANT BASIS 

Model plant emissions,a Mg/yr Percent emission reduction 

Regula tory 

a 1 ternative A B c 

I 29 (75) 88 (223) 288 (745) 

II 8.4 (23) 26 (70) 83 (235) 

III 8.0 ( 22) 25 ( 65) 80 (220) 

IV 6.6 (17) 20 (51) 66 (170) 

XX = VOC emission values. 

(xx) = Total hydrocarbon emission values. 

aFrom Table 7-2. Assume 365 days per year operation. 

bEmissions reduction from Regulatory Alternative I. 

cEmissions reduction from previous Regulatory Alternative. 

70 (68) 

73 ( 71) 

78 ( 77) 

lncrementalc 

70 (68) 

3 (3) 

5 (6) 
-....! 

I 

co 

Table 7-4. PROJECTED FUGITIVE EMISSIONS FROM AFFECTED MODEL P~ANTS AND 

REGULATORY ALTERNATIVES FOR 1983-1987 

~~~~~~!~v~o~~~~~a~isa Total fugitive emissions prsjected under 

regulatory alternative (1000 Mg/yr) 

Year A B c II III IV 

1983 0 40 0 3.5 (8.9) 1.0 (2.8~ 1.0 (2.6) 0.80 

1984 0 80 0 7.0 F·o~ (18~ 2.2 (5.6 2.0 (5.2) 1.6 4.1 

New 1985 0 120 0 11 (27 3.1 (8.4 3.0 (7.8) 2.4 (6.1) 

plants 1986 0 150 0 13 (33) 3.9 (11) 3.8 (9.8) 3.0 (7. 7) 

1987 0 180 0 16 (40) 4.7 (13) 4.5 (12) 3.6 (9.2) 

5th - year emission ( - ) 11.3 (27) 11.5 (28) 12.4 (30.8) reduction from baseline 

1983 2 3 3 1.2 (3.1) 0.34 (0.96) 0.33 (0.90) 0.27 (0.70) 

Modified/ 1984 4 6 6 2.5 (6.1) 0.69 ( 1.9) 0.67 (1.8) 0.54 (1.4) 

reconstructed 1985 6 9 9 3.7 (9.2) 1.0 (2.9) 1.0 ~2.7l 0.81 ~2.1~ plants 1986 8 12 12 4.9 ( 12) 1.4 (3.8) 1.3 3.6 1.1 2.8 

1987 10 15 15 6.2 (15) 1.7 (4.8) 1.7 (4.5) 1.4 (3.5) 

5th - year emission ( - ) 4.5 (10.2) 4.5 (10.5) 4.8 (11.5) reduction from baseline 

xx = VOC emission values. 

(xx) = Total hydrocarbon emission values. 

aThe number of affected model plants projected through 1987 distinguish between new plant construction and 

modification/reconstruction. Plants in existence prior to 1983 are otherwise excluded. A discussion of 

the growth projections is in Section 9.1.2.2. 

bThe total fugitive emissions from Model Plants A, B, and C are derived from the emissions per model plant 

in Table 7-3. The sum of emissions in any one year is the sum of the products of the number of affected 

facilities per model plant times the emissions per model plant. 
Implementation of Regulatory Alternatives II through IV would increase 

solid waste whenever equipment specifications require the replacement of 

existing equipment. 

Implementation of Alternatives II through IV, however, would have 

an insignificant impact beyond existing levels {Regulatory Alternative I). 

This is because most gas plant solid waste is unrelated to the regulatory 

alternatives. These sources of solid waste include separator and tank 

sludges, filter cakes, and slop oil. Also, metal solid wastes {e.g., 

mechanical seals, rupture disks, caps, plugs, and valve parts) could be 

recycled and thus minimize any impact on solid waste. 

7.5 ENERGY IMPACTS 

Implementation of Regulatory Alternatives ~I through IV results in 

a net positive energy impact. The energy savings from the 11 recovered 11 

emissions far outweigh the energy requirements of the alternatives. The 

regulatory alternatives would require a minimal increase in energy 

consumption due to: operation of monitoring instruments; installation 

of dual mechanical seals, which require a minimal increase in energy 

over single mechanical seals because of seal/shaft friction and operation 

of fluid flush system; operation of the compressor vent control system; 

closed loop sampling; and operation of combustion devices. 

The energy savings over a 5-year period from new plants alone is 

estimated at 4,600 terajoules (Regulatory Alternative II) up to 4,900 

terajoules {Regulatory Alternative IV) as shown in Table 7-5. Hodified/ 

reconstructed units may represent an additional 1,600 and 1,8.00 terajoules, respectively. Table 7-5 also shows the energy savings in crude 

oil equivalents. 

7.6 OTHER ENVIRONMENTAL CONCERNS 

7.6.1 Irreversible and Irretrievable Commitment of Resources 

Implementation of any of the regulatory alternatives is not expected 

to result in any irreversible or irretrievable commitment of resources. 

Rather, implementation of Alternatives II through IV would save resources 

due to the energy savings associated with the reductions in emissions. 

As previously noted, the generation of solid waste used in the control 

equipment will not be significant. 

7-9 
-.....! 

I 

0 

New 

plants 

t·1od if i ed I 

reconstructed 

plants 

Table 7-5. ENERGY IMPACTS OF EMISSION REDUCTIONS FOR 

REGULATORY ALTERNATIVES FOR 1983-1987 

Five-year total Energy value of 

Regula tory recovered emissions recovered emissigns 

alternative from baseline (1000 ttg)a (terajoules) ' 

I I 36 (88) 4,600 

III 37 (85) 4,400 

IV 40 (94) 4,900 

II 13 (31) 1,600 

III 13 (31) 1,600 

IV 14 (34) 1,800 

xx = VOC emission values. 

(xx) = Total hydrocarbon emission values. 

Crude oil equivalent 

of recovered emiasions 

(1000 bbl) 

750 

720 

800 

260 

260 

290 

aEstimated total fugitive emission reduction from t1odel Plants A, B, and C, from Table 7-4. Numbers are 

corrected to account for emissions not recovered due to venting of compressors to flares or heater fuel 

line in Regulatory Alternatives III and IV. 

bCalculated on the basis of 47 terajoules per gigagram of VOC. Heating value is assumed to be equal to 

that of natural gas plant liquid production for 1978-1980 of 3,925,000 Btu/bbl (4.14 gigajoules/bbl ), 

Reference 3. Specific gravity assumed to be 0.55, Reference 1. 

cCalculated on the basis of 55 terajoules per gigagram of methane-ethane. Composition is assumed to be 

80 percent methane and 20 percent ethane. The heats of combustion are assumed to be 23,000 Btu/lb and 

22,300 Btu/lb for methane and ethane, respectively, Reference 2. 

dCa1cu1ated on the basis of 163 bbl crude per terajoule. Heating value is assumed to be equal to that of 

crude petroleum production for 1978-1980 of 5,800,000 Btu/bbl, Reference 3. 
7.6.2 Environmental Impact of Delayed Regulatory Action 

As discussed in the above sections, implementation of the regulatory 

alternatives will not significantly impact water quality or solid waste. 

However, a delay in regulatory action would adversely impact air quality 

at the rate shown in Table 7-4. 

7-11 
7.7 REFERENCES 

1. Nelson, W. L. Petroleum Refinery Engineering. ~1cGraw-Hill Book 

Company, Inc. New York, 1958. p. 32. Docket Reference 

Number I l-l-1. * 

2. Perry, R. H., and C. H. Chilton, eds. Chemical Engineers' Handbook, 

Fifth Edition. McGraw-Hill Book Company, New York. 1973. 

p. 9-16. Docket Reference Number II-I-7.* 

3. DOE t~onthly Energy Review. January 1981. OOE/EIA-0035 (81/01). 

Docket Reference Number II-I-26.* 

4. Memorandum, T.W. Rhoads, PES to Docket A-80-20-B. Evaluation of 

the Effects of Leak Detection and Repair on Fugitive Emissions in 

the Onshore Natural Gas Processing Industry Using the LDAR ~1odel, 

November 1, 1982. Docket Reference Number II-B-18.* 

5. Memorandum T.W. Rhoads, PES to Docket A-80-20-B. Calculation of 

Controlled Emission Factors for Pressure Relief Valves and 

Compressor Seals. November 1, 1982. Docket Reference 

Number II-B-17.* 

*References can be located in Docket Number A-80-20-B at U.S. Environmental 

Protection Agency Library, Waterside t·1all, Washingto11, D.C. 

7-12 
8. COST ANALYSIS 

8.1 COST ANALYSIS OF REGULATORY ALTERNATIVES 

8.1.1 Introduction 

The following sections present estimates of the capital costs, 

annual costs, and cost effectiveness for each model plant and regulatory alternative discussed in Chapter 6. These estimates will then be 

used in Chapter 9 to estimate the economic impact of the regulatory 

alternatives upon the natural gas/gasoline processing industry. To 

ensure a common cost basis, Chemical Engineering cost indices were 

used to adjust control equipment to June 1980 dollars. 

8.1.2 New Facilities 

8.1.2.1 Capital Costs. The bases for the capital costs for 

monitoring instruments and control equipment are presented in Table 8-1. 

These data are used to tabulate the capital costs for each ~odel plant 

under the regulatory alternatives as given in Table 8-2. 

Regulatory Alternative I requires no additional controls and 

therefore incurs no capital costs. Under Regulatory Alternatives II 

through IV, caps for open-ended lines and two monitoring instruments 

would be purchased. Although only one instrument is required, it is 

assumed that plant operators will purchase a spare in the event that 

the first becomes inoperable. There are no other capital costs associated 

with Alternative II. 

Regulatory Alternative lii also includes the cost of a compressor 

vent control system and closed-loop sampling connections. As shown in 

Figure 4-2, the compressor vent control system capital costs for 

reciprocating seals include venting the seal and distance piece emissions 

to either a flare or the plant heater as fuel gas. For centrifugal 

seals, the compressor vent control system capital costs include capturing 

the seal emissions from the seal degassing vent and similarly destroying 

8-1 
Table 8-1. CAPITAL COST DATA (June 1980 dollars) 

1. Monitoring Instruments 

2 instruments (Foxbgro OVA-108) 

@ $4,600/instrument 

Total cost is $9,200/plant 

2. Caps for Open-Ended Lines 

Based on cost for 5.1 em screw-on gate valve, rated at 17.6 kg/cm2 

(250 psi) water, oil, gas (w.o.gt) pressure. June 1981 cost is $46.50b, 

June 1980 cost is~ percent less at $43. Retrofit installation= 

1 hour at $18/hour • Total cost is $61/line. 

3. Compressor Seal Vent Control System 

A. Vent Manifold Pipinge 

2m 30cm pipe @ $108.00/m 

100m 5.1cm pipe@ $6.50/m 

2 30 em blind flanges @ $50 

Total vent manifold and trap piping 

Labo/ 

= 3.4 hr for installation 

$ 216.00 

650.00 

100.00 

102m of pipe 

30m/hr/crew 2.5 hr for set-up/breakdown 

5.0 hr for fabrication 

10.9 hours/crew 

10.9 crew hrs. x 3 men x $18.00/hr = 

crew 

total labor 

total dollars 

B. Reciprocating Compressor Seal Pipinge 

1 double distance piece 

15m 2.5cm pipe @ $2.82/m 

5m 5.lcm pipe @ $6.50/m 

1 2.5cm tee @ $7.30 

2 5.1cm x 2.5cm tees @ $8.16 

3 2.5cm block valves @ $24.63 

1 2.5cm check valve @ $80.40 

3 2.5cm elbows @ $6.22 . 1 pressure alarm @ $9.901 

Total manifold piping 

8-2 

$ 2 ,ooo. ooj 

42.30 

32.50 

7.30 

16.32 

73.89 

80.40 

18.66 

_9.90 

$ 966 

$ 589 

$ 1,555 

$ 2,281 
Table 8-1. CAPITAL COST DATA (June 1980 dollars) 

(continued) 

Labo/ 

2<MI of pipe 

30m/hr/crew 

= 1 hr for installation 

0.75 hr for set-up/breakdown 

1.5 hr for fabrication 

3. 25 hr/crew 

3.25 crew hrs. x ~r~:n x $18.00/hr = 

C. Centrifugal Compressor Seal Pipinge 

5m 2.5cm pipe @$2.82/m $ 

5m 5.1cm pipe @ $6.50/m 

1 5.1cm x 2.5cm tees@ $8.16 

1 2.5cm block valves @ $24.63 

1 2.5cm elbows @ $6.22 . 1 pressure alarm @ 9.901 

Total manifold piping 

Laborf 

total labor 

total dollars 

14.10 

32.50 

8.16 

24.63 

6.22 

9.90 

10m of pipe 

30m/hr/crew 

= 0.33 hr for installation 

0.25 hr for set-up/breakdown 

0.5 hr for fabrication 

1.08 hours/crew 

1.08 crew hrs. x 

3 men x $18 00/hr = 

crew • 

D. Gas Supply System Costs 

Parts 

5m 2.5 em pipe @ $2.82/m $ 

2 2.5 em back valves @ $t4.63 

1 pressure alarm @ $9.90 . 1 gas shutoff valve @ $23.89 1 

Total Parts 

Labor @ 100% Parts Pricek 

8-3 

total dollars 

14.10 

49.26 

9.90 

23.89 

total dollars 

$ 176 

$ 96 

$ 58 

$ 97.15 

97.15 

$ 2,456 

$ 154 

$ 194 
Table 8-1. CAPITAL COST DATA {June 1980 dollars) 

{continued) 

4. Closed-purge Sampling Connectionsg 

5. 

Based on 6 m length of 2.5 on schedule 40 carbon steel pipe, and three 

2.5 em ball valves. Retrofit or new installation= 18 hours at $18/hour. 

Total cost is $530/sampling connection. 

Rupture Disk System with Block Valveg 

New Installation 

Ru~ture Disk Assembll 

7.6 em rupture disk {stainless) = 

7.6 em rupture disk holder 

(carbon steel) = 

0.6 em pressure gauge = 

0.6 em bleed gate valve = 

Subtotal 

U~stream Block Valve 

7.6 em gate valve = 

Offset Mounting 

10.2 em tee, elbow = 

Installation 

rupture disk assembly, 16 hrs @ $18/hr 

upstream block valve, 10 hrs @ $18/hr 

offset mounting, 8 hrs @ $18/hr 

Subtotal 

Total 

8-4 

$ 230 

384 

18 

30 

= $248 

= 180 

= 144 

$ 662 

$ 700 

$ 21 

$ 1,995 
Table 8-1. CAPITAL COST DATA (June 1980 dollars) 

(continued) 

8-5 
Table 8-1. CAPITAL COST DATA (June 1980 dollars) 

(concluded) 

$ 4,000 

Total -new installation 

Total retrofit installation 

aOne instrument used as a spare. Cost is based on Reference 1. 

bReference 2. 

$ 7,100 

$ 7,388 

cCost adjustment based on the economic indicators for pipe, valves, and 

fittings in April 1980 (final) vs. April 1981 (preliminary). Reference 3. 

dReference 4. 

eReference 5. 

fReference 18. 

9Reference 7. 

hReference 8. 

;Reference 6. 

jReference 16. 

kEngineering estimate. 

8-6 
Table 8-2. CAPITAL COST ESTIMATES FOR MODEL PLANTS 

(thousands of June 1980 dollars) 

Regulatory Alternative 

Capital cost item 

Model Plant A 

1. Monitoring instrument 

2. Caps for open-ended 

lines 

3. Compre~sor vent control 

system 

4. Closed-loop sampling 

connections 

5. Rupture disk systeme 

6. Dual mechanical seals 

Total 

9.2 

3.1 

12 

9.2 

3.1 

5.9 

2.1 

20 

9.2 

3.1 

5.9 

2.1 

12 

14 

46 

aCosts are the same for new or retrofit installation. 

bNew installation costs. 

cRetrofit installation costs. 

9.2 

3.1 

5.9 

2.1 

17 

15 

52 

dCosts based on installed compressor seal vent control system for 

50 percent reciprocating and 50 percent centrifugal compressors. 

eCosts based on 50% rupture disk systems with block valve and 

50% rupture disk systems with 3-way valve. 

8-7 
Table 8-2. CAPITAL COST ESTH1ATES FOR t10DEL PLANTS 

(thousands of June 1980 dollars) 

(Continued) 

Regulatory Alternative 

Capital cost item 

Model Plant B 

1. Monitoring instrument 

2. Caps for open-ended 

1 ines 

3. Compreasor vent control 

system 

4. Closed-loop sampling 

connections 

5. Rupture disk systeme 

6. Dual mechanical seals 

Total 

9.2 

9.2 

18 

9.2 

9.2 

11.1 

6.4 

36 

9.2 

9.2 

11.1 

6.4 

37 

43 

116 

aCosts are the same for new or retrofit installation. 

bNew installation costs. 

cRetrofit installation costs. 

9.2 

9.2 

11.1 

6.4 

51 

44 

131 

dCosts based on installed compressor seal vent control system for 

50 percent reciprocating and 50 percent centrifugal compressors. 

eCosts based on 50% rupture disk systems with block valve and 50/~ rupture disk systems with 3-way valve. 

8-8 
Table 8-2. CAPITAL COST ESTIMATES FOR MODEL PLANTS 

(thousands of June 1980 dollars) 

(Concluded) 

Regulatory Alternative 

Capital cost item 

Model Plant C 

1. t·1oni tori ng instrument 

2. Caps for open-ended 

lines 

3. Compre~sor vent control 

system 

4. Closed-loop sampling 

connections 

5. Rupture disk sys teme 

6. Dual mechanical seals 

Total 

9.2 

31 

40 

9.2 

31 

29 

21 

90 

9.2 

31 

29 

21 

9.2 

31 

29 

21 

120 170 

140 150 

350 410 

aCosts are the same for new or retrofit installation. 

bNew installation costs. 

cRetrofit installation costs. 

dcosts based on installed compressor seal vent control system for 

50 percent reciprocating and 50 percent centrifugal compressors. 

eCosts based on 50 percent rupture disk systems with block valve and 

50 percent rupture disk systems with 3-way ·valve. 

8-9 
the emissions. Table 8-1 shows the installed capital costs for the 

vent system piping arrangements. The model plant capital costs reported 

in Table 8-2 are based on the model unit number of compressors with 

50 percent reciprocating and 50 percent centrifugal compressor seals. 

The costs given in Table 8-2 reflect two vent manifold systems and 

one gas supply system for each plant, in addition to the required 

number of centrifugal and reciprocating seal piping systems. 

Alternative IV includes all the costs of Alternative III plus the 

costs of a rupture disk for pressure system relief valves and dual 

mechanical seals for pumps. The costs of Regulatory Alternative IV 

are different for new installation of equipment and for retrofit 

installations. 

8.1.2.2 Annual Costs. Implementation of Regulatory Alternatives II 

through IV would require visual and/or instrument monitoring of potential 

VOC emissions. The inspection requirements are given in Chapter 6. 

Table 8-3 summarizes the leak detection and repair labor-hour requirements, 

and Table 8-4 shows the annual costs for the alternatives by model 

plant. These repair costs cover the expense of repairing those components 

in which leaks develop after initial repair. The cost for leak detection 

and repair labor was assumed to be $18.00 per hour. 

Administrative and support costs were estimated at 40 percent of 

the sum of leak detection and repair labor costs. Leak detection 

labor, leak repair labor, and administrative/support costs are recurring 

annual costs for each regulatory alternative. 

8.1.2.3 Annualized Costs. The bases for the annualized control 

costs are presented in Table 8-5. The annualized capital, maintenance, 

and miscellaneous costs were calculated by taking the appropriate 

factor from Table 8-5 and applying it to the corresponding capital 

cost from Table 8-2. The capital recovery factors were calculated 

using the equation: 

CRF = ~1 + i)n 

(1 + i)n- 1 

Where =interest rate, expressed as a decimal, 

n = economic life of the component, years. 

The interest rate used was 10 percent. The expected life of the 

monitoring instrument was 6 years. Dual mechanical seals and rupture 

8-10 
co 

I 

,__. 

,__. 

Component 

type 

Valves 

Monitoring 

interval 

quarterly 

monthly/ 

quarterly 

monthly 

Relief valves quarterly 

monthly 

Conpressor seals 

quarterly 

TABLE 8-3. LEAK DETECTION AND REPAIR LABOR-HOUR REQUIREMENTS 

Components per 

model plant 

A 8 C 

250 750 2,500 

4 12 40 

instr1.111ent 

instrument 

instrument 

instrument 

instriJIIent 

20 instrument 

Leak detection 

Times 

monitored 

per year 

4.0h,g 

4.3h,g 

11.9h,g 

4 

12 

Monitoring 

labor-h~~ 

required • A 8 

33 100 

36 108 

99 298 

4.3 13 

13 38 

1.3 4.0 

c 

333 

358 

992 

43 

130 

13 

Fraction of sources 

maintained 

0.185g 

0.187g 

0.191g 

o.ose 

O.lle 

0.17e 

Leak repair 

Estimated 

number of 

1 eaks per year A B C 

46 139 464 

47 140 467 

48 143 478 

0.3 1.3 3.2 

0.4 1.3 4.4 

0.3 1.0 3.4 

Repair time 

per source 

(hours) 

Ha i ntenancef 

1 abor-hours 

A B C 

52 

53 

54 

0 

0 

12 

157 524 

158 528 

162 540 

0 

0 

0 

0 

40 136 

Pump seals quarterly 

monthly 

weekly 

2 

2 

6 

6 20 instrument 

ins tr1.111ent 

visual 

1.3 4.0 13 

4.0 12 40 

0.394g 0.79 2.4 

0.408g 0.82 2.5 

7.9 

8.2 

12.6 

13.1 

38 126 

40 131 

0.9 2.6 8.7 

aAssumes that instrument monitoring requires a two-person team, and visual monitoring, one person. 

bMonitoring 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. 

cl·lonitoring labor-hours = niJIIber of workers x number of components x time to monitor x times monitored per year. 

dBased on the number of sources leaking at 10,000 ppmv. From Table 4-1. 

eAnnual percent recurrence factors have been applied for monthly and quarterly instrument inspections for relief valves and compressor seals to 

determine the percentage of sources maintained. It is assumed that 5 percent of leaks initially detected are found with monthly monitoring (0.05 x 12 

= 0.6) and that 10 percent of leaks initially detected are found with quarterly monitoring (0.1 x 4 = 0.4). Fraction of sources initially leaking fran 

Table 4-1. Number of leaks = number of components x fraction of sources initially leaking x annual fraction of recurrence factor. Reference 7. 

fLeak repair labor-hours = number of leaks x repair time. 

gThe values used in calculatin~ labor-hour requirements for valves and pump seals were developed on the basis of the model and data presented in 

Appendix E. 

hFractional numbers accounted for by recognizing that it is not necessary to monitor valves that have previously been identified as leakers 

and have not yet been repaired. 

iWeighted average based on 75 percent of the leaks repaired on-line, requiring 0.17 hours per repair, and on 25 percent of the leaks, repaired offline, 

requiring 4 hours per repair. Reference 9. 

jlt is assumed that these leaks are corrected by routine maintenance at no additional labor requirements. Reference 10. 

kReferences 10 and 17. 
Table 8-4. ANNUAL LEAK DETECTION AND REPAIR LABOR COSTSa 

(June 1980 dollars) 

Leak detection cost Repair cost 

model plant model plant 

Regul atoryb alternative A B c A B 

IIC 730 2,200 7,400 1,400 4,300 

IIId 970 2,900 9,700 1,200 3,600 

IVe 1,800 5,400 18,000 970 2,900 

aCosts = labor-hours (Table 8-3) x $18/hour (Table 8-5). 

bRegulatory Alternative I (baseline control) has zero costs. 

cCalculated on the basis of quarterly instrument monitoring for 

valves, relief valves, compressor seals, and pump seals, and 

weekly visual monitoring for pump seals. 

dCalculated on the basis of monthly/quarterly instrument 

monitoring for valves, monthly instrument monitoring for 

relief valves and pump seals, and weekly visuaJ monitoring 

for pump seals. 

eCalculated on the basis of monthly monitoring of valves. 

8-12 

c 

14,000 

12,000 

9,700 
disks were assumed to have a 2-year life. All other control equipment 

is assumed to have a 10-year life. 

For the purposes of determining recovery credits, the value of 

VOC is assumed to be $192/Mg, and the value of methane-ethane is 

assumed to be $61/Mg. The derivation of these values is described in 

Table 8-5. Although compressor emissions can be routed to the process 

heater, resulting in a fuel savings, no credit is taken because most 

plants are likely to combust these organics in a flare. 

Implementation of Regulatory Alternatives II, III, and IV involves 

initial detection and repair of leaking components. As shown in 

Table 8-6, the repair labor-hour requirements of the initial survey 

are derived by multiplying the fraction of sources leaking and repair 

time per source by the model plant component counts. The cost of 

repairing initial leaks was amortized over a 10-year period, since 

this is a one-time cost. Administrative and support costs to implement 

the regulatory alternatives were assumed to be 40 percent of the leak 

detection and repair labor costs. Table 8-7 shows the initial leak 

repair costs. These costs include the labor costs from Table 8-6, and 

replacement mechanical pump seals. The initial leak repair cost in 

Table 8-7 shows Alternative II to be the most costly. Costs decrease 

for the other alternatives as equipment specifications replace the 

labor intensive equipment repairs. 

8.1.2.4 Recovery Credits. The annual emissions, total emissions 

recovered, and annual recovered product credits for each model plant 

and regulatory alternative appear in Table 8-8. Regulatory Alternative I 

represents 11 baseline emissions" and therefore receives no recovery 

credits. 

8.1.2.5 Net Annual Costs. The net annual model plant costs 

shown in Tables 8-9, 8-10, and 8-11 were determined by subtracting the 

annual recovered product credit fr~n the total cost before credit. 

For example, Model Plant A under Regulatory Alternative II has a net 

annual cost of $3,800, as a result of $9,700 in costs and $5,900 in 

recovery credits. 

8.1.2.6 Cost Effectiveness. The cost effectiveness of the 

regulatory alternatives for each model plant is shown in Table 8-12. 

Regulatory Alternatives II and III for all model plants entail 

8-13 
Table 8-5. DERIVATIOU OF ANNUALIZED LABOR, 

ADMINISTRATIVE, MAINTENANCE, AND CAPITAL COSTS 

1. Capital recovery factor for capital costs 

o Dual mechanical seals and rupture disks 

o Other control equipment 

o Monitoring instruments 

2. Annual maintenance costs 

o Control equipment 

o Monitoring 1nstruments 

o Replacement pump seals 

3. Annual miscellaneous costs 

4. Labor costs 

5. Administrative and support costs to 

implement regulatory alterRative 

6. Annualized charge for initial leak repairs 

7. Recovery credits 

o Nonmethane-nonethane hydrocarbons (VOC) 

o Methane-ethane 

0.58 x capitala 

0.163 x capitalb 

0.23 x capitalc 

0.05 x capitald 

$3,000e 

$140m 

0.04 x capitalf 

$18/hrg 

0.40 x (monitoringdlabor + 

maintenance labor) 

(estimated number of leak1ng 

components per model Hnit x repair time) x $18/hr x 1.4 

X 0.163 

$192/Mg~ $ 61/Mg 

aAppl1es to cost of seals ($972-incremental cost due to specification of dual 

seals instead of single seals) and disk ($230) only. Two year life, ten 

percent interest. Reference 7. 

bTen year life, ten percent interest. Reference 11. 

cSix year life, ten percent interest. Reference 11. 

dFrom Reference 11. 

eincludes materials and labor for ma1ntenance and calibration. 

fReference 11. 

9rncludes wages plus 40 percent for labor-related administrative and overhead 

costs. Reference 11. 

hFrom Reference 4. 

1

shown in Table 8-3. 

jinitial leak repair amortized for ten years at ten percent interest. 

ksased on LPG price of 40¢/gallon for June 1980 (Reference 13) and specific 

gravity of 0.55 (Reference 14). 

1sased on natural gas price of $1.46/Mcf for June 1980 (Reference 15) and 

assumed composition of 80% methane and 20% ethane at standard temperature 

and pressure. 

mReference 17, corrected to June 1980. 

8-14 
TABLE 8-6. LABOR-HOUR REQUIREMENTS FOR INITIAL LEAK REPAIR 

Percent of 

Nufllber of components sources Estimated Repair tims 

2er model 21 ant leaking in Number of leaks per source Re[!air labor-hours 

Component type A B c Initial surveya A B c (hours) A B c 

Valves 250 750 2,500 18 45 135 450 1.13 51 153 509 

Relief valves 4 12 40 19 0.76 2.3 7.6 0 0 0 (l 

Compressor seals 2 6 20 43 0.86 2.6 8.6 40 34 104 344 

Pul'lp seals 2 6 20 33 0.66 2.0 6.6 16 11 32 106 

C» aBased on the number of sources 1 eaki ng at 10,000 ppm from Table 4-1. I 

bsee Table 8-3 . ...... 

Ul 
Table 8-7. INITIAL LEAK REPAIR COSTS (JUNE 1980 DOLLARS) 

Initial repair co5ts Annualized initial repair 

for model plants costs for model plantsc 

Regula tory a 

alternative A B c A B c 

II 2,400 7,300 24,000 390 1,200 4,000 

III 1,600 4,700 16,000 260 770 2,500 

IV 1,300 3,900 13,000 210 640 2,100 

aRegulatory Alternative I (baseline control) has zero costs. 

bCosts = labor-hours (Table 8-6) x $18/hour (Table 8-5) x 1.4 (Administrative 

costs, Table 8-5) + new seal costs for pumps. 

cAnnualized cost= Initial Repair Costs x 0.163 (capital 

recovery factor, Table 8-5). 

8-16 
Table 8-8. RECOVERY CREDITS 

Model Plant A ~1ode 1 Plant B Model Plant C 

Recovered Recovered Recovered 

Recovered product Recovered product Re~ov~red a product Regulatory emissions,a value,b emissions,a value,b em1ss1ons, value,b 

alternative Mg/yr $/yr Mg/yr $/yr Mg/yr $/yr 

II 20.6 (52) 5,870 62 (113) 15,000 205 (510) 58,000 

III 20.3 ( 49) 5,650 61 (147) 17,000 201 (489) 56,200 

IV 22 (54) 6,180 66 {161) 18,500 215 ( 539) 61,000 

XX = voc emission values. 

(xx) = Total hydrocarbon emission values. 

aBased on emission reductions presented in Table 7-2 and 7-3. 

bBased on recovered VOC value of $192/Ng, and recovered non-VOC hydrocarbon (methane-ethane) value of 

$61/Mg from Table 8-5. No recovery credits are given for compressors. Compressor seal vent emissions could 

be used as process heater fuel resulting in recovery of these emissions at their fuel value. 

Example Calculation for ~lodel Plant A, Regulatory Alternative IV: 

Recovered Product Value ($/yr) = (22 t1g/yr VOC) ($192/tlg VOC) + (54 Mg/yr THC - 22 Mg/yr VOC) ($61/~1g 

c1, c2) = $6, 180 
Table 8-9. ANNUAL COST ESTIMATES FOR MODEL PLANT A 

(Thousands of Jane 1980 Dollars)-

Regulatory Alternative 

Cost Item 

Annualized Capital Costs 

A. Control equipmentd 

1. Monitor1ng instruments 

2. Caps for open-ended lines 

3. Compressor vent control system 

4. Closed-loop sampling connections 

5. Rupture disk system 

6. Dual mechanical seal system 

