# OEPA UnitedStates OfficeofAirQuality EPA-450/3-82-024a EnvironmentalProtection PlannrngandStandards December1983 Agency ResearchTriangleParkNC27711 Arr 

# EquipmentLeaks ofVOCin NaturalGas Draft EIS ProductionIndustry

- BackgroundInformation forProposedStandards

### EPA-450/3-82-024a


# EquipmentLeaksofVOC in NaturalGasProductionIndustryBackgroundInformation forProposedStandards

Emission StandardsandEngineeringDivision

U.S ENVIRONMENTALPROTECTIONAGENCY OfficeofAir,Noise,andRadiation OfficeofAirQualityPlanningandStandards ResearchTrianglePark, NorthCarolina27711 December1983Th1sreporthasbeenreviewedbytheEmissionStandardsandEngineeringDivisionoftheOfficeofAirQuality**~~':lnri11g** andStandards,EPA,andapprovedforpublication.Mentionoftradenamesorcommercialproductsisnotintender1to constituteendorsementorrecommendationforuse.Copiesofthisreportareavailablethroughthe**Ltbrar~J**Serv1cus Office(MD-35),U.S.EnvironmentalProtectionAgency,ResearchTrianglePark,NorthCarolina27711;or,forafee,f,·c.r. theNationalTechnicalInformationServices,5285PortRoyal Road,Springfield,Virginia22161.

II

### ENVIRONMENTAL PROTECTION AGENCY Background Information and Draft Environmental Impact Statement for Equipment Leaks ofVOC in Natural Gas Production Industry Preparedby:

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 ofperformance would limitemissions ofVOC from equipment leaks atnew, modified, and reconstructed affected facilities atnatural gas plants. Section 111 ofthe Clean Air Act (42 U.S.C. 7411), as amended, directs the Administrator to establish standards.ofperformance for any category ofnew stationary source of airpollution that

..... causes orcontributes significantlyto air pollution which may reasonably be anticipated toendangerpublic health orwelfare

... 2. Copies ofthisdoucment have been sentto 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 Stateand Territorial Air Pollution ProgramAdministrators; the Association ofLocal Air Pollution Control Officials; EPARegional Administrators; andother interestedparties. 3. For additional information contact: Mr. GilbertH. 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 documentmay 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

iiiMETRIC 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. 

### Alist of prefixes to metric units is also presented.
To Convert Metric Unit centimeter (em) meter (m) liter (1 ) cubic meter (m3) cubicf11eter (m3) cubic meter (m3) kilogram (kg) megagram**(r~g)** gigagram (Gg) 

### gigagram (Gg) joule (J)

Prefix tera giga mega ki10 centi mil1i 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) (bb1 ) cubic feet (ft3) pound (1 b) ton million pounds (106lbs) ton British thermal unit (Btu)

Multiplication Factor

1012 109 106 103 10-2 10-3 10-6

### TABLE OF CONTENTS



# . .. .

# .. 

# . . . . iv METRIC CONVERSION TABLE TABLE OF CONTENTS 

# . . .

# . . .

# .. • • • • v



# .

# .. . . . . . . . . . . . .. LIST OF TABLES•••.• LIST OF FIGURES 

# .

# .. 

# ...

# ..

# . 1.0 SUMMARY..•••. 

# .

# . . . ..

# .. 1.1 Regulatory Alternatives •• 

# . . . .

# .. . . Environmental Impact•••

# . . ..

# . . . . .

# .. 1.2 1.3 Economic Impact •••

# .

# . .. ..

# . . .

# ..

# .. . 2.0 INTRODUCTION ••••. 

# . . . . . . .

# ..

# .. . .

# .. . 2.1 Background and Authority for Standards••••. 2.2 Selection ofCategories 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 ofStandards ofPerformance. 3.0 SOURCES OF VOC**Et~ISSIONS** 

### ••

# . . .

# ..

# . . .. 3.1 General .•.••..•••••••. 3.2 Description of Fugitive Emission Sources. 3.3 Baseline FugitiveVOC 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 

### 3-12TABLE 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 Genera1Discussion ofModification and Reconstruction Provisions. 

# ... .

# .. . . . . . ..

# . .. . .

# . 5.2 Applicability ofModification 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 Qua1ity 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 Ana1 ysis 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 ImpactAnalysis

.. 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 ofthe Background Information Document. Index to Environmental Considerations Emission Source TestData

..... . PlantDescription and Test Results. C.2 Industry Valve Maintenance Study••.... C.3 References for Appendix C

. • . . . . . ..• D Emission Measurement and Continuous Monitoring.• D.1 Emission MeasurementMethods.

. ...... . D.2 Continuous Monitoring Systems and Devices

. 0.3 Performance TestMethod

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

. . . . . . . . . . .. . E Model for Evaluating the Effects ofLeak 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 ofEmission 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 viiLIST 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 ofTotal VOC Emissions Affected atVarious 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 ofVessels at Four Gas Plants •...•...•••.•• 6-4 6-3 Ratios of Numbers of Components to Numbers of Vessels •• 6-5 6-4 FugitiveVOC 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 aModel Plant Basis

. . . . . . . . . . . . . . . . . . 7-4 Projected Fugitive Emissions FromAffectedModel 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

. 7-10LIST OF TABLES (Continued)
Number

8-1 8-2 Capital Cost Data ••••••••••••••••••••8-2 Capita1Cost Estimates for**~lode**1Plants • • • • . • • 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 ofAnnualized 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 PlantA 8-10 Annual Cost Estimates for 1,1odel Plant B 8-11 Annual Cost Estimates for Model Plant C 8-12 Cost Effectiveness ofRegulatory Alternatives • 8-13 Fifth-Year Nationwide Costs of the Regulatory Alternatives .••.•.••.••• 8-14 StatutesThat May Be Applicable to the Natural Gas Processing Industry •••.•.••••••••••• 9-1 Distributionof Gas Plants by Capacity (1980} ••. 9-2 Distribution ofGas Plants by Process Method (1980} • 9-3 Distribution ofGas Plants by Ownership (1980). 9-4 Distribution ofGas 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 ixLIST OF TABLES (Concluded)
Number Page

9-13 Onshore Natural Gas Processing, Total and Cumulative Before-Tax Net Annualized Cost ofVOC NSPS Regulatory Alternatives 1983-1987•..•••.•••.••.••••9-27 9-14 Onshore Natural Gas Processing Model Plants• Before-Tax Net Annualized Cost ofVOC NSPS Regulatory Alternatives Per Plant ••.•.••••..•..•••.••.•••9-28 9-15 Onshore Natural Gas Processing Model Plants• After-Tax Net Annualized Cost ofVOC 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

XLIST OF FIGURES


### Number

3-1 General schematic of natural gas-gasoline processing. 3-2 Diagram ofa simple packed seal •..•.••.. Diagram of abasic singlemechanical seal • Diagram ofa 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 ofa 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

xi1.0 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 aresult 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 ofVOC 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, reliefvalves, 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 ismore restrictive than Alternative II.

1-1The requirements are as follows:
o Monthly monitoring of valves (ifa particular valve is founa not to be leaking for 3 successive months, then 2months 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 ofpump seals;
o Installation of avent 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 ofexisting 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

1-2compressor 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. Amore detailed analysis ofenvironmental and energy impacts is presented in Chapter 7. Asummary 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 fifthyear under Alternative III would be approximately $510,000; under Regulatory Alternative IV net annual costs ofover $7 million are incurred. Amore detailed analysis ofcosts is included in Chapter 8. Price impacts of the regulatory alternatives are expected to be slightregardless 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. Amore detailed economic analysis is presented in Chapter 9. Asummary ofenvironmental, energy, and economic impacts associated with the alternatives is shown in Table 1-1.

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

Solid Administrative Air Water 

### viaste Energy Noise Economic Action Impact Impact Impact Impact Impact Impact Regulatory Alternative I (No action) 0 0 0 0 0 0 Regulatory Alternative II +2** +1** 0 +1* 0 +1*

,_. Regulatory I .j::oo Alternative III +2** +1** 0 +1* 0 -1* Regulatory Alternative IV +2** +1** 0 +1* 0 -1*
KEY: +Beneficial impact 0No impact *Short-term impact

- Adverse impact 1Negligible impact ** Long-term impact 2Small impact *** Irreversible impact 3Moderate impact 4Large impact2.0 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 ofcontrol 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 oftheir 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 pollutionwhich 11••• causes, or contributes significantly to air pollution which may reasonably be anticipated to endanger public health orwelfare. 11 The Act requires that standards of performance for stationary
sources reflect, 11 ••• the degree ofemission 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 ofwhich
commences after regulations are proposed by publication in the Federal Register.

2-1The 1977 amendments to the Act altered or added numerous provisions thatapply to the process ofestablishing standards of performance. 1. EPA is required to review the standards of performance every 4years and, ifappropriate, 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 systemmust be continuous and may include alow- 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 6months•

. Standards of performance, by themselves, do not guarantee protection ofhealth orwelfare because they are not designed to achieve any specific airquality levels. Rather, they are designed to reflect the degree of emission limitation achievable through application of the best adequately demonstrated technological system ofcontinuous emission reduction, taking into consideration the costof 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 adegree ofuniformity are needed to avoid situations where some Statesmay attract industries by relaxing standards relativeto otherStates. 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 effectivelyexcluding certain coals from the reserve base because theiruntreated 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.

2-2Promulgation of standards of performance does not prevent State or local agencies from adopting more stringentemission limitations for the same sources. States are free under Section 116 of theAct 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. Asimilar situationmay arisewhen amajor emitting facility is to be constructed in a geographic area that falls under the prevention of significant deterioration of airquality provisions of Part Cof the Act. These provisions require, among other things, thatmajor 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 ofeach pollutant subjectto regulation under this Act emitted from, orwhich 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 availablemethods, systems, and techniques, including fuel cleaning or treatment or innovative fuel combustion techniques for control ofeach 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 ofnumerical emission limits where feasible, alternative approaches are sometimes necessary. In some cases physical measurement ofemissions from anew source may be impractical orexorbitantly expensive. Section lll(h) provides that the Administratormay promulgate adesign
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

2-3during 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, amore practical approach to standards of performance for storage vessels has been equipment specification. In addition, Section lll{j) authorizes the Administrator to grant \'laivers ofcompliance to permit a source to use innovative continuous emission control technology. In order to grant the waiver, the Administratormust find: (1) a substantial likelihood that the technology will produce greateremission 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 Statewhere the source is located consents; and (5) the waiver will not prevent the attainment ormaintenance 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 ofa performance standard. Finally, waivers have definite end dates and may be terminated earlier if the conditions are not met or ifthe system fails to perform as expected. In such a case, the
source may be given up to 3years to meet the standards with amandatory 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 significantlyto, air pollution which may reasonably be anticipated to endanger public health orwelfare

... Proposal and promulgation of standards of performance are to follow. Since passage ofthe 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 interestby considering the broad strategyof the Agency for implementing the Clean Air Act. Often, these 11areas 11 are actually pollutants

2-4emitted by stationary sources. Source categories that emit these pollutants are evaluated and ranked by a process involving such factors
as: (1) the level ofemission control (if any} already required by Stateregulations, (2) estimated levels of control thatmight be required from standards of performance for the source category, (3} projections of growth and replacement ofexisting 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, orwill be designed to emit; (2) the extent to which each such pollutantmay reasonably be anticipated to endanger public health or welfare; and (3) the mobility and competitive nature ofeach such category of sources and the consequent need for nationallyapplicable new source standards of performance. The Administrator is to promulgate standards for these categories according to the schedule referred to earlier. In some cases itmay 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, substantiallymore 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.

2-5After the source category has been chosen, the types of facilities within the source category to which the standard will apply must be determined. Asource categorymay have several facilities that cause airpollution, and emissions from some of these facilities may vary from insignificant to very expensive to control. Economic studiesof 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 aprogram for developing standards is to identify the best technological system ofcontinuous 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 atelephone 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 aproject, the information about the industry and the pollutants emitted is used in analytical studies. Hypothetical

..model plants 11 are defined to provide acommon basis for analysis. The model plant definitions, national pollutantemission

2-6data, and existing Stateregulations governing emissions from the source category are then used in establishing 11regulatory alternatives." These regulatory alternatives are essentiallydifferent levels of emission control. EPA conducts studies to determine the impact of each regulatory alternativeon 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 singlemost 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 ofperformance, 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 itmight take with members of the National Air Pollution Control Techniques Advisory Committee. Industry representatives and other interested parties also participate in thesemeetings. 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 aremade to the documentation. A 11proposal package" is assembled and sent through the offices of EPA AssistantAdministrators 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 apart 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

2-7parties. All public comments are summarized and incorporated into a second volume ofthe 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 itis approved by the EPA Administrator. After the Administrator signs the regulation, itis 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 ofcompliance with the regulation, including the extent to which the cost ofcompliance varies depending on the effectivedate of the regulation and the development of less expensive ormore efficient methods of compliance; (2) the potential inflationaryor 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 aproposed standard upon an industry is usually addressed both in absolute terms and in**te~ns** of the control costs thatwould be incurred as a result of compliance with typical, existing Statecontrol regulations. An incremental approach is necessary because both new and existing plants would be required to complywith State regulations in the absence ofa Federal standard of performance. This approach requires adetailed analysis of the economic impact from the costdifferential thatwould 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
2-8problem. The total environmental impact of an emission source must, therefore, be analyzed and the costs determined whenever possible. Athorough study of the profitability and price-settingmechanisms 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 pollutioncontrol 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 availabilityof 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 othermajor Federal actions significantly affecting the quality of the human environment. The objective ofNEPA 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 ofAppeals for the District of Columbia Circuithas held that environmental impact statements need not be prepared by the Agency for proposed actions under Section 111 of the Clean AirAct. Essentially, the Court ofAppeals 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 thesejudicial 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 toSection 7{c)(l), "No action taken under the Clean Air Act shall be deemed amajor Federal action significantly affecting the quality ofthe human environment within the meaning of the National Environmental Policy Act of 1969" {15 U.S.C. 793{c){l)).
2-9Nevertheless, 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) ofNEPA, 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 toNEPA 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 anew source as 11 ••• any stationary source, the construction ormodification ofwhich is commenced

..... afterthe proposed standards are published. An existing source is redefined as anew source if 11modified 11 or 11reconstructed 11 as defined in amendments to the general provisions of Subpart Aof 40 CFR Part 60, which were promulgated in the Federal Registeron 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 ofadesignated pollutant (i.e., a pollutant forwhich airquality criteria have not been issued under Section 108 orwhich has not been listed as ahazardous pollutantunder Section 112). If aStatedoes not act, EPAmust establish such standards. General provisions outlining procedures for control of existing sources under Section lll(d)were promulgated on November 17, 1975, as Subpart Bof 40 CFR Part 60 (40 FR 53340). 2.7 REVISION OF STANDARDS OF PERFORMANCE Congress was aware that the level of airpollution control achievable by any industrymay improve with technological advances. section 111 of the Act provides that the Administrator 11

2-10 Accordingly, •• shall,at leastevery 4years, review and, ifappropriate, 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.

2-113.0 SOURCES OF VOC EMISSIONS
3.1 GENERAL Natural gas processing plants are apartof 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 oftransporting it to treating or processing facilities. Treating is necessary in certain instances for removal ofwater, sulfurcompounds, or carbon dioxide. Gas gathering, compression, and treatingmay ormay not occur ata gas plant. For the purposes of this document, natural gas processing plants are defined as facilities engaged in the separation ofnatural gas liquids from field gas and/or fractionation of the liquids into natural gas products, such as ethane, propane, butane, and natural gasoline. Types ofgas ·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 volatileorganic compound (VOC) emissions that resultwhen process fluid (either gaseous or liquid) leaks from plantequipment. VOC emissions are defined as nonmethane-nonethane hydrocarbon emissions. There aremany potential sources of fugitive emissions in a gas plant. The following sources are considered in this chapter: pumps, compressors, valves, reliefvalves, 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 ofnatural 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 H 2

0Removal)


# ' Separation ofNatural 

### Gas Liquids from Field Gas**1----~**



### Fractionation of Natural Gas Liquids

Sales Products Dry Gas 

### to Sa1

### es

(ethane, propane,**iso-butane~** 

### butane, natural gasoline, etc.)

Figure 3-1. General Schematic ofNatural Gas-Gasoline Processing.

