United States OfficeofAir Quality EPA-450/3-83-007 EnvironmentalProtection PlanningandStandards December 1983 Agency Research Triangle Park NC27711 Air \ 

# GuidelineSeries Controlof Volatile Organic Compound ~quipment Leaks from Natural GadGasoline Processing Plants

# GuidelineSeries
Controlof Volatile Organic Compound Equipment Leaks

from NaturalGas/Gasoline Processing Plants

EmissionStandards and Engineering Division

U.S.ENVIRONMENTALPROTECTION AGENCY Officeof Air, Noise,and Radiation OfficeofAir QualityPlanningandStandards Research Triangle Park, NorthCarolina27711
December 1983GUIDELINESERIES
The guidelineseriesof reports isissuedbytheOfficeof Air Quality PlanningandStandards (OAQPS)toprovideinformationtostateandlocalairpollution.control agencies;forexample,to provide guidanceontheacquisition andprocessingofairqualitydataandontheplanning and analysis requisitefor the maintenanceof air quality. Reportspublishedinthisserieswillbe available
- assuppliespermit
-from the Library ServicesOffice(MD-35).U.S. Environmental ProtectionAgency, ResearchTrianglePark,NorthCarolina27711,or foranominalfee,fromthe NationalTechnical InformationService, 5285 Port RoyalRoad, Springfield, Virginia 22161.

### TABLE OF CONTENTS
Page List of Tables

# .........................v List of Figures 

# ........................vii Metric Conversion Table 

# .................... viii 1.0 Introduction 

# ........................ 2.0 Sources of 

### VOC Emissions 

# ................. 2.1 General 

# ....................... 2.2 Description of Fugitive Emission Sources

# ....... 2.3 Baseline Fugitive VOC 

### Emissions 

# ........... 2.4 References

# ...................... 3.0 Emission Control Techniques

# ................ 3.1 

### Leak Detection and Repair Flethods 

# .......... 3.2 Equi pment Specifications

# ............... 3.3 

### Other Control Strategies

# ............... 3.4 

### Other Considerations

# ................. 3.5 References

# ...................... 4.0 Environmental Analysis of RACT 

# .............. 4.1 Reasonably Available Control Techniques (RACT) Procedures

# ...................... 4.2 

### Air Pollution 

# .................... 4.3 Water Pollution 

# ...................
4.5 Energy

# ........................ 4.5 References

# ...................... 5.0 Control 

### Cost Analysis of RACT

# ............... 5.1 Basis for Capital Costs 

# ............... 5.2 Basis for Annual Costs

# ................ 5.3 Emission Control Costs of RACT

# ............ 5.4 Cost ~ffectiveness of RACT

# .............. 5.5 Analysis of Compressor Vent Control System Costs 

# ........................ 5.6 References

# ......................TABLE OF CONTENTS (concluded) Page
Appendix A

# . Emission Source Test Data

# .............A-1 Appendix B

# . Model Plants

# ................... S-1 Appendix C

# . Public Comments

# .................. C-1 Appendix D

# . Summary and Responses to DraftCTG Comments

# ....0-1Table 2-1

Table 2-2 Table 3-1

Table 3-2

Table 3-3

Table 3-4

Table 3-5 Table 4-1

Table 4-2

Table 4-3

Table 4-4 Table 5-1 Table

Table Table Table

Table5-2

5-3 5-4 5-5

5-6 LIST OF TABLES
Page Base1ine Fugitive Emission Factors for Gas Plants

# ............ ... ... ... 2-9 Baseline Emissions from Three Model Gas Plants 

# ... 2-11 Percent Emissions from Sources with Instrument Readings Equal to or Greater than 10.000 ppmv 

# ................... 3-6 Estimated Percent Components Leaking Per Inspection for QuarterlyMonitoring

# ..............3-9 Average Emission Rates from Components above 10.000 ppmv and at 1.000 ppmv

# .........3-10 C o n t r o l 1 ed Emission Factors for Quarterly Leak Detection and Repair

# .............. 3-13 Illustration of Skip-Period Monitoring

# ....... 3-21 Example Calculation of VOC Fugitive Emissions From Model Plant B Under RACT

# ............ 4-4 Annual Emissions on a Component Type Basis for Each Model Plant 

# ..................4-5 Energy Impacts on a Component Type Basis For Model Plant 6

# ...............4-7 Energy Impacts on a Flodel Plant 'dasis

# ........4-8 Capita1 Cost Data

# ..................5-7 Labor-Hour Requirements for Ini tia1 Leak Repair Under RACT

# .................. 5-1 Initial Leak Repair Costs

# ..............5-11 Basis for Annualized Cost Estimates

# .........5-12 Annual Leak Detection and Repair Labor Requirements for RACT

# ................5-13 Annual Leak Detection and Repair Costs 

# .......5-14LIST OF TABLES (concluded) Tab1e 5-7 Example Calculation of Product Recovery

Table 5-8 
 Flodel Plant Recovery Cost Credits. 