B. Initial leak repaire 

Operating Costs 

A. Maintenance costsf 

1. Monitoring instruments 

2. Caps for open-ended lines 

3. Compressor vent control system 

4. Closed-loop sampling connections 

5. Rupture disk system 

6. Dual mechanical seals 

7. Replacement seal system 

B. Miscellaneous costsf 

1. Monitoring instruments 

2. Caps for open-ended lines 

3. Compressor vent control system 

4. Closed-loop sampling connections 

5. Rupture disk system 

6. Dual mechanical seal system 

C. Labor charges 

1. Monitoring labor9 

2. Leak repair labor9 

3. Administrative and supportf 

Total Before Credit 

Recovery Credits h 

Net Annual Cost 

2.1 

0.51 

0.39 

3.0 

0.16 

0.11 

0.37 

0.12 

0.73 

1.4 

0.85 

9.7 

(5.9) 

3.8 

2.1 

0.51 

0.96 

0.34 

0.26 

3.0 

0.16 

0.30 

0.10 

0.11 

0.37 

0.12 

0.24 

0.08 

0.97 

1.2 

0.87 

12 

(5. 7) 

6.3 

aCosts are the same for new or modified/reconstructed facilities ( ) • cost savings. 

beasts for new facilities. 

cCosts for modified/reconstructed facilities. 

dcapital costs from Table 8-2. Capital recovery factor from Table 8-5. 

eFrom Table 8-7. 

fFrom Table 8-5 

gFrom Table 8-4. 

hFrom Table 8-8. 

8-18 

2.1 

0.51 

0.96 

0.34 

2.4 

3.1 

0.21 

3.0 

0.16 

0.30 

0.10 

0.60 

0.71 

0.37 

0.12 

0.24 

0.08 

0.48 

0.57 

1.8 

0.97 

1.1 

20 

(6.2) 

14 

IV' 

2.1 

0.51 

0.96 

0:34 

3.1 

3.5 

0.21 

3.0 

0.16 

0.30 

0.10 

0..85 

0.74 

0.37 

0.12 

0.24 

0.08 

0.68 

0.60 

1.8 

0.97 

1.1 

22 

(6.2) 

16 
Table 8-10. ANNUAL COST ESTIMATES FOR MODEL PLANT B 

(Thousands of June 1980 Dollars) 

Regulatory Alternative 

Cost Item IIa Ilia !Vb 

Annualized Capital Costs 

A. Control equipmentd 

1. Monitoring instruments 2.1 2.1 2.1 

2. Caps for open-ended lines 1.5 1.5 1.5 

3. Compressor vent control system 1.8 1.8 

4. Closed-loop sampling connections 1.0 1.0 

5. Rupture disk system 7.1 

6. Dual mechanical seals 9.4 

B. Initial leak repaire 1.2 o. 77 0.64 

Operating Costs 

A. Maintenance costs 

1. ~~nitoring instrumentsf 3.0 3.0 3.0 

2. Caps for open-ended lines 0.46 0.46 0.46 

3. Compressor vent control system 0.55 0.55 

4. Closed-loop sampling connections 0.32 0.32 

5. Rupture disk system 1.9 

6. Dual mechanical seals 2.1 

7. Replacement pump seals 0.34 0.35 

B. Miscellaneous costsf 

1. Monitoring instruments 0.37 0.37 0.37 

2. Caps for open-ended lines 0.37 0.37 0.37 

3. Compressor vent control system 0.44 0.44 

4. Closed-loop sampling connections 0.26 0.26 

5. Rupture disk system 1.5 

6. Dual mechanical seals 1.7 

c. Labor charges 

1. Monitoring labor9 2.2 2.9 5.4 

2. Leak repair laborg 4.3 3.6 2.9 

3. Administrative and supportf 2.6 2.6 3.3 

Total Before Credit 19 22 48 

Recovery Cred1tsh {15) (17) ( 19) 

Net Annual Cost 4 5 29 

aCosts are the same for. new or modified/reconstructed facil it1es. 

bcosts for new facilities. 

cCosts for modified/reconstructed facilities. 

dcapital costs from Table 8-2. Capital recovery factor from Table 8-5. 

eFrom Table 8-7. 

fFrom Table 8-5 

gFrorn Table 8-4. 

hFrorn Table 8-8. 

8-19 

!Vc 

2.1 

1.5 

1.8 

1.0 

9.4 

10 

0.64 

3.0 

0.46 

0.55 

0.32 

2.6 

2.2 

0.37 

0.37 

0.44 

0.26 

2.0 

1.8 

5.4 

2.9 

3.3 

52 

(19) 

33 
Table 8-11. ANNUAL COST ESTIMATES FOR MODEL PLANT C 

(Thousands of June 1980 Dollars) 

Regulatory Alternative 

Cost Iten II~ Ilia IVb 

Annualized Capital Costs 

A. Control equipmentd 

1. Monitoring instruments 2.1 2.1 2.1 

2. Caps for open-ended lines 5.0 s.o 5.0 

3. Compressor vent control systen 4.7 4.7 

4. Closed-loop sampling connections 3.4 3.4 

5. Rupture ·disk systen 24 

6. Oual mechanical seals 31 

B. Initial leak repaire 4.0 2.5 2.1 

Operating Costs 

A. Maintenance costsf 

1. Monitoring instruments 3.0 3.0 3.0 

2. Caps for open-ended lines 1.5 1.5 1. 5 

3. Compressor vent control systen 1.4 1.4 

4. Closed-loop sampling connect,ons 1.0 1.0 

5. Rupture disk system 6.1 

6. Dual mechanical seals 7.1 

7. Replacenent pump seals 1.1 1.1 

B. Miscellaneous costsf 

l. Monitoring instruments 0.37 0.37 0.37 

2. Caps for open-ended lines 1.2 1.2 1.2 

3. Compressor vent control system 1.2 1.2 

4, Closed-loop sampling connections 0.84 0.84 

s. Rupture disk system 4.8 

6. Dual mechanical seals 5.7 

c. Labor charges 

1. Monitoring laborg 7.4 9.7 18 

2. Leak repair laborg 14 12 9.7 

3. Administrative and supportf 8.6 8.7 11 

Total Before Credit 48 59 145 

Recovery Creditsh (58) (56) (61) 

ttet Annual Cost .(10) 3 84 

1Costs are the same for new or modified/reconstructed flc111ties. 

bcosts for new facilities. 

ccosts for modified/reconstructed facilities. 

dcapital costs from Table 8-2. Capital recovery factor from Table 8-5. 

eFrom Table 8-7. 

fFrom Table B-5 

9From Table 8-4. 

hFrom Table 8-8. 

8-20 

lVc 

2.1 

5.0 

4.7 

3.4 

31 

35 

2.-1 

3.0 

1.5 

1.4 

1.0 

8.4 

7.4 

0.37 

1.2 

1.2 

0.84 

6.8 

6.0 

1B 

9.7 

11 

161 

(61) 

100 
Table 8-12. COST EFFECTIVENESS OF REGULATORY ALTERNATIVES 

Regulatory Alternative 

Model Plant A 

Capital Cost ($)d e 

Net annual cost ($/yr) f 

Total VOC reduction (Mg/yr) 

Cost effectiveness ($/Mg VOC)g 

Model Plant B 

I 

0 

0 

0 

0 

Capital Cost ($)d h 0 

Net annual cost ($/yr) f 0 

Total VOC reduction (Mg/yr) 0 

Cost effectiveness ($/Mg VOC)g 0 

Model Plant C 

Capital Cost ($)d i 0 

Net annual cost ($/yr) f 0 

Total VOC reduction (Mg/yr) 0 

Cost effectiveness ($/Mg VOC)g 0 

II a 

12,000 

3,800 

20.6 

180 

18,000 

4,000 

62 

65 

40,000 

(10,000) 

200 

(50) 

Ilia 

20,000 

6,300 

21.0 

300 

36,000 

5,000 

63 

79 

90,000 

3,000 

210 

14 

IVb 

46,000 

14,000 

22.4 

630 

116,000 

29,000 

68 

430 

350,000 

84,000 

220 

380 

aCosts are the same for new or modified/reconstructed facilities. 

beasts for new facilities. 

cCosts for modified/reconstructed facilities. 

dFrom Tab 1 e 8-1. 

eFrom Table 8-9. 

fFrom Table 7-3. 

IVC 

52,000 

16,000 

22.4 

710 

131 '000 

33,000 

68 

490 

410,000 

100,000 

220 

450 

9cost effectiveness = total VOC emission reduction divided by the net annual 

cost. 

hFrom Table 8-10. 

;From Table 8-11. 

8-21 
relatively low costs per r~g of VOC emission reduction when compared to 

Alternative IV. Model Plant B Regulatory Alternative II and t1odel 

Plant C Regulatory Alternatives II and III have a net annual credit. 

8.1.3 Modified/Reconstructed Facilities 

8.1.3.1 Capital Costs. The bases for determining the capital 

costs for modified/reconstructed facilities are presented in Table 8-1. 

The capital cost for Alternatives I, II, and III are the same as for 

new plants. However, the capital cost for Regulatory Alternative IV 

is higher than for new plants. This is because of the additional 

costs incurred through replacement of relief valves, and retrofit 

installation of dual mechanical seals. 

8.1.3.2 Annual Costs. The annual control costs for modified/ 

reconstructed plants are derived from the same basis as new plants 

(see Table 8-5). The net annual costs for modified/reconstructed 

facilities are higher than for new facilities under Regulatory 

Alternative IV (I, II, and III are the same as new facilities), as 

shown in Tables 8-9, 8-10, and 8-11. The recovery credits remain the 

same as for new plants. 

8.1.3.3 Cost Effectiveness. The cost effectiveness of Regulatory 

Alternative IV for modified/reconstructed facilities is also shown in 

Table 8-12. The cost effectiveness of this Alternative is substantially 

higher than for new facilities. 

8.1.4 Projected Cost Impacts 

The projected fifth year industry wide costs of implementing the 

regulatory alternatives are presented in Table 8-13. The cost estimates 

were obtained by multiplying the costs per model plant by the model 

plant growth estimates given in Table 7-4 for 1983 to 1987. The cost 

impacts for new plants and modified/reconstructed plants are reported 

separately in order to differentiate between expected ;~pacts, represented 

by new plants, and maximum impacts, represented by new plants with the 

addition of modified/ reconstructed plant impacts. A maximum impact 

would result if all chanyes to existing plants constitute modification/ 

reconstruction. The total capital costs reflect the cumulative costs 

of implementing the regulatory alternatives in a given year. All 

other costs shown are for plants subject to new source performance 

standards in the indicated year. 

8-22 
co 

I 

N 

w 

Table 8-13. FIFTH-YEAR NATIONWIDE COSTS OF THE REGULATORY ALTERNATIVES 

(thousands of June 1980 dollars) 

Cost item II III 

New plantsa 

Cumulative capital costs by 1987 3,200 6,500 

Total annual costs 3,400 4,000 

Total recovery credit 2,700 3,100 

Net annual costs 700 900 

Modified/reconstructed facil iti esa 

Cumulative capital costs by 1987 990 2,100 

Total annual costs 1,100 1,300 

Total recovery credits 1,200 1,200 

t~et annual costs (100) 100 

( ) = cost savings 

IV 

21,000 

9,700 

3,400 

6,300 

8,600 

4,200 

1,300 

2,900 

aA schedule of projected new and modified/reconstructed model plants is presented 

in Table 7-4. 
L.2 OTHER COST CONSIDERATIONS 

Environmental, safety, and health statutes that may cause an 

outlay of funds by the gas processing industry are listed in Table 8-14. 

Specific costs to the industry to comply with the provisions, requirements, 

and regulations of the statutes are unavailable. 

8-24 
()) 

I 

N 

en 

Table 8-H STATUTES THAT MAY BE APPLICABLE TO THE NATURAL GAS PROCESSING INDUSTRY 

Applicable provision, regulation or Statute requirement of statute 

Clean Air Act and Admendments o State implementation plans 

Clean Water Act (Federal 

Water Pollution Act) 

Resource Conservation and 

Recovery Act 

Toxic Substances Control 

Act 

o National emission standards for 

hazardous air pollutants 

o New source performance standards 

o PSO construction permits 

o Nonattainment construction pennits 

o Oi scharge penni ts 

o Effluent limitations guidelines 

o Hew source performance standard~ 

o Control of oil spills and discharges 

o Pretreatment requirements 

o Monitoring and reporting 

o Permitting of Industrial projects 

that impinge on wetlands or public-waters 

o Env i ronmenta 1 impact statements 

o Permits for treatment, storage, and 

disposal of hazardous wastes 

o Establishes system to track 

hazardous wastes 

o Establishes recordkeeping, reporting, 

labeling, and monitoring system 

for hazardous waste 

o Superfund 

o Premanufacture notification 

a Labeling, recordkeeping 

a Reporting requirements 

o Toxicity testing 

Statute 

Occupational Safety & Health 

Act 

Applicable provision, regulation or requirement of statute 

o Walking-working surface standards 

o tleans of egress standards 

o Occupational health and environmental control standards 

o ltazardous material standards 

o Personal protective equipment 

standards 

o General environmental control 

standards 

o tledical and first aid standards 

Coastal Zone Management Act o Fire protection standards 

National Environmental Polley o ~ompressed gas and compressed air 

Act equipment 

Safe Drinking Water Act 

Harlne Sanctuary Act I, 

o Welding, brazing, and cutting 

standards 

o States may veto Federal permits for 

plants to be sited in coast! zone 

o Requires environmental impact 

statements 

o Requires undergrond injection 

control permits 

a Ocean dumping permits 

o Recordkeeping and reporting 
8. 3 REFERENCES 

1. Telephone conversation. Michael Alexander, TRW, with r1s. M. Fecci 

of Analabs/Foxboro. March 23, 1982. Price of Century Systems OVA-108 in July 1980. Docket Reference Number II-E-14.* 

2. Telephone conversation. 11ichael Alexander, TRW, with t1r. Harris of 

Dillon Supply, Durham, N.C. June 17, 1981. Price of gate valves. 

Docket Reference Number II-E-11.* 

3. Economic Indicators. Chemical Engineering. Vol. 88 #12. June 15, 

1981. p. 7. Docket Reference Number II-I-30.* 

4. Letter with attachments from Texas Chemical Council to Walt Barber, 

U.S. EPA. June 30, 1980. Docket Reference Number II-D-4.* 

5. Telephone conversation. r1ichael Alexander, TRW, with Danny Keith, 

Dillon Supply Co., Raleigh, N.C. June 15, 1981. Costs of valves, 

pipes, and fittings. Docket Reference Number II-E-10.* 

6. Telephone conversation. Tom Norwood, Pacific Environmental Services, 

Inc., with W.W. Grainger, Inc., Raleigh, NC. December 17, 1981. 

Costs of pressure switches and gas shutoff valves. Docket Reference 

Number II-E-18.* ' 

7. VOC Fugitive Emissions in Petroleum Refining Industry- Background 

Information for Proposed Standards. EPA-450/3-81-015a. U.S. EPA, 

OAQPS. November 1982. Docket Reference Number II-A-36.* 

8. Memorandum from Cole, D. G., PES, Inc., to K. C. Hustvedt, U.S. 

Environmental Protection Agency. Estimated Costs for Rupture Disk 

System with a 3-way valve. July 29, 1981. Docket Reference Number 

II-B-8. * 

9. Erikson, D. G. and V. Kalcevic. Organic Chemical t1anufacturing 

Volume 3: Storage, Fugitive, and Secondary Sources. EPA-450/3-80-025. 

U.S. EPA, OAQPS. December 1980. Docket Reference Number II-A-22.* 

10. Letter with attachments from J. M. Johnson, Exxon Company, U.S.A., 

to Robert T. Walsh, U.S. EPA. July 28, 1977. Docket Reference 

Number II-D-2.* 

11. Environmental Protection Agency. Control of Volatile Organic 

Compounds Leaks from Petroleum Refinery Equipment. EPA-450/2-78-036, 

OAQPS No. 1.2-111. June 1978. Docket Reference Number II-A-3.* 

12. Letter with attachments from R. E. Van Ingen, Shell Oil Company, to 

[). R. Goodwin, OAQPS, U.S. EPA. January 10, 1977. Response to 114 

letter on hydrocarbon sources from petroleum refineries. Docket 

Reference Number II-D-1.* 

8-26 
13. Telephone conversation. T. Hennings, TRW, with Editor, Oilgram 

News. February 25, 1981. Price of LPG on June 16, 1980. Docket 

Reference Number II-E-6.* 

14. Nelson, W. L., Petroleum Refinery Engineering. HcGraw-Hill Book 

Co., Inc. New York. 1958. p. 32. Docket Reference Number II-I-2.* 

15. DOE Monthly Energy Review. January 1981. DOE/EIA-0035{81/01). 

p. 88. Docket Reference Number II-I-26.* 

16. Telephone conversation. T. Norwood, Pacific Environmental Services, 

Inc., with P. Marthinetti, Ingersoll Rand. Distance Piece Price, 

December 8, 1982. Docket Reference Number II-E-16.* 

17. Fugitive Emission Sources of Organic Compounds - Additional Information 

on Emissions, Emission Reductions, and Costs. EPA 450/3-82-010, April 

1982. Docket Reference Number II-A-25.* 

18. McMahon, Leonard A., 1981 Dodge Guide. Annual Edition No. 13, 

McGraw-Hill Publishing Co. Docket Reference Number II-I-125.* 

*References can be located in Docket Number A-80-20-B at the U.S. Environmental 

Protection Agency Library, Waterside Mall, Washington, D.C. 

8-27 
9. ECONOMIC ANALYSIS OF THE REGULATORY ALTERNATIVES 

9.1 INDUSTRY PROFILE 

This section describes the general business and economic conditions of 

the onshore natural gas production industry. The primary focus of the 

discussion is on the natural gas processing segment of the industry for 

which alternative emission regulations are being considered. 

Projections for the year 1987, five years after a proposal date of 

1982 for the regulatory alternatives for new, modified or reconstructed 

sources, were developed for the industry. The growth·projections are 

presented to illustrate the future trend of the industry. The profile and 

the projections, including significant factors and trends in the industry, 

are presented to aid in the determination of economic impacts of the 

proposed standards. The energy and environmental impact analyses also were 

conducted based upon these projections. The economic impacts are described 

in subsequent sections. 

9.1.1 Onshore Natural Gas Production Industry 

The natural gas system in the United States consists of producers, 

processors, dealers, interstate and intrastate pipelines, distributors and 

consumers. The production industry includes hundreds of firms engaged in 

the exploration, drilling, producing and processing of natural gas. A 

relatively small number of companies dominate the industry. The American 

Association of Petroleum Geologists (AAPG) states that the 16 largest firms 

in the industry found 53.7 percent of 2.8 billion barrels of crude oil and 

40.3 percent of 41.3 trillion cubic feet of natural gas discovered during 

the period from 1969 to 1978. Also, the AAPG states that the 16 largest 

companies accounted for about 60 percent of industry expenditures for 

geological and geophysical information and lease acquisition. However, 

9-1 
these large companies spend almost twice as much money as smaller firms on 

predrilling exploration and one-half as much as the others on wildcat 

drilling. 1 

Approximately two-thirds of all processed gas is transmitted in 

pipelines across state lines to be sold in various metropolitan areas. The 

remainder is sold in intrastate markets. Approximately 100 pipeline 

companies operate the interstate pipeline network. The pipeline sector of 

the industry tends to be dominated by large companies more than the 

production sector. In 1971, the four largest pipeline companies accounted 

for 35 percent of the total interstate pipeline volume, while the 20 

largest companies transported over 93 percent of the gas. 

Companies involved in the final distribution of the gas constitute the 

least concentrated sector of the industry. Over 1,600 companies buy gas 

from pipelines and distribute it to various communities. Because they 

operate in different service areas, these companies rarely compete with one 

another, except in input markets, and are often regulated by state or local 

agencies. 

There is some vertical integration in the industry with pipeline · 

companies often owning producing wells. However, few companies engage in 

production, transmission and distribution of the gas. In contrast, 

horizontal integration is quite extensive. In the production sector, 

almost all companies produce crude oil and natural gas liquids in addition 

to natural gas although no one company predominates. In addition, many 

also have investments in coal, oil shale, synfuels and mineral industries. 

9.1.1.1 Natural Gas Processing Facilities. In 1980, there were 772 

gas processing plants in the United States, with a combined total capacity 

of approximately 71.2 billion cubic feet per day. As of January 1, 1980, 

these plants were utilizing about 63 percent of their combined capacity. 

Table 9-1 presents a distribution of the gas plants based on their 

capacity. As this table indicates, at least 60 percent of the plants have 

capacities of 50 million cubic feet per day (MMcfd) or less. Another 16.8 

percent of the plants have capacities between 50 MMcfd and 100 MMcfd. The 

remainder of the gas plants have capacities greater than 100 MMcfd, ranging 

as high as 2,650 MMcfd. 

9-2 
Table 9-1. DISTRIBUTION OF GAS PLANTS BY CAPACITYa (1980) 

Plant Capacity 

(MMcfd) 

50 

51 - 100 

100 - 200 

201 - 300 

301 - 400 

401 - 500 

501 - 600 

601 - 700 

701 - 800 

801 - 900 

901 - 1,000 

> 1,000 

No Response 

TOTAL 

Number of Plants 

460 

130 

70 

34 

9 

3 

7 

0 

2 

6 

6 

6 

39 

772 

a Based on data presented in Oil and Gas Journal, July 14, 1980. 

9-3 
There are a number of different process methods currently being used 

at natural gas processing plants: adsorption, refrigerated absorption, 

refrigeration, compression, adsorption, cryogenic--Joule-Thomson and 

cryogenic-expander. The distribution of gas plants by these process 

methods and combinations of these methods is presented in Table 9-2. 

In 1980, there were 138 different companies operating gas processing 

plants in the United States. Table 9-3, which shows the distribution of 

gas plants by ownership, lists the companies that own more than 20 plants. 

This table indicates that over 55 percent of the gas plants are owned by 

these 11 larger 11 companies. Also, Table 9-3 indicates that almost 85 percent 

of the 138 companies own less than ten gas plants. 

All the gas plants in the United States in 1980 were located in 

twenty-two states, including two plants in Alaska. Table 9-4 shows a 

distribution of gas plants based on location and ranked in order of gas 

plant capacity. As the table indicates, over 46 percent of the plants are 

located in Texas. States not listed in Table 9-4 have less than ten gas 

plants. 

9.1.1.2 Markets. Although the natural gas component of total energy 

production has decreased from 40 percent in 1973 to 34 percent in 1980 as 

indicated in Table 9-5, the natural gas production industry is expected to 

continue to supply a significant fraction of total domestic energy 

requir.ements. Exploration and production activities for natural gas are 

anticipated to continue to increase as a result of phased natural gas price 

deregulation and expected price increases. 

Imports of natural gas have remained fairly constant since 1973, 

ranging from 953 billion cubic feet in 1975 to 1,253 billion cubic feet in 

1979. Imports were 984 billion cubic feet in 1980 representing 4 percent 

of domestic consumption. Exports of natural gas declined from 77 billion 

cubic feet in 1973 to 49 billion cubic feet in 1980. Exports are primarily 

to Japan and Mexico. Imports are primarily from Canada, Mexico, and 

Algeria. 

Domestic aggregate retail price elasticities of demand for solid 

fuels, natural gas, electricity and petroleum are shown in Table 9-6. 

These elasticities represent the change in final demand for each fuel with 

9-4 
Table 9-2. DISTRIBUTION OF GAS PLANTS BY PROCESS METHODa (1980) 

Process Method 

Absorption 

Refrigerated Absorption 

Refrigeration 

Compression 

Adsorption 

Cryogenic-Joule-Thomson 

Cryogenic-Expander 

Absorption & Refrigerated Absorption 

Absorption & Compression 

Refrigerated Absorption & Refrigeration 

Refrigerated Absorption & Adsorption 

Refrigerated Absorption & Cryogenic-Joule-Thomson 

Refrigerated Absorption & Cryogenic-Expander 

Refrigeration & Compression 

Refrigeration & Cryogenic-Joule-Thomson 

Cryogenic-Joule-Thomson & Expander 

No Response 

TOTAL 

Number of Plants 

77 

280 

161 

7 

40 

19 

147 

2 

1 

2 

1 

2 

13 

1 

1 

10 

8 

772 

a Based on data presented in Oil and Gas Journal, July 14, 1980. 

9-5 
Table 9-3. DISTRIBUTION OF GAS PLANTS BY OWNERSHIPa (1980) 

Company Owner 

Amoco Production Company 

Cities Service Company 

Phillips Petroleum Company 

Warren Petroleum Company 

Exxon Company 

Shell Oil Company 

Sun Gas Company 

Getty Oil Company 

Mobil Oil Corporation 

Texaco, Inc. 

ARCO Oil and Gas Company 

Chevron USA, Inc. 

Union Oil Company of California 

Mitchell Energy & Development Corporation 

Number of companies that own between 10 and 20 plants 

Number of companies that own less than 10 plants 

Total number of companies that own gas plants 

TOTAL 

Number of Plants 

47 

41 

37 

35 

33 

33 

33 

26 

26 

25 

24 

23 

23 

22 

7 

117 

138 

772 

a Based on data presented in Oil and Gas Journal, July 14, 1980. 

9-6 
Table 9-4 DISTRIBUTION OF GAS PLANTS BY STATEa (1980) 

Plant 

State Number of plants capacity 

(MMcfd) 

Texas 356 24,646.9 

Louisiana 103 24,566.7 

Kansas 26 5,320.9 

Oklahoma 86 4,267.7 

New Mexico 34 3,632.1 

Wyoming 40 1,357.7 

California 37 1,254.5 

Colorado 27 799.6 

All other states 63 5,346.5 

TOTAL 772 71 '192 .6 

a Based on data presented in Oil and Gas Journal, July 14, 1980. 

9-7 
Table 9-5. PRODUCTION OF ENERGY BY TYPE, UNITED STATES (Quadrillion Btu) 

Natura 1 Hydro- Nuclear Total % NG Crude gas 

electric electric energy of 

Coal 1 "12 NGPL 3 power4 Other5 01 (dry) power produced total 

1973 14.366 19.493 2.569 22.187 2.861 0.910 0.046 62.433 40 

1974 14.468 18.575 2.471 21.210 3.177 1.272 0.056 61.229 39 

1975 15.189 17.729 2.374 19.640 3.155 1.900 0.072 60.059 37 

1976 15.853 17.262 2.327 19.480 2.976 2.111 0.081 60.091 36 

1977 15.829 17.454 2.327 19.565 2.333 2.702 0.082 60.293 36 

1.0 1978 15.037 18.434 2.245 19.485 2.958 2.977 0.068 61.204 . 36 I 

o:> 

1979 17.651 18.104 2.286 20.076 2.954 2.748 0.089 63.907 35 

1980 18.877 18.250 2.263 19.754 2.913 2.704 0.114 64.876 34 

Totals may not equal sum of components due to independent rounding. 

~ Includes bituminous coal, lignite and anthracite. 

3 Includes lease condensate. 

4 Natural gas plant liquids. 

5 Includes industrial and utility production of hydropower. 

Includes geothermal power and electricity produced from wood and waste. 

R = Revised data 

Source: U.S. Department of Energy, Energy Information Administration calculations. Monthly Energy Review, 

July 1981. 
Table 9-6. AGGREGATE RETAIL PRICE ELASTICITIES OF DEMAND, U.S. 

(Estimate for 1985) 

Price elasticit~ of demand 

Solid Natural 

With respect to fuels gas Electricity Petroleum 

Solid fuels -.215 .030 .131 .031 

Natural gas .005 -.426 .228 .062 

Electricity .011 .052 -.376 .111 

Petroleum .002 .013 .077 -.263 

Source: The Global 2000 Re ort to the President,(Volume III: 

Documentation , A report prepared by the Council on Environmental 

Quality and the Department of State. April 1981. p. 301. 

9-9 
respect to a change in the price of all four aggregate fuel types. 

Therefore, the diagonal corresponding to direct price elasticity should 

have a negative sign. For example, the domestic retail price ~lasticity 

for natural gas is -.426, indicating an inelastic aggregate retail demand. 

Electricity has the highest cross price elasticity with respect to natural 

gas with a value of .228, indicating that a one percent increase in the 

retail natural gas price causes a .228 percent increase in the aggregate 

quantity demanded of electricity. All of the cross price elasticities are 

positive, representing interfuel substitution. 

9.1.2 Onshore Natural Gas Production Industry--Growth and Projections 

This section discusses the historical production and price of natural 

gas. Natural gas production is projected for the years 1985, 1990 and 2000 

and distributed in the categories of onshore, offshore, discoveries from 

existing fields and discoveries from new fields. 

9.1.2.1 Historical Data. Marketed production of natural gas 

increased from 5.42 trillion cubic feet in 1949 to a peak of 22.65 trillion 

cubic feet in 1973. Increases in marketed production from 1949 through 

1973 averaged 6.0 percent annually. In 1974 and 1975, marketed production 

decreased 4.6 percent and 6.9 percent, respectively. After 1976, marketed 

production declined slightly to 19.67 trillion cubic feet in 1979. 

Total gross withdrawals of natural gas from both gas wells and oil 

wells generally follow the same trend as marketed production. However, the 

volume of natural gas withdrawn from oil wells has remained relatively 

constant at about three to five trillion cubic feet per year from 1949 to 

the present. Table 9-7 presents total natural gas production distributed 

between onshore and offshore production for the years 1949 through 1979. 2 

Onshore production declined from 99.1 percent of the total in 1954 to 72.4 

percent of the total in 1979. The difference between gross withdrawals and 

marketed production represents quantities from gas wells and oil wells that 

were either vented, flared or used for reservoir repressuring. 3 In 1980, 

there were approximately 175,000 producing gas wells in the United States. 

Although most natural gas is produced from natural gas wells, about 18 

percent is produced from crude oil wells. 

9-10 
Year 

1949 

1950 

1951 

1952 

1953 

1954 

1955 

1956 

1957 

1958 

1959 

1960 

1961 

1962 

1963 

196'4 

1965 

1966 

1967 

1968 

1969 

1970 

1971 

1972 

1973 

1974 

1975 

1976 

1977 

1978 

1979b 

Table 9-7. NATURAL GAS GROSS WITHDRAWALS AND MARKETED ONSHORE AND OFFSHORE PRODUCTION 

From 

Gas Wells 

4.99 

5.60 

6.48 

6.84 

7.10 

7.47 

7.84 

8.31 

8.72 

9.15 

10.10 

10.85 

11.20 

11.70 

12.61 