3-2

### transferred by pumps can leak at the point ofcontact between the**~oving** 

### shaft and stationarycasing. Consequently, all pumps except the canned-motor and diaphragm type require a seal at the pointwhere the shaftpenetrates 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 apacking 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 ofa 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 aremany variations to the basic design ofmechanical seals, but all have alapped seal face between a stationaryelement and arotating seal ring. In a single mechanical seal application (Figure 3-3), the rotating-seal ring and stationaryelement faces are lapped to a very high degree of flatness to maintain contact throughout theirentiremutual surface area. As with apacked seal, the seal faces must be lubricated 3-3to 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 abasic singlemechanical seal.2

3.2.2 Compressors Three types ofcompressors can be used in the natural gas production industry: centrifugal, reciprocating, and rotary. The centrifugal compressor utilizes arotating element or series ofelements containing curved blades to increase the pressure ofa gas by centrifugal force. Reciprocating and rotarycompressors increase pressure by confining the gas in a cavityand progressively decreasing the volume ofthe cavity. Reciprocating compressors usuallyemploy a piston and cylinderarrangement while rotarycompressors utilize rotating elements such as lobed impellers or sliding vanes. About halfof 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 ofthese seal types are leak restriction devices; none of them completelyeliminate leakage. Many compressors may be equipped with ports in the seal area to evacuate collected gases.**~1echanical** contact seals are acommon type of seal for rotary compressor shafts, and are similarto 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 3-4the 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

11Chevron11 or nested Vtype.4 Because of safetyconsiderations, the area between the compressor seals and the compressormotor (distance piece) is normally enclosed and vented outside ofthe compressor building. If hydrogen sulfide is present in the gas, then the vented vapors are normally flared.10 Reciprocating compressors may employ ametallic packing plate and nonmetallic partiallycompressible (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 ofvalves commonly used are globe, gate, plug, ball, butterfly, relief, and check valves. All except the reliefvalve (tobe discussed below) and check valve are activated through a valve stem, which may have arotational or linearmotion, 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 ofagate valve in Figure 3-4. The possibility ofa leak through this seal makes itapotential source of fugitive emissions. Since acheck valve has no stem or subsequent packing gland, it is not considered to be a potential source offugitive emissions. Sealing ofthe 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 orwithout rotationmust utilize a packing gland. Conventional packing glands are suited for awide varietyofpacking materials. The most common are various types ofbraided 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 awide range ofoperating temperatures. At high pressures these glands must be quite tight to attain a good seal.7 3-5PACKING GLAND

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



### Process Side
Figure 

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

3-63.2.4 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 reliefvalve (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 ofVOC fugitive emissions. Aseal 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 ofa 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-sealedjunctions 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), orjoining 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 ifthe 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 eithercontinuously bled to the atmosphere or is bled each time the valve is activated, this can potentially be a large source offugitive 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 amuch lower emissions potential than control valves in routine service. 3.2.8 Sampling Connections The operation ofagas plant is checked periodicallyby 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 itcan evaporate and releaseVOC 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 ofthe 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 ofa 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 3-8Table 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 shiftwith a 1sec purge through a 6.4mm 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. Therefory8the emission factors given are probably understated substantially.

3-9emissions 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 significantunderstatement 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 atamodel gas plant are shown in Table 3-2. Total dailyemissions are calculated by multiplying the number of pieces ofeach type ofequipment by the corresponding dailyemission factor. The average percent of total emissions attributed to each component type is also presented in Table 3-2.

3-10Table 3-2. ESTIMATED BASELINE FUGITIVE VOC EMISSIONS FROM ATYPICAL 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 InletGas 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. aFromTable 3-1. bAs discussed in Table 3-1, the compressor seal emission factor and thus

the percentage oftotal emissions from compressors may be substantially understated.

3-113.4 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 ProtectionAgency. Office ofAir 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. Letterfrom Hennings, T.J., TRW to K.C. Hustvedt, EPA. Hay 13, 1981. Results of atelephone survey concerning the use of pneumatic control valves atgas plants. Docket Reference Number II-B-6.* 6. Lyons, J.D., and C.L. Ashland, Jr. Lyons• Encyclopedia ofValves. 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. Letterfrom Hennings, T.J., TRW to K.C. Hustvedt, EPA. July 7, 1981. Results of atelephone survey concerning control of fugitive emissions from gas plantcompressor seals. Docket Reference Number II-B-7.* 11. Eaton, W.S., etal. 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.* 3-1213. Memo from Norwood, T.L., PES toDocket. Gas sampling connection purge emission factor and control costeffectiveness. 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 costeffectiveness. October 27, 1982. Docket Reference Number II-B-14.* 15. Letterand Attachments. Norwood, Tom, PacificEnvironmental Services, Inc. to Gibson, Jim, Seagull Products Company. DraftTrip Report to Palacios Gas Plant. December 9, 1982. Docket Reference Number II-C-18.* 16. 11National Air Pollution Control Techniques Advisory Committee Minutes ofMeeting 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 atU.S. Environmental

ProtectionAgency Library, Waterside Mall, Washington, D.C.

3-134.0 EMISSION CONTROL TECHNIQUES
4.1 INTRODUCTION Sources of fugitive VOC emissions from gas plant equipment were identified in Chapter 3ofthis 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 ofcontrol technology as applied to related industries. This approach is possible because the related industries (e.g., refineries) use similar types ofequipment, 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 applicabilityof the techniques used in controlling fugitive emissions. Chapter4also 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 repairmethods can be applied in order to reduce fugitive emissions from gas plant sources. Leak detection methods are used to identifyequipment components thatare emitting significantamounts ofVOC. Emissions from leaking sources may be reduced by three general methods: repair, modification, or replacement ofthe source. 4.2.1 Leak Detection Techniques Various monitoring techniques that can be used in a leak detection program include individual component surveys, unitarea (walk-through)

4-1surveys, 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, especiallypump seal failures. High pressure vapor leaks may be detected by hearing the escaping vapors, and leaks ofodorous materialsmay be detected by smell. Predominant industry practices are leak detection by visual, audible, and olfactorymethods. However, in many instances, even very largeVOC 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 subjectivelydetermine 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 shaftmay 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 ofVOC 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 entirearea where leaks may occur. This sampling traverse is called 11monitoring 11 in subsequent descriptions. Ameasure of the hydrocarbon concentration ofthe sampled air is displayed in the instrumentmeter. 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 ofcomponents thatare

4-2Component type
Valvesa 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 1,000ppmv
28 34 60 53predicted to have instrument readings greater than or equal to various concentrations during an individual component survey. 4.2.1.2 Unit Area Survey. Aunitarea or walk-through survey entailsmeasuring the ambient VOC concentration within a given distance, for example, one meter, of all equipment located atground level and other accessible levels within a processing area. These measurements are performed with aportable VOC detection instrument utilizing a stripchartrecorder. The instrument operator·walks apredetermined path to assure total coverage ofaunit on both the upwind and downwind sides of the equipment, noting on the chart record the location in aunitwhere any elevated VOC concentrations are detected. If an elevated VOC concentration is recorded, the components in thatarea can be screened individually to locate the specific leaking equipment. It isestimated that 50 percent of all significant leaks in a unitare detected by the walk-through survey, provided thatthere 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 unitarea survey are thatleaks from accessible leak sources near the ground can be located quickly and thatthe leak detectionmanpower requirements can be lower than those for the individual component survey. Some ofthe shortcomings ofthis method are thatVOC emissions from adjacent units can cause false leak indications; high or intermittentwinds (local meteorological conditions) can increase dispersion ofVOC, 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 abackground level indicatea leaking component. As in the walk-through method, an individual component survey is required to identifythe specific leaking component in the area. Leaks from

4-4adjacent units and meteorological conditions may affect the results obtained. The efficiencyofthismethod is not well established, but ithas been estimated that33 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 aremore expensive; multiple fixed pointmonitors 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-pointmonitors have been used to detect emissions of hazardous or toxic substances (such as vinyl chloride) as well as potentiallyexplosive conditions. Fixed-pointmonitors 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 ofthe leak detection techniques discussed above to detect evidence of liquid leakage from plantequipment. When such evidence is observed, the operatorcan use a portable VOC detection instrument tomeasure the VOC concentration of the source. In a specific application, visual inspections can be used to detect the failure ofthe outer seal of a pump•s dual mechanical seal system. Observation ofliquid 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 repairmethods include only those features ofeach fugitive emission source (pump, valve, etc.) that should be considered in assessing the applicabilityand effectiveness ofeach 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 itmay actually increase the emission rate ifthe packing is old and brittle orhas 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 thatare 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 repairand 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. Ifa line must be shut down in order to isolate aleaking valve, the emissions resulting from the shutdown may possibly be greater than the emissions from the valve ifitwere allowed to leak until the next process change that permits isolation for repair. Depending on site-specific factors, itmay also be possible to repair leaking process valves by injection ofa sealing fluid into the source ofthe leak.6 4.2.2.2 Pressure ReliefValves. 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 reliefvalve for repairwithout shutting down the process, the process must be kept isolated from atmosphere. The safestway to isolate the process is to install athree-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. Ifthe 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 itwill not be possible to bring leaks under the designated action level. In addition, therewill not often be a spare compressor to allow shutdown for repair of the leaking compressor seal. In these instances itwould 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 4-6would have no effect or possiblyeven 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 ofVOC. These temporary emissions have the potential of being greaterthan the continued leak from the seal. Therefore, the pump should be isolated from the process and flushed ofVOC 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 ismade. Most flanges and connections cannot be isolated to permit repair of leaks. Data show that flanges and connections emit relatively small amounts ofVOC (Table 3-1). 4.2.3 Emission Control Effectiveness ofLeak Detection and Repair The control efficiencyachieved 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 ofa Leak. The first step in developing a monitoring plan for fugitive VOC emissions is to define an instrument meter reading that is indicative ofan equipment leak. The choice of the meter reading for defining aleak is influenced by several considerations. The percent oftotal 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 atvarious leak definitions for a number of component types. From the table, itcan 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 aleak is a tradeoffbetween the desire to locateall significant leaks and to ensure that emission reductions are possible through maintenance. Although testdata 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 ofPlaSS emissions affected atthis leak definitiona Component type 100,000 ppmv 50,000 ppmv 20,000 ppmv 10,000 ppmv 1,000 ppmv b 54 Valves (59) 64 (70) 78 (83) 86 (87) 97 (98) Reliefvalvesc 41 (42) 53 (56) 67 (69) 77 (77) 96 (96) Compressor sealsb 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 relatethe leak definition to the percentage of total mass emissions thatcan

be expected from sources with concentrations atthe source greaterthan the leak definition. Ifthese sources were instantaneouslyrepaired to a zero leak rateand 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 repairattempts result in an increased emission rate. The increased emissions from such a source could be greater than the emission reduction ifmaintenance 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 significantenough so that an overall emission reduction is likely for aleak detection and repair program with a 10,000 ppm leak definition. In addition, testing by EPA and industry has shown thatmeter readings will generallybe eithermuch less than 10,000 ppm ormuch 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 ofan 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 sealswould tend to have low instrument meter readings. With time, however, as the seal begins to wear, the concentration and emission rate are likelyto increase. At any time, catastrophic seal failure can occur with a large increase in the instrumentmeter 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 aconcentration equal to or greater than 10,000ppm, 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 4-9a piece of equipment has been checked and/or repaired. This interval
can be related to the type ofequipment and service conditions, and different intervals can be specified for different pieces ofequipment. 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. Ifa leak is detected, the equipment should be repaired within acertain 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 plantmaintenance 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 ofReduction 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. Ifa leak detection and repair program resulted in repair of all such sources to 0ppmv, elimination ofall sources over the leak definition between inspections, and instantaneous repair of those sources found ateach 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 ofemissions 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 firstmodel (the computer leak detection and repair (LDAR) model) is described in Appendix Eand 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
4-10for 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 xCx D Where: A

## = Theoretical Maximum Control Efficiency

### =fraction of total mass emissions from sources with VOC concentrations greater than the leak definition (fromTable 4-2). B

### = Leak Occurrence and Recurrence Correction Factor

### =correction factor to account for sources which startto 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 ofa 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 1,000ppmv. As an example of this technique, Table 4-3 gives values for the 118, 11

11C, 11 and 11011 correction factors for various possible inspection intervals, allowable repair times, and leak definitions. These values are given only for reliefvalves and compressors seals, because the reduction efficiency for valves and pump seals is estimated according to the LDARmodel 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 engineeringjudgment employed to derive one of the model inputs. The accuracy ofthejudgmentwas approximated by the comparison ofthe LDARmodel 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 startto leak between inspections (occurrence), for sources thatare found

to be leaking, are repaired, and startto leak again before the next inspection (recurrence), and for leaking sources that cannot be repaired. Reference 11. bFactor accounts for emissions thatoccur between detection ofa leak and subsequent repair. Reference 11. cFactors accounts for the fact that some sources thatare repaired are not reduced to zero. Repaired

sources are assumed to be reduced to a 1,000 ppmv concentration level. FromTables 3-1, 4-1, 4-2, and References 1and 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 ofequipment that could be applied in such aprogram and the advantages and disadvantages of this equipment. 

### 4.3.1 Pressure ReliefValves As discussed in Chapter 3, pressure reliefvalves 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 ofthe valve, by connecting the discharge port ofthe valve toaclosed-vent system, or by use of soft seat technology such as elastomer "0-rings." Arupture disk can be used upstream ofa pressure reliefvalve so thatunder normal conditions it seals the system tightly butwill break when its set pressure is exceeded, atwhich time the pressure reliefvalve will relieve the pressure. Figure 

### 4-1 is a diagram ofa rupture disk and pressure reliefvalve installation. The installation is arranged to prevent disk fragments from lodging in the valve and preventing the valve from being reseated ifthe disk ruptures. It is important thatno pressure be allowed to build in the pocket between the disk and the pressure reliefvalve; otherwise, the diskwill not function properly. Apressure gauge and bleed valve can be used to prevent pressure buildup. With the use ofa pressure gauge, itcan be determined whether the disk is properly sealing the system against leaks. Itmay be necessary to install a2-port valve and parallel relief valve when using a rupture disk upstream ofa reliefvalve. Such a system may be required to isolate the reliefvalve/rupture disk system for repair in case ofan overpressure discharge. The parallel system would provide a backup reliefvalve during repair. However, a block valve upstream of the rupture disk/reliefvalve system will accomplish the same purpose where safetycodes allow the use ofa block valve for this purpose. An alternative method for controlling pressure reliefvalve emissions due to improper reseating is the use ofa softelastomer seat in the valve. An elastomer "0-ring" can be installed so that the 

### 4-13To atmospheric vent ---Tension-adjustment thimble

----Spnng

Figure 4-1. Rupture disk installationupstream ofareliefvalve.3**~·-14**valve always forms atight seal after an overpressure discharge. However, this approach will not prevent leakage due to 11Simmering, 11 a condition due to the system pressure being too close to the setpressure of the valve. 4.3.2 Compressor Seals As discussed in Chapter 3, there are three types ofcompressors used in natural gas plants: centrifugal, rotary, and reciprocating. Centrifugal and rotarycompressors are driven by rotating shafts while reciprocating compressors are driven by shafts having a linear reciprocating motion. In eithercase, fugitive emissions occur atthe junction of the moving shafts and the stationary casing, but the kinds of controls thatcan be effectivelyapplied depend on the type of shaft motion involved. 4.3.2.1 Centrifugal and Rotary Compressors. Centrifugal and · rotarycompressors are both driven by rotating shafts. Emissions fran these types of compressors can be controlled by the use ofmechanical seals with barrierfluid (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 ata 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 aclosed 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 shaftmotion 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 acollection system through vents in the housing. This is referred to as a 11Scavenger11 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

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

. suitablepiping to vent the emissions either to a flare, a plant process heater, or back intoalow pressure point in the process. For the lattertwo cases, an auxilliarycompressor may be required to compress the vent stream to ausable pressure. Purging the distance piece with natural gas could be performed to keep the enclosure above the upper explosive limitand to ensure a nonexplosive atmosphere (Figure 4-2). As shown in Figure 4-2, the distance piece enclosure could be maintained slightlyabove atmospheric pressure by purging the enclosure with residue or sales gas through a regulator. To ensure safety, eitherdouble distance pieces13 ormore sophisticated piston rod seals12 should be employed. Additionally, a high pressure sensor in the purge gas line should be used to shut offthe 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 11U 11 tube trap as shown to prevent loss of the purge gas while allowing uninterrupted oil flow. Asecond water filled trap in' the outlet serves to maintain the pressure in the enclosure, while allowing free flow ofemissions (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 agood seal at the distance piece door and atthe point where emissions are vented from the distance piece or seal area is necessary for maintaining a sufficient pressure (e.g., 2to 5psig). 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 toa compressor distance piecemay be infeasible for safety reasons.15 Therefore, the application ofthis preventive program as a retrofitwill 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 Flareor**..-------:J~or>rocess** Heater 2" (Scm) Header)

Check Valve -+
Distance Piece Vent_, BlockValve 

## ...,

PressureAlarm**~** Water _..-Filled Trap

Waste 011

-**~t:=:==~l==::;;::==~**F=====111===«========:s. Drain lfne toTankor Recovery Oil Cap



### Figure 4-2. COMPRESSOR DISTANCE PIECE PURGE SYSTEM 

### ....."_ Trap

# J Detailleakage 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 eithera back-to-back or a tandem configuration. In both configurations abarrier fluid circulates between the seals. The barrier fluid systemmay be circulating system, or itmay 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, itcan serve other functions as well. Abarrier 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 oxidizablematerials that form abrasive oxides or polymers upon exposure to air. Awide variety of fluids can be used as barrier fluids. Some ofthe 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, itmay also be possibleto use clean product, a product additive, or a product diluent. Emissions ofVOC from barrierfluid degassing vents can be controlled by aclosed vent system, which consists of piping and, ifnecessary, flow inducing devices to transport the degassing emissions to a control


# . device, such as a process heater, or vapor recovery system. Control effectiveness ofadual 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 relativelylarge 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 ofthe 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,
4-18product will remain in the line between the valves, and expansion of this product can cause leakage through the valve stem seals. The control efficiencywill depend on such factors as frequency ofvalve use, valve seat leakage, and material thatmay 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 peryear, that0.1 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 lineswould be 1kg. 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 ofclosing offopen-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 aclosed 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 isminimized. Other sampling systems are available that utilize partiallyevacuated sampling containers and require no line pressure drop.17 Reduction ofemissions 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 resultwhen field gas or flash gas is used as the operatingmedium. These emissions can be eliminated by the use ofcompressed air. This will require installation ofan aircompression system and connection of the appropriate pressure supply lines.