# ......... 5-16 credits for Model Plant B. 

# .............. 5-15

Table 5-9 Table 5-10 Annualized Control Costs for Model Units

# ...... 5-17 

### ' Examples of Cost Effectiveness by Component Type for Model Plant B 

# ............... 5-18 Table 5-11 Costs and Cost Effectiveness of Compressor Vent Control System for ;lode1 Plant B. 

# ....... 5-19 Gas Plants Tested for Fugitive Emissions

# ...... A-5 Instrument Screening Data for EPA-Tested Gas Plants

.. 

# .....................A-6 Soap Screening Data for API-Tested and EPA-Tested Gas Plants

# ..................... A-7 Example Types of Equipment Included and Excluded inVessel Inventories for Model Plant Development. 

# ....................B-4 Number of Components inHydrocarbon Service and Number of Vessels at Four Gas Plants

# ........5-5 Ratios of Numbers of Components to Numbers of Vessels 

# .....................0-6 Fugitive VOC Emission Sources forThree Model Gas Processing Plants. 

# ............... B-7 Table A-1 Table A-2

Table A-3

Table 

### B-1

Table B-2

Table B-3

Table B-4

### LIST 

### OF 

### FIGURES Page
Figure 2-1 

### General Schematic of Natural Gas-Gas01ine Processing

. 

# .

# . ..

# .. .. . . . ....

# ..

# . . . 2-2 

### Figure 2-2 

### Diagram of a Simp1e Packed Seal 

# .. . . ..

# . .

# .. 2-3 Figure 2-3 Diagram of a Basic Single Mechanical Seal 

# .

# . . .. 2-4 

### Figure 2-4 

### Diagram of a Gate Valve 

# .. . . .

# . .

# . . . . . .. 2-7 

### Figure 2-5 Diagram of Spring-Loaded Re1ief Valve 

# .. .

# ..

# .. 2-7 

### Figure 3-1 Compressor Distance Piece Purge System

. 

# ..

# .. . . 3-15 

### Figure 3-2 Cost-Effectiveness of QuarterlyLeak Detection and Repair of Valves with 

### Varying Initial Leak 

### Frequency 

# .

# ... .. ..

# ..

# . ..

# ..

# ..

# . . . . 3-18 

### Figure 3-3 Cost Effectiveness of QuarterlyLeak Detection and Repair of Valves for 

### Low Production Volume Units

. 

# .

# . . .

# . .

# ...

# . ....

# .. .

# .. 3-23

## METRIC CONVERSION 

### TABLE

EPA 

### policy is 

### to express 31

### 1 

### qeasirrernenti Agency docmencs in 

### metric units. List~d below are metric units us~d in 

### t~is 

### ragort ,vi:h 

### conversion factors 

### to obtain equivalent Englisn ~nitr.A 

### list 3f 

### prefixes to metric units is a1

### so prsent~d.

To 

### Convert Mu1

### tiply Sy 

### Metric Unit Conversion iact~r centimeter (ciil) inc9 :in.) 

### meter (m) 

### feet (ft.) 

### liter (1) g.S. 

### ;alion (;al) 

### cubic meter ( m3) 

### 1.5. gallon 

### (la:) 

### cubic 

### fleter 

### (m3) 

### barrel (oil) 

### (hi) 

### cubic meter (m

### 3) cxbic 

### =.?et 

### 3,

# , pound (IS) 

### ton

. , 

### million pounds (135 12s) 

### ton 8ri'tish thenal unii {~LI)



### PREFIXES

Mu1

### tip1icaiion Prefix 

### Factor tera 10

### l2 gigs 

### 10 

### mega lo5 ki

### 1

### o 10 

### centi 10-~ 

### milli lom3 mi

### cru 10-~



### viii1.0 INTRODUCTION

The Clean AirAct Amendments of 1977 require each State inwhich there are areas inwhich the national ambient air quality standards (NAAQS) are exceeded toadopt and submit revised State implementation plans (SIP's) to EPA. Revised SIP's were required to be submitted to EPA by January 1, 1979. States which were unable todemonstrate attainment with the NAAOS for ozone by the statutory deadline of December 31, 1982, could request extensions for attainment with the standard. States granted such an extension were required tosubmit a further revised SIP by July 1, 1982. Section l72(a)(2) and (b)(3) of the Clean Air Act require that ramattainment area SIP's include reasonably available control tech~iology (RACT) requirements for stationary sources. As explained inthe "General Presmhle fnr Propnc~d Rulemking ov Approval of State !mp! ewntatioo



## - Plan Revisions for Nonattainment Areas," (44 FR 20372, April 4, 1979) for ozone SIP's, EPA permitted States todefer the adoption of RACT regulations on a category of stationary sources of volati1 e organ;c compounds (VOC) unti1 after EPA pub1ished a control techniques guideline (CTG) for that VOC source category. See also 44 FR 53761 (September 17, 1979). This delay allowed the States tomake more technically sour,d decisions regarding the application of RACT. A1though CTG documents review existing inf ormation and data coiicerning thetechnology and cost of various control techniques to reduce emissions, they are, of necessity, general in nature, and do not fully account for variations within a stationary source category. Consequently, the purpose of CTG documents istoprovide State and local air pollution control agencies with an initial information base for proceeding with their owassessment of RACT for specific stationary sources.