13.11 

13.52 

13.89 

15.35 

16.54 

17.49 

18.59 

18.93 

19.04 

19.37 

18.67 

17.38 

17.19 

17.42 

17.39 

17.17 

Production in Trillion Cubic Feet 

From Gross Marketeda Onshore 

Oil Wells Withdrawals Production Production 

2.56 

2.88 

3.21 

3.43 

3.55 

3.52 

3.88 

4.07 

4.19 

3.99 

4.13 

4.23 

4.27 

4.34 

4.37 

4.43 

4.44 

5.14 

4.91 

4. 79 

5.19 

5.19 

5.16 

4.97 

4.70 

4.18 

3.72 

3.75 

3.68 

3.91 

3.75 

7.55 

8.48 

9.69 

10.27 

10.65 

10.98 

11.72 

12.37 

12.91 

13.15 

14.23 

15.09 

15.46 

16.04 

16.97 

17.54 

17.96 

19.03 

20.25 

21.33 

22.68 

23.79 

24.09 

24.02 

24.07 

22.85 

21.10 

20.94 

21.10 

21.31 

20.92 

5.42 

6.28 

7.46 

8.01 

8.40 

8.74 

9.41 

10.08 

10.68 

11.03 

12.05 

12.77 

13.25 

13.88 

14.75 

15.55 

16.04 

17.21 

18.17 

19.32 

20.70 

21.92 

22.49 

22.53 

22.65 

21.60 

20.11 

19.95 

20.03 

19.97 

19.67 

NA 

NA 

NA 

NA 

NA 

8.66 

9.28 

9.94 

10.51 

10.77 

11.70 

12.33 

12.77 

13.24 

13.99 

14.70 

15.10 

15.84 

16.33 

17.00 

17.86 

18.70 

18.74 

18.77 

18.67 

17.37 

15.85 

15.65 

15.49 

14.87 

14.25 

Offshore 

Productionc 

NA 

NA 

NA 

NA 

NA 

0.08 

0.13 

0.14 

0.17 

0.26 

0.35 

0.44 

0.48 

0.64 

0.76 

0.85 

0.94 

1.37 

1.84 

2.32 

2.84 

3.22 

3.75 

3.76 

3.98 

4.23 

4.26 

4.30 

4.54 

5.10 

5.42 

Percentage 

Onshore 

NA 

NA 

NA 

NA 

NA 

99.1 

98.6 

98.6 

98.4 

97.6 

97.1 

96.6 

96.4 

95.4 

94.8 

94.5 

94.1 

92.0 

89.9 

88.0 

86.3 

85.3 

83.2 

83.3 

82.4 

80.4 

78.8 

78.4 

77.3 

74.5 

72.4 

Offshore 

NA 

NA 

NA 

NA 

NA 

0.9 

1.4 

1.4 

1.6 

2.4 

2.9 

3.4 

3.6 

4.6 

5.2 

5.5 

5.9 

8.0 

10.1 

12.0 

13.7 

14.7 

16.8 

16.7 

17.6 

19.6 

21.2 

21.6 

22.7 

25.5 

27.6 

~A= Not Ava1lable. 

a Marketed production is den ved. It 1 s gross w1 thdrawa 1 s from producing reservoirs 1 ess gas used for reservoir 

representing and quantities vented and flared. 

b Est1mated, based on reported data through November. 

rlote: Sum of components may not equal total due to 1ndependent rounding. Beginn1ng w1th 1965 data, all volumes 

are shown on a pressure base of 14.73 ps1a at 60°F. For prior years, the pressure base is 14.65 psia at 

60"F. 

Sources: 

• 1949 through 1975, U.S. Department of the Inter1or, Bureau of Mines, Minerals Yearbook, "Natural Gas" 

chapter. 

• 1976 through 1978, u.s. Department of Energy, Energy !nformat1on Administration, Natural Gas Production 

and Consumption, annual. 

c Data from U.S. Department of the Inter1or, Geolog1cal Survey - Conservation Division, Outer Continental Shelf 

Stat1st1cs. 

9-11 
The nominal price of natural gas remained reasonably steady during the 

period from 1955 through 1973. Since 1973, the year of the Arab Oil 

Embargo, the price has consistently increased in real terms. Figure 9-1 

shows selected natural gas prices for three categories for the period from 

1955 through 1979. 4 In 1979, the price of natural gas at the wellhead was 

$1.13 per million Btu, $1.85 per million Btu at the city gate and $2.50 per 

million Btu delivered to ultimate customer. This consistent increase in 

the price coupled with the deregulation of the price of natural gas in 

almost all categories before the end of 1985 will boost the revenues and 

profitability margins for the industry. This will contribute to growth in 

capital availability potentially to be used for more drilling, deeper 

drilling and increased exploration and production of tight gas formations. 

Since the Oil Embargo in 1973, the financial condition of the onshore 

crude oil and natural gas production industry has been improving steadily 

in both revenues and net profits. Composite financial data shown in Table 

9-8 indicate increased revenues from $15,292 million in 1976 to $38,000 

million in 1980. During the same period, net profits increased from $1,155 

million to $1,925 million. ' 

Composite net profit margins as a percent of sales however have 

declined from 7.6 percent in 1976 to 5.1 percent in 1980. This fact 

indicates that production costs have risen at a faster pace than prices. 

Also, total capital has grown at a slower pace than revenues and profits. 

Consequently, return on total assets and return on equity have improved. 

According to Value Line Investment Survey, the composite industry will 

continue to have a healthy financial future into the 1980 1 5. It is 

projected in 1983-85 that the industry will have a composite net profit 

margin of 4.6 percent on annual revenues of approximately $70 billion in 

current dollars. The long term debt ratio is projected to be 45.5 percent. 

Total capital is projected to increase to $35,500 million in current 

dollars or 51 percent of revenues in 1983-85. 

9.1.2.2 Five-Year Projections. In this subsection, projections for 

the number of new and modified and reconstructed gas processing facilities 

in the years 1983 through 1987 are developed. The form of the growth in 

terms of new facilities, modified facilities and reconstructed facilities 

9-12 
2.50r--------r--------~-------,--------------~ 

a 

QO 

1: 

\.0 0 

I -- 1.50 

w --:a: 

........ 

r 

.., 

-,.... 1.00 

0 

Q 

Ultimate Customer 

50 ~~~~~~~~c=tt~ytG:a~t~e~~~~~~~JJ~ __ LJ 

----Wellhead ----- ...... 

QL-------~--------~---------L--------~----~ 

1955 1960 1965 1970 1975 78 79 

Year 

Figure 9-l. Selected natural gas prices -three categories for the period 1955-1979~! 
Table 9-8. COMPOSITE FINANCIAL DATA FOR THE NATURAL GAS INDUSTRY 1976-1981 and 

1983-1985 ESTIMATES (Current dollars) 

Item 1976 1977 1978 1979 1980 1981 83-85E 

Revenues ($mill) 15,292 19,430 22,463 30,357 38,000 46,000 70,000 

Net Profit ($mill) 1,155 1,356 1,399 1,702 1,925 2,200 3,200 

Income Tax Rate 44 .4~o 43.1% 43.9% 43.2% 44.0% 45.05:, 47.0°~ 

Net Profit Margin 7.6% 7.0% 6.2% 5.6% 5.1% 4.8% 4.6% 

Long-term Debt Ratio 54.3% 50.8~o 48.5% 48.0% 48.5% 47,0~o 45.5% 

Common Equity Ratio 41.0% 44.4% 46.8% 47.a 48.0% 50.0% 53.0% 

Total Capital ( $mi 11) 19,538 20,207 20,611 22,236 23,750 26,000 35,500 

Net Plant ($mill) 18,356 19,865 21,423 23,453 26,000 27,000 33,000 

I.D 

I % Earned Total Capital 8.0% 8.8% 8.9% 9.8% 10.5% 10.5% 11.5% .+::- ~ Earned Net Worth 12.9% 13.6% 13.2% 14.7% 15.5% 15.5% 16.5% 

% Earned Comm. Equity 13. 5~~ 14.2% 13.7% 15.4% 16.0% 16.0% 17.0% 

~a Retained to Comm. Equity 7.5% 8.0% 7.2% 8.9% 9.0% 9.0% 9.5% 

% All Dividends to Net Profit 48% 47% 50% 45% 45% 45% 45~~ 

Average Annual P/E Ratio 7.1 7.6 7.1 6.8 NA NA 8.0 

Average Annual Dividend Yield 6.3% 5.8% 6.6% 6.3% NA NA 6.0% 

Fixed Charge Coverage 278;'o 281% 284% 2875;, 290% 295% 310% 

E = Estimates 

NA = Not available 

Source: A. Bernhard & Company. 11 Natural Gas Industry ... Value Line Investment Surve~, July 18, 1980. 
is discussed. The size distribution of new facilities is developed based 

upon industry's historical trend. Information on the projection of natural 

gas price is presented, and the effect of price deregulation on natural gas 

production is discussed. 

Production of natural gas by conventional techniques has exceeded the 

rate of reserve additions in recent years. Consequently, conventional 

reserves are expected to continue declining and production from 

conventional reserves will decline as well. Annual production of 

conventional natural gas is expected to decline roughly 1.5 to 2.0 trillion 

cubic feet every five years through 1995. The production of associated and 

dissolved gas is expected to decline less rapidly than the production of 

nonassociated gas, due to higher price incentives for crude oil. 

Table 9-9 presents the American Gas Association's (AGA) projected 

Lower-48 states conventional natural gas production for the period from 

1980 through 2000. 5 In 1985, the production is projected to be 19.7 

trillion cubic feet, decreasing to 17.7 trillion cubic feet in 1990. 

Natural gas produced through enhanced gas recovery (EGR) techniques is 

expected to increase rapidly and provide a significant portion of the 

production by 1995. 

Production from new (past 1977) onshore discoveries according to AGA 

is projected to total 3.6 trillion cubic feet in 1985 and to increase 

consistently through 1990 when it will reach the maximum of 4.9 trillion 

cubic feet. An increasing percentage of total onshore production is 

projected to come from new discoveries. 5 Table 9-9 includes projected 

Lower-48 states onshore conventional natural gas production from new 

discoveries for the period from 1980 through 2000. 5 Figure 9-2 portrays 

the onshore natural gas production from new discoveries through the year 

2000. 

Natural gas supply projections are conducted by various oil and gas 

companies as well as government and independent study groups. Table 9-10 

presents a comparison of 1990 projection forecasts presented by the 

Department of Energy (DOE), the American Gas Association (AGA), Exxon, 

Tenneco and other private study groups. 6 AGA's forecast of 16.3 

quadrillion Btu per year is 8.4 percent lower than DOE's forecast of 17.8 

9-15 
Table 9-9. PROJECTED LOWER-48 STATES CONVENTIONAL 

NATURAL GAS PRODUCTION 

Gas Source 

Onshore 

Old Intera 

Old Intraa 

Old Direct Sale 

New 

Offshore 

Old Intera,b 

New Interc 

Total 

Old Inter 

Old Intra 

Old Direct Sale 

New 

TOTALd 

1980 

4.9 

3.6 

4.0 

1.5 

5.6 

0.1 

10.5 

3.6 

4.0 

1.6 

19.7 

Production, Trillion Cubic Feet 

1985 1990 1995 

3.6 

2.4 

2.6 

3.6 

4.1 

3.4 

7.7 

2.4 

2.6 

7.0 

19.7 

2.0 

1.3 

1.5 

4.9 

1.4 

6.6 

3.4 

1.3 

1.5 

11.5 

17.7 

1.1 

0.7 

0.8 

4.8 

0.7 

6.5 

1.5 

0.7 

0.8 

11.3 

14.6 

a Includes gas used as compressor fuel and net storage injections. 

b Including new additions from pre-1977 leases. 

c Post-1976 leases only. 

d Totals may not add due to independent rounding. 

2000 

0.7 

0.4 

0.5 

3.8 

nil 

5.4 

0. 7 

0.4 

0.5 

9.2 

10.8 

Source: American Gas Association, Gas Supply and Statistics--Total Energy Resource Analysis Model (TERA) 80-1, Appendix A. 

9-16 
s.o 

~ 4.5 u 

.. 

... • c 

0 4.0 -.., 

u 

:::1 

E 3.5 

t' • 3.0 • c 

u 

.. 

-

Q 2.5 

I 

z 

"Z 2.0 

., 

u 

., 

_, 

c 

... 1.5 -=-

1.0 

0.5 

0 

1980 1985 1990 1995 2000 

Year 

Figure 9·2. Projected new discovery onshore natural gas production.5 

9-17 
1.0 

I 

...... 

co 

Table 9-10. PROJECTIONS OF NATURAL GAS SUPPLY: COMPARISON OF 1990 FORECASTS6 (Quadrillion Btu) 

1979 Projections for 1990 

1978 DOE~ 

Units Actual EIA AGAb DPPc Paced 

Domestic Production 

Conventional 19.5 17.8 15.3-17.3 16.9 16.1 

North Alaska f 0.9 1.6 0.4 1.0 

Synthetic Gas 0.2 0.3 1.1 0.6 0.8 

Subtotal 19.7 19.0 19.9-21.9 18.0 18.0 

Net Imports 

Pipeline 0.9 0 2.1 2.0 1.4 

Liquefied Natural Gas g 0.8 2.0 1.0 0.8 

Subtotal 0.9 0.8 4.2 3.1 2.2 

Total Supply 20.6 19.8 24.1-26.1 21.0 20.2 

a DOE/EIA 1979 Annual Report to Congress, middle range forecast. 

b American Gas Association, The Future for Gas Energy in the United States, June 1979. 

c Data Resources, Inc., Energy Review, Winter 1980. 

Exxone Tenneco 

14.9 14.8 

f 1.0 

0.6-1.0 1.5 

15.5-15.9 17.3 

1.8 2.0 

0.8 3.1 

2.7 5.1 

18.2-18.6 22.4 

f 

d The Pace Company Consultants and Engineers, Inc., The Pace Energy and Petrochemical Outlook to 2000, October 

1979. 

e Exxon Company, U.S.A., Energy Outlook 1980-2101, December 

f Tenneco Oil Company, Energy 1979-2000, June 1979. 

g Included in conventional production. 

h Less than 0.5 quadrillion Btu. 

1979. 

Note: Non-EIA projections converted from trillion cubic feet with 1,020 Btu per cubic foot. Numbers may not 

add to totals because of rounding. 
quadrillion Btu per year, and Exxon's forecast of 14.9 quadrillion Btu is 

16.3 percent lower than DOE's forecast. AGA's projections were used for 

the purposes of this study because their projections included estimates of 

new production. The other forecasters did not. 

The natural gas processing industry is projected to add new plants 

needed to process new production. The number of new gas processing plants 

that are projected to begin operating between 1983 and 1987 are presented 

in Table 9-11. This table shows, for each year, the cumulative number of 

new plants that are expected to be in operation as a result of "new" 

natural gas production. For this analysis, "new" production is considered 

to be gas produced onshore after January 1, 1983 from any well located 

outside of a given radius and depth of a proven reserve and gas produced 

offshore from any tract leased after January 1, 1983. The figures listed 

under the "new production" column include the incremental new production 

for that particular year plus the gas produced from the new wells of the 

previous years, back to 1983. Therefore, the cumulative number of new gas 

plants expected to be in operation each of the five years was determined by 

dividing the projected annual new natural gas production by the average 

capacity of existing cryogenic gas plants. It is assumed that all new gas 

plants will employ the cryogenic process method. 

In addition to new gas processing plants being constructed, it is 

estimated that approximately eight existing gas plants will be modified or 

reconstructed during each year during the period 1983-1987. This estimate 

approximates the number of expansions reported each year by Oil and Gas 

Journal's semi-annual report on plant expansions and equals one percent of 

the total number of gas plants in the United States. 

Natural gas prices are projected by the Department of Energy to 

increase because of the Natural Gas Policy Act and phased deregulation of 

prices during the period from 1983 through 1987. By 1985, almost all 

categories of natural gas production will be deregulated. Very little new 

gas will be subject to controls; most old intrastate gas will be 

decontrolled and the quantity of old interstate gas that remains controlled 

will decline rapidly over time. Because of this phased deregulation, 

natural gas prices are projected to increase during the period from 1983 

9-19 
Table 9-11. ESTIMATED NUMBER OF NEW GAS PLANTS, 1983-1987 

New natural gas productiona Cumulative numberb 

Year (trillion cubic feet) of new gas plants 

1983 1.32 40 

1984 2.62 80 

1985 3.89 120 

1986 4.99 150 

1987 6.07 180 

a 11 New11 production is considered to be gas which is (1) produced from a new 

well beyond a specified distance from an old well; (2) produced from a 

reservoir from which gas was not produced in commercial quantities prior 

to January 1, 1983, or (3) produced from an offshore tract leased on or 

after January 1, 1983. These new production figures were developed 

based on American Gas Association's Total Energy Resource Analysis 

(TERA) Model 80-I, November 21, 1980. The figures reflect an average 

annual decline in production of 6.2 percent, and the source for this 

decline rate is the National Petroleum Council's U.S. Energy OutlookOil and Gas Availability, 1974. 

b It is assumed that all new gas plants will be cryogenic gas plants, with 

an average capacity equivalent to the average capacity of existing cryogenic plants (90 MMcfd). Therefore, the number of new gas plants 

is developed by dividing the projected annual new production by the 

average capacity of existing cryogenic gas plants. 

9-20 
through 1987. In turn, deregulated prices are expected to boost 

exploration and production activities. The history and projections for 

natural gas prices are summarized in Table 9-12. 7 

9.2 ECONOMIC IMPACT ANALYSIS 

This section presents the expected economic impacts of alternative 

emissions ·regulations limiting volatile organic compounds (VOC) emissions 

from natural gas/gasoline processing plants. 

9.2.1 Economic Impact Assessment Methodology 

The methodology for economic impact assessment of VOC emissions 

regulations on the onshore natural gas processing industry includes the 

following steps: 

Step 1 -Analyze the absolute magnitude of additional pollution control 

costs in terms of before-tax annualized cost and after-tax 

annualized costs. 

Step 2 Determine percentage product price increases required for 

regulated plants to maintain constant profitability. 

Step 3 Analyze the regulated plants• ability to pass additional emissions 

control costs forward to consumers or backward to suppliers. 

Step 4 -Determine the financial viability of regulated plants. 

Step 5 - Analyze expected impacts of emissions regulations on plant 

closings, curtailment of expansion, industry output, industry 

prices, employment, wages, productivity, plant location, 

international trade, and possible balance of payments effects. 

If it is determined in Step 1 and 2 that the emissions control costs are 

small in absolute and relative terms, then expected economic impacts on 

output, prices, employment, profitability, etc., will be small and further 

expenditure of resources for detailed impact analyses justifiably can be 

foregone. Such might be the case where annualized pollution control costs 

are much less than EPA•s trigger criteria for regulatory analysis, i.e., 

$100 million additional (before tax) annualized cost or a price increase of 

5 percent required for industry members to maintain pre-control levels of 

profitability. 

9-21 
Table 9-12. NATURAL GAS PRICES: HISTORY AND PROJECTIONS FOR 1965-1995 

(1979 Dollars per Thousand Cubic Feet) 

Hi stor~a p . t. b roJeC 1ons 

Price 1965 1973 1978 1985 1990 1995 

Domestic Wellhead Prices 

Old Interstate NA NA 0.93 1.01 1.18 1.39 

New Interstate NA NA NA 4.48 4.04 4.59 

Old Intrastate NA NA NA 3.29 3.32 3.78 

New Intrastate NA NA NA 4. 72 4.28 4.82 

North Alaska 1.85 1.85 

Average 0.36 0.35 1.02 3.26 3.42 4.17 

Synthetic Gas Prices 

High-Btu Coal Gas 4.76 4.19 4. 71 

Medium-Btu Coal Gas 3.70 4.50 5.44 

Imported Gas Prices 

Canadian Gas NA NA 2.41 6.21 6.92 8.51 

Mexican Gas NA NA NA 6.21 6.92 8.51 

Liquefied Natural Gas 1.54 5.91 6.42 7.70 

Delivered Prices 

Residential 2.34 2.04 2. 77 5.41 5.74 6.45 

Commercial 1.60 1.46 2.38 4.88 5.22 5.93 

Raw Material c NA NA NA 4.28 4.48 5.21 

Large boilers NA NA NA 5.24 4.54 5.26 

Industrial, Other 0.78 0. 77 1.61 4.34 4.51 5.22 

Refineries NA NA NA 4.55 4.43 5.13 

Electric Utilities 0.89 0.63 1.72 4.74 4.42 

Alternative Fuel Cost 6.23 6.94 8.29 

a Source for historical data is Volume 2 of the EIA Annual Report to 

Congress, 1979, and the following EIA Energy Data Reports: Natura 1 Gas 

Production and Consum~tion, 1978; United States Im~orts and Ex~orts of 

Natural Gas, 1978; and, Natural and S~nthetic Gas, 1978. 

c Major fuel-burning installations. 

Notes: NA = Not available. -- = Not applicable. 

b Source: DOE/EIA Annual Re~ort to Congress, 1980, Vol. 13, pg. 90. 

9-22 
If it is determined in Steps 1 and 2 that the direct emissions control 

costs are significant in either absolute or relative cost to the industry, 

then the focus of the analysis turns toward analyzing the ability of 

regulated plants to pass additional costs forward to consumers or backward 

to suppliers. The analysis in Step 3 is explained in the context of the 

industry's structure, conduct and performance as described in Section 9.1. 

Specifically, the level of competition within the industry and the 

elasticity of demand to the regulated plants is important as well as the 

elasticity of aggregate product demand. 

If it is determined that the industry is able to pass on all 

additional costs, then Step 4 can be omitted since the financial viability 

of regulated plants would not be jeopardized. Important impacts may occur 

in supplier or consumer sectors and these should be analyzed if expected 

price impacts are significant to these sectors. If, on the other hand, it 

is determined in Step 3 that the industry is unable to pass on all 

· additional emissions control costs, then Step 4 is needed to determine the 

economic viability of regulated and impacted plants. 

If needed, a net present value approach is used in Step 4 to determine 

the regulated plants• financial viability. Specifically, after-tax net 

annualized cost of emissions control is estimated and used to calculate 

required percentage price increases needed for regulated plants to maintain 

baseline net present values for each regulatory alternative. If the 

required price increase for some regulatory alternative exceeds the amount 

which can be successfully passed on or absorbed by the plant then it is 

determined that the plant is non-viable for that regulatory alternative. 

Based on the findings in Steps 1 through 4 and the industry profile in 

Section 9.1, additional analyses of expected economic impacts are 

completed. Expected industry price and output impacts are estimated 

simultaneously. Then related impacts on employment, productivity, 

international trade, etc. are brought into focus in Step 5. 

Before-tax annualized costs (BTAC) and after-tax annualized costs 

(ATAC) of emissions controls are computed in Step 1 using the following 

equations: 

9-23 
where, 

BTAC = I

0 CRF + O&M0 (1) 

ATAC = 1

0 CRF TAXF + (1-t) O&M0 (2) 

Io = initial base year investment 

OM

0 

= annual O&M cost less applicable by-product credits 

CRF = r(l+r)n the capital recovery factor 

(l+r)n-1 

r = the real cost of capital 

n =economic life of the asset, i.e. the capital recovery period 

(variable by asset) 

TAXF = l-ite - t PVDEP 

itc = investment tax credit rate 

t = corporate income tax rate 

PVDEP = preserit value of annual depreciation factors per $1 

of investment, i.e. 

PVDEP = 

y DEPY 

y = 1 (l+d)Y 

Y = length of the depreciation period, 3, 5, 10 or 15 years 

d = nominal discount rate, and 

= annual depreciation factors based on the most advantageous 

depreciation methods for the firm, either (1) rapid amortization of pollution control investments or (2) accelerated cost 

recovery as allowed by the 1981 Economy Recovery Act. 

9-24 
Required real price increases needed by model gas processing plants to 

maintain baseline profitability (net present value) are computed according 

to Equation 3. 

Required real 

price increase l/ = 

ATAC (3) Throughput (1-t) 

Inflation and the weighted nominal cost of capital are projected to be 

8 and 10 percent, respectively. This inflation rate is consistent with 

recent estimates of large econometric models of the U.S. economy. y Ten 

percent nominal weighted natural gas industry cost of capital was estimated 

using fon~casted 1981-1985 composite natura 1 gas industry stock price 

earnings ,'atios of 7 to 8, a 45 percent debt ratio, 47 percent marginal 

corporate income tax rates from Value Line Investment Survey, and 13 

percent nominal pre-tax interest rate on new debt for domestic corporations 

based on X~l-~~~ _Line Investment Survey estimates for 1981-1985. 

9.2.2 ~~onon,·:c Impact of VOC Regulatory Alternatives - Natural 

Gas/Gasoline Processing Plants 

Additional costs for natural gas processing plants to comply with VOC 

regulatory ,:tlternatives are expected to be small in both absolute and 

te1ative t:::'r'ms. Economic impacts on individual plants and the industry 

will be slight. Total additional before-tax annualized costs of controls 

in 1987, the fifth year of controls, are estimated to be as follows: 

_y 

g_er.;u LJ~_Q_rt a 1te rna t i ves, VOC 

I 

II 

III 

IV 

Total additional before-tax 

annualized cost, 1987 

(thousand 1980 dollars) 

0 

220.5 

652.9 

8,080.2 

The assumption ~NPV = 0 requires that (1-t) ~p Q - ATAC = 0; 

therefore, ~p = ATAC/(1-t)Q. P = the real price increase required to 

amortize at the cost of capital the additional pollution control 

investment and operating costs over constant throughput Q. 

'{! Data R(~sou,·ces, Inc. Trendlong 2005 Forecasts. September, 1980. 

9-25 
These estimates are derived at the bottom of Table 9-13 which displays 

aggregate or total before-tax annualized costs of regulatory alternatives 

II, III, and IV by year. The projected number of new gas plants during the 

period 1983-1987 is 180 mid-size plants. The total before-tax annualized 

cost for these new plants in 1987, the fifth year of the regulation, is 

$361,800 for regulatory alternative II, $585,000 for regulatory alternative 

III and $5,482,800 for regulatory alternative IV. 

The projected number of modified and reconstructed plants during the 

period 1983-1987 is 10 small, 15 mid-size and 15 large plants. The total 

before-tax annualized cost for these modified and reconstructed plants in 

1987 is -$141,300 for regulatory alternative II, $67,900 for regulatory 

alternative III and nearly $2.6 million for regulatory alternative IV. The 

combined total of new and modified and reconstructed plants constructed 

during the period 1983-1987 is 10 small plants, 195 mid-size plants, and 15 

large plants. Total before-tax annualized costs for these plants in 1987 

is estimated to be $220,500 for regulatory alternative II, $652,900 for 

regulatory alternative III and nearly $8.1 million for regulatory 

alternative IV. 

Before-tax net annualized costs for individual model gas plants and 

regulatory alternatives I through IV are shown in Table 9-14. The new 

model plant, producing 99 million cubic feet per day, has before-tax 

annualized costs for regulatory alternatives II, III, IV totalling $2,010, 

$3,250 and $30,460 respectively. The smallest modified and reconstructed 

model plant has before-tax net annualized costs of $3,060, $4,840 and 

$17,280 for alternatives II, III and IV, respectively. For the modified 

and reconstructed model plant B costs are $2,010, $3,250, and $40,080 while 

model plant C has costs of -$13,470, -$1,950 and $121,550 for regulatory 

alternatives II, Ill and IV, respectively. Negative before-tax net 

annualized costs stem from situations where recovery credits outweigh the 

annualized investment and operating costs for emissions control. 

After-tax net annualized costs of regulatory alternatives are shown in 

Table 9-15. For the new model plant, the after-tax net annualized cost for 

alternatives II, III and IV are $2,390, $2,590 and $16,660, respectively. 

9-26 
Table 9-13. ONSHORE NATURAL GAS PROCESSING, TOTAL AND CUMULATIVE BEFORE-TAX NET ANNUALIZED 

COST OF VOC REGULATORY ALTERNATIVES 1983-1987 

Projected Cumulative 

Category Number of Gas Plants E._/ Regulator~ Alternative 

of Facility Year A B c II III IV 

-------Thousands of 1980 Dollars------

New 

1983 0 40 0 80.4 130.0 1,218.4 

1984 0 80 0 160.8 260.0 2,436.8 

1985 0 120 0 241.2 390.0 3,655.2 

1986 0 150 0 301.5 487.5 4,569.0 

1987 0 180 0 361.8 585.0 5,482.8 

Modified/Reconstructed 

1983 2 3 3 -28.3 13.6 519.5 

1.0 1984 4 6 6 -56.5 27.2 1,039.0 I 

N 1985 6 9 9 -84.8 40.7 1,558.5 ......, 1986 8 12 12 -113.0 54.3 2,077.9 

1987 10 15 15 -141.3 67.9 2,597.4 

Total New, Modified & Reconstructed 

1983 2 43 3 52.1 143.6 1,737.9 

1984 4 86 6 104.3 287.2 3,475.8 

1985 6 129 9 156.4 430.7 5,213.7 

1986 8 162 12 188.5 541.8 6,646.9 

1987 10 195 15 220.5 652.9 8,080.2 

a/ Plants A, B and C ave. 10, 30 and 100 vessels, respectively. 
1.0 

I 

N 

co 

t•lode 1 

plant 

New 

Modified and 

Reconstructed 

A 

B 

c 

Table 9-14. ONSHORE NATURAL GAS PROCESSING MODEL PLANTS• BEFORE-TAX NET ANNUALIZED 

COST OF VOC REGULATORY ALTERNATIVES PER PLANT 

Size 

No. vessels MMcfd 

I 

Baseline 

contro 1 

level 

Regulatory alternative 

I I II I IV 

-----------------Thousands of 1980 dollars-----------------

30 

10 

30 

100 

90 

30 

90 

250 

0 

0 

0 

0 

2.01 

3.06 

2.01 

-13.47 

3.25 

4.84 

3.25 

-1.95 

30.46 

17.28 

40.08 

121.55 
1.0 

I 

N 

1.0 

Model 

plant 

New 

Modified and 

Reconstructed 

A 

B 

c 

Table 9-15. ONSHORE NATURAL GAS PROCESSING MODEL PLANTs• AFTER-TAX NET ANNUALIZED 

COST OF VOC REGULATORY ALTERNATIVES PER PLANT 

Size 

No. vessels MMcfd 

I 

Baseline 

control 

level 

Regulatory alternative 

II III IV 

-----------------Thousands of 1980 dollars-----------------