4-194.4 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 toVOC/Onshore Production Docket. April 2, 1982. Cumulative distribution ofmass 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 ProtectionAgency. 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 ofVolatile Organic Compound Emissions from Equipment Leaks. Paper presented at71st 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 ofVolatile 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. Letterfrom 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. Letterfrom 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. Letterwith 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.* 4-2011. Tichenor, B.A., K.C. Hustvedt, and R.C. Weber. Controlling Petroleum Refinery FugitiveEmissions Via Leak Detection and Repair. Symposium on Atmospheric Emissions from Petroleum Refineries. Austin, TX. Report NumberEPA-600/9-80-013. November 6, 1979. Docket Reference Number II-A-7.* 12. Letter from Sheppard, R.W., Ingersoll Rand to Ajax, R.L., EPA. October 29, 1982. Docket Reference Number II-D-43.* 13

...Reciprocating Compressors for General Refinery Service,

.. American Petroleum Institute, API Standard 618, July 1974, pp. 6-8. Docket Reference Number II-I-35.* 14. Letterand attachment from Hennings, T.J., TRW to K.C. Hustvedt, EPA. July 7, 1981. Results ofa telephone survey concerning control of fugitive emissions from gas plantcompressor seals. Docket Reference Number II-B-7.* 15. Letterand attachment from Hennings, T. J., TRW to K. C. Hustvedt, EPA. February 22, 1982. Results of atelephone survey on safety issues concerning compressor vent control systems. Docket Reference Number II-B-16.* 16. FugitiveEmission Sources ofOrganic Compounds. Additional Information onEmissions, Emission Reduction, and Costs. U.S. Environmental Protection Agency. EPA-450/3-82-010. April 1982. Docket Reference Number II-A-25.* 17. Letterand 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 ofControlledEmission 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 atU.S. Environmental

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

4-215. MODIFICATION AND RECONSTRUCTION
In accordance with the provisions ofTitle40 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 itis 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 ofmodification/ 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 ofoperation; 4. Use of an alternative fuel or raw material if, prior to the standard, the existing facility was designed to accommodate thatalternative fuel or raw material; 5. The addition or use of any system or device whose primary function is the reduction ofair pollutants, except when an emission

5-1control 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 ofan affected facility to a stationary source through any mechanism

-- new construction, modification, or reconstruction

-- does not make any other facilitywithin 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 ofany change in emission rate. Asource is identified for consideration as a reconstructed
source when: (1) the fixed capital costs ofthe new components exceed 50 percent of the fixed capital costs thatwould be required to construct acomparable entirelynew facility, and (2) it is technologically and economically feasible tomeet the applicable standards setforth 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 thatwould 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 entirelynew 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~ita** tions in compliance with applicable standards of performance which are inherent in the proposed replacements. The purpose of the reconstruction provision is to ensure that an owner or operator does not perpetuate an existing facility by replacing all but minor components, support structures, frames, housing, etc., rather than totally replacing it in order to avoid being subject to applicable performance standards. In accordance with Section 60.5, EPA

5-2will, upon request, determine ifan action taken constitutes construction (including reconstruction). 

### 5.2 APPLICABILITY OF MODIFICATION AND RECONSTRUCTION PROVISIONS TO NATURAL GAS/GASOLINE PROCESSING PLANTS As a result ofcostand energy considerations, as well as changes in product demand and feedstock supply, there are expected to be a number ofmodernization projects atexisting gas plants in the near future. Some ofthese projects could result in existing gas plants becoming subject to the provisions of Sections 60.14 and 60.15. For example, acompany 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 orcompressors. Routine changes are also made to gas plants, such as those made to increase ease ofmaintenance, to increase productivity, to improve plant safety, or correctminor design flaws. These types ofchanges 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 ofcapital expenditure as defined in Section 60.2(bb). Some changes may involve only the replacement ofa potential fugitive emission source such as a valve. Ifthe source is replaced with an equivalent source the level of fugitive emissions would be expected to remain unchanged. Itmay 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 costlyto operate and because it is more efficient. For the same reasons, owners ofexisting 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 ofnew equipment. It is possible that the cost of the conversion would exceed 50 percent ofthecostofa new plant.

5-36.0. MODEL PLANTS AND REGULATORY ALTERNATIVES
6.1 INTRODUCTION This chapter presentsmodel plants and regulatory alternatives for reducing fugitive VOC emissions from natural gas/gasoline processing plants. The model plantswere selected to represent the range ofprocessing complexity in the industry. They provide a basis for determining environmental and cost impacts of the regulatory alternatives. The regulatory alternatives consistofvarious combinations ofthe available control techniques and provide incremental levels ofemission control. 6.2 MODEL PLANTS There are a number ofdifferent process methods used atgas 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 ofprocess complexity (number of fugitive emission sources), ratherthan different process methods. In orderto estimateemissions, control costs, and environmental impacts on aplant specific basis, threemodel plants were developed. With the exception of sampling connections, the number ofcomponents for each model plant isderived from actual component inventories performed atfour gas plants. Two of the plants were inventoried during EPA testing,3and 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 ateach compressor.
6-1Complexity of gas plants can be indexed by means of calculating ratios ofcomponent populations to a more easily counted population. For gas plants, the number ofvessels 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,6and 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 ofnumbers ofcomponents 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 plantA. It is assumed that there are existing gas plantswith a similar configuration to the EPA-tested plant A, thathave only one process train. The high end of the range, 100 vessels, is slightly larger than the number ofvessels at the industry-tested plant C. Since thiswas the largest of the plants tested, itappears reasonable to use this as a guide in calculating the number of components at the largestModel plant. The middle-sized model plant has 30 vessels. This is approximately the same number of vessels as atthree of the four plants tested and may be representative of a common gas plant size. The threemodel 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

6-21.

2. 3.

0"1 I w 4.

5. 

### Table 6-1. EXAMPLETYPES OF EQUIPMENT INCLUDEDAND EXCLUDED IN VESSEL INVENTORIES FORMODEL PLANT DEVELOPMENT

Included Excluded Absorption/Desorption Units 1. Compressors, Pumps a. Absorbers 2. Piping Systems b. Scrubbers c. Dehydrators 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/FractionationUnits 4. Any equipment associated with sweetening

a. Demethanizer b. Deethanizer c. Depropanizer d. Splitter e. Flash Drum/Tank f. Sti11s 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. Knockout0"1 I +::> Vessels Va1ves Reliefvalves 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 plantwere tested and inventoried. Estimated total

number ofcomponents is therefore based on the sum of the number ofcomponents counted in the larger unitplus twice the number ofcomponents 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 Re1iefva1 ves 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 ofratio

9.9 0.1 3.0 0.2 0.2 59.7Table 6-4. FUGITIVE VOC EMISSION SOURCES FOR THREE MODEL GAS PROCESSING PLANTS

Number ofcomponents Model plant Mode1 plant Model plant Component type Valvesa Reliefvalvesa Open-ended linesa Compressor sealsa Pump sea1sa 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 ofcomponents based on average ratios presented in Table 6-3. bBased on one liquid connection ateach pump and one gas connection at

each compressor.

6-6emission 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 increasinglyrestrictive controls comprised ofthe techniques discussed in Chapter4. 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 ofthe other regulatory alternatives. 6.3.2 Regulatory Alternative II Regulatory Alternative II provides a higher level ofemission control than the baseline alternative through leak detection and repair methods as well as equipment specifications. This regulatory alternative requires quarterly instrumentmonitoring ofvalves, reliefvalves, compressor seals, and pump seals for leaks. Leaks thatare found to be in excess ofa prescribed hydrocarbon concentration (as indicated by a hydrocarbon detection instrument) would be repaired within a prescribed time period. Pump sealswould additionally receive weekly visual inspections for leaks. Leaks found to be in excess ofthe prescribed concentration would be repaired within the prescribed time period. The regulatory alternative also requires thatcaps (including plugs, flanges, or second valves) be installed on open-ended lines. 6.3.3 Regulatory Alternative III Regulatory Alternative III achieves a greateremission reduction than Alternative II by requiring monthly instrumentmonitoring of valves, reliefvalves, and pump seals. Ifa particular valve is found not to be leaking for 3successive months, then 2months may be skipped before the next time it ismonitored with an instrument. Acompressor vent control system would be installed to control compressor seal emissions. Sampling connections would be equipped with aclosed 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**itoring Equipment !1onitoring 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
aQuarterlymonitoring and repair is not an effectivecontrol technique for all compressors. In some instances, reduction in emissions

from compressors through seal repairmay necessitate a process unit turnaround because compressors generally are not spared. In addition, itmay not be possible to repair acompressor seal to below a prescribed leak definition because the seals can normally operatewith concentrations above the action level. In these instances a coo1pressor vent control system should be substituted formonitoring. binstrumentmonitoring 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 instrumentmonitoring ofvalves. Reliefvalves should be 

### equipped with arupture disc, and pumps are required to have dual mechanical seals. Other requirements are the same as Alternative III.

6-96.4 REFERENCES 1. Cantrell, A. Worldwide Gas Processing. Oil and Gas Journal, July 14, 1980. p. 88. Docket Reference Number 11-I-23.* 2. Assessment ofAtmospheric 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 TestData 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, lettertoD. 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., etal. 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.

6-107.0 ENVIRONMENTAL IMPACTS
7.1 INTRODUCTION This chapterdiscusses the environmental impacts from implementing the regulatory alternatives presented in Chapter 6. The primary emphasis is a quantitative assessment of the fugitive emissions thatwould result from each ofthe alternatives. The impacts on water quality, solid waste, energy and otherenvironmental concerns are also addressed. 7.2 EMISSIONS IMPACT 7.2.1 Emission Source Characterization As discussed in Chapter 6, the model plants consistof several types ofcomponents (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 arecharacteristic ofexisting gas plantcomponents. These emissions are referred to as 11baseline11 and representemissions under Regulatory Alternative I. The control technology·discussed in Chapter 4is 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 toestimate the impacts of the regulatoryalternatives 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 thatwould be controlled by the implementation ofa leak detection and repairprogram and are given in Table 7-1. Controlled emission factors for pressure reliefvalves and compressor sealswere derived based upon theABCD model correction factors and the leak detection and repair (LDAR) model as discussed in Chapter4.5 Controlled emission factors for valves and pump sealswere derived directly from the LDAR model as described in Chapter 4and Appendix E.

7-1Table 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 aFromTable 3-1. bcontrolled emission factor= baseline emission factor x(!-control efficiency). cFromTable E-1. dReferences 4, 5.

7-2Where 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 Cunder 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 (baselineemissions) and the incremental costeffectiveness between each regulatory alternativeand the previous alternative. 7.2.3 Future Impact on Fugitive VOC Emissions Future impacts ofthe regulatory alternativeswere estimated for the 5-yearperiod, 1983 to 1987 as shown in Table 7-4. The number of affectedmodel plants (detailed in Section 9.1.2.2) projected foreach yearwas multiplied by the estimated total fugitive emissions permodel plant for each ofthe alternatives (fromTable 7-3). Over the 5-year period, the total fugitive VOC emissions for new plants under baseline control (Regulatory Alternative I) are projected at52 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/reconstructionmay 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 plantequipment primarily impact airquality, they also adversely impactwater quality. In particular, leaking components handling liquid hydrocarbon streams increase the waste load entering wastewater treatment systems. Leaks from equipment contributeto 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 thatare generated by the natural gas/gasolineprocessing 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 PLANTA)

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) Reliefvalves 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

### ~g~ connections L.17 (.17) <1 (<1) .17 (.17) <1 (<1) o.o (0.0) 0 (0) 0.0 0.0 0 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) * FromChapter 6

xx =VOC emission values (xx) =THC emission values aG =Gas Service

L=Liquid Service

### Table 7-2. 

### EMISSIONS FORREGULATORYALTERNATIVES (MODEl PlANTB) 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) Re1 ief va1 ves 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)

....... Samplinga 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 connect1 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) *FromChapter 6

xx =VOC emission values (xx) =THC emission values aG =Gas Service

L=Liquid Service

### Table 7-2. EMISSIONS FOR REGULATORYALTERNATIVES (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 =liquidService....... I

....... 

### Table 7-3. 

### TOTAL AND INCREMENTAL EMISSION REDUCTIONS OFTHE REGULATORY ALTERNATIVES ON AMODEL PLANT BASIS

Model plantemissions,a Mg/yr Percent emission reduction Regulatory 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 peryear 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 FROMAFFECTEDMODEL**P~ANTS**

### AND REGULATORYALTERNATIVES FOR 1983-1987

### ~~~~~~!~v~o~~~~~a~isa Total fugitive emissions prsjectedunder regulatoryalternative (1000Mg/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

### F·o~ 1984 0 80 0 7.0**(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 ofaffectedmodel plants projected through 1987 distinguish between new plantconstructionand

modification/reconstruction. Plants in existence priorto 1983 areotherwiseexcluded. Adiscussionof the growth projections is in Section 9.1.2.2. bThe total fugitive emissions from Model PlantsA, B, and Carederived from the emissions permodel plant

inTable 7-3. The sum ofemissions in any oneyear is the sumofthe products of the number ofaffected facilities permodel plant times the emissions permodel 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 solidwaste is unrelated to the regulatory alternatives. These sources of solidwaste include separatorand 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 ofRegulatory Alternatives**~I** through IV results in a net positiveenergy impact. The energy savings from the 11recovered 11 emissions far outweigh the energy requirements of the alternatives. The regulatory alternativeswould require aminimal increase in energy consumption due to: operation ofmonitoring instruments; installation ofdual mechanical seals, which requireaminimal increase in energy over singlemechanical seals because of seal/shaftfriction and operation offluid flush system; operation of the compressor vent control system; closed loop sampling; and operation ofcombustion devices. The energy savings over a 5-year period from new plants alone is estimated at 4,600terajoules (Regulatory Alternative II) up to 4,900 terajoules {Regulatory Alternative IV) as shown in Table 7-5. Hodified/ reconstructed unitsmay represent an additional 1,600and 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 Irreversibleand Irretrievable Commitment of Resources Implementation ofany of the regulatory alternatives is not expected to result in any irreversible or irretrievable commitment ofresources. Rather, implementation ofAlternatives II through IV would save resources due to the energy savings associated with the reductions in emissions. As previouslynoted, the generation of solidwaste used in the control equipmentwill not be significant.

7-9-.....! I 0 New plants
t·1odifiedI reconstructed plants Table 7-5. ENERGY IMPACTS OF EMISSION REDUCTIONS FOR REGULATORY ALTERNATIVES FOR 1983-1987 Five-year total Energy value of Regulatory recovered emissions recovered emissigns alternative from baseline (1000ttg)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 ofcompressors to flares or heater fuel line in Regulatory Alternatives III and IV. bCalculated on the basis of47 terajoules per gigagram ofVOC. Heating value is assumed to be equal to

that of natural gas plant liquid production for 1978-1980 of 3,925,000Btu/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 ofmethane-ethane. Composition is assumed to be

80 percentmethane and 20 percent ethane. The heats ofcombustion 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 5,800,000Btu/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 atthe rate shown in Table 7-4.

7-117.7 REFERENCES 1. Nelson, W. L. Petroleum Refinery Engineering.**~1cGraw-Hill** Book Company, Inc. New York, 1958. p. 32. Docket Reference Number Il-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 ofLeak 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. MemorandumT.W. Rhoads, PES to Docket A-80-20-B. Calculation of Controlled Emission Factors for Pressure ReliefValves and Compressor Seals. November 1, 1982. Docket Reference Number II-B-17.* *References can be located in Docket Number A-80-20-B atU.S. Environmental

Protection Agency Library, Waterside t·1all, Washingto11, D.C.