### 2.0 SOURCES OF VOC 

### EMISSIONS

2.1 

### GENERAL Natural gaslgasoline processing plants (gas plants) are a part of the oil and gas industry. Field gas isfirstgath2red inthe field directly from gas we11s or from oiljgas separation equipment (see Figure 2-1). The gas may be compressed at field stations for the

. purpose of transporting it to treating or processing facilities. Treating is necessary incertain instances for removal of water, sulfur compounds, or carbon dioxide. Gas gathering, compression, and treating may or may not occur at a gas plant. For the purposes of this document, natural gas processing plants are defined as facilities engaged inthe separation of natural gas liquids from field gas and/or fractionation of the 1iquids.into natural gas products, such as ethane, propane, bukdne, dflci r~dturd;

### cgascj; irie. 

### 'cxc;;uded finGii

### the 6eff iiitio~ are compressor stations, dehydration units, sweetening units, field treatment, underground storage facilities, liquefied natural gas units, and field gas gathering systems unless these facilities are located at a gas plant. Types of gas plants are: absorption, refrigerated absorption, refrigeration, compression, adsorption, cryogenic

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


### 2.2 

### DESCRIPTION OF FUGITIVE EMISSION SOURCES Inthis document, fugitive emissions from gas plants are considered to be those volatile organic compound (VOC) emissions that result when process fluid (either gaseous or liquid) leaks from plant equipment. 

### VOC emissions are defined as nonmethane-nonethane hydrocarbon emissions. There are many potential sources of fugitive emissions ina gas plant. The foll..owing sources are considered inthis chapter: pumps, compressors, valves, relief valves, open-ended lines, flanges and connections, and gas-operated control valves. These source types are described be1ow.

# IField Gas Gathering Systems

# (

Fie1 d 

### Compression

i

1



### Fractiana tion of 

# I Natural Gas 

### Liquids Sulfur Recovery

+

r 

# J
1'



# I Sal

### es Pmduc

### ts

(ethane, propane, 

### fso-butane, butane, 

### natural gas01ine, etc. 

# 1 ) Gas 

### Treating Sweetening and Dehydration 

### ' 

# (H9. C02, and 

### H20 Remval

### )

A



### Separation 

### of Natural Gas 

### Llqutds 

### from FieldGas



# .

Figure 

### 2-1. General Schematic of 

### Natural Gas-Gas01I

### ne Pmcessing

# .
2-2 Dry 

### Gas 

## - to 

### Sales

J2.2.1 Pumps Pumps are used ingas plants for the niove~nentof natural gas liquids. The centrifugal pump isthe most widely used pump. However, other types, such as the posi tive-displacement

### , reciprocating and rotary action, and special canned and diaphragm pumps, may a1so be used. Natural gas liquids transferred by pumps can leak at the point of contact between the moving shaft and stationary casing. Consequently, a11 pumps except the canned-motor and diaphragm type require a seal at the point where the shaft penetrates the housing inorder 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 Figlrre 2-2 shows, a packed seal consists of a cavity ("stuffing box") inthe pump casing filledwith special packing material that iscompressed with a packing gland to foma seal around the shaft. Lubrication is required to prevent the buildup of frictional heat between the seal and shaft. The necessary lubrication isprovided by a lubricant that flows between the packing and the shaft.2

Fluid End

Figure 2-2. Diagram of a simple packed seal.

### 2

Mechanical seals are limited inapplication to pumps with rotating shafts and can further be categorized as single and dual mechanical

### seals. There are many variations 

### to the basic design of nechanical seals, but 

### all have a lapped seal face between a stationary elenent and
a rotating seal ring. In a single mechanical seal application (Figure 2-3), the rotating-seal ring and stationary element faces are lapped 

### to a very high degree of flatness to maintain contact throughout their entire mutual surface area. As with a packed seal, the seal faces must be lubricated 

### to remove frictional heat. However, because of its construction, much less lubricant is needed.

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

2.2.2 

### Compressors Three types of compressors can be used in the natural gas production industry: centrifugal

## ,reciprocating

### , and rotary. The centrifugal compressor utilizes a rotating element or series of elements containing curved blades to increase the pressure of a gas by centrifugal force. Reciprocating and rotary compressors increase pressure by confining the gas in a cavity and progressively decreasing the volume of the cavity. Reciprocating compressors usually employ a piston and cylinder arrangement whi1e rotary compressors utilize rotating elements such as 1obed impellers
or sliding vanes. As with pumps, sealing devices are required 

### to prevent 1

### eakage from compressors. Rotary shaft seals for compressors may be chosen from several different types: 1abyrinth, restrictive carbon rings, mechanical contact, and liquid film. All of these seal types are leak restriction

### devices ;

### none of them completely eliminates leakage. rlany compressors may be equipped with ports in 

### the seal area to 

### evacuate collected gases. Mechanical contact seals are a common type of seal for rotary compressor shafts, and are similar to the mechanical seals described for pumps. In this type of seal the clearance between the rotating and stationary elements is reduced to zero. Oil or another suitable lubricant is suppli