30 

10 

30 

100 

90 

30 

90 

250 

0 

0 

0 

0 

2.39 

2.06 

2.39 

-2.86 

2.59 

2.88 

2.59 

1.88 

16.66 

9.32 

21.68 

65.82 
For modified and reconstructed model plant A, these costs are $2,060, 

$2,880, and $9,320, respectively; $2,390, $2,590, and $21,680, 

respectively, for model plant B; and -$2,860, $1,880 and $65,820 for model 

plant C. 

Required price increases for affected gas plants to maintain baseline 

profitability (net present value) are very small as estimated below. For 

purposes of this order of magnitude calculation, gas throughput was assumed 

to be 30, 90, and 250 MMcfd for plants A, B, and C, respectively. Gas 

throughput for new cryogenic plants was assumed to be 90 MMcfd as explained 

in Table 9-11 footnote b. 

Required price increases for VOC Regulatory Alternatives, 1980 $/Mcf 

Regulatory 

alternative 

II 

III 

IV 

New 

Plant B 

(90 MMcfd) 

.00020 

.00022 

.00140 

Modified and Reconstructed 

Plant A Plant B Plant C 

(30 MMcfd) (90 MMcfd) (250 MMcfd) 

.00052 

.00072 

.00234 

.00020 

.00022 

.00182 

-.00009 

.00006 

.00199 

Given the inelasticity of retail demand for natural gas and gas 

liquids products, it is expected that gas processors will pass a large 

portion, if not all, of the incremental emissions control costs forward to 

pipelines, gas utilities and eventually to the ultimate consumers of 

natural gas and natural gas liquids. The price impacts will be slight 

relative to current product prices, less than 0.5 percent, regardless of 

regulatory alternative. No plant closures or curtailments are expected due 

to the VOC regulatory alternatives analyzed. Effects on industry 

profitability, output, growth, employment, productivity, and international 

trade will be negligible or zero due to the VOC regulatory alternatives 

analyzed. 

This concludes the analysis of direct economic impacts of VOC 

regulatory alternatives on the Natural Gas Processing Industry. Control 

costs for VOC regulatory alternatives and associated economic impacts are 

expected to be negligible for individual plants and particularly for the 

composite natural gas processing industry. 

9-30 
9.3 POTENTIAL SOCIOECONOMIC AND INFLATIONARY IMPACTS 

This section discusses the potential social disruption and 

inflationary impacts associated with the VOC regulatory alternatives. 

Data presented in Section 9.2 above indicated that additional costs 

for control of VOC emissions from natural gas processing plants are 

expected to be small on an absolute and relative basis for all four 

regulatory alternatives considered. No impact is expected on plant 

location or structure of the natural gas processing industry. No job 

losses are expected. 

Additional costs for VOC emissions controls on new, remodeled and 

reconstructed gas plants are not expected to have significant inflationary 

impacts because the annualized control costs per unit of production are 

small, i.e., less than 0.5 percent of sales for all model plants and 

regulatory alternatives. It is expected, however, that gas processors will 

succeed in passing a large share of the added costs forward into product 

markets for natural gas liquids. The direct effect on price will be 

negligible, especially when compared to total industry sales, including 

existing (exempt) plants. No productivity, plant location, or balance of 

payments effects are expected due to any of the VOC regulatory 

alternatives. 

9-31 
9.4 REFERENCES FOR CHAPTER 9 

1. Oil & Gas Journal, January 28, 1980, p. 81. Docket Reference 

Number A-80-20-B (VOC) II-I-39.* 

2. U.S. Deparment of Energy, Energy Information Administration. 

Annual Report to Congress-1979. Volume Two (of Three): Data, 

Docket Reference Number A-80-20-B (VOC) II-I-36,* and, U.S. 

Department of the Interior, U.S. Geological Survey-Conservation 

Division, Outer Continental Shelf Statistics, June 1980. Docket 

Reference Number A-80-20-B (VOC) II-I-40.* 

3. U.S. Department of Energy, Energy Information Administration. 

Annual Report to Congress-1979. Volume Two (of Three): Data. 

Docket Reference Number A-80-20-B (VOC) II-I-36.* 

4. American Gas Association, Department of Statistics, Gas Facts - 1979 

Data. Docket Reference Number A-80-20-B (VOC) II-I-38.* 

5. American Gas Association, Gas Supply and Statistics - Total 

Energy Resource Analysis Model (TERA) 80-1, Appendix A, Figure A-2, 

p. 21. Docket Reference Number A-80-20-B (VOC) II-I-41.* 

6. U.S. Department of Energy, Energy Information Administration. 

Annual Report to Congress-1979. Volume Three (of Three): Projects. Docket Reference Number A-80-20-B (VOC) II-I-37.* 

7. U.S. Department of Energy, Energy Information Administration. 

Annual Report to Congress-1979. Volume Three (of Three): Projections. Docket Reference Number A-80-20-B (VOC) II-I-37.* 

*References can be located in Docket Number A-80-20-B at U.S. Environmental 

Protection Agency Library, Waterside Mall, Washington, D.C. 

9-32 
APPENDIX A - EVOLUTION OF THE BACKGROUND INFORMATION DOCUMENT 
Date 

November 30, 1979 

December 7, 1979 

December 18, 1979 

December 19, 1979 

January 1980 

March 19, 1980 

July 14, 1980 

July 16, 1980 

July 18, 1980 

APPENDIX A - Evolution of the 

Background Information Document 

A-2 

Nature of Action 

Meeting to discuss onshore 

production and to solicit the 

aid of API in gathering field 

data. 

Introductory rneeti ng with 

API. 

Visit to Exxon Company, 

U.S.A., Blackjack Creek facility, Jay Field, Florida to gain 

familiarity with process 

equipment and operating conditions. 

Visit to Phillips Petroleum, 

Chatham facility, Chatham, 

Mississippi, to gain familarity 

with process equipment and 

operating conditions. 

Plant visits to various tank 

battery sites in the West 

Texas oil and gas field to 

gain knowledge of processing 

equipment. 

Source Category Survey 

Report. 

Visit to Exxon Company tank 

battery in Kingsville, Texas, 

to gain familarity with gas 

and oil production processes 

and facilities. 

Visit to Phillips Petroleum 

Company, Roosevelt County, New 

Mexico, to acquire familiarity 

with gas and oil product in 

processes and facilities. 

Visit to Shell Oil Company Stateline Production Unit in 

Sidney, Montana, to acquire 

familiarity with gas and oil 

production. 
July 21 & 22, 1980 

July 24, 1980 

October 6-9, 1980 

October 14-16, 1980 

February 9-27, 1981 

March 2-13, 1981 

t~arch 1981 

April 29 & 30, 1981 

Apri 1 1981 

May 1, 1981 

A-3 

Meeting with API concerning 

NSPS development for the 

onshore production industry. 

Visit to Phillips Petroleum 

Company, Canadian County, 

Oklahoma, to gain information 

on gas processing facilities. 

Emission source testing at 

Houston Oil and Minerals, 

Smith Point gas plant, Chambers 

County, Texas. 

Emission source testing at 

Amoco Production Company, 

Hastings gas plant, Brazoria 

County, Texas. 

Emission source testing 

at Texas, Inc., Paradis gas plant, Paradis, Louisiana. 

Emission source testing at 

Gulf Oil Company, Venice 

Plant, Venice, Louisiana. 

Preliminary draft CTG document, 

Control of Volatile Organic 

Compound Equipment leaks from 

National gas/gasoline processing 

plants. 

Meeting of the National Air 

Pollution Control Techniques 

Advisory Committee to review 

the gas/gasoline processing 

plants standard. 

Model plant package mailed 

to industry representatives 

for comment. 

Meeting with API concerning 

Model plants. 
September 1981 

December 1981 

January 28, 1982 

July 21, 1982 

August 18~ 1982 

November 11, 1982 

November 12, 1982 

January 25, 1983 

A-4 

Drafts of Chapters 3 through 6 

sent out for industry review 

and comments. 

Draft CTG Document, Control of 

Volatile Organic Compound 

Equipment Leaks from Natural 

Gas/Gasoline Processing Plants. 

Meeting with API concerning fugitive VOC emission factor 

development for gas plants. 

NAPCTAC Meeting 

Meeting with industry representatives 

to discuss comments on the 

draft NSPS for natural gas 

processing plants. 

Visits to Phillips Petroleum 

Co., Alvin, Texas, plant and 

Amoco Production Co., Old 

Ocean, Texas, Plant. 

Visits to Texaco U.S.A.; 

Blessing, Texas, Plant and 

Seagull Products Co., Pelacious 

Texas, Plant. 

Meeting with Union Texas 

Petroleum Co. to discuss 

comments on the draft NSPS 

for natural gas processing plants. 
;\PPENDIX B - INDEX TO ENVIRONMENTAL IMPACT CONSIDERATIONS 
0::1 

I 

N 

Table B-1. INDEX TO ENVIRONMENTAL IMPACT CONSIDERATIONS 

Agency Guidelines for Preparing 

Regulatory Action Environmental 

Impact Statements (39 FR 37419) Location ~ithin the Background Information Document (BID) 

1. Background, description, and 

purpose of the regulatory alternatives and the statutory 

authority. 

2. 

The relationship to other 

actions and proposals significantly affected by the regu- latory alternatives. 

Industry affected by the 

regulatory alternatives. 

Specific sources affected 

by the regulatory alternatives. 

Applicable control techniques. 

Alternatives to the action. 

The regulatory alternatives fr~n which standards will be chosen 

are summarized in Chapter 1, Section 1.1, as is the statutory authority for proposing standards. 

To the extent possible, other regulations that apply to the 

affected industries are detailed in Chapter 8, Section 8.2 

and are considered in the econ~ic impact study in Chapter 9. 

The industry and emission sources within the indu~try affected 

by the regulatory alternatives are listed in Chapter 3. 

The speci fie sources affected by the regulatory 

alternatives are summarized in Chapter 3, Section 3.2. 

A discussion of available emission control techniques 

is presented in Chapter 4, Sections 4.2 and 4.3. 

The various categories of alternatives to the actions which 

were considered are listed below. 

a. Alternative regulatory approaches. The alternative 

approaches for regulating VOC emissions under Section 111 of 

the Clean Air Act are outlined in Chapter 6. 

b. Alternative control techniques. The alternative control 

techniques that could be utilized by the regulatory 

alternatives are outlined in Chapter 4. 

(continued) 
CO· 

I 

w 

Agency Guidelines for Preparing 

Regulatory Action Environmental 

Impact Statements (39 FR 37419) 

Agency's canparative evaluation 

of the beneficial and adverse 

environmental. health, social. 

and economic effects of each 

reasonable alternative. 

3. Environmental impact of the 

regulatory alternatives. 

a. Primary impact. 

Primary impacts are those that 

can be attributed directly to 

the action. such as reduced 

levels of specific pollutants brought about by a new standard 

and the physical changes that 

occur in the various media with 

this reduction. 

Table B-1. CONTINUED 

Location Within the Background lnfonnation Document (BID) 

a. A discussion of the Agency's canparative evaluation of the 

various alternative regulatory approaches for VOC emissions 

from onshore natural gas production facilities can be 

found in Chapter 6. Section 6.3. 

b. A sun~ry of the beneficial and adverse environmental 

effects of the regulatory alternatives can be found in 

Chapter 7. A detailed description of the economic impacts 

of each alternative control level. including the capital 

and annual costs to the industry. can be found in 

Chapter 8. The socioeconomic impacts of the regulatory alternatives can be found in Chapter 9. 

The primary air impacts of the alternative control 

levels are quantified in Chapter 7, Section 7.2. 

(continued) 
Agency Guidelines for Preparing Regulatory Action Environmental 

Impact Statements (39 FR 37419) 

b. Secondary impact. 

Secondary impacts are indirect 

or induced impacts. For example, 

mandatory reduction of specific 

pollutants brought about by a 

new standard could result in the 

adoption of control technology that exacerbates another pollution problem and would be a secondary 

impact. 

4. Other considerations. 

a. Adverse impacts which cannot 

be avoided should a regulatory 

alternative be implemented. 

b. Irreversible and irretrievable 

commitments of resources that 

would be involved with the 

regulatory alternatives, should 

one be implemented. 

Table B-1. CONCLUDED 

Location Within the Background Infonnation Document (BID) 

Other environmental impacts (i.e., solid waste, water 

quality) of the individual controls that can be used to 

meet the regulatory alternatives are identified 

qualitatively in Chapter 7, Sections 7.3, and 7.4. 

The energy impacts of the alternative control levels are 

quantified in Chapter 7, Section 7.5. 

A sulllllilry of the potential adverse environmental impacts 

of the regulatory alternatives and a discussion of the 

significance of each impact can be found in Chapter 7. 

A discussion of irreversible and irretrievable 

committment of resources is in Section 7. 6.1. 
APPENDIX C. EMISSION SOURCE TEST DATA 
APPENDIX C. EMISSION SOURCE TEST DATA 

Fugitive emission test data have been collected at six natural 

gas/gasoline processing plants (see Table C-1) by EPA and industry. Two 

gas plants were tested under contract to the American Petroleum 

Institute (API}, and four gas plants were tested under contract to EPA. 

All six gas plants were screened for fugitive emissions using either 

portable hydrocarbon detection instruments, soap solution, or both. 

Instrument screening (using EPA's proposed Method 21, described in 

Appendix D) was performed at all four of the EPA-tested plants (Plants 3, 

4, 5, and 6). The instruments were calibrated with methane. Soap 

screening (using the method described in Reference 1) was performed at 

the two API-tested plants and at three of the EPA-tested plants. Selected 

components were measured for mass emissions at both of the API-tested 

plants (Plants 1 and 2) and at two of the EPA-tested plants (Plants 5 

and 6). These mass emission measurements were used in development of 

emission factors for gas plant fugitives, which are presented in Table 3-1. 

A study of ~~intenance effectiveness at production field tank batteries 

was also performed by API. These data are discussed in Section C.2. 

C.1 PLANT DESCRIPTION AND TEST RESULTS 

One API-tested gas plant was of the refrigerated absorption type, 

and the other was a cryogenic plant. Descriptions and schematics of the 

plants are provided in Reference 1. Of the four EPA-tested plants, the 

first tested was a solid bed adsorption type (Reference 2). Natural gas 

liquids are removed by adsorption onto silica gel, then stripped from 

the bed with hot regeneration gas and condensed out for sales. There 

were three adsorption units, of which only one was operating. This unit 

had a capacity of 60 MMSCFD (million standard cubic feet per day}, and 

was operating between 33 and 55 MMSCFD during the testing period. The 

second unit was shut down and depressurized, and therefore not tested. 

C-2 
Table C-1. GAS PLANTS TESTED FOR FUGITIVE EMISSIONSa 

Data 

Plant collection Plant process Principal screening 

No. sponsor type method(s) used 

1 API Refrigerated Absorption Soaping 

2 API Cryogenic Soaping 

3 EPA Adsorption Instrument, Soaping 

4 EPA Cryogenic Instrument, Soaping 

5 EPA Refrigerated Absorption Instrument, Soaping 

6 EPA Refrigerated Absorption Instrumentb 

aReference 6. 

bless than 50 components were soap screened at plant No. 6. 

C-3 
The third unit was also not operating, but it was under natural gas 

pressure and was tested. 

The second EPA-tested plant was of the cryogenic type (Reference 3). 

Feed gas to the plant is compressed and then chilled. Natural gas 

liquids are condensed out and split into two streams: ethane/propane 

and butane-plus. The cryogenic plant was operating at its rated capacity 

of 30 ~1MSCFD. 

The third EPA-tested plant was of the refrigerated absorption type 

(Reference 4). There were three absorption systems for removal of 

natural gas liquids. The liquids were combined and sent to a single 

fractionation train. The fractionation train separated the liquids into 

ethane, propane, iso-butane, butane, and debutanized natural gasoline. 

Testing was performed on the fractionation train and on the largest 

absorption system. The absorption system that was tested was operating 

at 450 MMSCFD, near its capacity of 500 MMSCFD. 

The fourth EPA-tested plant was also of the refrigerated absorption 

type (Reference 5). There were two parallel absorption trains, and one 

fractionation train. Natural gas liquids were fractionated into ethane/propane, 

propane, iso-butane, butane, and debutanized natural gasoline streams. 

The plant was operating at approximately 450 MMSCFD, about half of its 

rated capacity of 800 MMSCFD. 

A summary of the instrument screening data collected at the four 

EPA-tested plants is presented in Table C-2. A summary of the soap 

screening data collected at the two API-tested pl.ants and at all of the 

EPA-tested plants is presented in Table C-3. (Only a very small amount 

of soap screening data were collected at Plant 6). The instrument 

screening data are tabulated for each plant, showing the number of each 

type of component tested and the percent emitting. The soap screening 

data are not tabulated for each plant but are instead summarized by soap 

score. A complete tabulation of the soap screening data by plant and by 

soap score is provided in Reference 6. 

C.2 INDUSTRY VALVE MAINTENANCE STUDY 

The API study that developed the gas plant data presented in Section C.l 

also included a study of maintenance. Gate valves in gas and condensate 

service in oil and gas production field tank batteries were studied. 

C-4 
The sources were monitored with soap scoring at intervals over a 9-month 

period. t1aintenance was performed on a portion of the valves studied. 

The results of an analysis of this data show that monthly leak occurrence 

was 1.3 percent, monthly leak recurrence was 1.6 percent, and leak 

repair effectiveness was 100 percent. 7 These results compare favorably 

with the 1.3 percent monthly leak occurrence and recurrence and 90 percent 

repair effectiveness used to analyze leak detection and repair control 

effectiveness in Chapter 4 and 7. The industry study results were not 

specifically used here, however, because (1) the data were gathered in 

tank batteries which, based on API data, appear to have different leak 

characteristics, (2) very few valves were studied (25 total data points), 

and (3} a soapscore value of 3 was used to define a leak rather than a 

meter reading of 10,000 ppm. 

C-5 
Table C-2. INSTRUMENT SCREENING DATA FOR EPA-TESTED GAS PLANTSa 

Flanges and 

Valves Relief valves Open-ended lines Compressor seals Pump seals connections 

Pl.:wt No. Percent No. Percent No. Percent No. Percent No. Percent No. Percent 

Nu Tested ~ 10,000 pp41V Tested ~10,000 ppmv Tested ~10,000 ppav Tested ~10,000 PPIIV Tested ~10,000 ppev Tested ~10,000 ppav 

j 331 23.6 10 90.0 45 15.6 0 0.0 l 0.0 223 5.4 

4 506 16.8 7 14.3 65 18.5 4 100 9 44.4 281 2.1 

n 

I !I 1,804 12. 1 60 5.0 472 11. 7 30 46.7 51 33.3 768 3.6 

0"\ 

L 1,038 21.5 3 33.3 139 8.6 2 50.0 40 22.5 506 2.0 

Told) 3,679 16.4 80 17.5 721 ll. 9 36 52.6 101 29.7 1,778 3, l 

aRderence 6. 
Table C-3. SOAP SCREENING DATA FOR API-TESTED AND EPA-TESTED GAS PLANTSa 

Flanges and 

Valves Relief valves Open-ended Hoes Coapressor seals PUIIIJl r.ealr. connections 

<;nap l of % of l of l of l of % of 

Score Nu.ber Total HUIIber lola l Number Total NUIIIber Total Numbe•· Total Number Total 

Cl 

I 0 4,483 7~.l 123 91.8 945 79.2 8 28.6 14 77.8 17,982 92.7 ..... 1 322 5.4 4 3.0 63 5.3 1 3.6 0 0.0 706 3.6 

2 468 7.8 2 1.5 83 7.0 2 7.1 1 5.6 454 2.3 

3 426 7.1 2 1.5 59 4.9 7 2!1.0 0 0.0 190 1.0 

4 _ill 4.6 3 2.2 43 3.6 10 35. 1 3 16. 7 65 0.3 

Total 5,973 134 1,193 28 18 19,397 

alncludes data fro• lwl} API-tesled plauts and four lPA-tested plants. Reference 6 
C.3 REFERENCES FOR APPENDIX C 

1. Eaton, W. S., et al., Fugitive Hydrocarbon Emissions from Petroleum 

Production Operations. API Publication No. 4322. March 1980. 

Docket Reference Number II-I-20, II-I-21.* 

2. Harris, G. E. Fugitive VOC Testing at Houston Oil and Minerals 

Smith Point Plant. U.S. EPA, ESED/EMB Report No. 80-0SP-1. 

October 1981. Docket Reference Number II-A-13.* 

3. Harris, G. E. Fugitive VOC Testing at the Amoco Hastings Gas 

Plant. U.S. EPA, ESED/EMB Report No. 80-0SP-2. July 1981. Docket 

Reference Number II-A-12.* 

4. Harris, G. E. Fugitive VOC Testing at the Texaco Paradis Gas 

Plant, Volume I and II. U.S. EPA, ESED/EMB Report No. 81-0SP-7. 

July 1981. Docket Reference Numbers II-A-17, II-A-18.* 

5. Harris, G. E. Fugitive Test Report at the Gulf Venice Gas Plant, 

Volume I and II. U.S. EPA, ESED/EMB Report No. 80-0SP-8. 

September 1981. Docket Reference Number II-A-14, II-A-15.* 

6. DuBose, D. A., J. I. Steinmetz, and G. E. Harris. Emission Factors 

and Leak Frequencies for Fittings in Gas Plant. Final Report. 

U.S. EPA, ESED/EMB Report No. 80-FOL-1. July 1982. Docket Reference 

Number 11-A-19.* 

7. Memorandum, Hustvedt) K.C., EPA to Durham, J.F .. , EPA 11API/Rockwell 

r1aintenance Data 11 • December 9, 1982. Docket Reference Number II-B-22.* 

*References can be located in Docket Number A-80-20-B at the U.S. 

Environmental Protection Agency Library, Waterside Mall, Washington, 

D.C. 

C-8 
APPENDIX D 

EMISSION t1EASUREMENT AND 

CONTINUOUS MONITORING 

,, 
APPENDIX D. EMISSION MEASUREMENT AND CONTINUOUS MONITORING 

D.1 EMISSION MEASUREMENT METHODS 

D.1.1 General Background 

A test method was not available when EPA began the development of 

control technique guidelines, new source performance standards, and 

hazardous pollutant standards for fugitive volatile organic compounds 

from industrial categories such as petroleum refineries, synthetic 

organic chemical manufacturing, and other types of processes that 

handle organic materials. 

During development and selection of a test method, EPA reviewed 

the available methods for measurement of fugitive leaks with emphasis 

on procedures that would provide data on emission rates from each 

source. To measure emission rates, each individual piece of equipment 

must be enclosed in a temporary cover for emission containment. After 

containment, the leak rate can be determined using concentration 

change and flow measurements. This procedure has been used in several 

studies1'

2 and has been demonstrated to be a feasible method for 

research purposes. It was not selected for this study because direct 

measurement of emission rates from leaks is a time consuming and 

expensive procedure, and is not feasible or practical for routine 

testing. 

Procedures that yield qualitative or semiquantitative indications 

of leak rates were then reviewed. There are essentially two alternatives: 

leak detection by spraying each component leak source with a soap 

solution and observing whether or not bubbles were formed; and, the 

use of a portable analyzer to survey for the presence of increased 

organic compound concentration in the vicinity of a leak source. 

Visual, audible, or olefactory inspections are too subjective to be 

used as indicators of leakage in these applications. The use of a 

portable analyzer was selected as a basis for the method because it 

D-2 
would have been difficult to establish an enforceable leak definition 

based on a subjectve parameter such as bubble formation rates. Also, 

the temperature of the component, physical configuration, and relative 

movement of parts often interfere with bubble formation. 

Once the basic detection principal was selected, it was then 

necessary to define the procedures for use of the portable analyzer. 

Prior to performance of the first field test, a procedure was reported 

that conducted surveys at a distance of 5 em from the components. 3 

This information was used to formulate the test plant for initial 

testing. 4 In addition, measurements were made at distances of 25 em 

and 40 em on three perpendicular lines around individual sources. Of 

the three distances, the most repeatable indicator of the presence of 

a leak was a measurement of 5 em, with a leak definition concentration 

of 100 or 1,000 ppmv. The localized meteorological conditions affected 

dispersion significantly at greater distances. Also, it was more 

difficult to define a leak at greater distances because of the small 

changes from ambient concentrations observed. Surveys were conducted 

at 5 em from the source during the next three facility tests. 

The procedure was distributed for comment in a draft control 

techniques guideline document. 5 Many commenters felt that a measurement 

distance of 5 em could not be accurately repeated during screening 

tests. Since the concentration profile is rapidly changing between 0 

and 10 em from the source, a small variance from 5 em 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 em. This change required 

that the leak definition be increased. Additional testing at two 

refineries and three chemical plants was performed by measuring volatile 

organic concentrations at the interface surface. 

A complication that this change introduces is that a small mass 

emission rate leak ( 11 pin-hole leak 11 ) can be totally captured by the 

instrument and a high concentration result will be obtained. This has 

occurred occasionally in EPA tests, and a solution to this problem has 

not been found. 

D-3 
The calibration basis for the analyzer was evaluated. It was 

recognized that there are a number of potential vapor stream components 

and compositions that can be expected. Since all analyzer types do 

not respond equally to different compounds, it was necessary to establish 

a reference calibration material. Based on the expected compounds and 

the limited information available on instrument response factors, 

hexane was chosen as the reference calibration gas for EPA test programs. 

At the 5 em measurement distance, calibrations were conducted at 

approximately 100 or 1,000 ppmv levels. After the measurement distance 

was changed, calibrations at 10,000 ppmv levels were required. Commenters 

pointed out that hexane standards at this concentration were not 

readily available commercially. Consequently, modifications were 

incorporated to allow alternate standard preparation procedures or 

alternate calibration gases in the test method recommended in the 

Control Techniques Guideline Document for Petroleum Refinery Fugitive 

Emissions. 

Since that time, studies have been completed that measured the 

response factors for several instrument types. 6'

7'

8 The results of 

these studies show that the response factors for methane and hexane 

are similar enough for the purposes of this method to be used interchangeably. Therefore, in later NSPS, the calibration materials were 

hexane or methane. 

The alternative of specifying a different calibration material 

for each type stream and normalization factors for each instrument 

type was not intensively investigated. There are at least four 

instrument types available that might be used in this procedure, and 

there are a large number of potential stream compositions possible. 

The amount of prior knowledge necessary to develop and subsequently 

use such factors would make the interpretation of results prohibitively 

complicated. Additionally, based on EPA test results, the measured 

frequency of leak occurrence in a process unit was not significantly 

different when the leak definition was based on meter reading using a 

reference material and when response factors were used to correct 

meter readings to actual concentrations for comparison to the leak 

definition. 

D-4 
An alternative approach to leak detection was evaluated by EPA 

during field testing. 9'

10 The approach used was an area survey, or 

walkthrough, using a portable analyzer. The unit area was surveyed by 

walking through the unit, positioning the instrument probe within 