7-128. 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 9to estimate the economic impact of the regulatory alternatives upon the natural gas/gasoline processing industry. To ensure acommon cost basis, Chemical Engineering cost indices were used to adjust control equipment to June 1980dollars. 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 thatplant 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 acompressor 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 aflare 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 similarlydestroying

8-1Table 8-1. CAPITAL COST DATA (June 1980dollars)

1. Monitoring Instruments 2instruments (Foxbgro OVA-108) @$4,600/instrument Total cost is $9,200/plant 2. Caps forOpen-Ended Lines Based on costfor 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 1980cost**is~** percent less at$43. Retrofit installation= 1hour 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/

= 3.4hr 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 3men 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

$2,281Table 8-1. CAPITAL COST DATA (June 1980dollars) (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 ofpipe 30m/hr/crew 

### = 0.33 hr for installation 0.25 hr for set-up/breakdown 0.5 hr for fabrication 1.08hours/crew 1.08crew hrs. x3men 

### 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

. 1gas shutoffvalve @$23.891 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 mlength 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** 

### DiskAssembll 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 = OffsetMounting 10.2 em tee, elbow = Installation rupture disk assembly, 16 hrs @

### $18/hr upstream block valve, 10hrs @

### $18/hr offsetmounting, 8hrs @

### $18/hr Subtotal 

### Total

8-4 $ 230 384

18 30



### =$248 

## = 180 = 144 $

### 662
$

### 700

$ 21

$ 

### 1,995Table 8-1. CAPITAL COST DATA (June 1980 dollars) (continued)

8-5Table 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.

8-6Table 8-2. CAPITAL COST ESTIMATES FORMODEL PLANTS (thousands ofJune 1980 dollars)
Regulatory Alternative Capital cost item
Model PlantA 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% rupturedisk systems with 3-way valve.

8-7Table 8-2. CAPITAL COST ESTH1ATES FOR t10DEL PLANTS (thousands ofJune 1980 dollars) (Continued)
Regulatory Alternative Capital cost item
Model Plant B 1. Monitoring instrument 2. Caps for open-ended 1ines 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.

8-8Table 8-2. CAPITAL COST ESTIMATES FOR MODEL PLANTS (thousands ofJune 1980 dollars) (Concluded)
Regulatory Alternative Capital cost item
Model Plant C 1. t·1onitoring 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 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.

8-9the emissions. Table 8-1 shows the installed capital costs for the vent system piping arrangements. The model plantcapital 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 arupture disk for pressure system relief valves and dual mechanical seals for pumps. The costs ofRegulatory 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 instrumentmonitoring 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 costfor leak detection and repair laborwas 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/supportcosts are recurring annual costs for each regulatory alternative. 8.1.2.3 Annualized Costs. The bases for the annualized control costs are presented inTable 8-5. The annualized capital, maintenance, and miscellaneous costs were calculated by taking the appropriate factor from Table 8-5 and applying itto the corresponding capital costfrom 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 adecimal, n = economic life of the component, years. The interest rateused was 10 percent. The expected life of the monitoring instrumentwas 6years. Dual mechanical seals and rupture 8-10co I ,__. ,__. Component type
Valves Monitoring interval quarterly monthly/ quarterly

monthly Relief valves quarterly monthly Conpressor seals quarterly

### TABLE 8-3. LEAKDETECTIONANDREPAIRLABOR-HOURREQUIREMENTS

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

peryear 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 peryear 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) Haintenancef 1abor-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 instr1.111ent 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 instrumentmonitoring requires a two-person team, and visual monitoring, one person. bMonitoring time per person: pumps-instrument 5min., visual 1/2min.; compressors 5min.; valves 1min., and safety/relief valves 8min. Reference 10. cl·lonitoring labor-hours =niJIIber ofworkers xnumber of components xtime tomonitor xtimes monitored peryear. 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 5percent of leaks initiallydetected are found with monthly monitoring (0.05 x 12 =0.6) and that 10 percent of leaks initiallydetected are found with quarterlymonitoring (0.1 x 4=0.4). Fraction of sources initially leaking fran Table 4-1. Number of leaks =number of components xfraction of sources initially leaking xannual fraction of recurrence factor. Reference 7. fLeak repair labor-hours =number of leaks xrepair time. gThe values used in**calculatin~** labor-hour requirements for valves and pump seals were developed on the basis of themodel 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 4hours per repair. Reference 9. jlt is assumed that these leaks are corrected by routinemaintenance at no additional labor requirements. Reference 10. kReferences 10 and 17.Table 8-4. ANNUAL LEAKDETECTION AND REPAIR LABOR COSTSa (June 1980 dollars)

Leak detection cost Repair cost model plant model plant Regulatoryb 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 ofquarterly instrumentmonitoring for

valves, relief valves, compressor seals, and pump seals, and weekly visual monitoring forpump seals. dCalculated on the basis ofmonthly/quarterly instrument

monitoring for valves, monthly instrumentmonitoring for relief valves and pump seals, and weekly visuaJ monitoring for pump seals. eCalculated on the basis ofmonthly monitoring of valves.

8-12 

## c 14,000 12,000

9,700disks 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 ofmethane-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 afuel savings, no credit is taken because most plants are likely to combust these organics in aflare. 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 aone-time cost. Administrative and support costs to implement the regulatory alternativeswere assumed to be 40 percent ofthe 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 replacementmechanical pump seals. The initial leak repair cost in Table 8-7 shows Alternative II to be themost 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 11baseline 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 PlantAunder Regulatory Alternative II has a net annual costof $3,800, as aresultof $9,700 in costs and $5,900 in recovery credits. 8.1.2.6 Cost Effectiveness. The costeffectiveness 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. DERIVATIOUOFANNUALIZED 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 xcapitala 0.163 xcapitalb 0.23 xcapitalc

0.05 xcapitald $3,000e $140m 0.04 xcapitalf $18/hrg 0.40 x (monitoringdlabor + maintenance labor) (estimated number of leak1ng components permodel Hnit x repair time) x$18/hr x 1.4 X0.163**$192/Mg~** $61/Mg aAppl1es to cost of seals ($972-incremental costdue to specification ofdual

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. cSixyear life, ten percent interest. Reference 11. dFrom Reference 11. eincludesmaterials 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. 1shown in Table 8-3. jinitial leak repair amortized for ten years at ten percent interest. ksased on LPG price of40¢/gallon forJune 1980 (Reference 13) and specific

gravity of 0.55 (Reference 14). 1sased on natural gas priceof $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-HOURREQUIREMENTS FOR INITIAL LEAKREPAIR

Percent of Nufllber of components sources Estimated Repair tims 2er model 21ant 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 eaking at 10,000 ppm from Table 4-1. I bseeTable 8-3

. ...... Ul

### Table 8-7. INITIAL LEAK REPAIR COSTS (JUNE 1980 DOLLARS)

Initial repairco5ts Annualized initial repair costs formodel plantsc formodel plants Regulatory 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 (baselinecontrol) 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 x0.163 (capital recovery factor, Table 8-5).

8-16Table 8-8. RECOVERY CREDITS

Model PlantA**~1ode**1Plant

### 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, 

## c 2) 

### =$6,180

### Table 8-9. 

### ANNUAL COST ESTIMATES FORMODEL PLANTA (Thousands ofJane 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 repairlabor9 3. Administrative and supportf Total Before Credit Recovery Creditsh 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 ormodified/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. eFromTable 8-7. fFrom Table 8-5 gFrom Table 8-4. hFromTable 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 FORMODEL PLANT B (Thousands ofJune 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 repairlaborg 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 facilit1es. 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 FORMODEL PLANT C (Thousands ofJune 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. Compressorventcontrol 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. Capsfor 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 disksystem 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. Capsfor 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 repairlaborg 14 12 9.7 3. Administrative and supportf 8.6 8.7 11
Total Before Credit 48 59 145 Recovery Creditsh (58) (56) (61)
ttetAnnual Cost .(10) 3 84
1Costs are the same for new ormodified/reconstructed flc111ties. bcosts for new facilities. ccostsformodified/reconstructed facilities. dcapital costs fromTable8-2. Capital recovery factorfromTable 8-5. eFromTable 8-7. fFrom Table B-5 9FromTable 8-4. hFromTable 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) 100Table 8-12. COST EFFECTIVENESS OF REGULATORY ALTERNATIVES
Regulatory Alternative Model PlantA Capital Cost ($)d e Net annual cost ($/yr) f Total VOC reduction (Mg/yr) Cost effectiveness ($/Mg VOC)g Model PlantB I 0 0 0 0
Capital Cost ($)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 IIa 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 Tab1 e8-1. 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. ;FromTable 8-11.

8-21relatively low costs per**r~g** of VOC emission reductionwhen compared to Alternative IV. Model Plant BRegulatory Alternative II and t1odel Plant CRegulatory 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 inTable 8-1. The capital costforAlternatives I, II, and III arethe 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 ofdual 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 (seeTable 8-5). The net annual costs formodified/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 costeffectiveness of Regulatory Alternative IV for modified/reconstructed facilities is also shown in Table 8-12. The costeffectiveness 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 inTable 8-13. The costestimates were obtained by multiplying the costs permodel 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 todifferentiate between expected**;~pacts,** represented by new plants, and maximum impacts, represented by new plants with the addition ofmodified/ reconstructed plant impacts. Amaximum impact would result if all chanyes to existing plants constitutemodification/ reconstruction. The total capital costs reflect the cumulative costs of implementing the regulatory alternatives in agiven year. All other costs shown are for plants subject to new source performance standards in the indicatedyear. 8-22co I N w Table 8-13. FIFTH-YEAR NATIONWIDE COSTS OF THE REGULATORY ALTERNATIVES (thousands ofJune 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 facilitiesa 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 thatmay cause an outlay offunds by the gas processing industry are listed inTable 8-14. Specific costs to the industry tocomplywith the provisions, requirements, and regulations ofthe statutes are unavailable.

8-24()) I N en Table 8-H 

### STATUTES THATMAY BE APPLICABLE TO THE NATURAL GAS PROCESSING INDUSTRY

Applicable provision, regulationor Statute requirement of statute Clean Air Act and Admendments o State implementation plans

Clean Water Act (Federal

Water PollutionAct)

Resource Conservation and

Recovery Act

Toxic Substances Control

Act o National emission standards for hazardous airpollutants

o New sourceperformance standards

o PSO constructionpermits

o Nonattainment constructionpennits

o Oischarge pennits
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 Environmenta1 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, regulationor 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 protectiveequipment 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 SanctuaryAct I, o Welding, brazing, and cutting standards

o Statesmay 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 reporting8.3 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 gatevalves. 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. Letterwith 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 ofpressure switches and gas shutoffvalves. 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 ProtectionAgency. 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 ProtectionAgency. 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. Letterwith attachments from R. E. Van Ingen, Shell Oil Company, to [). R. Goodwin, OAQPS, U.S. EPA. January 10, 1977. Response to 114 letteron 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 ofLPG 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. DOEMonthly 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 ofOrganic 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.

8-279. 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 ofthe industry for which alternative emission regulations are being considered. Projections for theyear 1987, fiveyears afteraproposal 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 ofthe industry. The profile and the projections, including significant factors and trends in the industry, are presented to aid in the determination ofeconomic impacts of the proposed standards. The energy and environmental impact analyses alsowere 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, interstateand intrastatepipelines, distributors and consumers. The production industry includes hundreds offirms engaged in the exploration, drilling, producing and processing ofnatural 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 of41.3 trillion cubic feet of natural gas discovered during the period from 1969 to 1978. Also, the AAPG states thatthe 16 largest companies accounted for about 60 percent of industry expenditures for geological and geophysical information and lease acquisition. However,

9-1these large companies spend almost twice as much money as smaller firms on predrilling exploration and one-halfas 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 intrastatemarkets. Approximately 100 pipeline companies operate the interstate pipeline network. The pipeline sectorof 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 ofthe 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 sectorof 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 industrywith 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 ofJanuary 1, 1980, these plantswere utilizing about 63 percent of theircombined 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.

9-2Table 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

aBased on data presented in Oil and Gas Journal, July 14, 1980.

9-3There are anumber ofdifferent process methods currentlybeing 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 ofthesemethods 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 thatown more than 20 plants. This table indicates that over 55 percent ofthe gas plants are owned by these 11larger11 companies. Also, Table 9-3 indicates that almost 85 percent ofthe 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 plantcapacity. As the table indicates, over46 percent ofthe 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 from40 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 resultofphased 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 4percent ofdomestic consumption. Exports ofnatural gas declined from 77 billion cubic feet in 1973 to49 billion cubic feet in 1980. Exports are primarily toJapan and Mexico. Imports are primarily from Canada, Mexico, and Algeria. Domestic aggregate retail priceelasticities ofdemand for solid fuels, natural gas, electricityand petroleum are shown in Table 9-6. These elasticities represent the change in final demand for each fuel with

9-4Table 9-2. DISTRIBUTION OF GAS PLANTS BY PROCESS METHODa (1980)
Process Method Absorption RefrigeratedAbsorption Refrigeration Compression Adsorption Cryogenic-Joule-Thomson Cryogenic-Expander Absorption 

### &RefrigeratedAbsorption Absorption 

### &Compression RefrigeratedAbsorption 

### &Refrigeration RefrigeratedAbsorption 

### &Adsorption RefrigeratedAbsorption 

### &Cryogenic-Joule-Thomson Refrigerated Absorption 

### &Cryogenic-Expander Refrigeration

### &Compression Refrigeration 

### &Cryogenic-Joule-Thomson Cryogenic-Joule-Thomson 

### &Expander No Response TOTAL Number ofPlants

77 280 161 7 40 19 147 2 1 2 1 2 13

1 1 10

8 

### 772

aBased on data presented in Oil and Gas Journal, July 14, 1980.

9-5Table 9-3. DISTRIBUTION OF GAS PLANTS BY OWNERSHIPa (1980) Company Owner
Amoco Production Company Cities Service Company Phillips PetroleumCompany 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 ofCalifornia Mitchell Energy 

### &Development Corporation Number ofcompanies that own between 10 and 20 plants Number ofcompanies that own less than 10 plants Total number ofcompanies that own gas plants TOTAL Number ofPlants

47 41 37 35 33 33 33 26 26 25 24 23 23 22

7 117 138 772

aBased on data presented in Oil and Gas Journal, July 14, 1980.

9-6Table 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

aBased on data presented in Oil and Gas Journal, July 14, 1980.

9-7Table 9-5. PRODUCTION OF ENERGY BY TYPE, UNITED STATES (Quadrillion Btu)
Natura1 Hydro- Nuclear Total %NG Crude gas electric electric energy of Coal1 "12 NGPL3 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 ofcomponents due to independent rounding.

### ~ Includes bituminous coal, lignite and anthracite. 3 Includes lease condensate. 4Natural gas plant liquids. 5 Includes industrial and utilityproduction ofhydropower. Includes geothermal power and electricity produced from wood and waste. R

### =Revised data Source: U.S. Department ofEnergy, 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~** ofdemand 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 , Areport prepared by the Council on Environmental Quality and the Department of State. April 1981. p. 301.

9-9respect to a change in the price ofall four aggregate fuel types. Therefore, the diagonal corresponding to directprice elasticity should have anegative 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 elasticitywith 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 ofelectricity. All ofthe cross priceelasticities are positive, representing interfuel substitution. 9.1.2 Onshore Natural Gas Production Industry--Growth and Projections This section discusses the historical production and price ofnatural gas. Natural gas production is projected for theyears 1985, 1990 and 2000 and distributed in the categories ofonshore, offshore, discoveries from existing fields and discoveries from new fields. 9.1.2.1 Historical Data. Marketed production ofnatural 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 ofnatural 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 peryear 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 ofthe total in 1979. The difference between gross withdrawals and marketed production represents quantities from gas wells and oil wells that were eithervented, flared or used for reservoir repressuring. 3 In 1980, therewere 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.

9-10Year
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.

aMarketed production is denved. It 1 s gross w1thdrawa1 s from producing reservoirs 1 ess gas used for reservoir representing and quantities vented and flared. bEst1mated, 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 apressure base of 14.73 ps1a at 60°F. For prioryears, the pressure base is 14.65 psia at 60"F. Sources:

• 1949 through 1975, U.S. Department of the Inter1or, Bureau ofMines, Minerals Yearbook, "Natural Gas" chapter. • 1976 through 1978,u.s. Department of Energy, Energy !nformat1on Administration, Natural Gas Production and Consumption, annual.

cData from U.S. Department of the Inter1or, Geolog1cal Survey

- Conservation Division, Outer Continental Shelf

Stat1st1cs.