### ed 

### to the seal faces. Mechanical seals can achieve the lowest leak rates of the types identified above, but 

### they are not suitable for a11 

### processing conditi

### ons

# .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 "chevron"or nested V 

### type.4 Because of safety considerations, the area between the compressor seal s and the compressor motor (distance piece) is normally enclosed and vented outside of the compressor building. If hydrogen sulfide is present in the gas, then the vented vapors are normally f 1 ared.10 Reciprocating compressors may employ a metal1 ic packing plate and nonmetal1 ic partially compressible (i e., 

### GRAFFOIL,~ TEFLONR) 

### material or oil wiper rings 

### to seal shaft leakage 

### to the distance piece. Nevertheless,
some leakage into the distance piece may occur. 2.2.3 

### Process Valves One of 

### the most common pieces of equipment in gas plants is the valve. The types of valves commonly used are globe, gate, plug, ball, butterfly, re1ief, and check valves. All except the re1ief valve (to be discussed below) and check valve are activ'ated through a valve stem, which may have a rotational or linear motion, depending on the specific design. This stem requires a seal to isolate the process fluid inside the valve from the atmosphere as illustrated by the diagram of a gate valve in Figure 2-4. 

### The possibility of a leak through this seal makes ita potential source of fugitive emissions. Since a check valve has no stem or subsequent packing gland, itis not considered to be a potential
source of fugitive missions. Sealing of the stem to prevent'leakage can be achieved by packing inside a packing gland or O-ring seals. Valves that require the stem to
move in and 

### out with or without rotation must utilize a packing gland.

### Conventional packing glands are suited for a wide variety of packing materials. The most common are various types of braided asbestos that contain lubricants. Other packing 

### materia1s include graphite, graphiteimpregnated fibers, and tetrafluoroethylene polymer. The packing material used depends on the valve application and configuraton.6 These conventional packing glands can be used over a wide range of operating temperatures. Athigh pressures these glands must be quite tight to attain a good 7 seal. 2.2.4 

### Pressure Re1i ef Devices Engineering codes require that pressure-re1ieving devices or systems be used in applications where the process pressure may exceed the maximum a1lowable working pressure of the vessel

# . The most common type 

### of pressure-re1ieving device used in process units is the pressure re1i ef valve (Figure 2-5). 

### Typically, re1ief valves are spring-l~adedand designed to open when the process pressure exceeds a set pressure, a1lowing 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.* The seal is


### a disk 

### on a seat, and the possibility of a leak through this seal makes the pressure re1ief valve a potential source of VOC 

### fugitive emissions. A 

### seal leak can result from corrosion or from improper reseating of the va1 ve after 

### a re1ieving 

### operation.2 

### Rupture disks may also be used in process units. These disks are made of a material that ruptures when a set pressure is exceeded, thus a1lowing the system to depressurize. The advantage of 

### a rupture disk is that the disk seals tightly and does not allow any VOC 

### to escape from the system under normal operation. However, when the disk does rupture, the system depressurizes until atmospheric conditions are obtained, unless the disk is used in series with 

### a pressure re1ief valve. 2.2.5 

### 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 mu1

### ti-use product lines 

### toprevent products from collecting in cross-tie lines dueSTEM Y



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

### 2



### Process Slde



### gure 2-5. Diagram of 

### a spring-1 oaded 

### re1ief valve.tovalve seat leakage. In addition tovalve seat leakage, an incompletely closed valve could result inVOC emissions to the atmosphere. 2.2.6 Flanqes and Connections Flanges are bolted, gasket-sealed junctions used wherever pipe or other equipment such as vessels, pumps, valves, and heat exchangers may require isolation or removal

# . Connections are a11 other nonwelded fittings that serve a similar purpose to flanges, that also allow bends inpipes (ells), joining two pipes (coup1ings), or joining three or four pi pes (tees or crosses)

# . The connections are typicallythreaded. Flanges may become fugitive emission sources when leakage occurs due to improperly chosen gaskets or poorly assembled flanges. The primary cause of flange leakage isdue to thermal stress that piping or flanges insome services unde'rgo; this results inthe deformation of the seal between the flange faces.' ~hreaded connections may leak if the threads become damaged or corroded, or iftightened without sufficient lubrication or torque. 2.2.7 Gas-Operated Control Valves Pneumatic control valves are used widely in process control atgas plants. Typically, compressed air is used as the operating medium for these control valves. Incertain instances, however, field gas or flash gas isused to supply pressure.5 Since gas iseither continuously bled to the atmosphere or is bled each time the valve is activated, this can potentially be 

### a large source of fugitive emissions. There are also
some instances where highly pressurized field gas is used as the operating mediurn for emergency control valves. However, these valves are seldom activated and, therefore, have a much lower emissions potential than control valves in routine service. 2.3 BASELINE FUGITIVE VOC EMISSIONS Baseline fugitive emission data have been obtained atsix natural gas/gasoline processing plants. Two of the plants were tested by Rockwell International under contract to the Arnerican Petroleum 1nstitute,ll and four plants were tested by Radian Corporation under contract to €PA. 12 Baseline fugitive emission factors were developed from these data,'' and
are presented inTable 2-1. The factors represent the average baselineTab1e 2-1. BASELINE FUGITIVE EIIISSION FACTORS FOR GAS PLANTS (kg/day)

Component Emission factor 95%Confidence interval
Valves 0.18 (0.48) 0.1 

## - 0.3 (0.2 

## - 1) 

### Re1 ief valves 0.33 (4.5) 0.007 

## - 8 (0.1 

# - 100) Open-ended lines 0.34 (0.53) 0.1 

# - 0.7 (0.2 

# - 1) b Compressor seals 6.4 (18) Pump seals 1.2 (1.5) 0.5 

# - 3 (0.5 

# - 4) Flanges and 0.011 (0,026) 0.006 

# - 0.02 (0.01 

# - 0.05) connections

xx = VOC emission values. (xx)= Total hydrocarbon emission values.
b~ompressor seal emission factors from Reference 12were not used because the data base included dry gas compressors (which are not subject to RACT). The missionfactors shown are a weighted average of wet gas and natural gas 1iquids compressor seals as developed inReference 13.