1 meter of all valves and pumps. The concentration readings were 

recorded on a portable strip chart recorder. After completion of the 

walkthrough, the local wind conditions were used with the chart data 

to locate the approximate source of any increased ambient concentrations. 

This procedure was found to yield mixed results. In some cases, the 

majority of leaks located by individual component testing could be 

located by walkthrough surveys. In other tests, prevailing dispersion 

conditions and local elevated ambient concentrations complicated or 

prevented the interpretation of the results. Additionally, it was not 

possible to develop a general criteria specifying how much of an 

ambient increase at a distance of 1 meter is indicative of a 10,000 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. 

0.1.2 Emission Testing Experience 

During the data collection phase of this project, tests were 

conducted at four natural gas liquids facilities. Each unit was 

surveyed using ~1ethod 21 and, for portions of two plants, comparative 

screening using a soap scoring technique was performed. The purpose 

of this comparison was to determine if leak detection by the two 

methods could be incorporated into one data set for emission factor 

calculation. The result of this comparison was a general correlation 

between soap scoring and Method 21 and the combination of the two data 

sets for emission factor development. 11 Because soap scoring could 

not be used in all cases and because soap scoring requires subjective 

observations while an objective concentration measurement procedure is 

available, this alternate procedure was not included as a part of the 

reference test procedure. However, soaping is being allowed as a 

preliminary screening technique. For sources where soaping is possible, 

0-5 
soap would be applied to the potential leak surfaces and if no bubbles 

are observed, the source is presumed not to be leaking. 

In addition, source enclosure with measurement was performed at 

two plants to develop additional emission rate data. The test procedures 

and results are described in Reference 11. 

The calibration species used in this study was methane. Flame 

ionization type analyzers were used for screening. The analyzers were 

tested and could achieve the performance requirements of Method 21. 

D.2 CONTINUOUS MONITORING SYSTEMS AND DEVICES 

Since the leak determination procedure is not a direct emission 

measurement technique, there are no continuous monitoring approaches 

that are directly applicable. Continual surveillance is achieved by 

repeated monitoring or screening of affected potential leak sources. 

A continuous monitoring system or device could serve as an indicator 

that a leak has developed between inspection intervals. The EPA 

performed a limited evaluation of fixed-point monitoring systems for 

their effectiveness in leak detection. 8,

12 , 13 The systems consisted 

of both remote sensing devices with a central readout and a central 

analyzer system (gas chromatograph) with remotely collected samples. 

The results of these tests indicated that fixed point systems were not 

capable of sensing all leaks that were found by individual component 

testing. This is to be expected since these systems are significantly 

affected by local dispersion conditions and would require either many 

individual point locations, or very low detection sensitivities in 

order to achieve similar results to those obtained using an individual 

component survey. 

It is recommended that fixed-point monitoring systems not be 

required since general specifications cannot be formulated to assure 

equivalent results, and each installation would have to be evaluated 

individually. 

D.3 PERFORMANCE TEST METHOD 

The recommended fugitive emission detection procedure is Reference 

Method 21. This method incorporates the use of a portable analyzer to 

detect the presence of volatile organic vapors at the surface of the 

interface where direct leakage to atmosphere could occur. The approach 

of this technique assumes that if an organic leak exists, there will 

D-6 
be an increased vapor concentration in the vicinity of the leak, and 

that the measured concentration is generally proportional to the mass 

emission rate of the organic compound. 

An additional procedure provided in Reference Method 21 is for 

the detennination of 11 no detectable emissions ... The portable VOC 

analyzer is used to determine the local ambient VOC concentration in 

the vicinity of the source to be evaluated, and then a measurement is 

made at the surface of the potential leak interface. If a concentration 

change of less than 5 percent of the leak definition is observed, then 

a 11 no detectable emissions 11 condition exists. The definition of 

5 percent of the leak definition was selected based on the readability 

of a meter scale graduated in 2 percent increments from 0 to 100 percent 

of scale, and not necessarily on the performance of emission sources. 

Reference Method 21 does not include a specification of the 

instrument calibration basis or a definition of a leak in terms of 

concentration. Based on the results of EPA field tests and laboratory 

studies, methane or hexane is recommended as the reference calibration 

basis for fugitive emission sources in the natural gas and crude oil 

production industries. 

There are at least four types of detection principles currently 

available in commercial portable instruments. These are flame ionization, 

catalytic oxidation, infrared absorption (NDIR), and photoionization. 

Two types (flame ionization and catalytic oxidation) are know to be 

available in factory mutual certified versions for use in hazardous 

atmospheres. 

The recommended test procedure includes a set of design and 

operating specifications and evaluation procedures by which an analyzer•s 

performance can be evaluated. These parameters were selected based on 

the allowable tolerances for data collection, and not on EPA evaluations 

of the performance of individual instruments. Based on manufacturers• 

literature specifications and reported test results, commercially 

available analyzers can meet these requirements. 

The estimated purchase cost for an analyzer ranges from about 

$1,000 to $5,000 depending on the type and optional equipment. The 

cost of an annual monitoring program per unit, including semiannual 

instrument tests and reporting is estimated to be from $3,000 to 

D-7 
$4,500. This estimate is based on EPA contractor costs experienced 

during previous test programs. Performance of monitoring by plant 

personnel may result in lower costs. The above estimates do not 

include any costs associated with leak repair after detection. 

An alternative preliminary screening procedure has been added for 

those sources that can be tested with a soap solution. These sources 

are restricted to those with nonmoving seals, moderate surface temperatures, 

without large openings to atmosphere, and without evidence of liquid 

leakage. The soap solution is sprayed on all applicable sources and 

the potential leak sites are observed to determine if bubbles are 

formed. If no bubbles are formed, then no detectable emissions or 

leaks exist. If any bubbles are formed, then the instrument measurement 

techniques must be used to determine if a leak exists, or if no detectable 

emissions exist, as applicable. 

The alternative soap solution procedure does not apply to pump 

seals, sources with surface temperatures greater than the boiling 

point or less than the freezing point of the soap solution, sources 

such as open-ended lines or valves, pressure relief valve horns, vents 

with large openings to atmosphere, and any source where liquid leakage 

is present. The instrument technique in the method must be ~sed for 

these sources. 

The alternative of establishing a soap scoring leak definition 

equivalent to a concentration based leak definition is not included in 

the 1~ethod and is not recommended for inclusion in an applicable 

regulation because of the difficulty of calibrating and normalizing a 

scoring technique based on bubble formation rates. A scoring technique 

would be based on estimated ranges of volumetric leak rates. These 

estimates depend on the bubble size and formation rates. A scoring 

technique would be based on estimated ranges of volumetric leak rates. 

These estimates depend on the bubble size and formation rate, which 

are subjective judgments of an observer. These subjective judgments 

could only be calibrated or normalized by requiring that the observers 

correctly identify and score a standard series of test bubbles. It 

has been reported that trained observers can correctly and repeatably 

classify ranges of volumetric leak rates. However, because soap 

scoring requires subjective observations and since an objective 

D-8 
concentration measurement procedure is available, a soap scoring 

equivalent leak definition is not recommended for the applicable 

regulation. The alternate procedure that has been included will allow 

more rapid identification of potential leaks for more rigorous instrumental 

concentration measurement. 

0-9 
D.4 REFERENCES 

1. Joint District, Federal, and State Project for the Evaluation of 

Refinery Emissions. Los Angeles County Air Pollution Control 

District, Report Six of Nine Reports. 1957-1958 •. April 1958. 

Docket Reference Number A-80-20-B (VOC) II-I-1.* 

2. Wetherold, R. and L. Provost. Emission Factors and Frequency of 

Leak Occurrence for Fittings in Refinery Process Units. Radian 

Corporation, Austin, TX. For U.S. Environmental Protection 

Agency, Research Triangle Park, NC. Report Number EPA-600/2-79-044. 

February 1979. Docket Reference Number A-80-20-B (VOC) II-A-27.* 

3. Telecon. Harrison, P., Meteorology Research, Inc., with Hustvedt, 

K.C., EPA, CPB. December 22, 1977. Docket Reference Number A-80-20-B 

(VOC) II-E-17.* 

4. Miscellaneous Refinery Equipment VOC Sources at ARCO, Watson 

Refinery, and Newhall Refining Company. U.S. Environmental 

Protection Agency, Emission Standards and Engin~ering Division, 

Research Triangle Park, NC. EMB Report Number 77-CAT-6. December 

1979. Docket Reference Number A-80-20-B (VOC) II-A-28.* 

5. Hustvedt, K.C., R.A. Quaney, and W.E. Kelly. Control of Volatile 

Organic Compound Leaks from Petroleum Refinery Equipment. U.S. 

Environmental Protection Agency, Research Triangle Park, NC. 

OAQPS Guideline Series. Report Number EPA-450/2-78-036. June 1978. 

Docket Reference Number A-80-20-B (VOC) II-A-3.* 

6. DuBose, D.A., and G.E. Harris. Response Factors of VOC Analyzers 

at a Meter Reading of 10,000 ppmv for Selected Organic Compounds. 

U.S. Environmental Protection Agency, Research Triangle Park, NC. 

Publication No. EPA 600/2-81-051. March 1981. Docket Reference 

Number A-80-20-B (VOC) II-A-32.* 

7. Brown, G.E., et al. Response Factors of VOC Analyzers Calibrated 

with Methane for Selected Organic Compounds. U.S. Environmental 

Protection Agency, Research Triangle Park, NC. Publication No. 

EPA 600/2-81-002. September 1980. Docket Reference Number A-80-20-B 

(VOC) II-A-34.* · 

8. DuBose, D. A., et al. Response of Portable VOC Analyzers to 

Chemical Mixtures. U.S. Environmental Protection Agency, Research 

Triangle Park, N.C. Publication No. EPA 600/2-81-110. June 1981. 

Docket Reference Number A-80-20-B (VOC) II-A-35.* 

9. Emission Test Report: Dow Chemical Company, Plaquemine, La. Et1B 

Report No. 78-0CM-12-c, December 1979. Docket Reference Number 

A-80-20-B (VOC) II-A-31.* 

10. Weber, R.C., et al. 11Evaluation of the Walkthrough Survey ~1ethod 

for Detection of Volatile Organic Compound Leaks, .. EPA Report No. 

600/2-81-073, EPA/IERL Cincinnati, Ohio. April 1981. Docket 

Reference Number A-80-20-B (VOC) II-A-33.* 

D-10 
11. 11Data Analysis Report: Emission Fact(1rs and Leak Frequencies for 

Fittings in Gas Plants, .. EMB Report No. 80-FOL-1. July 1982. 

Docket Reference Number A-80-20-B (VOC) II-A-36.* 

12. 11Emission Test Report: Sun Petroleum Products Co., Toledo, OH, 11 

EMB Report No. 78-0CM-12B, October 1980. Docket Reference Number 

A-80-20-B (VOC) II-A-29.* 

13. 11Emission Test Report: Union Carbide Corporation, Torrance, CA, .. EMB Report No. 78-0CM-12A, November 1980. Docket Reference 

Number A-80-20-B (VOC) II-A-30.* 

*References can be located in Docket Number A-80-20-B (VOC) at the 

U.S. Environmental Protection Agency Library, Waterside Mall, Washington, D.C. 

D-11 
APPENDIX E - MODEL FOR EVALUATING THE EFFECTS OF LEAK DETECTION 

AND REPAIR ON FUGITIVE EMISSIONS FROM PU:~PS AND VALVES 
E.1 INTRODUCTION 

The purpose of Appendix E is to present a mathematical model (LDAR 

Model) for evaluating the effectiveness of leak detection and repair 

programs on controlling fugitive emissions from pumps and valves. In 

contrast to the ABCD model presented in Chapter 4 for analysis of leak 

detection and repair programs on relief valves and compressor seals, the 

LDAR model incorporates recently available data on leak occurrence and 

recurrence and data on the effectiveness of simple in-line repair. 1 In 

the ABCD model, leak detection and repair program impacts are evaluated 

through emission correction factors that are based in part upon engineering 

judgment. 

E.2 LDAR MODEL 

The LDAR model is based on the premise that all sources at any 

given time are in one of four categories: 

1) Non-leaking sources (sources screening at less than the action 

level); 

2) Leaking sources (sources screening at greater than or equal to 

the action level); 

3) Leaking sources that cannot be repaired on-line and are awaiting 

a shutdown for repair; and 

4) Repaired sources with early leak recurrence. 

There are four basic components to the LDAR ~odel: 

1) Screening of all sources except those in Category 3, above; 

2) Maintenance of screened sources in Category 2 and 4 above; 

3) Rescreening of repaired sources; 

4) Process turnaround during which maintenance is performed for 

sources in Categories 2, 3, and 4, above. Figure E-1 shows a schematic 

diagram of the LDAR model. 

Since there are only four categories of sources, there are only 

four 11 leak rates 11 for all sources. In fact, there are only three distinct 

leak rates since the repaired sources experiencing early leak recurrence 

are assu~ed to have the same leak rate as sources that were unsuccessfully 

repaired. The LDAR model does not evaluate gradual changes in leak 

rates over time but assumes that all sources in a given category have 

the same average leak rate. 

E-2 
r'T'1 

I 

w Qu.arterlJ 

ScrHttlaa a..t 

Katateaaace of 

Leak! .. 

S.O.rcea1 

Lukl.. Soul'caa 1 

vU .. lllltateaeoc:e 

Peda~ 

.,._Led.! .. 

Source a 

loul'c.e• aot Ia heel 

&o.rua lepahed ultll LeU 

hcurreace Durlq ttoatlil 

le 1r ed Source• 

ILeakJae; aourc .. taclude all .aurc .. vhlch h•• leek l"ecuneii'Ce 0 bad eapettenc.N 

eady btl una. or "-41 leak occureoce aod re.alned lealtan at tiM ... of tM ,..ec .. t .. •-nar, 

Leakera 

Fi(Jure E-1. SCHEMATIC DIAGRAM OF THE LDAR MODEL 

Qw.arter ly kn••l"' ef all Sourua end 

ltatat .... ac .. 'or 

LMU .. Sourc .. 
The LDAR model is implemented by a statistical analysis LDAR system 

computer (SAS) computer program enabling investigation of several leak 

detection and repair program scenarios. General inputs pertaining to 

the leak detection and repair program may vary (for example, frequency 

of inspection, repairs, and turnarounds). Further, input characteristics 

of the emission sources may vary. Inputs required in the latter group 

include: 

1) The fraction of sources initially leaking; 

2) The fraction of sources that become leakers during a period; 

3) The fraction of sources with attempted maintenance for which 

repair was successful; 

4) The emission reductions from successful and unsuccessful 

repair. 

Other assumptions associated with the model are: 

1) All repairs occur at the end of the repair period; the effects 

associated with the time interval during which repairs occur are negligible; 

2) Unsuccessfully repaired sources instantaneously fall into the 

unrepaired category; , 

3) Leaks other than unsuccessful maintenance and early recurrences 

occur at a linear rate with time during a given inspection period; 

4) A turnaround essentially occurs instantaneously at the end of 

a turnaround period and before the beginning of the next monitoring period; and 

5) The leak recurrence rate is equal to the leak occurrence rate; 

sources that experience leak occurrence or leak recurrence immediately leak at the rate of the "leaking souq:es" category. 

E. 3 t10DEL OUTPUTS 

The outputs from the LDAR model are summarized in Table E-1 for 

three leak detection and repair scenarios for valves (quarterly, monthly/ 

quarterly, and monthly) and two scenarios for pumps (quarterly and 

monthly). 2 These scenarios enabled estimation of emission reductions 

and costs for valves and pumps under Regulatory_Alternatives II, Ill, 

and IV. These estimates are presented in Chapters 7 and B. 

E-4 
Table E-1. RESULTS OF THE LDAR MODEL LEAK DETECTION AND REPAIR PROGRAMS 

Total fraction of Fraction of sources 

sources screened in operated on in 

Emission source Emission factor, Percent emission second turnaround - second turnaround - and LOR scenario kg/day reduction annual average annual average 

Valves 

Quarterly 0.041 (0.11) 77 4.0 0.19 

Monthly/Quarterly 0.041 (0.11) 78 4.3 0.19 

I'T1 Monthly 0.029 ( 0.079) 84 11.9 0.19 I 

(,11 

Pumps 

Quarterly 0.50 (0.63) 58 4.0 0.39 

Monthly 0.42 (0.53) 65 12.0 0.41 

XX = VOC emission values. 

(XX) =Total hydrocarbon emission values. 
E. 4 REFERENCES 

1. Wetherold, R. G., G. J. Langley, et. al. Evaluation of Maintenance 

for Fugitive VOC Emissions Control. EPA/IERL EPA-600/52-81-080. 

May 1981. Docket Reference Number II-A-11.* 

2. Memorandum. T.W. Rhoads, Pacific Environmental Services, Inc., to 

Docket A-80-20. Evaluation of the Effects of Leak Detection and 

Repair on Fugitive Emissions in the Onshore Natural Gas Processing Industry Using the LDAR Model. November 1, 1982. Docket Reference 

Number II-B-18.* 

*References can be located in Docket Number A-80-20-B at the U.S. 

Environmental Protection Agency Library, Waterside t1all, Washington, D.C. 

E-6 
APPENDIX F - DOCKET ENTRIES ON CORRELATION BETWEEN COST-EFFECTIVENESS 

AND THROUGHPUT FOR SMALL GAS PLANTS 

Attached as Appendix F are two docket entries that develop a 

correlation between cost-effectiveness and throughput for the recommended 

new source performance standard controls for pump seals, valves, and 

pressure relief valves. This analysis is only valid for small gas 

plants that do not fractionate mixed natural gas liquids into separate 

products. Two major assumptions used in this analysis are that throughput 

can be related to emissions for small plants and that small non-complex 

gas plants would use off-site personnel to implement a leak detection 

and repair program. These docket entries are included here to enable 

interested parties to review the basis for the recommended small size 

cutoff for gas plants without having to obtain copies from the docket. 
M E M 0 R A N D U M 

DATE: November 8, 1982 

TO: Docket A-80-20 

FROM: Tom Norwood, PES, Inc~ 

SUBJECT: Cost-Effectiveness as a Function of Throughput for Small 

Gas Plants 

-------------------------------------------------------J--------------

In a meeting with EPA on August 18, 1982, representatives of 

Allied Corporation (Union Texas Petroleum Corporation) indicated that 

the leak detection and repair programs required by the recommended 

NSPS for VOC fugitive emissions for on-shore natural gas processing 

plants would have ·to be performed by corporate staff engineers rather 

than plant personnel. Allied indicated in NAPCTAC testimony that to 

ensure the program was properly implemented, the cost of such a program 

would be $15,000 annually as opposed to the $2,070 indicated by EPA 

(Attachment I). It was assumed that Allied's estimates were based on 

1982 dollar values. 

Given that central office personnel may be required to perform 

the program, the cost estimates prepared by Allied were exanined for 

reasonability and corrected to 1980 dollar values as described in 

Attachment II. The Allied estimates seem to be slightly excessive, as 

follows: 

(1) Inspector Labor: Assuming a plant has 256 valves, relief 

valves, and pump seals subject to the leak detection and 

repair program (BID Model Plant A), the complete inspection should take less than 5 hours, as opposed to the two days predicted by Allied. This time is illustrated in Table 1. 

Eight hours should be allowed, however, to cover travel time 

and preparation for testing. Four extra hours are allowed 

for return air travel. Thus, a total of 1~ days is considered 

realistic. 

{2) Travel living expense--since only one day in the field is 

required, the living expense should be approximately: 

( 1980 dollars) 

Car $34 

Living Expense 57 

Total $9I 

F-2 
2 

In the adr.linistrative cost portion, no additional travel expense 

is required. As such, the Allied estimates were adjusted as shovm in 

Table II, and annual costs calculated for monthly inspections. The 

cost of replacement pump seals and of amortized initial repairs are 

added to the EPA estimate. 

As the cost incurred for routine leak detection and repair is 

relatively fixed for small plants, the control cost effectiveness is 

primarily a function of plant emissions. As such, a limiting plant 

size can be determined for a given cost effectiveness. Table III 

presents the emissions reductions for a small plant as presented in 

BID Table 7-2. Based on the component mixture used in this small 

plant, the average emissions reduction for monthly leak detection and 

repair was determined to be 82 percent. As the cost effectiveness is 

a function of the amount of VOC removed, a graph of cost effectiveness 

versus emissions reduction can be nade (Figur~ 1). 

Based on the source tests performed by EPA for small gas plants, 

the VOC emissions can be related to throughput as: 

VOC Emissions (Mg/yr) = throughput (MMscfd) 1 

THC emission reductions can be calculated from Table III as (for model 

plant A): 

THC reduction = 116 Mg THC x VOC reduction 

40.2 t1g voc 

or THC = 2.9 x VOC 

Cost effectiveness is equal to the annualized cost divided by the 

emissions reduction. The annualized cost is reduced by the value of 

the products retained in the process. Based on the BID, the VOC value 

was established as $192/t1g and the methane-ethane value vJas $61/t1g. 

Since the emissions reduction for monthly monitoring v-1as 82 percent, 

the net annual cost = 

COST ($/yr) = $15,013 (from Table III) - [$61 x (THC - VOC) 

+ $192 x VOC] x 0.82 

The cost effectiveness is: 

CE ($/Mg) = $15,013 - [61 (1.9 x VOC) + 192 x (VOC)] x 0.82 

0.82 X VQC 

= $18,300 - 300 ~1Mscfd 

1

r1emorandum, K.C. Hustvedt, EPA to J. F. Durham, EPA; 11Estimation of 

VOC Emissions as a Function of Throughput for Small Gas Plants .. ; 

November 5, 1982. Docket Reference Number II-B-24. 

F-3 
3 

Using these relationships, cost effectiveness can be calculated 

for any plant throughput. Figure 1 presents a curve of cost effectiveness 

of the recommended leak detection and repair program as a function of gas 

plant capacity. This curve can be used to select a plant size cutoff. 

Component 

Valves 

Relief Valves 

Pump Seals 

Table I. LEAK DETECTION TIME REQUIREMENTS (~1ode 1 Plant A) 

Number in Plant 

250 

4 

2 

Total 

Min/Componenta Total Minutes 

1 250 

8 32 

5 10 

292 minutes = 4 hrs 52 min 

aBID Chapter 8, 2-man team. 

F-4 
4 

TABLE II 

COMPARISON OF EPA AND ALLIED 

LEAK DETECTION AND REPAIR COSTS ESTIMATES FOR RECOHPENDED NSPS 

MONITORING WITH OUTSIDE PERSONNEL 

Plant Inspection Costs for Each Trip 

Mechanic 

Inspector 

Air Travel 

Car 

Living 

Sub Total 

Allied Estimate (1982 $) 

8 hrs 

16 hrs 

2 days 

2 days 

$200 

384 

200 

80 

100 

$964 

Additional Ad~inistrative Costs for Each Trip 

By Inspector 

1 day in office 

1/3 day in plant Travel Expense 

Subtota 1 

Total Cost per 

Sample Period 

Annual Costs 

Instrument Costs 

(BID Basis) 

Monthly Inspection 

$192 

64 

30 

$286 

$1,250 

$ 5,500 $15,000 

Other Costs Not Considered By Allied 

Replacement Seals Pumps 

Amortized Initial Repairs 

Total Annual Cost $20,500 

Basis: 

Mechanic $25/hr 

(With Overhead) 

Salary Technical Staff Person $192/day (\~ith Fringes) 

F-5 

EPA -~stimate ( 1980 $) 

8 hrs 

12 hrs 

1 day 

1 day 

$144 

216 

167 

34 

57 

$618 

$144 

not required 

not required 

$144 

$762 

$5,500 

$9' 144 

114 

255 

$15,013 

$18/hr 

$18/hr 
Component Type 

Valves 

Relief Valves 

Pump Seals 

Total 

Emissions 

XX = VOC 

(XX) = THC 

Reduction* 

5 

TABLE III 

EMISSIONS REDUCTIONS (MODEL PLANT A) 

Uncontrolled Emissions t~onth ly LDRP 

kg/day kg/day 

45 (120) 7.3 (20) 

1.3 (18) 0. 40 ( 4. 4) 

2.4 (3.0) 0.84 ( 1. 1) 

48.7 (141) 8.54 (35.5) 

82% ( 82%) 

*ER =Uncontrolled Emissions - Controlled Emissions x 100% 

Uncontrolled Emissions 

F-6 

Emission Reduction 

kg/day 

37.7 (100) 

0.9 (73.6) 

1.6 ( 1. 9) 

40.2 (116) 
10 

8 

C'l 

::E 

-

0 

0 6---1 0 

r- I ~ 

,., 

I (./) 4J "'"'-~ (./) 

w 

z 

w 

> 

....... 

tu 

w 

LJ... 

LJ... 

w 

t- 2 (./) 

0 

u 

0 5 10 15 20 25 30 35 40 45 50 

PLANT SIZE (MMscfd) ~ 

Figure 1 - Cost Effectiveness Vs. Plant Size for Small Gas Plants 
J\ttach111ent l 

COSTS FOR ROUTINE INSPECTION & REPAIR PROGRAM 

FoR ONE SIZE A PLANT 

CosT BAsis = CoNTRACT MECHANIC <WEsT TEXAs) = $25/HouR 

(WITH OVERHEADS) 

SALARY TECHNICAL STAFF MAN 

(\iiTH FRINGES) 

PLANT MoNTHLY INsPECTION TRIP. 

MECHANIC - 3 HouRs 

INSPECTOR - SALARY - 2 DAYS 

TRAVEL ExPENSES 

AIRLINES 

CAR 

LIVING ExPENSES 

SuB TJJTAL 

ADDITIONAL ADMINISTRATIVE TIME 

:= $192/DAY 

200 

384 

200 

80 

100 

-

964 

BY INSPECTOR - 1 DAY/MONTH IN OFFICE 192 

1 DAY/QuARTER IN PLANT 

SALARY ($192 f 3) 64 

TRAVEL ExPENSE ($90 f 3) _2U 

MINIMUM MoNTHLY CosT 1250 

ANNUAL CosT - RouTINE T&I ONLY $15JOOO 

EsTIMATED EPA ToTAL PRoGRAM CosT $ 2J070 

F-8 
ATTACHt1ENT II -Derivation of EPA Costs 

Assuming Allied costs are 1982 $ 

Correction Factor: 1 CE Index July 82 314.22 

I. Air Travel 

Allied = $200 

Corrected = 2b0/1.19 

II. Car 

Allied 2 days, $80 

( 1 day = $40) 

Corrected = $40/1.19 

July 80 263.2 

Ratio= 1.19 

= $167 

= $34 

I I I. Living Allied 2 days $100 

for 1 day, will assume Allied estimate is 1 night motel 0 $35.00 

and two days expenses @ $32.50/day 

Allied for 1 day= 32.50 + 35.00 = $67.50 

Corrected = 67.50/1.19 = $57 

IV. All labor- will use BID basis of $18/hr 

Table 8-5 

V. Instrument Costs 

will use BID basis of $5,500/yr 

(Table 8-9} 

References 

1 - Chemical Engineering, Vol. 

October 18, 1982 

2 - Chemical Engineering, Vol. 

October 6, 1980 

F-9 

89' No. 21, 

87, No. 20, 
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

Office of Air Quality Planning and Standards 

Research Triangle Park, North Carolina 27711 

November 5, 1982 

MEMORANDUM 

SUBJECT: Estimation of VOC Emissions as a Function of Throughput for Small 

Gas Plants 

FROM: K. C. Hustvedt 

Petroleum Section, CPB/ESED 

TO: James F. Durham, Chief 

Petroleum Section, CPB/ESED 

The purpose of this memo is to document the development of a correlation 

between VOC emissions and throughput capacity for small gas plants. The 

results of the analysis show that the VOC emissions [in megagrams per 

year (Mg/yr)] from small gas plants are approximately equal to plant 

throughput capacity in millions of standard cubic feet per day (MM scfd). 

This correlation can be used to determine a size cutoff for small gas 

plants. 

In general, there is no relationship between throughput capacity and 

emissions. Emissions are related to number of pieces of equipment, or process 