9-11The nominal price ofnatural gas remained reasonably steady during the period from 1955 through 1973. Since 1973, theyear ofthe Arab Oil Embargo, the price has consistently increased in real terms. Figure 9-1 shows selectednatural gas prices for three categories for the period from 1955 through 1979. 4 In 1979, the price ofnatural gas at thewellhead was $1.13 permillion Btu, $1.85 permillion Btu atthe citygate and $2.50 per million Btu delivered to ultimate customer. This consistent increase in the price coupled with the deregulation ofthe price ofnatural gas in almost all categories before the end of 1985 will boost the revenues and profitabilitymargins 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 oftight gas formations. Since the Oil Embargo in 1973, the financial condition ofthe onshore crude oil and natural gas production industry has been improving steadily in both revenues and netprofits. Composite financial data shown inTable 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 netprofitmargins as apercent of sales however have declined from 7.6 percent in 1976 to 5.1 percent in 1980. This fact indicates thatproduction costs have risen at a faster pace than prices. Also, total capital has grown ata 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 industrywill continue to have a healthy financial future into the 1980 15. It is projected in 1983-85 that the industrywill have a composite net profit margin of4.6 percent on annual revenues ofapproximately $70 billion in currentdollars. 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 ofnew and modified and reconstructed gas processing facilities in theyears 1983 through 1987 aredeveloped. The form of the growth in terms ofnew 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. 

### Selectednatural gas prices-threecategories 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 ProfitMargin 7.6% 7.0% 6.2% 5.6% 5.1% 4.8% 4.6% Long-termDebt 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 ($mi11) 19,538 20,207 20,611 22,236 23,750 26,000 35,500 Net Plant ($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. 11Natural Gas Industry

... Value Line Investment**Surve~,** July 18, 1980.is discussed. The size distribution ofnew facilities is developed based upon industry's historical trend. Information on the projection ofnatural gas price is presented, and the effectof pricederegulation on natural gas production is discussed. Production of natural gas by conventional techniques has exceeded the rate of reserve additions in recentyears. 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 fiveyears through 1995. The production of associatedand 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 significantportion ofthe 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 itwill reach the maximum of4.9 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 theyear 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 acomparison of 1990 projection forecasts presented by the Department ofEnergy (DOE), the American Gas Association (AGA), Exxon, Tenneco and otherprivate study groups. 6 AGA's forecast of 16.3 quadrillion Btu peryear is 8.4 percent lower than DOE's forecast of 17.8

9-15Table 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. bIncluding new additions from pre-1977 leases.
c Post-1976 leases only. dTotals 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 

### 4.0 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
9-171.0 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

aDOE/EIA 1979 Annual Report to Congress, middle range forecast. bAmerican Gas Association, The Future for Gas Energy in the United States, June 1979. cData 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

dThe 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 fTenneco Oil Company, Energy 1979-2000, June 1979. g Included in conventional production. hLess than 0.5 quadrillion Btu. 1979.

Note: Non-EIA projections converted from trillion cubic feetwith 1,020 Btu per cubic foot. Numbers may not add to totals because of rounding.quadrillion Btu peryear, and Exxon's forecast of 14.9quadrillion Btu is 16.3 percent lower than DOE's forecast. AGA's projections were used for the purposes ofthis study because theirprojections 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 ofnew gas processing plants thatare projected to begin operating between 1983 and 1987 are presented in Table 9-11. This table shows, foreach 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 afterJanuary 1, 1983 from any well located outside of agiven radius and depth ofa proven reserve and gas produced offshore from any tract leased afterJanuary 1, 1983. The figures listed under the "new production" column include the incremental new production for thatparticularyearplus the gas produced from the newwells ofthe previousyears, back to 1983. Therefore, the cumulative number of new gas plants expected to be in operation each ofthe fiveyears was determined by dividing the projected annual new natural gas production by the average capacityofexistingcryogenic gas plants. It is assumed that all new gas plantswill employ the cryogenic process method. In addition to new gas processing plantsbeing constructed, it is estimated that approximately eightexisting gas plants will be modified or reconstructed during eachyearduring the period 1983-1987. This estimate approximates the number ofexpansions reported each year by Oil and Gas Journal's semi-annual report on plantexpansions and equals one percent of the total number ofgas plants in the United States. Natural gas prices are projectedby the Department ofEnergy to increasebecause ofthe Natural Gas PolicyAct and phased deregulation of pricesduring the period from 1983 through 1987. By 1985, almost all categories ofnatural gas productionwill be deregulated. Very littlenew gas will be subject to controls; most old intrastate gas will be decontrolled and the quantity ofold interstategas that remains controlled will decline rapidly over time. Because ofthis phased deregulation, natural gas prices are projected to increase during the period from 1983

9-19Table 9-11. ESTIMATED NUMBER OF NEW GAS PLANTS, 1983-1987
New natural gas productiona Cumulative numberb Year (trillion cubic feet) ofnew gas plants
1983 1.32 40 1984 2.62 80 1985 3.89 120 1986 4.99 150 1987 6.07 180

a 11New11 production is considered to be gas which is (1) produced from anew well beyond a specifieddistance from an oldwell; (2) produced from a reservoirfromwhich gas was not produced in commercial quantities prior toJanuary 1, 1983, or (3) produced from an offshore tract leased on or afterJanuary 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 of6.2 percent, and the source for this decline rate is theNational Petroleum Council's U.S. Energy OutlookOil and Gas Availability, 1974. b It is assumed that all new gas plantswill be cryogenic gas plants, with an average capacity equivalent to the average capacity ofexisting cryogenic plants (90 MMcfd). Therefore, the number ofnew gas plants is developed by dividing the projected annual new production by the average capacity ofexisting cryogenic gas plants.

9-20through 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 ofalternative emissions ·regulations limiting volatile organic compounds (VOC) emissions from natural gas/gasoline processing plants. 9.2.1 Economic ImpactAssessment Methodology The methodology for economic impact assessment ofVOC emissions regulations on the onshore natural gas processing industry includes the following steps: Step 1-Analyze the absolutemagnitude ofadditional pollution control costs in terms ofbefore-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• abilityto pass additional emissions control costs forward to consumers orbackward to suppliers. Step4-Determine the financial viabilityof regulated plants. Step 5 - Analyze expected impacts ofemissions regulations on plant closings, curtailmentofexpansion, industry output, industry prices, employment, wages, productivity, plant location, international trade, and possible balance ofpayments effects. If it is determined in Step 1and 2thatthe 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 analysesjustifiably can be foregone. Such might be the case where annualized pollution control costs aremuch less than EPA•s trigger criteria for regulatory analysis, i.e., $100 million additional (before tax) annualized cost or aprice increase of 5percent required for industrymembers tomaintain pre-control levels of profitability.

9-21Table 9-12. NATURAL GAS PRICES: HISTORY AND PROJECTIONS FOR 1965-1995 (1979 Dollars perThousand 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

aSource for historical data is Volume 2of the EIA Annual Report to Congress, 1979, and the following EIA Energy Data Reports: Natura1Gas Production and**Consum~tion,** 1978; United States**Im~orts** and**Ex~orts** of Natural Gas, 1978; and, Natural and**S~nthetic** Gas, 1978.
cMajor fuel-burning installations. Notes: NA

### =Not available.



### -- =Not applicable. bSource: DOE/EIAAnnual**Re~ort** to Congress, 1980, Vol. 13, pg. 90.

9-22If it is determined in Steps 1and 2that the directemissions control costs are significant in eitherabsolute or relative cost to the industry, then the focus ofthe analysis turns toward analyzing the ability of regulatedplants to pass additional costs forward to consumers orbackward to suppliers. The analysis in Step 3is explained in the contextofthe industry's structure, conduct and performance as described in Section 9.1. Specifically, the level ofcompetitionwithin the industry and the elasticity ofdemand to the regulated plants is important as well as the elasticityofaggregate product demand. If it is determined that the industry is able to pass on all additional costs, then Step 4can be omitted since the financial viability of regulated plantswould not be jeopardized. Important impacts may occur in supplieror consumer sectors and these should be analyzed ifexpected price impacts are significant to these sectors. If, on the other hand, it is determined in Step 3that the industry is unable to pass on all

·additional emissions control costs, then Step 4is needed to determine the

economic viabilityof regulated and impacted plants. Ifneeded, anet present value approach is used in Step 4to determine the regulated plants• financial viability. Specifically, after-tax net annualized cost ofemissions control is estimated and used to calculate required percentage price increases needed for regulated plants tomaintain baseline net present values for each regulatory alternative. If the required price increase for some regulatory alternativeexceeds 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 1through 4and the industry profile in Section 9.1, additional analyses ofexpected economic impacts are completed. Expected industry price and output impacts are estimated simultaneously. Then related impacts on employment, productivity, international trade, etc. are brought intofocus in Step 5. Before-tax annualized costs (BTAC) and after-tax annualized costs (ATAC) ofemissions controls are computed in Step 1using the following equations:

9-23where,BTAC =I0 CRF +O&M0 (1)
ATAC = 10 CRF TAXF +(1-t) O&M0 (2)

Io =initial base year investment
OM0 =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 ofcapital

n=economic lifeofthe asset, i.e. the capital recovery period (variableby 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 ofthe depreciation period, 3, 5, 10 or 15years
d = nominal discount rate, and

= annual depreciation factors based on themost advantageous depreciationmethods for the firm, either (1) rapid amortization of pollution control investments or (2) accelerated cost recovery as allowed by the 1981 Economy Recovery Act.

9-24Required 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 8and 10 percent, respectively. This inflation rate is consistentwith 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 natura1gas industry stock price earnings ,'atios of7to 8, a45 percent debt ratio, 47 percentmarginal 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 ofcontrols in 1987, the fifthyear of controls, are estimated to be as follows:



## _y g_er.;u**LJ~_Q_rt** 

### a1ternat ives, 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.

9-25These estimates are derived at the bottom ofTable 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 yearof 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 ofmodified 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 thesemodified 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 smallestmodified 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 Bcosts are $2,010, $3,250, and $40,080 while model plant Chas 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.

9-26Table 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 1985 6 9 9 -84.8 40.7 1,558.5 N ......, 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, Band Cave. 10, 30 and 100 vessels, respectively.1.0 I N co 

### t•lode1 

### plant

New Modified and Reconstructed A B 

## c Table 9-14. 

### ONSHORE NATURAL GAS PROCESSINGMODEL PLANTS• BEFORE-TAX NET ANNUALIZED COST OF VOC REGULATORY ALTERNATIVES PER PLANT

Size No. vessels MMcfd I 

### Baseline

contro1

level Regulatory alternative I I III 

### IV



### -----------------Thousandsof1980dollars----------------- 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 40.08 121.551.0 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 65.82For modified and reconstructedmodel plant A, these costs are $2,060, $2,880, and $9,320, respectively; $2,390, $2,590, and $21,680, respectively, formodel plant B; and -$2,860, $1,880 and $65,820 for model plantC. 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 ofmagnitude calculation, gas throughput was assumed to be 30, 90, and 250 MMcfd for plants A, 

### B, and C, respectively. Gas throughput for new cryogenic plantswas 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 thatgas processors will pass a large portion, ifnot 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 tradewill 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 sectiondiscusses the potential social disruption and inflationary impacts associatedwith the VOC regulatory alternatives. Data presented in Section 9.2 above indicated that additional costs for control ofVOC emissions from natural gas processing plants are expected tobe small on an absolute and relativebasis for all four regulatory alternatives considered. No impact is expected on plant location or structureofthe natural gas processing industry. Nojob 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 ofproduction are small, i.e., less than 0.5 percentofsales for all model plants and regulatory alternatives. It is expected, however, that gas processors will succeed in passing alarge share ofthe added costs forward into product markets for natural gas liquids. The directeffecton pricewill be negligible, especiallywhen compared to total industry sales, including existing (exempt) plants. No productivity, plant location, orbalance of payments effects are expected due to any ofthe VOC regulatory alternatives.

9-31

### 9.4 REFERENCES FOR CHAPTER 9 1. Oil 

### & Gas Journal, January 28, 1980, p. 81. Docket Reference NumberA-80-20-B (VOC) II-I-39.* 2. U.S. Deparment of Energy, Energy Information Administration. Annual Report to Congress-1979. VolumeTwo (ofThree): Data, Docket Reference NumberA-80-20-B (VOC) II-I-36,*and, U.S. Department ofthe Interior, U.S. Geological Survey-Conservation Division, Outer Continental ShelfStatistics, June 1980. Docket Reference NumberA-80-20-B (VOC) II-I-40.* 3. U.S. Department of Energy, Energy Information Administration. Annual Report to Congress-1979. Volume Two (ofThree): Data. Docket Reference NumberA-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 (ofThree): 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 (ofThree): Projections. Docket Reference Number A-80-20-B (VOC) II-I-37.* *References can be located in Docket NumberA-80-20-B atU.S. Environmental

ProtectionAgency Library, Waterside Mall, Washington, D.C.

9-32

### APPENDIX A - EVOLUTION OF THE BACKGROUND INFORMATION DOCUMENTDate 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 ofthe Background Information Document



### A-2 Nature ofAction Meeting to discuss onshore production and to solicitthe aid ofAPI in gathering field data. Introductoryrneeting with API. Visit to Exxon Company, U.S.A., Blackjack Creek facility, Jay Field, Florida to gain familiarity with process equipment and operating conditions. Visitto Phillips Petroleum, Chatham facility, Chatham, Mississippi, to gain familarity with process equipment and operating conditions. Plant visits to various tank battery sites in theWest Texas oil and gas field to gain knowledge of processing equipment. Source Category Survey Report. Visitto Exxon Company tank battery in Kingsville, Texas, to gain familaritywith gas and oil production processes and facilities. Visit to Phillips Petroleum Company, Roosevelt County, New Mexico, toacquire familiarity with gas and oil product in processes and facilities. Visit to Shell Oil Company StatelineProduction 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

Apri1 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 atTexas, Inc., Paradis gas plant, Paradis, Louisiana. Emission source testing at GulfOil Company, Venice Plant, Venice, Louisiana. Preliminary draft CTG document, Control ofVolatile 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 3through 6 sent out for industry review and comments. Draft CTG Document, Control of VolatileOrganic 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 draftNSPS for natural gas processing plants. Visits to Phillips Petroleum Co., Alvin, Texas, plant and Amoco Production Co., Old Ocean, Texas, Plant. Visits toTexaco U.S.A.; Blessing, Texas, Plant and Seagull Products Co., Pelacious Texas, Plant. Meeting with Union Texas Petroleum Co. to discuss comments on thedraft NSPS for natural gas processing plants.

### ;\PPENDIX B - INDEX TO ENVIRONMENTAL IMPACT CONSIDERATIONS0::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- latoryalternatives. 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 industryand emission sources within the**indu~try** affected by the regulatoryalternatives are listed in Chapter 3. The specifie sources affected by the regulatory alternatives are summarized in Chapter 3, Section 3.2. Adiscussion ofavailable emission control techniques is presented in Chapter4, Sections 4.2 and 4.3. The various categories ofalternatives to the actions which were considered are listed below. a. Alternative regulatory approaches. The alternative approaches for regulatingVOC emissions under Section 111 of the Clean Air Act are outlined in Chapter 6. b. Alternativecontrol techniques. The alternativecontrol techniques thatcould be utilized by the regulatory alternatives are outlined in Chapter 4. (continued)CO· I w Agency Guidelines for Preparing RegulatoryAction Environmental Impact Statements (39 FR 37419) Agency's canparativeevaluation of the beneficial and adverse environmental. health, social. and economic effects ofeach reasonable alternative.

3. Environmental impact of the regulatory alternatives.

a. Primary impact. Primary impacts are those that can be attributed directlyto the action. such as reduced levels of specific pollutants brought about by anew standard and the physical changes that occur in the various media with this reduction. Table B-1. CONTINUED

Location Within the Background lnfonnationDocument (BID)

a. Adiscussion of the Agency's canparative evaluationofthe various alternative regulatory approaches forVOC 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 effectsof the regulatory alternatives can be found in Chapter 7. Adetailed description of the economic impacts ofeach alternativecontrol 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. Forexample, mandatory reduction of specific pollutants brought about by a new standard could resultin the adoption ofcontrol 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. Irreversibleand irretrievable commitments of resources that would be involved with the regulatory alternatives, should one be implemented. Table B-1. CONCLUDED

Location Within the Background InfonnationDocument (BID)

Other environmental impacts (i.e., solidwaste, water quality) of the individual controls that can be used to meet the regulatoryalternatives 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.

Asulllllilry of the potential adverse environmental impacts of the regulatory alternatives and a discussion ofthe significanceofeach impact can be found in Chapter 7. Adiscussion of irreversible and irretrievable committment of resources is in Section 7.6.1.

### APPENDIX C. EMISSION SOURCE TEST DATAAPPENDIX C. EMISSION SOURCE TEST DATA Fugitiveemission testdata have been collected at six natural gas/gasoline processing plants (see Table C-1) by EPA and industry. Two gas plants were tested under contractto 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 atall 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 ofthe EPA-tested plants. Selected components were measured for mass emissions atboth of the API-tested plants (Plants 1and 2) and at two ofthe 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. Astudy 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 plantwas of the refrigerated absorption type, and the otherwas acryogenic plant. Descriptions and schematics of the plants are provided in Reference 1. Ofthe 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, ofwhich only one was operating. This unit had acapacity of 60MMSCFD (million standard cubic feet per day}, and was operating between 33 and 55 MMSCFD during the testing period. The second unitwas shut down and depressurized, and therefore not tested.
C-2Table C-1. GAS PLANTS TESTED FOR FUGITIVE EMISSIONSa

Data Plant collection Plantprocess 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 RefrigeratedAbsorption Instrument, Soaping 6 EPA Refrigerated Absorption Instrumentb

aReference 6. bless than 50 components were soap screened atplant No. 6.