### emission rate from each of the components of a specific type in a gas plant. The compressor seal emission factor represents a weighted average of compressor seals in wet gas and natural gas 1

### iquids service.13 

### Compressor seal emission factors are not directly from gas plant testing because this data included dry gas compressors which are 

### not subject 

### to RACT. 

### The total daily and 

### annual emissions from fugitive sources at each of 

### the three model gas plants (developed in Appendix B) 

### are shown in

### Table 2-2. Total daily emissions are calculated by mu1tiplying the number of pieces of each type of equipment by the corresponding daily emission factor. The average percent of total emissions attributed 

### to each component type is also presented in Table 2-2. 

### The average percent of total emissions attributed 

### to each component type is the
same for each mode1 plant.ONOWWO m-2 0 h



# - - w m-m -cu u V) V) V) 02.4 REFERENCES 1. Cantrell, A. Worldwide Gas Processing. Oil and Gas Journal, July 14, 1980. p. 88. 2. Organic Chemical Hanufacturing

## ,Volume 3: Storage, Fugitive, and Secondary Sources. Report 2, Fugitive Emissions. U.S. Environmental ProtectionAgency. Off ice of AirQua1ity Planning and Standards. Emission Standards and Engineering Division. Research Triangle Park, North Carolina. EPA-450/3-80-025, December 1980. 3. Nelson, W.E. Compressor Seal Fundamentals. Hydrocarbon Processing, 56(12):91-95. 1977.


## - 4. Telecon. R.A. McAllister, TRW, toG.H. Holliday, Shell Oil, Houston, Texas. March 10, 1981. Compressors and seals at gas plants. 5. Letter from Hennings, T.J., TRW to K.C. Hustvedt, EPA. May 13, 1981. Results ofa telephone survey concerning the use of pneumatic control valves atgas plants. 6. Lyons, J.D., and C.L. Ashland, Jr. Lyons' Encyclopedia of Valves. New York, Van Nostrand Reinhold Co., 1975. 290 p. 7. Temp1eton, H.C. Valve I n s t a l l a t i o n , Operation and ;laintenance. Chem. E., 78(23)141-149, 1971. 8. Steigerwald, B.J. Emissions of Hydrocarbons to the Atmosphere from Seals on Pumps and Compressors. Report No. 6, PB 216 582, Joint District, Federal and State Project for the Evaluation of Refinery Emissions. Air Pol1 ution Control District, County of Los Angeles, California. April 1958. 37 p. 9. McFarland, I. Preventing Flange Fires. Chemical Engineering Progress, 

# - 65(8):59-61. 1969. 10. Letter from Hennings, T.J., TRW to K.C. Hustvedt, EPA. July 7, 1981. Results of a telephone survey concerning control of fugitive emissions from gas plant compressor seals. 11. Eaton, W.S., et a1

# . Fugitive Hydrocarbon Emissions from Petroleum Production Operations. API Pub1ication No. 4322. March 1980. 12. DuBose, D.A., J.I. Steinmetz, and G.E. Harris. Radian Corp., Austin, TX. Frequency of Leak Occurrence and Emission Factors for Natural Gas Liquid Plants. Final Report. Prepared for U.S. Envi ronmental Protection A ency, Research Triangle Park, North Carolina. EMB Report NO. 

# 80-FOL-1. ~uly 1982.13. Memorandum, K.C. Hustvedt, EPA, CPB to James F. Durham, EPAy CPB. Revised Gas Plant Compressor 

### Seal Emission Factor. February 10, 1983.

### 3.0 

### EMISSION CONTROL 

### TECHNIQUES

Sources of fugitive VOC 

### emissions from gas plant equipment were identified in Chapter 2 

### of this document. This chapter discusses the emission control techniques which are considered 

### to be reasonably available control technology (RACT) 

### forthese sources. These techniques include leak detection and repair programs and equipment specifications. The estimated control effectiveness of the techniques is 

### also presented. This chapter (Section 3.3) 

### also presents other control strategies applicable to control of fugitive emissions from gas plants. However, the control effectiveness of these alternative strategies has not been estimated. 3.1 

### LEAK 

### DETECTION AND 

### REPAIR METHODS Leak detection and repair methods can be applied to reduce fugitive ernissi'ons from gas plant sources. Leak detection methods are used 

### to identify equipment components that are emitting significant amounts of VOC. 

### Emissions from leaking sources may be reduced by three general methods: repair, modification, or replacement of 

### the source. 

### 3.1.1 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, audibl-e, olfactory, soap solution,
or instrument techniques. Visual methods are good for locating liquid leaks, especially pump 