complexity, and process complexity does not consistently relate to throughput 

capacity. However, as throughput capacity is reduced to relatively small 

quantities, it seems reasonable to assume that emissions would not remain 

primarily related to process complexity. If emissions were completely 

unrelated to throughput capacity, complex plants (Model Plant C) with very 

small throughput capacities such as one million cubic feet per day would 

lose a significant portion of their product (almost 10 percent). However, it 

is likely that these plants would take action to reduce these losses and 

therefore it is likely that emissions would be less for smaller plants. 

The basis used for developing this correlation is the results of 

the EPA source tests of two relatively small gas plants. Table l shows 

the development of the leaker and nonleaker emission factors for valves, 

relief valves, and pump seals based on the technique described in 

EPA-450/3-82-010 (April 1982), "Fugitive Emission Sources of Organic 

Compounds -Additional Information on Emissions, Emission Reductions, and 

Costs" (AID). Table 2 and 3 present the development of emission estimates 

for the two EPA tested small gas plants based on the factors presented 

in Table 1. Plant 3 (Table 2) emits 89.2 kilograms per day (kg/day) of 

VOC (32.6 Mg/yr) and has a capacity of 60 MM scfd for a ratio of emissions 

to throughput of 0.54. Plant 4 (Table 3) emits 120 kg/day (43.9 Mg/yr) 

F-10 
of VOC and has 

ratio of 1.46. 

estimation for 

the throughput 

·3 Attachments 

2 

a capacity of 30 ~1 scfd for emissions to throughput 

The arithmetic average of these two ratios yields the 

small gas plants that the VOC emissions in 1~/yr equals 

in MM scfd (average ratio equals 1.00). 

F-11 
, 

I 

N 

Source 

Valves 

(VOC) 

(THC) 

Relief Valves 

(VOC) 

(TIIC) 

Pump Seals 

(VOC) 

(TIIC) 

'fable l. DEVELOPNENT OF EMISS WN FACTORS FOR LEAKING AND NON LEAKING 

SOURCES IN GAS PLANTSa 

Leaker Leaker Nonleaker Nonleaker 

Overall Correction Emission Correction Emission 

Emissionb Factor Factor(b ,c) Factor FactorCb,d) Factor 

(kg/ day) (kg/ day) (kg/ day) 

0.18 86 0.86 14 0.031 

T8 82 

0.48 87 2.3 13 0.076 

T8 82 

0.33 77 1.3 23 0.094 

T9 8T 

4.5 77 18 23 1.3 

19 8T 

1.2 79 2.9 21 0.38 

TI 67 

1.5 79 3.6 21 0.95 

TI TI 

a Technique described in EPA-450/3-82-010 (April 1982) "Fugitive Emission Sources of Organic Compounds -

Additional Information on Emissions, Emission Reduction, and Costs." (AID) 

b Emission factors and the inputs to the correction factors are from ESED/EMB Report No. 80-FOL-1 (July 1982), 

"!o'requency of Leak Occurrence and Emission Factors for Natural Gas Liquid Plants." 

c As outlined in the AID, the leaker correction factor is the ratio of the percent of overall emissions from 

leaking sources divided by the percent of overall sources leaking. This number is multiplied times the 

overall emission factor to derive the leaker emission factor. 

d As discussed under footnote "c," the nonleaker correction factor is the ratio of the percent of overall 

emissions from nunleaking sources divided by the percent of overall sources that are not leaking. 
..,., 

I 

_... 

w 

Table 2. ESTIMATED EMISSIONS FOR EPA PLANT. TEST NUMBER 3 (60MH scfd capacity) 

Total Number Percent Number Leakera 

Source Sources Leaking Leaking Emissions 

__________________________________________ (!tg/<!_a_Y_l __ 

Valves 

Pressure 

Relief Valves 

Pump Seals 

Totnl 

341 

1 1 

XX - VOC Emissions 

23.6 

90.0 

o.o 

(XX) - Total Hydrocarbon Emissions 

80 68.8 (184) 

9 11.7 (162} 

0 0 (O) 

80.5 (346} 

Number Not 

Leaking 

261 

2 

Nonleakerb 

Emissions 

(kgfday) 

8.1 (19.8} 

0.2 (2.6) 

0.4 (1) 

8.7 (23.4) 

Total 

Emissions 

---'-(k_,g~fday} 

76.9 (204) 

11 • 9 ( 1 65) 

0.4 ( 1) 

89.2 ( 3 70) 

Reference: Fugitive VOC Testing at Houston Oil and Minerals Smith Point Plant. U.S. EPA, ESED/EHB 

Report No. 80-0SP-l, October 1981. 

a Based on leaker emission factor derived in Table 1. 

b Bnsed on nonleaker emission factor derived in Table 1. 
., 

I 

__, 

+:-

Table 3. ESTIMATED EMISSIONS FOR EPA PLANT TEST NUMBER 4 (30MM scfd capacity) 

Total Number Percent Number Leakera 

Source Sources Leaking Leaking Emissions 

____________________________________ (_kg/day) __ 

Valves 

Pressure 

Relief valves 

Pump Seals 

Total 

565 

- 13 

1 4 

XX - VOC Emissions 

16.8 

14.3 

44.4 

(XX) - Total Hydrocarbon Emissions 

95 81.7 (218) 

2 2.6 (36) 

6 17.4 (21.6) 

102 (276) 

Number Not 

Leaking 

470 

1 1 

8 

Nonleakerb Total 

Emissions Emissions 

(kgj_9_a_x_) _________ (kg/~a.xl__ __ _ 

14.6 (35.7) 96.3 (254) 

1.0 (14.3) 3.6 (50.3) 

3.0 (7.6) 20.4 (29.2) 

18.6 (57.6) 120 ( 334) 

Reference: Fugitive VOC Testing at the AMOCO Hastings Gas Plant. U.S. EPA, ESED/EMB 

Report No. 80-0SP-2, July 1981. 

a Based on leaker emission factor derived in Table 1. 

b Based on nonleaker emission factor derived in Table 1. 
APPENDIX G 

REVISED COMPRESSOR SEAL EMISSION FACTORS AND 

SEAL VENT SYSTEM CONTROL COSTS 

Appendix G contains three memoranda that document revisions to the 

emissions estimates and control cost estimates for compressors. The 

compressor seal emission factors presented in Chapters 3, 4, 7 and 8 of 

this document were revised. The original emission factors represented the 

average emission from all compressors, including those processing dry gas. 

Because dry gas compressors are not subject to the proposed standards, the 

emission factors were revised to represent average emissions from wet gas 

and natural gas liquids compressors, the compressor types that are covered 

by the proposed standards. The development of the revised emission factors 

is documented in the memorandum dated February 10, 1983, that is included 

in this appendix. 

After completion of Chapter 8 of this document, the costs for 

reciprocating compressor seal controls were also revised in response to 

comments received from industry representatives. The revised costs are 

presented in the memorandum dated February 23, 1983, that is included in 

this Appendix. Finally, the effect of control device costs on compressor 

seal vent enclosure cost effectiveness is included in this appendix in a 

memorandum dated June 28, 1983. 
•• I J '4•, 

.: ;;r~ . 

~~a: -. ' . ·~- ..-

lJNlTED STATES ENVIRONMU,JIAL PROTECTION AGE:\iCY 

Off1ce of .ll..1r Oual1ty Plannmg and Standards 

Research Triangle Park, North Carolina 27711 

February 10, 1983 

MEMORANDUM 

SUBJECT: Revised Gas Plant Compressor Seal Emission Factor 

FROM: K. C. Hustvedt ~v{ft--

Petroleum Section, Chemicals and Petroleum Branch, ESED (MD-13) 

TO: James F. Durham, Chief 

Petroleum Section, Chemicals and Petroleum Branch, ESED (MD-13) 

Recommendation 

In the February 3, 1983, AA review package for the onshore production 

new source performance standard (ESED Project No. 80/22A}, we included a 

recommendation to exempt dry gas equipment from the standards. A review 

of the data used in developing our present compressor seal VOC emission 

factor (0.36 megagrams per year (Mg/yr) per seal} shows a large portion 

of the data are from dry gas compressors; therefore, the overall emission 

factors used in the package were not representative of the population 

now being regulated. In developing the basis for compressor seal regulations, I recommend that the refinery hydrocarbon service compressor 

seal VOC emission factor (5.5 Mg/year per seal} be used for natural gas liquids (NGL} service compressor seals and that an estimated emission 

factor (0.7 Mg/yr per seal} be used for wet gas service compressor seals. 

Weighting these emission factors based on the occurrence of these compressor seal services in the API and EPA testing yields an average gas plant 

compressor seal VOC emission factor of 2.3 Mg/yr. Further, using equipment controls to reduce these emissions will essentially eliminate the emissions 

and, where it is technically feasible, quarterly monitoring will reduce 

the VOC emissions to 0.4 Mg/yr. 

Background 

The background information document (BID} for the gas plants NSPS 

states that the compressor seal emission factor is probably substantially understated. This is because both the EPA and API testing of compressors included only open frame compressor distance piece emissions. No seal 

packing vents or enclosed distance pieces were tested. In the past, 

industry has stated that most of the compressor seal emissions will come 

from the seal packing vent if the compressor has one. They have also 

stated that enclosing and venting the distance piece is likely to increase 

compressor seal emissions because the seal is harder to visually inspect for 

failure and because seal maintenance is more difficult (the enclosure 

must be removed). These industry comments certainly support our contention 

that the compressor seal emisson factor could be substantially understated. 

G-2 
2 

Based on comments received at the NAPCTAC meeting that certain sources 

within gas plants have essentially no VOC emission reduction potential and 

a subsequent review of the available data, we have recommended that the 

NSPS include an exemption for dry gas service equipment (defined as less 

than 1.0 weight percent VOC). Because our data base includes dry gas 

compressors and because these are likely to have the lowest VOC emissions 

of the compressors studied, the data base should be reviewed to determine 

if the emission factors should be corrected to represent only the compressor 

seals affected by the recommended NSPS. 

Review of Available Data 

Table 1 shows a summary of the gas plant compressor seal data used 

to develop the gas plant emission factor. As you can see, there were 

71 seals screened and 26 measured for mass emissions. Over one-third 

of the sources screened and measured were in dry gas service. While 

deleting the dry gas service data and recalculating a new emission factor 

based on the remaining data would be possible, this would not necessarily 

result in a better emission factor due to another shortcoming. As shown 

in Table 1, 16 of the remaining (non-dry gas) 47 compressor seals, or 

about one-third are in natural gas liquids (NGL) service and only one of 

these 16 was tested for mass emissions. Simply calculating a new emission 

factor based on the existing data base (after remov~~g the dry gas compressors) 

would greatly understate the VOC emissions from NGL compressor seals because 

the mass emissions data from wet gas compressors (averaging 6.8 percent VOC) 

are used to estimate mass emissions from NGL compressors (100 percent VOC 

in the one compressor tested) in the development of emission factors. 

For these reasons, different methods should be used to develop emission 

factors for gas plant compressor seals. 

Development of Emission Factors 

Because there is a large difference in process stream VOC concentration 

between NGL and wet gas service compressors as seen in Table 1, emission factors 

are developed for both services. NGL service compressors contain mixed 

natural gas liquids, LPG, propane refrigerant, etc., and usually contain 

greater than 50 percent VOC. In gas plant testing of NGL compressors, 

16 were screened for leakage, yet only one seal was tested for mass 

emissions. Because these limited data are insufficient for direct emission 

factor calculation, other methods of developing emission factors were 

investigated. The technique based on percent of sources leaking used to 

calculate emission factors for chemical plant compressor seals in the 

AID (Fugitive Emission Sources of Organic Compounds: Additional Information 

on Emissions, Emission Reductions, and Costs, EPA 450/3-82-010, April 1982) could be used, but it was felt that the 83 percent (5 of 6) NGL service 

compressor seals leaking found by EPA was not representative of the natural gas 

G-3 
3 

processing industry. These NGL service compressors are, however, essentially 

identical to hydrocarbon service compressors in petroleum refineries and 

thus the refinery compressor seal VOC emission factor of 15 kg/day (5.5 Mg/yr) 

will be used for gas plant NGL service compressor seals. 

For wet gas service compressors, it appears as though sufficient 

data are available to use the AID techniques to calculate an emission 

factor. Fourteen out of 30, or 46.7 percent, of the wet gas service 

compressor seals leaked. Using the procedure outlined in Section 2 of 

the AID, this leak frequency translates into an emission factor of 19.2 

kg/day (7.0 Mg/yr) as shown in Table 2. This factor, however, is for total 

hydrocarbon emissions (THC) and only a portion of the wet gas service 

compressor seal THC emissions would be VOC. Based on an estimated average 

VOC concentration of 10 weight percent, the wet gas service compressor 

seal VOC emission factor would be 1.9 kg/day (0.70 Mg/yr). 

To obtain an overall gas plant compressor seal emission factor, the 

weighted average of the wet gas and NGL service emission factors are 

used. As shown in Table 1, 66 percent (31 of 47) of the seals screened 

were in wet gas service and 34 percent (16 of 47) were in NGL service. 

Weighting the individual emission factors by these percentages yields an 

average emission factor for gas plant compressor seals of 6.4 kg/day (2.3 Mg/yr) of VOC and 18 kg/day (6.6 Mg/yr) of THC. 

Emission Reductions 

In the calculation of the emission reduction obtained through control 

of gas plant compressor seals, 100 percent control is estimated for 

equipment controls. In the CTG, however, quarterly monitoring is allowed 

where it is technically feasible. In calculating the ABCD estimated 

emission reduction, the B, C, and D values from Table 7-1 of the Refinery BID (EPA 450/3-81-015a, November 1982) are used because the refinery 

compressor seal data form the basis for the new gas plant compressor 

seal emission factors. A weighted average A factor for wet gas and NGL 

service compressor seals is used. For NGL the A factor is 0.91 (Refinery BID) and for wet gas compressors the A factor is 0.94 [18026 kg/day per thousand seals (leaker emissions from Table 2) divided by 19172 kg/day 

per thousand seals (total emissions in Table 2)]. Weighting these A 

factors as was done for the overall emission factor yields an average A 

factor of 0.93. Overall emission reduction is therefore calculated as 

follows: 

Emission Reduction = A x B x C x D 

= 0.93 X 0.90 X 0.98 X 0.98 

= 0.80 

G-4 
4 

This estimated 80 percent emission reduction is then corrected as was 

explained in the AID and the Gas Plant BID to lessen the impact of the 

estimated B factor on the overall estimate. As was determined in 

T. Rhoads (PES) November 1, 1982, memo, "Calculation of Controlled Emission 

Factors for Pressure Relief Valves and Compressor Leaks", the VOC correction 

factor is 1.04 and the THC correction factor is 1.01. Using these 

correction factors, the estimated emission reductions for quarterly monitoring of gas plant compressor seals is &3 percent for VOC emissions 

and 81 percent for THC emissions. This equates to controlled emission 

factors of 0.4 Mg/yr VOC and 1 .2 Mg/yr THC after implementation of a 

quarterly leak detection and repair program. 

cc: Dianne Byrne, SOB 

Fred Dimmick, SOB 

Tom Norwood, PES 

Tom Rhoads, PES 

Bruce Tichenor, ORD/RTP 

G-5 
Service 

--API DATA--

Dry gas(e) 

Wet gas (f) 

NGL (g) 

--EPA DATA--

Dry gas 

Wet gas 

NGL 

--OVERALL--

Table 1. GAS PLANT COMPRESSOR SEAL DATA SUMMARY 

Number 

Screened 

24 

10 

0 

30 

6 

71 

Number 

Emitting( a) 

18 

0 

9 

0 

19 

5 

51 

Number 

Leaking( b) 

0 

14 

5 

Number 

Measured( c) 

9 

0 

0 

0 

16 

26 

Percent 

voc (d) 

0.42 

6.8 

100 

6.3 

REFERENCE: "Frequency of Leak Occurrence and Emission Factors for Natural Gas 

Liquid Plants." - EMB No. 80-FOL-1, July 1982. 

(a) Emitting sources are ones that showed any evidence of leakage when screened. 

(b) Leaking sources screened greater than 10,000 ppm. 

(c) Sources measured for mass emissions. 

(d) Total measured VOC emissions divided by total hydrocarbon emissions X 100. 

(e) Dry gas is field natural gas after the natural gas liquids are removed. 

(f) Wet gas is field natural gas. 

(g) NGL is natural gas liquids including raw NGL mix, LPG, propane refrigerant, 

etc. 

G-6 
Table 2. Calculation of Gas Plant Wet Gas -:>ervice Compressor Seal 

Emission Factors 

. -- -------------

Number of Sources 

Per 1000 

Emission Factor(b) 

(kg/day) 

Emissions Per 

1000 Sources 

(kg/day) 

--------------------------------------------

Leaking Sources 467(a) 38.6 18026 

Non-Leaking Sources 533 2.15 1146 

------------ ----------------------------------------- ----------··-

Tota 1 1000 19172(c) 

------------------------------------------------

(a) From Table 1, 14 of 31 or 46.7 percent of wet gas service compressor seals 

were leaking in the EPA testing. 

(b) Leaking and non-leaking source emission factors were developed in the AID 

(p 2-62). 

(c) The resulting overall average emission factor per sources would therefore b~ 

19.2 kg/day or 5.0 Mg/yr. This factor however, estimates the total hydrocarbJn 

emissions. Based on an average wet gas VOC content of 10 weight percent, Lhe 

VOC emission factor for wet gas compressor seals becomes 1.9 kg/day (0.7 Mg/yr). 

G-7 
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY A-80-20-B(VOC) 

Office of Air Quality Planning and Standards 

Research Triangle Park, North Carolina 27711 I I -B-37 

February 23, 1983 

MEMORANDUM 

SUBJECT: Revised Cost Analysis for Reciprocating Compression Seal Vent Controls 

FROM: Kent 

Petroleum 

c. Hustvedt 

Section, ~ CPB (MD-13) 

TO: James F. Durham, Chief 

Petroleum Section, CPB (MD-13) 

Over the past several months many changes have been made in our 

configuration and cost basis for controlling gas plant reciprocating 

compressor seals. These changes have been made in our continuing effort 

to design and cost a safe, realistic ·system for control of compressor 

seal emissions. While the system described and analyzed in the background information document (BID) is basically adequate, information recently supplied to us by Union Texas Petroleum (UTP) shows that several oversights 

were made in our analysis. Table 1 summarizes revised capital costs for the 

reciprocating compressor seal control systems based on our review of UTP's 

submittal. A contingency of 10 percent has been added to the capital costs and 

they have been annualized as in the BID. These costs will be used to 

assess the cost and cost-effectiveness of compressor seal vent control 

systems for the gas plant NSPS and CTG. 

Table 2 is a detailed listing of the capital costs of the reciprocating 

compressor seal control system. Table 2 is a revision of an order of 

magnitude cost estimate made by UTP and supplied to us in a letter from 

Bill Taylor of UTP to Susan Wyatt dated February 8, 1983, (Docket No. 80-20-B, 

I I -0-53). 1 have revised their cost estimates as fo 11 ows: ( 1) their costs 

were corrected using cost indices to make them consistent with our year basis (1980), (2) our vendor quote equipment costs were used as documented 

in the BID, and (3) reasonable alternative equipment were used. Justifications 

for the use of the alternative equipment are provided as references to the table. 

Attachment 

cc: Dianne Byrne, SOB 

Fred Dimmick, SOB ·~-Tom Norwood, PES 

Tom Rhoads, PES 

Bruce Tichenor, ORD/RTP 

G-8 
4 

• 

Table 1 - Summary of Reciprocating Compressor Control System Costs (1980 $) 

Item 

Double Distance Piece 

Distance Piece Piping 

Instrumentation For 

Purge Gas 

Flare 

Flare Piping 

• 

Capital 

Cost (a) 

2500 

1000 

1780 

6670 

3380 

Capital Costs 

With Contingency (b) 

2750 

1100 

1960 

7340 

3700 

Annual 

Costs (c) 

700 

280 

500 

1860 

940 

(a) Revised capital costs based on our review of the February 8, 1983, 

Union Texas Petroleum submittal (Table 2). 

(b) Total capital costs including 10 percent contingency. 

(c) Annualized capital costs based on 0.163 capital recovery factor 

(10 percent interest rate and 10 year lifetime), 0.05 x capital 

costs for maintenance and 0.04 x capital costs for taxes, insurance, 

and administration. · 

G-9 
EPA REVtSI,:,(II n CATP(.CJsT'5 

~ ~·c../93 

TABl~ 2 

ORDER OF MAGNITUDE ESTIMATE 

FOR COMPRESSOR SEAL LEAK CONTROL~ 

Cost Per Cost Pe~ 

Cylinder ~odel A Plant 

Incremental Cost for Double Distance 

Piece 

S3 ,ooe --z. s oo ® $-6 ,ooo 

E*teRtieA ef Compresso~ Skie & $ ~00 $1,000 

r9b1RdatiaR 

Distance Piece Piping 

"'31 f't\ • i> '2. S l/ m 

1" Piping - -1-00 it. @ $2.00/R:. 

1" Check Va 1 ves -X\ @ eo 

1" Block Valves- 2 ~. '2.5 

@; 1 Seal Pot -

Misc. Flanges, Fittings, Etc. 

Indirects 

Sub-Total 

Instrumentation For Puroe Gas 

®OIL S~f\-L.Pol ,;:}t-:nlet Control Val •e ) 'V >ul"'f'l"f Q6-u. LPt'T'O R..,.(vt~.l•r7"•k &o11 t1 all er 

~ '-&ad Pres sur~ CoAtrel Val • e 

~ (G-eRtrol1 e1 

1'' S 1 ock Va 1 ves - 2 ~ '2 S 

,., Piping -~a....,@ z.82.j(Y\ 

Misc. Flanges, Fittings Q~Bo$) 

Indirects 

Sub-Total 

Material 

~ CJO 

-$-500- ao 

~~0 

_SgQQ 

~ f\.0 

Sl,SQ9" 1'0v 

.$-2,900 

l()~\) 

Material· 

9oc 

800 

350 

1100 

800 

1100 

$4,250 1'-"30 

55,200 

ll 8o 

* A-ltc..<.~ ,...,.._+ i-.o ... (d~( r ~- ~;1\ i•-,l•r UrrP) 

-b s~~ ... w_,,-tt(~llA-) 1 ~+.:.J. ~s{~J .(etA J.•ckc.+ 

.,\J .... ~r ,4-so-z..u-8) J['- 1)- 51) G-10 

Labor 

(18. 85/Manhour) 

$300 

$ -&& '"' s so ~;so (l'tSo'f>f b.2o 

$200 

$ 50 

$210 

s~ bz.o 

$5,600 

Lab0r 

-z..oo 

59 So 

270 

50 

270 

SBo $) 5t:;O l'tSo 

60 

25 

50 

195 

s -%&- S~o 

$5,200 
Cost of 2 mm sue Flare (1c;~o $) 

Piping To Flare 

t.=\ Residue Ga! le Fl al"'e 

~ 500 Ft. • 2" Pipe @ $3/Ft. 

Inlet Line from Compressor to 

Flare 500 ~-i. - 211 Pipe @ ~. 

tZ:) IOOf"l"\ ~ so/rn ~upture Disk (v( ... J..,. 1., .. -tc) • 

Misc. Flares, Fittings 0.,&.,.$) 

Indirects 

Sub-Total 

Materia 1 

msc. Costs For Pipe Supports~.,io.t) 

T9ta1 Mater;a1s & Labor 

~ntiA§eAcy 20~ 

T-&tal Gos-t 

• 

Adjust~ent FQr 1982 9S. 1~80 Costs ( 2Q%} 

Mttts tme11 t to =lilA Cost fer Oeubl e DistanceRieee $2,000 eaeA 

G-11 

Cost Per 

Cylinder ~ 

~5;900* ~eeo ~ '&70 

$10,000 21.~0 

$49,000 

$ g,sooSS9,00Q. 

Labor 

"Cost Per 

Model A. l'lan.t 

-$25 ,000* 

$10,000 

s 3,000 ' 

-$55 ,800 

$11 ,200 

$67,00& 

$55,800 

$SJ ,800... 
.. 

• 

References for Table 2 

A. Telephone conversation report. T. Norwood, Pacific Environmental 

Services, Inc., with P. Marthinetti, Ingersoll-Rand. December 8, . 1982. Distance piece price verified by Mr. Marthinetti as $2,000 

to $3,000 (1980). Average value of $2,500 used. Docket Reference 

Number II-E-19.* 

B. Single oil seal pot required for all compressors instead of one per 

compressor. 

C. Telephone convers·ation. T. Norwood, Pacific Environmental Services, 

Inc., with D. Rudolph, Fairchild ·Industries. Price of natural gas 

supply_regulator. Docket Referen~e Number 11-E-22.* 

D. These costs are already included in flare cost. 

E. Letter, R.W. Kreutzen, Chevron U.S.A. to J.R. Farmer, EPA:CPB, 

•oraft CTG for Natural Gas Processing Plants,• March 12, 1982. 

1982 installed cost of flare given as $8,000. Deflated to 1980 

dollars • $6,670.- Docket Reference Number II-D-32. * 

F. Pilot gas for flare not needed as compressor vent stream is the 

pilot. Flare is auto ignited type. 

G. Telephone conversation. T.L. Norwood, Pacific Envirdnmental Services, 

Inc., with Continental Disk Co., February 14, 1983. Quote of 

$100/holder and $64/disk corrected to June 1980 dollars • $52/disk 

and $82/holder. ·Docket Reference Number II-E-23.* 

*References can be located in Docket Number A-80-20-B at the U.S. Environmental 

Protection Agency Library, Waterside Mall, Washington, D.C . 

G-12 

• 
M E M 0 R A N D U M 

A-80-20-B(VOC) 

II-B-44 

DATE: June 28, 1983 

TO: K.C. Hustvedt 

FROM: T .L. Norwood, PES, Inc. {~w 

SUBJECT: Effect of Control Device Costs on Compressor Seal 

Vent Enclosure Cost Effectiveness 

Prior to preparation of the current draft of the new source 

performance standard for ~quipment leaks of VOC from natural gas processing plants, representatives from Union Texas Petroleum 

indicated that not all gas plants have operating flares. They ·contended that the cost effectiveness of controlling compressor 

seal leaks by using enclosed distance pieces should be adjusted to 

include the cost of the control device in the enclosure costs.l 

As some plants do use operating flares, the costs and cost 

effectiveness for compressor seal vent controls in plants both with 

and without control devices present (Model Plant B) were calculated. 

These calculations were perfonmed for two types of compressors 

(centrifugal and reciprocating) in either of two types of service 

{wet gas or natural gas liquids). 

Table 1 presents the cost and cost effectiveness for the eight resulting cases. As can be seen, the cost effectiveness varies 

from $36/Mg fo~ the best ~ase (centrifugal compressors in NGL 

service with existing control devices) to $2200/Mg for the worst 

case (reciprocating compressors in wet gas service with a new 

control device). 

Table 2 pres~nts the ~:~ital cost calculations required to 

develop Tab 1 e 1. 

l Memo, T.L. Norwood to Dianne Byrne EPA:SDB, January 27, 1983, 

"Meeting to Discuss Industry Comments on the Draft NSPS for Natural 

Gas Processing Plants." Docket Index No. I I ... £ .. 24. 

G-13 
Gl 

I 

Compressor Typea 

Table 1. COSTS AND COST-EFFECTIVENESS FOR COMPRESSOR VENT CONTROL 

SYSTEM FOR HODEL PLANT 8 

Control 

Device 

Presentb . Compressorc 

Service 

Capital Annual 

Costd Coste 

($1,000) ($1,000/yr) 

Emission 

Reductionf 

(Mg/yr) 

Cost 

Effectiveness9 

($/Mg) 

Cent r1 fugal yes wet gas 4.7 1.2 4.2 280 

NGL 33 36 

no wet gas 12.0 3.0 4.2 710 

NGL 33 91 

Reciprocating yes wet gas 29.0 7.3 4.2 1,700 

a 

b 

NGL 33 200 

no wet gas 36.0 9.1 4.2 2,200 

NGL 33 280 

Centrifugal compressors are driven by rotating shafts while reciprocating compressors are driven 

by shafts having a linear motion. 

"Yes" indicates that a control device is present at the plant. The cost of a control device 

(flare) has been added to the compressor vent control system costs for plants without an 

existing control device. 

c - Wet gas means field gas with an average VOC content of 10 percent by weight NGL (Natural gas 

liquids) consists of mixed liquids separated from wet gas (i.e., liquid petroleum gas). 

d 

Capital costs per Table 2. 

e Annualized cost -CAPITAL RECOVERY +MAINTENANCE COSTS+ MISCELLANEOUS COSTS 

- [.163 + .05 + .04] x CAPITAL - 0.253 x CAPITAL COST (8IO Table 8-5). 

f 

From BID Appendix G, page G-2, Emission reduction based on six seals in Model Unit B. 

9

cost Effectiveness - Annual Cost 

Emission Reduction 
Table 2. COMPRESSOR SEAL VENT SYSTEM CAPITAL COSTS 

(Mode 1 Plant B) 

ll!!!t 

Double Distance pieces 

Seal Vent Piping 

Purge Gas Supply 

Flare Piping 

Subtota 1 d 

Flare 

Centr1 fuga 1 

Compressors 

3,7ooa 

4,624 

7,34oa 

11,964 

a From BID Appendix G, page G-10, Table 1. 

b From BID Table 8-1. 

c Costs are for six compressor seals. 

d 

Reciprocating 

Compressors a 

16,SOOC 

6,600C 

1,960 

3,700 

28,760 

7,340 

36,100 

Total capital costs for plants with existing control devices. 

e Total capital costs for plants without existing control devices. 

G-15 
APPENDIX H 

CALCULATION OF EMISSION REDUCTIONS AND COST EFFECTIVENESS 

FOR THE PROPOSED STANDARDS BY SOURCE TYPE 

Chapter 6 of this document presents the model plants and regulatory 

alternatives on which the emission reductions and costs impacts in 

Chapters 7 and 8 were determined. The proposed standards however, are 

not based on a single regulatory alternative: they are based on selected 

control strategies from different alternatives for each component. 

Consequently, this appendix documents the emission reductions and cost 