C-3The third unitwas also not operating, but itwas under natural gas pressure and was tested. The secondEPA-tested plantwas 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 plantwas operating at its rated capacity of30**~1MSCFD.** The thirdEPA-tested plantwas 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 thatwas testedwas operating at450 MMSCFD, near its capacity of500 MMSCFD. The fourthEPA-tested plant was also of the refrigerated absorption type (Reference 5). There were two parallel absorption trains, and one fractionation train. Natural gas liquidswere fractionated intoethane/propane, propane, iso-butane, butane, and debutanized natural gasoline streams. The plantwas operating atapproximately 450 MMSCFD, about halfof its rated capacityof800 MMSCFD. Asummary of the instrument screening data collected at the four EPA-tested plants is presented in Table C-2. Asummary ofthe soap screening data collected atthe 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 atPlant 6). The instrument screening data are tabulated for each plant, showing the number ofeach type ofcomponent tested and the percent emitting. The soap screening data are not tabulated for each plant but are instead summarized by soap score. Acomplete 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 ofmaintenance. Gate valves in gas and condensate service in oil and gas production field tank batteries were studied.

C-4The sources were monitored with soap scoring at intervals over a9-month period. t1aintenance was performed on aportion of the valves studied. The results of an analysis of this data show thatmonthly leak occurrence was 1.3percent, monthly leak recurrencewas 1.6percent, and leak repair effectivenesswas 100percent.7 These results compare favorably with the 1.3percent monthly leak occurrence and recurrence and 90 percent repair effectiveness used to analyze leak detection and repair control effectiveness in Chapter 4and 7. The industry study results were not specificallyused 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 3was used to define a leak ratherthan a meter reading of 10,000ppm.

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**~**10,000pp41V 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 1,804 12.1 60 5.0 472 11.7 30 46.7 51 33.3 768 3.6 I 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

aRderence6.

### Table C-3. SOAP SCREENING DATA FORAPI-TESTED AND EPA-TESTEDGAS 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 lolal 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-tesledplauts and four lPA-testedplants. Reference 6C.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 atHouston 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. FugitiveVOC 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. FugitiveVOC Testing at theTexaco Paradis Gas Plant, Volume I and II. U.S. EPA, ESED/EMB Report No. 81-0SP-7. July 1981. DocketReference Numbers II-A-17, II-A-18.* 5. Harris, G. E. FugitiveTest Report atthe GulfVenice 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 toDurham, J.F

.., EPA 11API/Rockwell r1aintenance Data11 • December 9, 1982. Docket Reference Number II-B-22.* *References can be located in Docket Number A-80-20-B atthe 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 Atestmethod was not availablewhen EPA began the development of control technique guidelines, new source performance standards, and hazardous pollutant standards for fugitive volatileorganic 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 atestmethod, EPA reviewed the availablemethods for measurement of fugitive leaks with emphasis on procedures thatwould provide data on emission rates from each source. To measure emission rates, each individual piece ofequipment must be enclosed in atemporary 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 studies1'2and has been demonstrated to be a feasiblemethod for research purposes. Itwas 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 thatyield qualitative or semiquantitative indications of leak rates were then reviewed. There are essentially two alternatives: leak detection by spraying each component leak sourcewith a soap solution and observing whether or not bubbles were formed; and, the use of aportable analyzer to survey for the presence of increased organic compound concentration in the vicinity ofa 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 analyzerwas selected as abasis for the method because it



### D-2would 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 interferewith bubble formation. Once the basic detection principal was selected, itwas then necessary to define the procedures for use of the portable analyzer. Prior to performance of the first field test, aprocedure was reported that conducted surveys at a distance of 5em 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 aleak was ameasurement of 5em, with a leak definition concentration of 100 or 1,000 ppmv. The localized meteorological conditions affected dispersion significantlyat greaterdistances. Also, itwas more difficultto define a leak at greater distances because of the small changes from ambient concentrations observed. Surveys were conducted at 5em from the source during the next three facility tests. The procedure was distributed for comment in adraft control techniques guidelinedocument.5 Many commenters felt that ameasurement distance of 5em could not be accurately repeated during screening tests. Since the concentration profile is rapidly changing between 0 and 10em from the source, a small variance from 5em could significantly affect the concentration measurement. In response to these comments, the procedures were changed so thatmeasurements were made atthe surface of the interface, oressentially 0em. This change required that the leak definition be increased. Additional testing attwo refineries and three chemical plants was performed by measuring volatile organic concentrations at the interface surface. Acomplication that this change introduces is thata small mass emission rate leak (11pin-hole leak11 ) can be totallycaptured by the instrument and a high concentration resultwill be obtained. This has occurred occasionally in EPA tests, and a solution to this problem has not been found.

D-3The calibration basis for the analyzer was evaluated. Itwas recognized thatthere areanumber of potential vapor stream components and compositions that can be expected. Since all analyzer types do not respond equally to different compounds, itwas necessary toestablish a reference calibrationmaterial. 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 5emmeasurement distance, calibrationswere 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 thathexane standards atthis concentrationwere not readily availablecommercially. Consequently, modifications were incorporated to allow alternate standard preparation procedures or alternatecalibration gases in the testmethod recommended in the Control Techniques Guideline Document for Petroleum Refinery Fugitive Emissions. Since that time, studies have been completed thatmeasured the response factors for several instrument types.6'7'8 The results of these studies show that the response factors formethane and hexane are similarenough for the purposes of this method to be used interchangeably. Therefore, in laterNSPS, the calibrationmaterialswere hexane ormethane. The alternative of specifying adifferent calibrationmaterial for each type stream and normalization factors for each instrument type was not intensively investigated. There are at leastfour instrument types available thatmight be used in this procedure, and there are alarge 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 aprocess unitwas not significantly differentwhen 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-4An alternative approach to leak detectionwas 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 1meter 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 chartdata to locate the approximate source of any increased ambient concentrations. This procedure was found to yieldmixed results. In some cases, the majority of leaks located by individual component testing could be located by walkthrough surveys. In othertests, prevailing dispersion conditions and local elevated ambient concentrations complicated or prevented the interpretation of the results. Additionally, itwas not possible to develop a general criteria specifying how much of an ambient increase at adistance of 1meter is indicative of a 10,000ppm concentration at the leak source. Because of the potential variability in results from site to site, routinewalkthrough 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 unitwas 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 ageneral 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 concentrationmeasurement 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,

0-5soap 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 enclosurewith 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 ofMethod 21. D.2 CONTINUOUS MONITORING SYSTEMS AND DEVICES Since the leak determination procedure is not a directemission 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. Acontinuous monitoring system or device could serve as an indicator that aleak has developed between inspection intervals. The EPA performed a limited evaluation offixed-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 thatfixed point systems were not capable of sensing all leaks thatwere found by individual component testing. This is to be expected since these systems are significantly affected by local dispersion conditions and would require eithermany individual point locations, or very low detection sensitivities in order to achieve similarresults to those obtained using an individual component survey. It is recommended thatfixed-pointmonitoring systems not be required since general specifications cannot be formulated to assure equivalent results, and each installationwould 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 ofa portable analyzer to detect the presence of volatile organic vapors at the surface of the interfacewhere direct leakage to atmosphere could occur. The approach of this technique assumes that ifan organic leak exists, therewill 

### D-6be an increased vapor concentration in the vicinity of the leak, and that the measured concentration is generally proportional to themass emission rateof the organic compound. An additional procedure provided in Reference Method 21 is for the detennination of 11no detectable emissions

... The portableVOC analyzer is used to determine the local ambient VOC concentration in the vicinityof the source to be evaluated, and then ameasurement is made at the surface of the potential leak interface. Ifaconcentration change of less than 5percent of the leak definition is observed, then a 11no detectable emissions 11 condition exists. The definition of 5percent of the leak definitionwas selected based on the readability of ameter scale graduated in 2percent increments from 0to 100 percent of scale, and not necessarily on the performance of emission sources. Reference Method 21 does not includea specification ofthe instrument calibrationbasis or adefinition of aleak 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 leastfour types ofdetection principles currently available in commercial portable instruments. These are flame ionization, catalytic oxidation, infrared absorption (NDIR), and photoionization. Two types (flame ionization and catalyticoxidation) are know to be available in factorymutual certified versions for use in hazardous atmospheres. The recommended test procedure includes a set ofdesign 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 testresults, 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 ofan 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 ofmonitoring 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 largeopenings 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 ifbubbles are formed. Ifno 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 reliefvalve 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 aconcentration based leak definition is not included in the**1~ethod** and is not recommended for inclusion in an applicable regulation because of the difficultyof calibrating and normalizing a scoring technique based on bubble formation rates. Ascoring technique would be based on estimated ranges of volumetric leak rates. These estimates depend on the bubble size and formation rates. Ascoring technique would be based on estimated ranges of volumetric leak rates. These estimates depend on the bubble size and formation rate, which are subjectivejudgments of an observer. These subjectivejudgments 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-8concentration measurement procedure is available, asoap scoring equivalent leak definition is not recommended for the applicable regulation. The alternate procedure that has been included will allow more rapid identificationof potential leaks for more rigorous instrumental concentration measurement.

0-9D.4 REFERENCES 1. JointDistrict, 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 NumberA-80-20-B (VOC) II-E-17.* 4. Miscellaneous Refinery Equipment VOC Sources atARCO, 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 ofVolatile 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 ofVOC Analyzers ataMeter Reading of 10,000 ppmv for Selected Organic Compounds. U.S. Environmental ProtectionAgency, 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., etal. 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 TestReport: 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 theWalkthrough Survey**~1ethod** for Detection ofVolatile 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. 11

### Data Analysis Report: Emission Fact(1rs and Leak Frequencies for Fittings inGas Plants,

.. EMB Report No. 80-FOL-1. July 1982. Docket Reference NumberA-80-20-B (VOC) II-A-36.* 12. 11

### Emission 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. 11

### Emission Test Report: Union Carbide Corporation, Torrance, CA,

.. EMB Report No. 78-0CM-12A, November 1980. Docket Reference NumberA-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 LEAKDETECTION AND REPAIRON FUGITIVE EMISSIONS FROM**PU:~PS** 

### AND VALVESE.1 INTRODUCTION The purpose ofAppendix Eis to present amathematical model (LDAR Model) for evaluating the effectiveness of leak detection and repair programs on controlling fugitive emissions from pumps and valves. In contrastto the ABCD model presented in Chapter 4for analysis of leak detection and repairprograms on reliefvalves 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 thatare based in partupon engineering judgment. E.2 LDARMODEL The LDARmodel is based on the premise thatall sources atany 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 greaterthan or equal to the action level); 3) Leaking sources thatcannot be repaired on-line and are awaiting a shutdown for repair; and 4) Repaired sources with earlyleak 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 2and 4above; 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 ofthe LDARmodel. Since there are only four categories of sources, there are only four 11leak rates 11 for all sources. In fact, there are only three distinct leak rates since the repaired sources experiencing earlyleak recurrence are**assu~ed** to have the same leak rateas sources thatwere unsuccessfully repaired. The LDARmodel 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-2r'T'1 I w Qu.arterlJ ScrHttlaaa..t Katateaaace of

Leak!

.. S.O.rcea1 Lukl.. Soul'caa1 vU

..lllltateaeoc:e**Peda~**

.,._Led.!

..

Sourcea loul'c.e• aot Ia heel

&o.rua lepahed ultllLeU hcurreaceDurlqttoatlil

le 1red Source•

ILeakJae; aourc.. taclude all .aurc.. vhlch h•• leek l"ecuneii'Ce0 bad eapettenc.N eady btluna. or "-41 leak occureoce aod re.alned lealtan at tiM

...of tM ,..ec..t

..•-nar, Leakera

Fi(Jure E-1. 

### SCHEMATIC DIAGRAMOFTHE LDARMODEL Qw.arterlykn••l"' ef all Souruaend

ltatat

.... ac..

'or LMU

..Sourc

..The LDARmodel 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 programmay vary (forexample, frequency of inspection, repairs, and turnarounds). Further, input characteristics of the emission sources may vary. Inputs required in the lattergroup include: 1) The fraction of sources initiallyleaking; 2) The fraction of sources that become leakers during a period; 3) The fraction of sources with attempted maintenance for which repairwas successful; 4) The emission reductions from successful and unsuccessful repair. Other assumptions associated with the model are: 1) All repairs occur atthe end of the repairperiod; the effects associated with the time interval during which repairs occur are negligible; 2) Unsuccessfully repaired sources instantaneouslyfall into the unrepaired category; , 3) Leaks other than unsuccessful maintenance and earlyrecurrences occur ata linearratewith time during a given inspection period; 4) Aturnaround essentiallyoccurs instantaneouslyatthe end of a turnaround period and before the beginning ofthe next monitoring period; and 5) The leak recurrence rate is equal to the leak occurrence rate; sources thatexperience leak occurrence or leak recurrence immediately leak atthe rate ofthe "leaking souq:es" category. E.3 t10DEL OUTPUTS The outputs from the LDARmodel 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 (quarterlyand monthly).2 These scenarios enabled estimation ofemission reductions and costs for valves and pumps under Regulatory_Alternatives II, Ill, and IV. These estimates are presented in Chapters 7and B.



### E-4Table E-1. RESULTS OF THE LDARMODEL 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 ofMaintenance 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 DocketA-80-20. Evaluation of the Effects ofLeak Detection and Repair on Fugitive Emissions in the Onshore Natural Gas Processing Industry Using the LDARModel. November 1, 1982. Docket Reference Number II-B-18.* *References can be located in Docket Number A-80-20-B atthe 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 Fare two docket entries thatdevelop a correlationbetween cost-effectiveness and throughput for the recommended new source performance standard controls for pump seals, valves, and pressure reliefvalves. This analysis isonly valid for small gas plants thatdo 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 repairprogram. These docket entries are included here to enable interestedparties to review the basis for the recommended small size cutofffor gas plantswithout having to obtain copies from the docket.M E M0R A N D UM DATE: November 8, 1982 TO: Docket A-80-20 FROM: Tom Norwood, PES,

## Inc~ SUBJECT: Cost-Effectiveness as aFunction ofThroughput for Small Gas Plants 

## -------------------------------------------------------J-------------- In ameeting with EPA on August 18, 1982, representatives of Allied Corporation (UnionTexas Petroleum Corporation) indicated that the leak detection and repair programs required by the recommended NSPS forVOC fugitive emissions for on-shore natural gas processing plantswould have·to be performed by corporate staffengineers rather than plant personnel. Allied indicated in NAPCTAC testimony that to ensure the programwas properly implemented, the cost of such a program would be $15,000 annually as opposed to the $2,070 indicated by EPA (Attachment I). Itwas assumed that Allied's estimates were based on 1982 dollarvalues. Given that central officepersonnel may be required to perform the program, the cost estimates prepared by Allied were exanined for reasonability and corrected to 1980dollarvalues as described in Attachment II. The Allied estimates seem to be slightlyexcessive, as follows: (1) InspectorLabor: Assuming aplant has 256 valves, relief valves, and pump seals subject to the leak detection and repairprogram (BID Model PlantA), the complete inspection should take less than 5hours, 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 airtravel. 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: (1980dollars) Car $34 Living Expense 57 Total 

### $9I

F-22

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 costofreplacement 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 afunction of plant emissions. As such, a limiting plant size can be determined for agiven cost effectiveness. Table III presents the emissions reductions for a small plant as presented in BID Table 7-2. Based on the componentmixture used in this small plant, the average emissions reduction for monthly leak detection and repairwas determined to be 82 percent. As the cost effectiveness is afunction of the amount ofVOC removed, agraph 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 (formodel plant A): THC reduction

### =116 Mg THC xVOC reduction 40.2 t1g 

### voc

orTHC 

### =2.9 

### xVOC 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)
+$192 x VOC] x0.82 The cost effectiveness is: CE ($/Mg) 

### =$15,013

- [61 (1.9 xVOC) + 192 x (VOC)] x0.82 0.82 XVQC



## =$18,300

- 300**~1Mscfd** 1r1emorandum, K.C. Hustvedt, EPA to J. F. Durham, EPA; 11Estimation of

VOC Emissions as a Function ofThroughput for Small Gas Plants

..; November 5, 1982. Docket Reference Number II-B-24. 

### F-33 Using these relationships, cost effectiveness can be calculated for any plant throughput. Figure 1presents acurve of cost effectiveness of the recommended leak detection and repairprogram as afunction of gas plant capacity. This curve can be used to select aplant sizecutoff.

Component Valves ReliefValves Pump Seals Table I. LEAK DETECTION TIME REQUIREMENTS**(~1ode**1Plant A) Number in Plant 250 4 2 TotalMin/Componenta Total Minutes 1 250 8 32 5 10 292 minutes
=4 hrs 52 min aBID Chapter 8, 2-man team.