### seal failures. High pressure leaks may be 

### detected by hearing the escaping vapors, and 

### leaks of odorous materials may be detected by smell. Predominant industry practices are leak detection by visual, audible, and olfactory methods. However, in many instances, even very large VOC 

### leaks are not detected by 

### these methods. Applying 

### a soap solution (soaping) to equipment components is one individual survey method. If bubbles are seen in the soap solution, apotential leak from the component is indicated. The rateof leakage may be subjectively determined by the observer by determining the number of bubbles formed over a specified time period. Inaddition, soaping may also serve as a preliminary screening technique, inthat the number of equipment components otherwise subject to instrument monitoring may be reduced to only those components for which bubbles
were detected. Soaping isnot appropriate for very hot sources, a1though ethylene glycol can be added to the soap solution to extend the temperature range. This method isalso not suited for moving shafts on pumps or compressors, since the motion of the shaft may cause entrainment of air inthe soap solution and indicate a leak when
none ispresent. 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 isthe best individual survey method for identifying leaks of VOC from equipment components because it isapplicable to a11 types of sources. EPA Reference uethod 21, Determination of Volatile Organic Compound Leaks, specifi es the procedures for instrument monitoring. This method incorporates the use of a portable analyzer to detect the presence of volatile organic vapors atthe surface of the interfacewhere direct leakage to atmosphere could occur. This sampling traverse iscalled "monitoring" insubsequent descriptions

# . A measure of the hydrocarbon concentration of the sampled air isdisplayed inthe instrument meter. The approach of this technique assumes that if an organic leak exists, there will be an increased vapor concentration inthe vicinity of the leak, and that the measured concentration isgenerally proportional to the mass emission rateof the organic compound. 3.1.2 Repair Methods The following descriptions of repair methods include only those features of each fugitive emission source (pump, valve, etc,) which need to be considered inassessing the applicability and effectiveness of each method. 3.1.2.1 Pumps. Inmany cases, it is possible tooperate a spare pump while the leaking pump isbeing repaired. Leaks from packedseals may be reduced by tightening the packing gland. At some point, the packing may deteriorate tothe point where further tiyhtening would have no effect or possibly even increase fugitive emissions from the seal. The packing can be replaced with the pump out of service. When mechanical seals are utilized, the pump must be dismantled so the leaking seal can be repaired or replaced. Dismantling pumps may result inspillage of some process fluid causing emissions of VOC. The maximum amount of VOC released toatmosphere from these temporary emissions may be estimated by assuming all the.trapped VOC found between the inlet and outlet block valves are released. The mass emissions fran pump repair were quantified assuming the VOC contained between the block valves isapproximated by 2 m of'10 cm pipe. As such, a conservative estimate of pump repair emissions is8.6 kg VOC,
or the equivalent of the emissions from a leaking pump over a three day period.1 Pumps should be isolated from the process and flushed of VOC toa closed system as much as possible prior to repacking or seal replacement tominimize spi 1 lage emissions, however, even with spi 1 lage, repairwill result inan emission reduction. 3.1.2.2 Compressor Seals. As discussed inChapter 2, there are three types of compressors used innatural gas plants: centrifugal, rotary, and reciprocating. Centrifugal and rotary kompressors are driven by rotatingshafts whilereciprocating compressors are driven by shafts having a linear reciprocating motion. Ineither case, fugitive emissions occur at the junction of the moving shafts and the stationary casing, but the kinds of controls that can be effectively applied depend on the type of shaft motion involved. Repair of leaking compressor seals may be accomplished ifthere isa spare compressor or spare compressor capacity such that repairs can be performed on the leaking seal without a unit shutdown. Leaks from compressor seals may be reduced by the Same repair procedure that
was described for pumps (i.e., tightening the packing). Other types of seals, however, may require that the compressor be taken out of service for repair. 3.1.2.3 Relief Valves. Ingeneral, relief valves which leak must be removed inorder to repair the leak. Insome cases of improper

### reseating, manual re1ease of the valve may improve the seat seal

# . In 

### order to remove the relief valve without shutting down the process, a block valve may be required upstream of the relief valve. A spare relief valve should be attached while the faulty valve is repaired and tested. As an alternative to the potential hazard introduced by the chance of a block valve being mistakenly closed when a vessel is overpressured, itmay be preferable to instal1 a second block valve and re1ief valve for use when the first re1ief valve is under repair. An


### even safer a1ternative is to instal1 

### a three-way valve with para1lel relief systems so that one of the two relief systems is always open. Some re1ief valves may be difficult tomonitor. A 

### state or local agency may wish 

### torequire less frequent monitoring for relief valves that are difficult to access because of location or hazardous operating conditions. 3.1.2.4 

### Valves. Most valves have a packing gland which 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 if the packing is old and brittle or has been over- , 

### tightened. Unbalanced tightening of the packing gland may also cause the packing material to be positioned improperly in the valve and a1low leakage. Valves which are not often used can build up 