effectiveness of alternative controls and the proposed standards by 

source type for Model Plant B. 
M E M 0 R A N D U M 

TO: Docket A-80-20B 

FROM: T.L. Norwood and D.G. Cole ~ 

SUBJECT: Costs and VOC Emission Reduction for 

the Recommended Standards of Performance 

for Equipment Leaks of VOC in Onshore 

Natural Gas Processing Plants (ESED 

Project No. 80/22) 

DATE: May 26, 1983 

The purpose of this memo is to document the costs and VOC emission 

reductions for the New Source Performance Standards for onshore natural 

gas plants (VOC) recommended for proposal. This is necessary because the 

standards for each fugitive emission source are based on the selection of 

control techniques rather than regulatory alternatives. Table 1 provides 

a summary of the Model Plant B emission reductions and the average and 

incremental cost effectiveness of various controls for each fugitive 

emission source. The control techniques that are underlined in Table 1 

were selected as the basis for the standards because the incremental costeffectiveness numbers were judged to be reasonable. 

Tables 2 through 7 provide a detailed breakdown of the analyses used 

to produce Table 1. All information in the tables is from the BID for 

the proposed standards, and footnotes at the end of each table explain 

how the numbers were calculated. All of the tables except Table 3 for 

compressor seals are based on the control of a single component because 

there are no economies of scale. The compressor cost analysis in Table 3 

was performed for Model Plant B because there are fJxed costs for the system. 

cc: K.C. Hustvedt 

Dianne Byrne 

H-2 
Source 

Pressure relief 

devices 

Compressors 

Open-ended valves 

and lines 

Sampling connection 

systems 

Va 1 ves 

Pumps 

2 

Table 1. EMISSIONS REDUCTIONS AND CONTROL 

COST EFFECTIVENESS FOR MODEL PLANT B 

Control 

Technique 

Quarterly leak 

detection and 

repaird 

Monthly 1 eak 

detection and 

repair 

Rupture diskse 

Closed-vent and 

sea 1 systemd 

Capsd 

Closed-purge 

sampling 

Quarterly leak 

detection and 

repair 

Monthly 1 eak 

detection and 

repaird 

Quarterly 1 eak 

detection and 

repair Monthly 1 eak 

detection and 

repai rd 

Dual mechanical 

sealse 

Average 

Emission Cost 

Reductionb Effectivenessa 

(Mg/yr} ($/Mg } 

0.95 __ c 

1.0 0 

1.5 6,700 

460 

19 __ c 

0.22 7,oooe 

40 __ c 

43 0 

1.5 830 

1.7 900 

2.6 4,900 

Incremental 

Cost 

Effect i venessa 

( $/Mg) 

__ c 

5,800 

22,000 

460 

__ c 

7,oooe 

__ c 

1,400 

830 

1,500 

12,000 

--------------------------

aFrom Tables 2 through 7 of this memo. 

bfrom BID Table 7-2. 

ccost savings occur. 

dcontrol techniques selected as the basis for the recommended standards. 

ermpacts shown are weighted averages based on 180 new plants and 40 modified/ 

reconstructed plants. 

fFrom Reference 2. 

H-3 
3 

Table 2. ANNUALIZED CONTROL COSTS PER COMPONENT 

FOR PRESSURE RELIEF DEVICESa 

(June 1980 Dollars) 

CONTROL TtCHNIQUE 

Rupture Rupture 

Quarterly Monthly Disks Disks 

Inseections lns~ections (new) (Retrofit) 

Installed Capital Cost 0 0 3 'lQOb 4,200b 

Annualized Capital 

A. Centro 1 

Equipment --c --c 60Qd 780d 

B. I n i t i a 1 L e ak 

Repai re 0 0 0 0 

Annualized Operating 

Costs 

A. -Maintenancef --c --c 160 210 

B. Miscellaneous9 --c --c 120 170 

c. Labor 

1. Monitori ngh 19 58 0 0 

2. Leak R epa ire 0 0 0 0 

3. Administrative and 

Supporti 7.6 23 0 0 

Total Annual Cost 

Before Credit 27 81 880 1,160 

Recovery Credid 73 81 116 116 

Net Annualized Costsk (46) 0 760 1,040 

Total VOC Emission 

Reduction (Mg/yr)l 0.076 0.084 0.12 0.12 

Cost Effectiveness 

($/Mg VOC )m (610) 0 6,300 8, 700 

Incremental Cost 

Effectiveness" 

($;M 9 voq (610) 5,800 21,000 29,000 

H-4 
4 

Table 2. ANNUALIZED CONTROL COSTS PER COMPONENT 

FOR PRESSURE RELIEF DEVICEsa 

(June 1980 Dollars) (Concluded) 

Footnotes: 

aAll costs and emission reduction estimates are for one piece of 

equipment in VOC service. 

bsee BID Table 8-1. Assume l/2 of relief valves controlled by rupture 

disks with 3-way valves and l/2 with rupture disk/block valve. 

1995 + 4116 = 3100 (new); 3631 + 4764 = 4200 (retrofit) 

ccost of monitoring instrument is not included in this analysis. 

dObtained by multiplying capital recovery factor (2 years, 10 percent 

interest = 0.58) by capital cost for rupture disk and capital recovery 

factor (10 years, 10 percent interest = 0.163) by capital cost for all 

other equipment (rupture disk holder, piping, valves, pressure relief 

valve). 

New installation cost= 0.163 (3100- 230) + 0.58 (230) = 600 

Retrofit installation cost = 0.163 (4200 - 230) + 0.58 (230) = 780 

eleaks are corrected by routine maintenance in the absence of the 

standards; therefore, no cost is incurred for repair. fo.o5 x capital cost. 

90.04 x capital cost. 

hMonitoring labor hours (i.e., number of workers X number of components 

x time to monitor x times monitored per year) x $18 per hour. 

Assumes 2-man monitoring team per relief valve, 8 minutes monitoring 

.time per valve, mnitored quarterly or rronthly. 

:o.4o x (monitoring cost +leak repair cost). 

JRecovery credit based.on uncontrolled VOC emission factor of 0.33 

kg/day and total hydrocarbon emission factor of 4.5 kg/day and recovered 

VOC value of $192/Mg and recovered non-VOC hydrocarbon (methane-ethane) 

value of $61/Mg from Table 8-5. Based on 63 percent control efficiency 

for quarterly inspections, 70 percent con~rol efficiency for monthly 

inspections, and 100 percent control efficiency for rupture disks. 

kTotal annual cost (before credit) minus recovery credit. 

lsased on uncontrolled VOC emission factor and control efficiencies for 

each control technique in footnote j. 

fllQbtained by dividing net annualized cost· by total VOC emission reduction. 

nincremental dollars per megagram = (net annual cost of control technique 

-net annual cost of next less restrictive control) divided by (annual 

reduction of next less restrictive control). 

H-5 
5 

Table 3. ANNUALIZED CONTROL COSTS FOR 

COMPRESSOR SEALS - MODEL PLANT sa 

(June 1980 Dollars) 

Installed Capital Costb 

Annualized Capital 

Control EquipmentC 

Annualized Operating 

Costs 

A. Maintenanced 

B. Miscellaneouse 

Total Annual Cost 

Before Credit 

Recovery Creditf 

Net Annualized Cost9 

Total VOC Emission 

Reduction (Mg/yr)h 

Cost Effectiveness 

($/Mg VOC)i 

H-6 

CONTROL TECHNIQUE 

Closed vent and seal system 

25,100 

4,100 

1,300 

1,000 

6,400 

0 

6,400 

14 

460 
Footnotes: 

6 

Table 3. ANNUALIZED CONTRTOL COSTS FOR 

COMPRESSOR SEALS - MODEL PLANT sa 

(June 1980 Do 11 a rs) (Cone 1 uded) 

acosts and emission reduction are for 6 compressor seals (Model Plant B). 

bcapital cost is based on 50 percent reciprocating and 50 percent centrifugal compressors: 

1. 3 double distance pieces @ $2750 (Reference 1) = $8250 

2. 3 distance pieces piping systems @ $1100 (Reference 1) 

3. 3 centrifugal compressor seal vent piping 

systems @ $169 [BID cost of $154 from 

Table 8-1 plus 10 percent conti1gencies ($15)] 

4. Instrumentation system for purge ga::, :.upply 

(Reference 1) 

5. 1 flare (Reference 1) 

6. Piping to flare (Reference 1)* 

Total = 

= 3300 

= 507 

= 1960 

= 7340 

= 3700 

$25,057 

*It is assumed that centrifugal compressors and reciprocating 

compressors are not used in the same plant. If the two types 

of compressors are mixed, two flare piping systems might be 

necessary. However, this case is considered unlikely because 

(1) a new plant would typically use all of one type of compressor, and (2) modified or reconstructed plants would be 

unlikely to have both types of compressors fall under NSPS . requirements. · co.l63 (capital recovery factor) x capital costs; see BID Table 8-5. 

do.os x capital cost. 

eo.04 x capital cost. 

fNo recovery credits are given for compressors because the cost analysis 

is based on the captured emissions being flared. Compressor seal 

vent emissions could be used for process heater fuel resulting in 

recovery of these emissions at their fuel value or recycled to a 

process line with a full product credit. 

9Total annual cost (before credit) minus recovery credit. 

hsased on uncontrolled VOC emission factor of 2.3 Mg/yr and 100 percent 

control efficiency for a closed vent and seal system. Compressor seal 

emission factor is from Reference 2. 

iQbtained by dividing net annualized cost by total VOC emission reduction. 

H-7 
7 

Table 4. ANNUALIZED CONTROL COSTS PER COMPONENT 

FOR OPEN-ENDED LINEsa 

(June 1980 Dollars) 

Installed Capital Costb 

Annualized Capital Control EquipmentC 

Annualized Operating 

Costs 

A. Maintenanced 

B. Miscellaneouse 

Total Annual Cost 

Before Credit 

Recovery Creditf 

Net Annualized Costg 

Total VOC Emission 

Reduction (Mg/yr)h 

Cost Effectiveness 

($/Mg VOC)i 

CONTROL TECHNIQUE 

Caps 

61 

9.9 

3.0 

2.4 

15.3 

28.1 

(12.8) 

0.124 

(103) 

aAll costs and emission reduction estimates are for one piece of 

equipment in VOC service. 

bsee BID Table 8-1. 

co.163 (capital recovery factor) x capital cost; see BID Table 8-5. 

do.os x capital cost. 

eo.04 x capital cost. 

fRecovery credit based on uncontrolled VOC emission factor of 0.34. 

kg/day and total hydrocarbon emission factor of 0.53 kg/day, BID 

Table 3-1. Based on 100 percent control efficiency for caps and $192/Mg 

(recovered VOC value) and $61/Mg (recovered non-VOC hydrocarbon value) 

from BID Table 8-5. 

grotal annual cost (before credit) minus recovery credit. 

hBased on uncontrolled emission factor of 0.34 kg/day and 100 percent 

.control efficiency for caps on open-ended lines. 

lObtained by dividing net annualized cost by total VOC emission reduction. 

H-8 
8 

Table 5. ANNUALIZED CONTROL COSTS PER COMPONENT 

FOR SAMPLING CONNECTION SYSTEMS 

(June 1980 Dollars)a 

Installed Capital Costb 

Annualized Capital 

Control EquipmentC 

Annualized Operating 

Costs 

A. Maintenanced 

B. Miscellaneouse 

Total Annual Cost 

Before Credit 

Recovery Creditf 

Net Annualized Costg 

Total VOC Emission 

Reduction (Mg/yr)h 

Cost Effectiveness 

($/Mg VOC)i 

CONTROL TECHNIQUE 

Closed purge sampling system 

530 

86 

26 

21 

133 

7 

126 

0.018 

7,000 

aAll costs and emission reduction estimates are for one piece of 

equipment in VOC service. 

bsee BID Table 8-1. 

ccapital recovery factor (10 years, 10 percent interest = 0.163) times 

capital cost. 

do.os x capital cost. 

eo.04 x capital cost. 

fRecovery credit based on average of inlet gas sampling emission factor 

(VOC = 0.016 kg/day, THC = 0.32 kg/day) and product liquids emission 

factor (VOC 0.085 kg/day, THC = 0.095 kg/day) from BID Table 3-1 and 

recovered VOC value of $192/Mg and recovered non-VOC hydrocarbon (methane-ethane) value of $61/Mg from BID Table 8-5. Based on 100 percent control efficiency. 

9Total annual cost (before credit) minus recovery credit. 

hsased on average of gas and liquid sampling VOC emission factors in 

footnote f above. 

iObtained by dividing net annualized cost by total VOC emission reduction. 

H-9 
9 

Table 5. ANNUALIZED CONTROL COSTS PER COMPONENT 

FOR VALVEsa 

(June 1980 Dollars) 

coNtRol tE~~NIQUE 

Annualized Cap1tal 

Initial Leak 

Repai ro 

Annualized Operating 

Costs 

Laoor 

l. Moni tori ngC 

2. Leak Repa1 ,.d 

3. Administrative and 

supporte 

Total Annual Cost 

Before Credit 

Recovery Credit f 

~et Annualized Cost9 

Total VOC Emission 

Reduction (Mg/yr)h 

Cost Effectiveness 

(S/Mg VOC)i 

Incremental Cost 

E ffe<:t i veness 

($/Mg VOC)J 

Quarterly 

Inspe<:t1ons 

0.84 

2.4 

3.8 

2.5 

9.5 

15 

(S.S) 

0.051 

( 110) 

(110) 

Monthly 

Inspections 

0.84 

7.1 

3.9 

4,4 

16 

15 

0 

0.055 

0 

1,400 

aAll costs and emission reduction est1mates are for one p1e<:e of equ1pment 

in VOC serv1ce. 

bAnnuallzed initial leak repair costs are obtained by: numoer of leaks 

x repair time x labor rate x 1.4 (overnead) x 0.163. (Number of leaKs 

based on 18 percent of valves leaking in 1n1t1al survey.) 

(0.18 x 1.13 hours x $18/hr x 1.4 x 0.163 s 0.84) 

c~onitoring laoar costs for valves based on the follow1ng: numoer of 

valves screened (numoer ':lf valves x fract1oned screened) x .mn1tor1ng 

time (hours) x laoar rate. 

Quarterly: 3.94 x 2/60 x S18 2 2.4 

Monthly: 11.79 x 2/60 x S18 2 7.1 

dt.eak repair costs are based on the follow1ng: fractlon of sources 

ma1 ntai ned x repair time (hour~) x laoor rate a 

Quarterly: 0.185 x 1.13 x S18 2 3.8 

Monthly: 0.191 ;( 1.13 X S18 a 3.9 

!0.40 x (l!l)nitor1ng cost ., leak repair cost). 

fRecoverJ credit based on uncontrolled 'IOC emHs1on factor of 0.18 ·~g/day 

and total hydrocarbon emission factor of 0.48 Kg/day (BID Table 7-l), 

and a recovered 'IOC ·1a lue of Sl92/Mg and recovered non-VOC hydrocaroon 

(metnane-~thane) value of S6l/Mg from BID Taole 3-5. Based on 77 per~ent 

control eff1c1ency for quarterly 1nspect1ons and 84 percent control 

efficiency for monthly 1nspections (BID Taole 7-l). 

9Total annual cost (before credit) minus recovery credit. 

hsased on uncontrolled VOC em1ss1on factor dnd control eff1c1enc1es 

presented in footnote f. 

.~et annua·l cost divided oy total '/OC em1ssion reduction. 

JSee Table 2, footnote n. 

H-10 
10 

Table 7. ANNUALIZED CONTROL COSTS PER COMPONENT 

FOR PUMPS a 

(June 1980 Dollars) 

~ORT~OC rWlR!OOE 

Dual .'!ecnanlca I 

Seal System with 

Barrier Fluid 

System and 

Degassing Vents 

Quarterly Montilly 

Inspections Inspections '~ew Retrofit 

Installed Capital 

Cost 

A. Seal 0 0 12500 l590b 

8. Barrier Fluid 

System and 

Degassing 

Vents 0 0 58500 sasob 

Annualized Cap1tal Cost 

A. Cont ro 1 Equi pmentc 

1. Dual 

Mechani ca 1 

Seal 

0 Seal 0 0 S60d noe 0 1nstalat ion 0 0 49, 569 

2. Barrier 

Fluid 

System and 

Degassing 

Vents 0 0 9SOh 9SOh 

3. Rep 1 ac ement 

Seal ssi 57i 0 0 

8. Initial Leak 

Repair zzj Z2J 0 0 

c. !niti al Seal 

Replacement 7 .sok 7 .sok 0 0 

Annualized Operat1ng 

Costs 

A. Maintenancel 0 0 355 372 

B. Mfscellaneousm 0 Q 284 298 

c. Labor 

l. Mon1tori ngn 20 44 a 0 

2. Leak Repai rn 110 120 0 0 

3. Administratove and 

SupportO 52 66 0 0 

Total Annual Cost 

Before Credit 270 320 2200 2400 

Recovery CreditP 53 59 91 91 

Net Annualized Cost q 217 261 2109 2309 

Total VOC Emissionr 

Reduction (Mg/yr) 0.26 0.29 0.44 0.44 

Cost Effectiveness 

($/Mg VOC )S 830 900 -+800 '5200 

[ncremental Cost 

Effect 1 venes s 

(S/Mg 'IOC)t 830 1500 12,000 1<1,000 

H-11 
11 

Table 7. ANNUALIZED CONTROL COSTS PER COMPONENT 

FOR PUMPsa 

(June 1980 Dollars) (C:>ncluded) 

Footnotes: 

aAll costs and emission reduction estimates are for one piece of equipment 

in VOC service. 

bsee BID Table 8-1. 

ccost of monitoring instrument is not included in the analysis. 

dFor new installation, annualized cost of dual seal = $1,250 (dual seal 

cost) x 0.58 (capital recovery factor for 2-year life) less single seal 

credit ($278 x 0.58). 

eFor retrofit installation, annualized cost of dual seal is same as new 

installation, except no single seal credit is given. 

fsixteen hours of installation at $18/hr, annualized over 10 years 

(0.163 X $288). 

gNineteen hours of installation at $18/hr, annualized over 10 years 

(0.163 X $342). ~0.163 x capital cost. 

lReplacement seal cost is 1/2 the cost of a new seal (old seal has 

salvage value). Cost corrected to June 1980 dollars ($140/seal) is 

based on Reference 3. Multiply replacement cost per seal by number 

of leaks per year. For quarterly and monthly inspections, number 

of leaks per pump equals 0.39 and 0.41, respectively (number of 

.Pumps x "fraction of sources operated on" from BID Table E-1). 

JAnnualized initial leak repair costs from BID Tables 8-5 and 8-6. 

Based on 33 percent of pump seals leaking in initial survey. 

kinitial seal replacement cost =percent of pumps initially leaking 

x replacement seal cost x capital recovery factor (0.33 x $140 x 0.163 

= $7.50). 

lo.os x capital cost. 

mo.04 x capital cost. 

nMonitoring labor and leak repair costs for pumps are based on 

BID Table 8-3 plus weekly visual inspection cost (based on 0.5 minutes/ 

source, 52 times/yr, $18/hr) or $7.80 per source. 

oo.40 x (monitoring cost+ leak repair cost). 

PRecovery credit based on uncontrolled VOC emission factor of 1.2 kg/day 

and uncontrolled total hydrocarbon emission factor of 1.5 kg/day. 

Recovered VOC value of $192/Mg and recovered non-VOC (methane-ethane) 

value of $61/Mg are from Table 8-5. Based on 58 percent control efficiency 

for quarterly inspections, 65 percent control efficiency for monthly 

inspections, and 100 percent control efficiency for dual seal systems 

(from BID Table 7-1). 

qrotal annual cost (before credit) minus recovery credit. 

rsased on uncontrolled VOC emission factors and control efficiencies in 

footnote p. 

SNet annualized cost divided by total VOC emission reduction. 

tsee Table 2, footnote n. 

H-12 
12 

REFERENCES 

1. Memorandum from K.C. Hustvedt to J.F. Durham, EPA:OAQPS. Revised 

Cost Analysis for Reciprocating Compressor Seal Vent Controls. 

February 23, 1983 (Docket No. A-80-20-B (VOC) II-B-37). 

2. Memorandum from K.C. Hustvedt to J.F. Durham, EPA:OAQPS. Revised 

Gas Plant Compressor Seal Emission Factor. February 10, 1983 

(Docket No. II-B-35). 

3. Fugitive Emission Sources of Organic Compounds -Additional Information 

on Emissions, Emission Reductions, and Costs. U.S. EPA, OAQPS, 

EPA-450/3-82-010, April 1982, p. 5-19 (Docket No. II-A-25). 

H-13 
APPENDIX I 

REVISED PUMP SEAL LEAK DETECTION AND REPAIR 

EMISSION REDUCTION 

Attached as Appendix I is a memorandum dated December 7, 1983 that 

describes the calculation of pump seal control emission reduction. Due to 

an error made the inputs to the leak Detection and Repair (LDAR) model 

during the development of the BID, the values used throughout the BID 

chapters and previous appendices are incorrect. The memorandum attached 

documents the correct emission reduction values for natural gas plant pump 

seals, as well as the correct pump seal control cost effectiveness values 

for leak detection and repair programs. 
MO'ORANDUM 

SUBJECT: 

FRC1>1: 

UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

Off1ce of A1r Qual1ty Plann1ng and Standards 

Research Triangle Park. North Carolina 27711 

Gas Plants Pump Se~ls Emission Reduction 

K. 

Petroleum 

C. Hustvedt 

Section/CPS ~ 

TO: James F. Durham, Chief 

Petroleum Section/CPS 

While I was preparing for our November 29, 1983, meeting with OMB on 

the NSPS and CTG for VOC equipment leaks from gas plants, I recalculated 

the cost effectiveness of leak detection and repair programs (LDRP) for 

pump seals. In checking my results against the numbers developed for 

the CTG and NSPS, I found that my new calculations estimated a much 

higher emission reduction for all monitoring intervals. I discovered 

that in our computer runs for gas plants we had used 87 percent emission 

reduction for repair of leaking pump seals (F2 equals 0.13 in the leak 

detection-and repair (LDAR) model)1, while in the AID2 we had used an F2 

value of 0.028 (97.2 percent emission reduction). As discussed in the 

AID, it is likely that repa,ir (replacement) of a leaking pump seal will 

result in essentially 100 percent emission reduction or an F2 of 0.00, 

so that the AID value is a low estimate of the emission reduction from 

repair. Because we feel the LDAR inputs developed in the AID are appropriate 

for all of our VOC equipment leak projects, I have recalculated the pump 

impacts using 0.028 for F2. 

Attached are the LDAR model inputs and outputs for monthly, quarterly, 

semiannual and annual LDRP. I have summarized the results of these runs, 

including the incremental impacts between alternative LDRP, in Table 1. 

The costs and emission reductions shown in Table 1 are based on 100 pump 

seals to minimize effects of rounding on the calculated results. To correct 

these numbers to model plant numbers, the costs or emission reductions 

should be multiplied times the number of pump seals in the model plant divided 

by 100. Since there are 6 pumps in model plant B, this means you would 

multiply these numbers times 0.06 to get model plant B impacts. The cost 

effectiveness numbers are independent of number of pumps so they are already 

correct for all the model plants. 

I-2 
2 

REFERENCES 

1. T. W. Rhoads, PES, Inc. to Docket A-80-20-B. "Evaluation of the Effects 

of Leak Detection and Repair on Fugitive Emissions Using the LDAR Model," 

November 1, 1982, Docket Reference Number Il-B-18. 

2. Fugitive Emission Sources of Organic Compounds--Additional Information 

on Emission$, Emission Reductions, and Costs, EPA-450/3-82-010, April 1982. 

Attachments 

cc: Dianne Byrne, EPA/SOB 

Fred Dimmick, EPA/SOB 

Tom Norwood, PES....-

Tom Rhoads, PES 

Docket A-80-20-B 

I-3 
Table 1. LDAR ANALYSIS FOR NATURAL GAS PLANT PUMPS - CTG & NSPSa 

Monitoring Emission Change Net Cost Cost Incremental 

Interval Reduction E.R. Cost 

~ Effectiveness C/E 

Case (Months) TPercent) (Mg7JrT {Mg/yr) Tl?Yrr y { $ /Mg) (-$/Mg} Notesb ----- ----

M 1 87.2 38.2 23,200 610 

4.0 3,200 800 M to Q 

Q 3 78.0 34.2 20,000 587 

5.8 700 121 Q to SA 

I SA 6 65.0 28.4 19,300 680 ..,. 

10.2 300 29 SA to A 

A 12 41.6 18.2 19,000 1,040 

16.0 1,000 62 Q to A 

aBased on 100 pump seals. 

bJncrements between the two monitoring intervals shown. 
INPUT DATA 

PlANT tiATUGAS CTG&NSPS 

C FOR LIGL T LIQUID PUtiPS t 

FOR EXAMINING EMISSION REDUCTIONS DUE TO LDARl 

HOHlTORitiG INTERVAL f NOIDtiS J 

TURUAIHMIO FREQUEUCY (NOIITHSJ 

EMISSIOII FACTOR I KG/lfR/SOURCE J 

LEAK OCCURREIICE RATE (7. PER PERIOOJ 

IUlTIAL X LEAKING 

EtiiSSIOIIS REDUCTION FOR UIISUCCESSFUL REPAIR 00 

EHISSI(IIIS REDUCTION FOR SUCCESSFUL REPAIR 00 

EARLY lEAK RECURREI~E IX OF REPAIRS) 

UIISUCCESSFUl REPAIR RATE IX) 

UIISUCCESSFUL REPAIR RATE 1%1 AT TURNAROutiO 

FOR EXAHIIHIIG THE COSTS Of LOAR: 

l 

24 

o.os 

J.4 

33.0 

0.0 

97.2 

o.o 

o.o 

o.o 

TOTAl HUMBER OF SOURCES 100 

tiOHITORitiG TitlE PER SOURCE IUSPECTION ., MINUTES J I 0. 0 

VISUAL t!OIIITORIUG TitlE PER SOURCE ININUTESJ 0.50 

tMIBER OF VISUAL IHSPECTIOtiS PER YEAR 52 

REPAIR TINE PER SOURCE CNINUTESJ 960 

LABOR RATE If/HOUR I 18 

PARTS COST PER SOURCE (t) 140 

ADMINISTRATIVE & SUPPORT OVERHEAD COST FACTOR (1.J 40.0 

CAPITAL RECOVERY FACTOR IXJ 16.1 

RECOVERY CREDIT FOR ENISSimiS REDUCTION Ct/HGJ 207 

FOR EXAMINING EMI SSIOH REOUCTIOHS DUE TO LDAR I (6. WA'-.4. T'W ~ &. '/) 

NotiiTORitiG. IIDERVAL INONTHSJ 3 

TURHAR<MIO FREQUENCY (MONTHS). 24 
I 

C"'\ 

I H P U T D A T A 

CFOR 

PLAHT UATUGAS CTG&NSPS 

LIGLT LIQUID PUNPSt 

EMISSION FACTOR IKG/HR/SOURCEJ 

lEAK OCCURREUCE RATE C Y. PER PERIOD I 

IIIIT'IAL 1. lEAKING 

ENISSIOIIS REDUCTION FOR UtiSUCCESSFUL REPAIR C Y. J 

EtiiSSIOIIS REDUCTION FOR SUCCESSFUL REPAIR 00 

EARLY LEAK RECURRENCE (1. OF REPAIRSJ 

~!SUCCESSFUL REPAIR RAT~ IY.t 

~~SUCCESSFUL REPAIR RATE (7.1 AT TURNAROUND 

FOR EXAMINING THE COSTS OF LDAR: 

TOTAL NUHBER OF SOURCES 

HOIIITORIIIG TINE PER SOURCE INSPECTION (MINUTESt 

VISUAL NOIIITORING TINE PER SOURCE ( HIIIUTES J 

tiUliBER Of VISUAL IIISPECTIOHS PER YEAR 

REPAIR TitlE PER SOURCE C HIHUTES t 

LADOR RATE ($/HOURJ 

PARTS COST PER SOURCE ltJ 

ADMINISTRATIVE & SUPPORT OVERHEAD COST FACTOR 11.) 

CAPITAL RECOVERY FACTOR i7.1 

RECOVERY CREDIT FOR EHISSIOHS REDUCTION (t/HGt 

o.os 

10.2 

33.0 

o.o 

97.2 

o.o 

o.o 

o.o 

100 

10.0 

0.50 

52 

960 

18 

140 

40.0 

16.3 

207 

FOR EXAHINIHG ENISSIOH REDUCTIONS DUE TO lDAR1 ~'"'l- ANtN4~ 

t10tiiTORIUG IUTERVAL ltiDmHSJ 

TURNARO~IO FREQUEtiCY CNOHTIIS J 

ENISSIOII FACTOR CKG/HR/SOURCE) 

LEAK OCCURREIICE RATE CY. PER PERIOOI 

ItiiTU.L Y. LEAKING 

EHISSIOUS REDUCTION FOR UtiSUCCESSFUL REPAIR 00 

EHISSIOIIS REDUCTiotl FOR SUCCESSFUL REPAIR OD 

EARLY LEAK RECURRENCE C1. OF ~EPAIRSJ 

~!SUCCESSFUL REPAIR RATE CY.J 

~~SUCCESSFUL REPAIR RATE CY.t AT TURNAROUND 

6 

tit 

0.05 

20.4 

33.0 

o.o 

97.2 

0.0 

0.0 

o.o 
INPUT DATA 

PLANT NATUGAS CTG&NSPS 

(FOR liGlT liQUlD PUMPS) 

FOR EXAMINING THE COSTS OF lDARJ 

TOTAl NUNSER OF SOURCES 100 

tiOtUTORIHG TitlE PER SOURCE INSPECTION (HIHUTESJ 10.0 

VISUAl NOtUTORING TINE PER SOURCE fHIHUTESt 0.50 

NUtSER OF VISUAL INSPECTIONS PER YEAR 52 

REPAIR TINE PER SOURCE (Nit~TESJ 960 

LABOR RATE ( t/HOUR t l& 

PARTS COST PER SOURCE (tt 140 

ADMINISTRATIVE & SUPPORT OV~RHEAD COST FACTOR (7.J 40.0 

CAPITAl RECOVERY FACTOR (7.1 . 16.3 

RECOVERY .CREDIT FOR EMISSIONS REDUCTION (t/HGJ 207 

FOR EXAMINING EMISSION REDUCTIONS DUE TO lDAR: 

tiONITORltiG INTERVAl U10NTHS J 

TURtiAROlUJ. FREQUENCY HIOHTttS J 

ENISSIOII FACTOR (KG/HR/SOURCEJ 

lEAK OCCUP.REIIC£ RATE (X PER PERIOD J 

INITIAl 7. lEAKING 

EI1ISSIOUS REDUCTION FOR utiSUCCESSFUl REPAIR 00 

EHISSimiS REDUCTION FOR SUCCESSFUl REPAIR (XJ 

EARlY lEAK RECURRENCE (1. OF REPAIRSJ 

UtiSUCCESSFUl REPAIR RATE 00 . .UNSUCCESSFUL REPAIR RATE t?.J AT TURHAROl'NIJ 

FOR EXANifiiHG THE COSTS Of lOARJ 

It 

!4 

0.05 

40.5 

33.0 

o.o 

97.t 

o.o 

0.0 

o.o 

TOTAl NUHBER OF SOURCES 100 

ttoNITORltiG TINE PER SOURCE INSPECTION U1IHUTESJ 10.1 

VISUAl HOtUTORIUG TINE Pl:R SOURCE tNIHUTESJ 0.50 

NUMBER OF VISVAl INSPECTIONS PER YEAR 52 

REPAIR TINE PER SOURCE (HIHUTESJ 960 
........ 

I 

OJ 

INPUT DATA 

PLANT HATUGAS CTG&HSPS 

CFOR liGLT LIQUID PUHPSt 

lAOOR RATE U/HOUR l 18 

PARTS COST PER SOURCE ftl 140 

AOHitUSTRATIVE & SUPPORT OVERtfEAD COST FACTOR 00 40.0 

CAPITAL RECOVERV FACTOR (Y.t 16.1 

RECOVERV CREDIT FOR EHISSIOHS REDUCTION ( t/ttG l 207 

f 

.t 
....... 

I 

1.0 

.. 

5\HtAR'f Of !STirtATED EHISSIOH FACTORS CKG/HIU AND PERCENT REDUCTION 

IN HASS EHISSIONS FOR PUHPS/LIGLT LIQUID SERVICE BY TURNAROUND - PLANT NATUGAS CTG&NSPS 

TURNAROUND 

PERIOD 

1 

t 

3 

1 

2 

l 

1 

z 

3 

1 

z 

3 

HEAN EHISSIOH-KGIHR 

0.0064 

0.0064 

0.0064 

O.OllO 

O.OllO 

0.0110 

0.0175 

0.0175 

0.0175 

o.onz 

o.onz 

0.0292 

PERCENT REDUCTION 

COHPARED TO EHISSION 

COHPARED TO FOR '*fiCH NO HAIHTENAUCE 

INITIAL EMISSION WAS DOHE DURING PERIOD 

t··· tt.t ,..,f\tL1 87.t 81.3 

87.2 81.3 

c·· 86.7 

6,-.t&tttL-f 78.0 69.8 

78.0 69.8 

c··· 78.8 

\e~u ... 65.0 56.5 

. /rf'N'IItf- . 65.1) 56.5 

('·' 65.1 

/rll ~NfrL 41., 38.3 

41.6 38.3 

.., 
...... 

I 

0 

1 

SOlRCE TYPE 

EHISSIOH 

REDUCTION 

tHG/YR) . 

PLANT HATUGAS CTG&HSPS SUflARYs 

AVERAGE ANNUAL COST EffECTIVENESS 

I HONTHL Y LDAR ) 

RECOVERY 

CREDIT 

NET 

COSTS 

GROS~ COST 

EffECTIVENESS 

tPER HG) 

NET COST 

EffECTIVENESS 

CPEA ttiU 

----------------------------·-----------------------------------------------------------------

fV1PS 

LIGLT LIQUID 38.2 • 7,910 • n.no • 817 • 610 ~·tltm.'i 

LIGl T LIQUID 34.2 7,070 u,oot 794 587 Q """" Tf.C.' ~ LI6l T LIQUID 28.~ 5,&90 19,]00 887 680 Sf'AI Atltfti'Al., 

l16l T liQUID 18.! ],770 19,000 l,tso 1,0~0 /t'tllltl~\.. 

·------ ---------- --------- ------- ------- PWfT TOTAl 119 • 24,600 • 81,700 • 89] • 686 
r . . . 

1. REPORT NO. ,2. 

3. RECIPIENT'S ACCESSION NO. 

EPA-450/3-B2-024a - -

TECHNICAL REPORT OATA 

(Please read Instncetions on the revers-> before compl,.til·g) 

'4.-TITLf AND SUBTITLE 5. '' .. PORT DJITF 

Equipn~nt Leaks of VOC in Natural Gas Production December ·198.3 ~~--

Industry - Background Information for Proposed Standards 6. PERFORMING ORGANIZATION CODE 

7. AUTHOR(S) 8. PERFORMING ORGANIZATION REPORT NO. 

-· 

~FORMING ORGANIZATION NAME AND ADDRESS 10. PROGRAM ELEMENT NO. 

\Office of Air Quality Planning and Standards 

U.S. Environmental Protection Agency 11. CONTRACT/GRANT NO. 

Research Triangle Park, NC 27711 

. ----- 12. SPONSORING AGENCY NAME AND ADDRESS 13. TYPE OF fiEPORT AND PERIOD COVERED 

Director for Air Quality Planning and Standards 

Office of Air, Noise, and Radiation 14. SPONSORING AGENCY CODE 

u.s. Environmental Protection Agency 

Research Triangle Park, NC 27711 EPA/200/04 

15. SUPPLEMENTARY NOTES This report discusses the regulatory alternatives considered d~ring dev~lopment of-the .. 