### F-44

TABLE II COMPARISON OF EPA AND ALLIED LEAKDETECTION 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 $) 8hrs 16 hrs

2days 2days $200 384 200

80 100 $964 Additional**Ad~inistrative** Costs for Each Trip By Inspector 1day in office 1/3day in plant Travel Expense Subtota1 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) SalaryTechnical StaffPerson $192/day**(\~ith** Fringes)



### F-5 EPA**-~stimate** (1980 $) 8 hrs 12 hrs

1day 1day $144 216 167

34 57 $618

$144 not required not required $144 $762

$5,500 $9'144

114 255 $15,013

$18/hr $18/hrComponentType

Valves ReliefValves Pump Seals Total Emissions XX =VOC (XX) 

### =THCReduction* 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 

## 6---1 0 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 PlantsJ\ttach111ent l



### COSTS FOR ROUTINE INSPECTION 

## &REPAIR

# PROGRAM
FoR ONE SIZE 

## APLANT

CosT BAsis = 

### CoNTRACT MECHANIC <WEsT TEXAs) = 

## $25/HouR (WITH OVERHEADS) SALARY TECHNICAL STAFF MAN (\iiTH FRINGES)
PLANT MoNTHLY INsPECTION TRIP.
MECHANIC

- 

## 3HouRs INSPECTOR

- SALARY

- 

## 2DAYS TRAVEL ExPENSES AIRLINES CAR LIVING ExPENSES SuB TJJTAL ADDITIONAL ADMINISTRATIVE TIME := 

### $192/DAY



## 200 384


## 200



## 80 100



# - 964

BY INSPECTOR

- 

# 1DAY/MONTH IN OFFICE 

# 192 1DAY/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-8ATTACHt1ENT 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 2days, $80 ( 1day =$40) Corrected =$40/1.19July 80 263.2 Ratio= 1.19

=$167

=$34 I II. Living Allied 2days $100 for 1day, will assume Allied estimate is 1nightmotel 0$35.00 and two days expenses @$32.50/day Allied for 1day= 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,UNITEDSTATESENVIRONMENTALPROTECTIONAGENCY OfficeofAirQualityPlanningandStandards ResearchTrianglePark, NorthCarolina 27711

November 5, 1982

MEMORANDUM SUBJECT: Estimation of VOC Emissions as a Function ofThroughput 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 wouldnot 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 wouldbe 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 andnonleaker 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 inTable 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-10of VOC andhas 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 inMM 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 EMISSWN FACTORS FOR LEAKING AND NONLEAKING 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 ( 165)

0.4 (1)

89.2 (370)

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

11

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 Gcontains threememoranda thatdocument revisions to the emissions estimates and control costestimates for compressors. The compressor seal emission factors presented in Chapters 3, 4, 7and 8of 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 subjectto the proposed standards, the emission factors were revised to represent average emissions from wet gas and natural gas liquids compressors, thecompressor types thatare covered by the proposed standards. The development of the revisedemission factors isdocumented in thememorandum dated February 10, 1983, that is included in this appendix. Aftercompletion ofChapter 8of this document, the costs for reciprocating compressor seal controlswere 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 effectofcontrol device costson compressor seal vent enclosure costeffectiveness is included in this appendix in a memorandum dated June 28, 1983.•• I J '4•, .:**;;r~** .**~~a:** -. '

.**·~-** ..- lJNlTEDSTATES ENVIRONMU,JIAL PROTECTION AGE:\iCY Off1ceof.ll..1rOual1tyPlannmgand Standards ResearchTrianglePark, NorthCarolina 27711

February 10, 1983 MEMORANDUM SUBJECT: Revised Gas PlantCompressor Seal Emission Factor FROM: K. C. Hustvedt**~v{ft--** Petroleum Section, Chemicals and PetroleumBranch, 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. Areview ofthe data used in developing our presentcompressor seal VOC emission factor (0.36megagrams peryear (Mg/yr) per seal} shows alargeportion ofthe data are from dry gas compressors; therefore, the overall emission factors used in the package were not representativeofthe population nowbeing regulated. In developing the basis for compressor seal regulations, I recommend thatthe refinery hydrocarbon servicecompressor seal VOC emission factor (5.5 Mg/year per seal} be used for natural gas liquids (NGL} servicecompressor seals and thatan estimated emission factor (0.7 Mg/yr per seal} be used for wet gas servicecompressor seals. Weighting these emission factors based on the occurrence ofthese compressor seal services in the API and EPA testingyields an average gas plant compressor seal VOC emission factor of2.3Mg/yr. Further, using equipment controls to reduce these emissions will essentiallyeliminate the emissions and, where itis technicallyfeasible, quarterlymonitoring will reduce the VOC emissions to0.4Mg/yr. Background The background information document (BID} for the gas plants NSPS states thatthe compressor seal emission factor is probably substantially understated. This isbecause both the EPA and API testingofcompressors included only open frame compressor distance piece emissions. No seal packing vents or enclosed distance pieceswere tested. In the past, industry has stated thatmost ofthe compressor seal emissions will come from the seal packing vent ifthe compressor has one. They have also stated thatenclosing and venting the distance piece is likely to increase compressor seal emissions because the seal is harder to visuallyinspect for failure and because seal maintenance ismore difficult (the enclosure mustbe removed). These industry comments certainly support our contention thatthe compressor seal emisson factorcould be substantially understated.



### G-22 Based on comments received atthe NAPCTAC meeting thatcertain sources within gas plants have essentially no VOC emission reduction potential and a subsequent review ofthe available data, we have recommended thatthe NSPS include an exemption for dry gas serviceequipment (defined as less than 1.0weight percentVOC). Because our data base includes dry gas compressors and because these arelikelyto have the lowest VOC emissions ofthe compressors studied, the data base should be reviewed to determine ifthe emission factors should be corrected to representonly the compressor seals affectedby the recommended NSPS. Review ofAvailableData Table 1shows a summary ofthe gas plantcompressor seal data used todevelop the gas plantemission factor. As you can see, there were 71 seals screened and 26 measured formass emissions. Over one-third ofthe sources screened and measured were in dry gas service. While deleting the dry gas service data and recalculating anew emission factor based on the remaining data would be possible, this would not necessarily resultin abetteremission factor due to another shortcoming. As shown in Table 1, 16 ofthe remaining (non-dry gas) 47 compressor seals, or about one-third are in natural gas liquids (NGL) service and only one of these 16was tested formass emissions. Simply calculating anew emission factorbased on the existing data base (after**remov~~g** the dry gas compressors) would greatlyunderstate the VOC emissions from NGL compressor sealsbecause themass emissions data from wet gas compressors (averaging 6.8percentVOC) are used to estimatemass emissions from NGL compressors (100 percent VOC in the one compressor tested) in the development ofemission factors. For these reasons, differentmethods should be used to develop emission factors for gas plantcompressor seals. Development ofEmissionFactors Because there is alargedifference in process streamVOC concentration between NGL and wet gas servicecompressors as seen in Table 1, emission factors are developed for both services. NGL service compressors containmixed natural gas liquids, LPG, propane refrigerant, etc., and usually contain greaterthan 50 percentVOC. In gas planttesting ofNGL compressors, 16 were screened for leakage, yetonly one seal was tested formass emissions. Because these limited data are insufficientfor directemission factor calculation, othermethods ofdeveloping emission factors were investigated. The technique based on percent of sources leaking used to calculate emission factors for chemical plantcompressor seals in the AID (Fugitive Emission Sources ofOrganic Compounds: Additional Information on Emissions, Emission Reductions, and Costs, EPA 450/3-82-010, April 1982) could be used, but itwas felt thatthe83 percent (5 of6) NGL service compressor sealsleaking found by EPA was not representativeofthe natural gas

G-33 processing industry. These NGL servicecompressors are, however, essentially identical to hydrocarbon servicecompressors in petroleum refineries and thus the refinerycompressor seal VOC emission factor of 15 kg/day (5.5Mg/yr) will be used for gas plantNGL servicecompressor seals. Forwet gas servicecompressors, itappears as though sufficient data are available to use theAID techniques to calculate an emission factor. Fourteen out of30, or46.7 percent, ofthe wet gas service compressor seals leaked. Using the procedure outlined in Section2of the AID, thisleak frequency translates into an emission factor of 19.2 kg/day (7.0Mg/yr) as shown in Table 2. This factor, however, is for total hydrocarbon emissions (THC) and only aportion ofthe wet gas service compressor seal THC emissions would be VOC. Based on an estimated average VOC concentration of 10 weight percent, the wet gas servicecompressor seal VOC emission factor would be 1.9kg/day (0.70Mg/yr). To obtain an overall gas plantcompressor seal emission factor, the weighted average ofthe wet gas and NGL service emission factors are used. As shown in Table 1, 66 percent (31 of47) ofthe seals screened were in wet gas service and34 percent (16 of47) were in NGL service. Weighting the individual emission factors by these percentagesyields an average emission factor for gas plantcompressor sealsof 6.4kg/day (2.3Mg/yr) ofVOC and 18 kg/day (6.6Mg/yr) ofTHC. Emission Reductions In the calculationofthe emission reduction obtained through control ofgas plantcompressor seals, 100 percentcontrol isestimated for equipmentcontrols. In the CTG, however, quarterlymonitoring is allowed where itis technically feasible. In calculatingthe ABCD estimated emission reduction, the B, C, and Dvalues from Table 7-1 ofthe Refinery 

### BID (EPA 450/3-81-015a, November 1982) are used because the refinery compressor seal data form the basis for the new gas plantcompressor seal emission factors. Aweighted average Afactor for wet gas and NGL servicecompressor seals is used. ForNGL the Afactor is 0.91 (Refinery BID) and for wet gas compressors the Afactor 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 factoryields an average A factorof0.93. Overall emission reduction is therefore calculated as follows: Emission Reduction

## =AxBxCx

### D


## =0.93 X0.90 X0.98 X0.98

=0.80

G-44 This estimated80 percentemission reduction is then corrected as was explained in the AID and the Gas PlantBID tolessen the impact ofthe estimated Bfactor on the overall estimate. As was determined in T. Rhoads (PES) November 1, 1982, memo, "CalculationofControlled 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 ofgas plantcompressor seals is&3 percent for VOC emissions and 81 percent for THC emissions. This equates to controlled emission factors of0.4Mg/yr VOC and 1.2 Mg/yr THC after implementation ofa quarterly leak detection and repairprogram.
cc: Dianne Byrne, SOB Fred Dimmick, SOB Tom Norwood, PES Tom Rhoads, PES Bruce Tichenor, ORD/RTP

G-5Service --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 formass emissions. (d) Total measured VOC emissions divided by total hydrocarbon emissions X100. (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-6Table 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

----------------------------------------------------- ----------··- Tota1 1000 19172(c)

------------------------------------------------
(a) From Table 1, 14 of 31 or46.7 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 1.9kg/day (0.7 Mg/yr).



### G-7UNITEDSTATESENVIRONMENTALPROTECTIONAGENCY A-80-20-B(VOC) OfficeofAirQualityPlanningandStandards ResearchTrianglePark, NorthCarolina 27711 I I-B-37


### February 23, 1983 MEMORANDUM SUBJECT: Revised Cost Analysis for Reciprocating Compression Seal VentControls FROM: Kent

## c. Hustvedt

### ~ Petroleum Section, CPB (MD-13) TO: James F. Durham, Chief Petroleum Section, CPB (MD-13) Over the past several months many changes have beenmade in our configuration and costbasis forcontrolling gas plantreciprocating compressor seals. These changes have beenmade in our continuing effort to design and costa safe, realistic·system for control ofcompressor seal emissions. While the system described and analyzed in the background information document (BID) isbasically adequate, information recently supplied to us by Union Texas Petroleum (UTP) shows that several oversights weremade in our analysis. Table 1 summarizes revised capital costs for the reciprocating compressor seal control systems based on our reviewofUTP's submittal. Acontingency of10 percenthas been added to the capital costs and they have been annualized as in the BID. These costs will be used to assess the costand cost-effectiveness ofcompressor seal vent control systems for the gas plantNSPS and CTG. Table 2isadetailedlistingofthe capital costs ofthe reciprocating compressor seal control system. Table 2is arevisionof an orderof magnitude costestimatemade by UTP and supplied to us in aletterfrom Bill Taylor of UTP to Susan Wyatt dated February 8, 1983, (Docket No. 80-20-B, I I-0-53). 1have revised theircostestimates as fo11ows: (1) theircosts were corrected using cost indices to make them consistentwith ouryear basis (1980), (2) our vendor quote equipment costswere used as documented in the BID, and (3) reasonable alternativeequipment were used. Justifications for the use ofthe alternativeequipment areprovided as references to the table. Attachment
cc: Dianne Byrne, SOB Fred Dimmick, SOB**·~-Tom** 

### Norwood, PES Tom Rhoads, PES Bruce Tichenor, ORD/RTP

G-84

• 

### Table 1 - Summary ofReciprocating Compressor Control System Costs (1980 $)



### Item

Double Distance Piece

Distance Piece Piping

Instrumentation For Purge Gas

Flare

FlarePiping 

# • 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 costsbased on our review ofthe February 8, 1983, Union Texas Petroleum submittal (Table 2). (b) Total capital costs including 10 percentcontingency. (c) Annualized capital costsbased on 0.163 

### capital recovery factor (10 percent interestrate and 10yearlifetime), 0.05 xcapital costs formaintenance and0.04 xcapital costs for taxes, insurance, and administration. ·

G-9EPA REVtSI,:,(II 

### n CATP(.CJsT'5**~ ~·c../93** **TABl~** 

### 2 

### ORDER OFMAGNITUDE ESTIMATE FOR COMPRESSOR SEAL LEAK

## CONTROL~ Cost Per Cost**Pe~** Cylinder**~odel** 

### APlant Incremental Cost for Double Distance Piece 

### S3

## ,ooe --z.

### soo

# ® $-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 Va1ves 

## -X\ @

# eo 1" Block Valves- 2**~.** '2.5 

# @;1Seal 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** &o11t1aller

### ~'-&ad Pres

### sur~ CoAtrel Val•e

### ~ (G-eRtrol1e1 1'' S1ock Va1ves - 2**~**'2S

,., 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** 

### .(etAJ.•ckc.+



### .,\J

....**~r** 

### ,4-so-z..u-8) J['-1)- 

### 51) G-10 Labor (18.85/Manhour) $300 $-&&'"' 

## sso

## ~;so(l'tSo'f>fb.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** $5,200Cost of 2 mm

## sue Flare**(1c;~o**

### $) Piping To Flare t.=\Residue Ga! le Flal"'e**~** 500 Ft. • 2" Pipe @$3/Ft. InletLine from Compressor to Flare 500**~-i.** - 211 Pipe @**~.** tZ:) IOOf"l"\**~**so/rn**~upture** Disk (v(

...J..,.1.,..-tc) • Misc. Flares, Fittings0.,&.,.$) Indirects
Sub-Total Materia1

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%} Mtttstme11t to =lilA Cost fer Oeuble 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 

# s3,000' -$55,800 $11,200 $67,00& $55,800 $SJ,800...

### .. • 

### References forTable2 A. Telephoneconversationreport. T. Norwood, PacificEnvironmental Services, Inc.,with P. Marthinetti, Ingersoll-Rand. December 8,

.1982. DistancepiecepriceverifiedbyMr. Marthinetti as $2,000

to $3,000 (1980). Averagevalue of$2,500used. Docket Reference Number II-E-19.* B. Single oil seal potrequired for all compressors instead ofone per compressor. C. Telephoneconvers·ation. T. Norwood, PacificEnvironmental Services, Inc., withD. Rudolph, Fairchild·Industries. Price ofnatural gas supply_regulator. Docket**Referen~e** 

### Number 11-E-22.* D. These costs arealready included in flarecost. E. Letter, R.W. Kreutzen, Chevron U.S.A. toJ.R. Farmer, EPA:CPB, •oraftCTGforNatural Gas Processing Plants,•March 12, 1982. 1982installedcostofflaregiven as $8,000. Deflated to 

### 1980 dollars• $6,670.- DocketReference Number II-D-32.* F. Pilotgas forflarenot needed as compressorvent stream isthe pilot. Flare is auto ignited type. G. Telephoneconversation. T.L. Norwood, PacificEnvirdnmental Services, Inc.,with Continental DiskCo., February 14, 1983. Quote of $100/holderand $64/diskcorrected to June 1980dollars • $52/disk and $82/holder. ·DocketReference Number II-E-23.*

*References canbe located in DocketNumberA-80-20-B atthe U.S. Environmental

ProtectionAgencyLibrary, Waterside Mall, Washington, D.C

.