### a "static" seal of paint 

### or hardened lubricant which could be broken by tightening the packing gland. Plug-type valves can be lubricated with grease to reduce emissions around the plug. Some types of valves have no means of in-service repair and must be isolated from the process and removed for repair or replacement. Other valves, such as control valves, may be excluded from in-service repair by operating procedures or safety procedures. In many cases, valves cannot be isolated from the process for removal. If 

### a line must be shut down in order to isolate a leaking valve, the emissions resulting from the shutdown will possibly be greater than the emissions from the valve if allowed to leak until the next process change which permits isolation for repair. Depending on site-specific factors, itmay also be possible 

### to repair leaking process valves by 2 

### injection of a sealing fluid into the source of the leak.3.1.2.5 Flanges and Connections. Insome cases, leaks from flanges can be reduced by replacing the flange gaskets. Leaks from small threaded connections can be reduced by placing synthetic (e.g., Teflon) tape or "pipe dope" on the male threads before the connection ismade. Most flanges and connections cannot be isolated to petmit repair of leaks. Data show that flanges and connections emit relatively small amounts of VOC (Tab1e 2-1). 3.1.3 Control Effectiveness of Leak Detection and Repair Methods There are several factors which determine the control effectiveness of a leak detection and repair program; these include: a Action level or leak definition,
0 Inspection interval or monitoring frequency,
0 Achievable emission reduction from maintenance, and a Interval between detection and repair of the leak. 3.1.3.1 Action Level. The instrument reading atwhich maintenance is required iscalled the "action level

# ." The RACT action level is 10,000 ppmv. Components which have indicated instrument readings equal to or higher than this "action level" are marked for repair. Table 3-1 gives the percent of total mass emissions affected by the 10,000 ppmv action level for a number of component types. Available data indicate that a 10,000 ppmv action level provides a reasonable level of confidence that most large leaks will be detected inroutine screening. However, a higher action level (e.g., 20,000 ppmv) will result 

### in lower maintenance costs because somewhat fewer leaks will be detected. Higher action levels were considered for RACT, but the actual savings inmaintenance costs are not likely to be large compared to the high credits to be realized from product recovery. Inaddition, the monitoring instruments presently inuse for fugitive emission surveys have a maximum meter reading of 10,000 ppm. Add-on dilution devices are available to extend the range of the meter beyond 10,000 ppm, but these dilution probes are inaccurate and impractical for fugitive emissions monitoring surveys. Other considerations for selection of the action level are component specific. For valves, the selection of an action level for defining a leak isa tradeoff between the desire to locate all significant leaks andTable 3-1. PERCENT EMISSIONS FROM SOURCES WITH INSTRUrlENT READINGS EQUAL TO OR GREATER THAN 10,000 ppmv

Percent of mass emissions for 10,800 ppnv Component action level b Valves 

### 86 (87) Re1 ief valvesL Compressor sealsb,d b Pump seals

xx = VOC emission values. (xx) = Total hydrocarbon values. a~raction of total emissions from a given source type that is attributable to sources with instrument readings equal to or greater than the 10,000 ppmv action level. b~ef erence 3. '~eference4. d~ased on a weighted average of compressor seals inwet gas and natural gas liquids service. Reference 5.

### to ensure that mission reductions are possible through maintenance. A1

### though test data show that some valves with 

### meter readings less than 10,000 ppm 

### have significant emission rates, most of the major emitters have meter readings greater than 10,000 ppm. 

### Informati

### on obtained through EPA 

### in-house testing and industry indicates that in actual fugitive emission surveys, most sources of VOC 

### have meter readings which are very low or very high. Maintenance programs on valves have shown that emission reductions are possible through on-line repair for essentially all valves with non-zero meter readings. There are, however, cases where on-line repair attempts result in an increased emission rate. The increased emissions from such a source could be greater than the emission reduction if maintenance is attempted on low leak valves. These valves, however, should be able toachieve essentia1ly 100-percent emission reduction through off-line repair because the leaking valves can either be repacked or replaced. The emission rates from valves with meter readings greater than or equal to 10,000 ppm 

### are significant enough so that an overall emission reduction will occur for 

### a leak detection and repair program with a 10,000 ppm 

### action 1

### eve1

# . For pump 

### and compressor seals, selection of an action level is different because the cause of leakage isdifferent. Compared to valves which generally hdve zero leakage, most seals leak to 

### a certain extent whi1 e operating normally. The routine 1

### eakage is generally low, so these seals would tend 

### tohave low instrument meter 'readings. With time, however, as the seal begins to wear, the concentration and emission rate are likely 

### to increase. At

### any time, catastrophic seal failure can occur with a large increase in the instrument meter reading and emission rate. As shown in Table 3-1, over 90 percent of the emissions from compressor seals and approximately 80 percent of the emissions from pumps are from sources with instrument meter readings greater than or equal to 10,000 ppm. 