~~~Eg~~t~~e~; ~Ru ~~~h P~~~~,W~~~e ~ r~~~~~~~ v~nd the environmental and economic impacts r· ABSTRACT · 

Standards of performance for the control of VOC emissions from equjpment leaks 

at natural gas processing plants are being proposed under Section 111 .of the Clean 

Air Act. This document contains background information and- environmental and 

economic impact assessments of the regulatory alternatives considered in developing the proposed standards. 

. 

~ 

17. KEY WORDS AND DOCUMENT ANALYSIS 

a. DESCRIPTORS b. IDENTIFIERS/OPEN ENDED TERMS c. CDSATI Field/Group 

Air pollution Air Pollution Control 13b 

Pollution control 

Standards of performance .. Volatile organic compounds (VOC) 

Natural Gas Production 

Fugitive emissions 

18. DISIAIBUTION STATEMENT 19. SECURITY CLASS (This Report) 21. NO. OF PAGES 

Unclassified 230 Unlimited 20. SECURITY CLASS (This page) 22. PRICE -- Unclassified 

f.PA Form 2220-1 (Rev. 4-77) PREVIOUS EDITION IS OBSOLETE 
Un1ted States 

Environmental ProtectiOn 

Agency 

Otf1c1al Busmess 

Penalty for Pr~vate Use 

$300 

Off1ce of A1r, No1se. and Rad1at1on 

Off1ce of A1r Oual1ty Plannmg and Standards 

Research Tnangle Park NC 27711 

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