G-12 •

### ME

### M0

### R AND UM 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 ofControl Device Costs on Compressor Seal Vent Enclosure Cost Effectiveness

Priortopreparation ofthe current draft of the new source performance standardfor**~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 ofcontrollingcompressor

seal leaks by using enclosed distance pieces should be adjusted to include the cost ofthe 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 calculationswere perfonmed for

### two types of compressors (centrifugal and reciprocating) in either oftwo types of service {wet gas or natural gas liquids). Table 1presents the cost and cost effectiveness for

### the eight resultingcases. As can be seen, the cost effectiveness varies from $36/Mg**fo~** 

### the best**~ase** 

### (centrifugal compressors in NGL servicewith existing control devices) to $2200/Mg for

### the worst case (reciprocating compressors in wet gas servicewith a new control device). Table 2**pres~nts** 

### the**~:~ital** 

### cost calculations required to develop Tab1

### 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-13Gl 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)
Centr1

### 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 reciprocatingcompressors are driven by shafts having a linearmotion. "Yes" indicates that acontrol device is present at theplant. The cost of acontrol device (flare) has been added tothe compressor vent control systemcosts forplantswithout an existingcontrol device. c -



### Wet gas means field gas with an average VOC content of 10percent by weight NGL (Natural gas liquids) consists ofmixed liquids separated from wet gas (i.e., liquidpetroleum gas). d

### Capital costs per Table 2.
e

### Annualized cost -CAPITAL RECOVERY +MAINTENANCE COSTS+ MISCELLANEOUS COSTS

- [.163 +.05 +.04]xCAPITAL

- 0.253 xCAPITAL 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 (Mode1

### Plant B) 

## ll!!!t DoubleDistance pieces Seal Vent Piping Purge Gas Supply FlarePiping Subtota1 d 

### Flare Centr1fuga1 

### Compressors

3,7ooa 4,624 7,34oa 

### 11,964

a

### FromBIDAppendix G, page G-10, Table 1. b



### FromBID Table 8-1. c



### Costs are

### for six compressor seals. d 

### Reciprocating Compressorsa 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 6of this document presents the model plants and regulatory alternatives on which the emission reductions and costs impacts in Chapters 7and 8were 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 M0R 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 theRecommended 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 1provides a summary of theModel Plant Bemission 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 2through 7provide 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 3for 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 forModel Plant Bbecause there are fJxed costs for the system.

cc: K.C. Hustvedt Dianne Byrne



### H-2Source Pressure relief devices

Compressors Open-ended valves and lines Sampling connection systems Va1ves

Pumps 2
Table 1. EMISSIONS REDUCTIONS AND CONTROL COST EFFECTIVENESS FOR MODEL PLANT B

Control Technique Quarterly leak detection and repaird Monthly 1eak detection and repair Rupture diskse
Closed-vent and sea1systemd Capsd Closed-purge sampling Quarterly leak detection and repair Monthly 1eak detection and repaird Quarterly 1 eak detection and repair Monthly 1 eak detection and repaird 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 Effectivenessa ($/Mg)

__c
5,800 22,000
460

__c
7,oooe

__c
1,400

830
1,500 12,000



### -------------------------- aFromTables 2through 7ofthis memo. bfromBID Table 7-2. ccost savings occur. dcontrol techniques selected as the basis for the recommended standards. ermpacts shown areweighted averages based on 180 new plants and 40 modified/

reconstructed plants. fFromReference 2.

H-33
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) InstalledCapital Cost 0 0 3'lQOb 4,200b Annualized Capital A. Centro1 Equipment --c --c 60Qd 780d B. I nitia1L eak Repaire 0 0 0 0 Annualized Operating Costs A. -Maintenancef --c --c 160 210 B. Miscellaneous9 --c --c 120 170 

### c. Labor 1. Monitoringh 19 58 0 0 2. Leak R epaire 0 0 0 0 3. Administrative and Supporti 7.6 23 0 0 Total Annual Cost BeforeCredit 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 ($/Mg VOC)m (610) 0 6,300 8,700 Incremental Cost Effectiveness" ($;M9

### voq (610) 5,800 21,000 29,000



### H-44
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/2with 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 otherequipment (rupture disk holder, piping, valves, pressure relief valve). New installationcost=0.163 (3100- 230) +0.58 (230) 

### =600 Retrofit installation cost =0.163 (4200

- 230) +0.58 (230) =780 eleaks are corrected by routinemaintenance in the absence of the

standards; therefore, no cost is incurred for repair. fo.o5 xcapital cost. 90.04 xcapital cost. hMonitoring labor hours (i.e., number of workers Xnumber of components

xtime to monitor xtimes monitored peryear) x$18 per hour. Assumes 2-man monitoring teamper relief valve, 8minutes monitoring .time per valve, mnitored quarterly or rronthly. :o.4o x (monitoring cost +leak repaircost). JRecovery credit based.on uncontrolled VOC emission factor of 0.33

kg/day and total hydrocarbon emission factor of4.5 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 forquarterly 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-55
Table 3. ANNUALIZED CONTROL COSTS FOR COMPRESSOR SEALS

- MODEL PLANT 

### sa (June 1980 Dollars)

InstalledCapital 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

460Footnotes: 6
Table 3. ANNUALIZED CONTRTOL COSTS FOR COMPRESSOR SEALS

- MODEL PLANT sa (June 1980 Do11ars) (Cone1uded)

acosts and emission reduction are for 6compressor seals (Model Plant B). bcapital cost is based on 50 percent reciprocating and 50 percent centrifugal compressors: 1. 3double distance pieces @$2750 (Reference 1) = $8250 2. 3distance pieces piping systems @$1100 (Reference 1) 3. 3centrifugal 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. 1flare (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. Ifthe two types ofcompressors are mixed, two flare piping systems might be necessary. However, this case is consideredunlikely because (1) a new plant would typically use all of one type of compressor, and (2) modified or reconstructed plantswould be unlikely to have both types ofcompressors fall under NSPS

.requirements. · co.l63 (capital recovery factor) xcapital costs; see BID Table 8-5. do.os xcapital cost. eo.04 xcapital 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 linewith afull 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 aclosed vent and seal system. Compressor seal emission factor is from Reference 2. iQbtained by dividing net annualized cost by total VOC emission reduction.



### H-77
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) xcapital cost; see BID Table 8-5. do.os xcapital cost. eo.04 xcapital 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-88
Table 5. ANNUALIZED CONTROL COSTS PER COMPONENT FOR SAMPLING CONNECTION SYSTEMS (June 1980 Dollars)a

InstalledCapital 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 (10years, 10 percent interest =0.163) times

capital cost. do.os xcapital cost. eo.04 xcapital 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-99
Table 5. ANNUALIZED CONTROL COSTS PER COMPONENT FOR VALVEsa (June 1980 Dollars) coNtRol**tE~~NIQUE**

Annualized Cap1tal

Initial Leak

Repairo Annualized Operating

Costs Laoor l. MonitoringC 2. Leak Repa1,.d 3. Administrative and supporte Total Annual Cost

Before Credit Recovery Creditf**~et** Annualized Cost9 Total VOC Emission

Reduction (Mg/yr)h Cost Effectiveness (S/Mg VOC)i Incremental Cost

Effe<:tiveness ($/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

ma1ntained 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 ·1alue 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-1010
Table 7. ANNUALIZED CONTROL COSTS PER COMPONENT FOR PUMPS

### a (June 1980 Dollars)**~ORT~OC** rWlR!OOE Dual .'!ecnanlcaI Seal Systemwith BarrierFluid

System and Degassing Vents Quarterly Montilly Inspections Inspections**'~ew** Retrofit
Installed Capital

Cost A. Seal 0 0 12500 l590b 8. BarrierFluid Systemand Degassing Vents 0 0 58500 sasob Annualized Cap1tal Cost

A. Contro1Equipmentc 1. Dual Mechanica1 Seal 0 Seal 0 0 S60d noe 0 1nstalation 0 0 49, 569 2. Barrier Fluid System and Degassing Vents 0 0 9SOh 9SOh 3. Rep1 acement Seal ssi 57i 0 0 8. Initial Leak Repair 

### zzj Z2J 0 0 c. !nitial 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. Mon1toringn 20 44 a 0 2. Leak Repairn 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

Effect1veness (S/Mg 'IOC)t 830 1500 12,000 1<1,000

H-1111
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) x0.58 (capital recovery factor for 2-year life) less single seal credit ($278 x0.58). 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** xcapital 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 peryear. 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 xcapital recovery factor (0.33 x$140 x0.163 

### =$7.50). lo.os xcapital cost. mo.04 xcapital cost. nMonitoring labor and leak repair costs for pumps are based on

BID Table 8-3 plusweekly 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-1212


### REFERENCES

1. Memorandum from K.C. Hustvedt toJ.F. Durham, EPA:OAQPS. Revised CostAnalysis 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. FugitiveEmission Sources ofOrganic 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 amemorandum dated December 7, 1983 that describes the calculationofpump seal control emission reduction. Due to an errormade the inputs to the leak Detection and Repair (LDAR) model during the development ofthe BID, the values used throughout the BID chapters and previous appendices are incorrect. The memorandum attached documents the correctemission reduction values for natural gas plantpump seals, as well as the correctpump seal control costeffectiveness values for leak detection and repairprograms.MO'ORANDUM SUBJECT: FRC1>1: UNITEDSTATESENVIRONMENTALPROTECTIONAGENCY Off1ce ofA1r Qual1ty Plann1ngandStandards ResearchTriangle Park. NorthCarolina27711

Gas PlantsPump**Se~ls** Emission Reduction K. C. Hustvedt

## ~ Petroleum Section/CPS TO: James F. Durham, Chief Petroleum Section/CPS While I was preparing for our November29, 1983, meeting with OMB on the NSPS and CTG for VOC equipment leaks from gas plants, I recalculated the costeffectivenessofleak detection and repairprograms (LDRP) for pump seals. In checkingmy results againstthe numbers developed for theCTG and NSPS, I found thatmy new calculationsestimated amuch higher emission reduction for all monitoring intervals. I discovered thatin our computer runs for gas plantswe had used 87 percentemission reduction for repairofleakingpump seals (F2 equals 0.13 in the leak detection-and repair (LDAR) model)1, while in the AID2 we had used an F2 value of0.028 (97.2 percentemission reduction). As discussed in the AID, itislikelythatrepa,ir (replacement) of aleaking pump seal will resultin essentially 100 percentemission reduction or an F2 of0.00, so thattheAID value is alow estimateofthe emission reduction from repair. Because we feel the LDAR inputs developed in the AID are appropriate for all ofour VOC equipmentleak projects, I have recalculated the pump impacts using0.028 forF2. Attached are the LDARmodel inputs and outputs formonthly, quarterly, semiannual and annual LDRP. I have summarized the results ofthese runs, including the incremental impacts between alternativeLDRP, inTable 1. The costs and emission reductions shown in Table 1are based on 100pump seals tominimize effectsof rounding on the calculated results. To correct these numbers tomodel plantnumbers, the costsor emission reductions should be multiplied times the number ofpump seals in the model plantdivided by 100. Since there are 6pumps inmodel plantB, thismeans you would multiply these numbers times 0.06 to getmodel plantBimpacts. The cost effectiveness numbers are independentofnumber ofpumps so they are already correctfor all themodel plants.

I-22
REFERENCES 1. T. W. Rhoads, PES, Inc. to DocketA-80-20-B. "Evaluation ofthe Effects ofLeak Detection and Repair on Fugitive Emissions Using theLDAR Model," November 1, 1982, Docket Reference Number Il-B-18. 2. Fugitive Emission SourcesofOrganic 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 DocketA-80-20-B

I-3Table 1. LDARANALYSIS 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 Mto Q Q 3 78.0 34.2 20,000 587 5.8 700 121 Qto SA

I SA 6 65.0 28.4 19,300 680 

### ..,. 10.2 300 29 SA toA A 12 41.6 18.2 19,000 1,040 16.0 1,000 62 QtoA
aBased on 100pump seals. bJncrements between the two monitoring intervals shown.INPUT DATA PlANT tiATUGAS CTG&NSPS C

FOR LIGLT LIQUID PUtiPS t

FOR EXAMINING EMISSION REDUCTIONS DUE TO LDARl

HOHlTORitiG INTERVAL fNOIDtiSJ TURUAIHMIO FREQUEUCY (NOIITHSJ EMISSIOII FACTOR IKG/lfR/SOURCEJ 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 .,MINUTESJ I0.0 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/HOURI 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 EMISSIOH REOUCTIOHS DUE TO LDARI 

# (6.WA'-.4.T'W**~**&.'/)

NotiiTORitiG.IIDERVAL INONTHSJ 3 TURHAR<MIO FREQUENCY (MONTHS). 24I C"'\ I HPUT DATA

CFOR PLAHT UATUGAS CTG&NSPS LIGLT LIQUID PUNPSt EMISSION FACTOR IKG/HR/SOURCEJ lEAK OCCURREUCE RATE C Y. PER PERIODI 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 (HIIIUTESJ tiUliBER Of VISUAL IIISPECTIOHS PER YEAR REPAIR TitlE PER SOURCE C HIHUTESt 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 CNOHTIISJ 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.oINPUT 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 VISUAlNOtUTORING TINE PER SOURCE fHIHUTESt 0.50 NUtSER OF VISUAL INSPECTIONS PER YEAR 52 REPAIR TINE PER SOURCE**(Nit~TESJ** 960 LABOR RATE (t/HOURt 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 U10NTHSJ TURtiAROlUJ.FREQUENCY HIOHTttSJ ENISSIOII FACTOR (KG/HR/SOURCEJ lEAK OCCUP.REIIC£ RATE (X PER PERIODJ INITIAl 7. lEAKING EI1ISSIOUS REDUCTIONFORutiSUCCESSFUl REPAIR 00 EHISSimiS REDUCTION FOR SUCCESSFUlREPAIR (XJ EARlY lEAK RECURRENCE (1. OF REPAIRSJ UtiSUCCESSFUl REPAIR RATE 00

. .UNSUCCESSFULREPAIR RATE t?.J ATTURHAROl'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

TOTAlNUHBER 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/HOURl 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/ttGl 207

f .t....... I 1.0



## .. 5\HtAR'f Of !STirtATED EHISSIOH FACTORS CKG/HIU AND PERCENT REDUCTION INHASS 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 NOHAIHTENAUCE 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 IHONTHLYLDAR)

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'SACCESSION NO.



### EPA-450/3-B2-024a

-
-TECHNICALREPORTOATA (PleasereadInstncetionsontherevers->beforecompl,.til·g)

'4.-TITLf ANDSUBTITLE 5. ''

..PORT DJITF**Equipn~nt** 

### Leaks ofVOC in Natural Gas Production December·198.3**~~--**



### Industry

- Background Information for Proposed Standards 6.PERFORMINGORGANIZATIONCODE

7. AUTHOR(S) 8.PERFORMINGORGANIZATION REPORTNO.

-·**~FORMING** ORGANIZATION NAMEANDADDRESS 10.PROGRAM ELEMENTNO. 

### \OfficeofAir Quality Planning and Standards

U.S. Environmental ProtectionAgency 11.CONTRACT/GRANTNO. 

### Research Triangle Park, NC 27711

. ----- 12.SPONSORINGAGENCY NAMEANDADDRESS 13.TYPEOF fiEPORTANDPERIODCOVERED 

### Director forAir QualityPlanning and Standards OfficeofAir, Noise, and Radiation 14.SPONSORINGAGENCYCODE 

## u.s. Environmental ProtectionAgency Research Triangle Park, NC 27711 EPA/200/04
15.SUPPLEMENTARY NOTES 

### This report discussesthe regulatory alternativesconsidered**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 ofperformance for the control ofVOC emissions from equjpment leaks atnatural gas processing plants are being proposed under Section 111.ofthe Clean AirAct. This documentcontains background information and-environmental and economic impact assessments ofthe regulatoryalternativesconsidered in developing the proposed standards.

.**~** 17. KEYWORDSAND DOCUMENTANALYSIS
a. DESCRIPTORS b.IDENTIFIERS/OPEN ENDEDTERMS c. CDSATIField/Group 

### Airpollution AirPollution Control 13b Pollution control Standards ofperformance 

# .. Volatileorganic compounds (VOC) Natural Gas Production Fugitive emissions

18.DISIAIBUTIONSTATEMENT 19.SECURITYCLASS(ThisReport) 21.NO.OFPAGES 

### Unclassified 230 

### Unlimited 20.SECURITYCLASS(Thispage) 22.PRICE 

### -- Unclassified
f.PA Form2220-1 (Rev.4-77) PREVIOUS EDITION IS OBSOLETEUn1ted States Environmental ProtectiOn Agency

Otf1c1al Busmess Penaltyfor**Pr~vate** Use $300 Off1ceofA1r, No1se.andRad1at1on Off1ceofA1rOual1tyPlannmgandStandards ResearchTnangle Park NC27711

-------------- ------------------------------------------------------ Publ1cat1on No EPA-450/3-82-024a

Ifyouraddress1smcorrect,pleasechangeontheabovelabel, tearoff,andreturntotheaboveaddress Ifyoudonotdes1retocontmuerece1vmgthostechn1calreport senes, CHECK HERE D,tearofflabel,andreturn ot tothe aboveaddress Postageand Fees Pa1d Environmental Protection Agency EPA335