### Properly designed, installed, and operated seals have low 

### instrument meter readings, and the bulk 

### of the pump 

### and compressor seal emissions are from seals that have worn out or failed such that they have a concentration equal to or greater than 10,000 ppm.3.1.3.2 Inspection Interval. The length of time between inspections depends on the expected occurrence and recurrence of leaks after a piece of equipment has been checked or repaired. The choice of the interval affects the emission reduction achievable since more frequent inspectionwill result inleaking sources being found and fixed sooner. The leak occurrence and recurrence correction factor for quarterly inspections isestimated to be 90 percent. The estimated percentages of components found leaking with quarterly inspections are given in Tab1e 3-2. 3.1.3.3 Allowable Interval Before Repair. If a leak isdetected, the equipment should be repaired within a certain time period, The allowable repair time should reflect an interest ineliminating a source of VOC emissions but should also allow the plant operator sufficient time to obtain necessary repair parts and maintain some degree of flexibility inoverall plant maintenance scheduling. The determination of this a1lowable repair time will affect emission reductions by influencing the length of time that leaking sources are allowed tocontinue to ernit pollutants. Some of the components with instrument readings inexcess of the leak definition action level may not be able to be repaired until the next line shutdown. The allowable interval before repair for RACT is chosen to be 15 days. The percent of emissions from a component which would be affected by the 15-day repair interval if all other contributing

'- factors were 100 percent efficient is98 percent. The emissions which occur between the time the leak isdetected and repair is attempted
are increased with longer a1lowable repair intervals. 3.1.3.4 Achievable Emission Reduction. Repair of leaking components will not always result incomplete emission reduction. To estimate the emission reduction from repair of equipment, itwas assumed that leaks are reduced by maintenance to an instrument reading of 1,000 ppmv. The percent emissions reduction due to repair of 1 zaking valves, pressure relief valves, and compressor seals isderived from the average emission rates of these components above 10,000 ppmv and at 1,000 ppmv as shown inTable 3-3.C Table 3-2. ESTIMATED PERCENT COMPONENTS LEAKING PER INSPECTION FOR QUARTERLY MONITORING

Estimated Annual Percentage of Estimated Percent Components Found of Components Leaking with Component Type Leaking Initi a1lya Quarterly Inspections

Val ves Re1 ief Valves Compressor Seals Pump Seals

aApproximate fraction of components having an instrument reading

equal toor greater than 10,000 ppmv prior to repair. bReference 3.

Reference 8. dReference 9. eAnnual percent recurrence factors have been applied for quarterly

inspections for re1 ief valves and compressor seals todetermine the percentage of sources maintained. It is assumed that 10 percent of sources initiallydetected are found with quarterly monitoring, therefore, the annual average iscalculated as: 0.10 x 4 = 0.4. The estimated annual percentage of components found leaking at quarterly inspections iscalculated as: Estimated percentage of Percent of components found leaking = components

# )
, 0.4 with quarterly inspections (1 eaking \initially fReference 5.Table 3-3. AVERAGE EMISSION RATES FRO14 COIIPONENTS ABOVE 10,000 ppmv AND AT 1,000 ppmv
Average emission Average emission rate from sourcesa rate from sourc

# 6s above 10,000 ppmv, at 1,000 ppmv, Percentc Compoqent type kg/day kg/day reduction Valves 0.86 (2.3) 0.015 (0.017) 98 (99) Compressor Seals d 18 (39) 0.36 (0.78) 98 (98) Re1 ief valves 1.3 (18.2) 0.141 (0.146) 83 (99)

xx = VOC emission values. (xx) = Total hydrocarbon values. a~rnission factor for leaking sources. Calculated by mu1tiplying the base1ine emission factor (Table 2-1) tines the percent emissions with instrument readings greater than 10,000 ppmv (Tab1e 3-l) , divided by the percent components with instrument readings greater than 10,000 ppmv (Table 3-2). b~ssurnedemission factor for leaking sources that have been successfully

repaired (on the average, repair is not perfect). C ~ m m e d i a t e p e r c e n t .reduction inemissions due to successful on-1ine

leak repair.3.1.3.5 Development of Controlled Emission Factors. There are two models available for estimating emission reduction efficiency from leak detection and repair programs. Controlled emission factors used inthis document are calculated using both models. The firstmodel (the computer leak detection and repair (LDAR) modello) isapplied to valves and pumps. 

### It isthe preferred model because it incorporates recently available data on leak occurrence and recurrence and data on the effectiveness of simple in-line repair. These data are not available for relief valves and compressor seals. Therefore, a second model (The ABCD model

### ) isapplied to re1ief valves and compressor seals. The ABCD model can be expressed mathematically by the following equation: 11 Emission reduction efficiency = A x 

### 3 x C x D

Theoretical Flaximum Control Efficiency = fraction of total mass emissions for each source type with instrument readings greater than the action level (Table 3-1). Leak Occurrence and Recurrence Correction Factor = correction factor to account for sources which start to leak between inspections (occurrence) and for sources which are found to be leaking, are repaired and start to leak again before the next inspection (recurrence), and for sources not repaired. Noninstantaneous Repair Correction Factor = correction factor toaccount for emissions which occur between detection of a leak and subsequent repair; that is, repair isnot instantaneous. Imperfect Repair Correction Factor = correction factor to account for the fact that some sources which are repaired
are not reduced to zero emission levels. For computational purposes, all sources which are repaired are assumed to be reduced to an emission level equivalent to an instrument reading of 1,000 ppmv.

The 

### ABCD model control efficiencies for re1iefvalves and compressor seals, however, have been modified tocorrect for the accuracy of theengineering judgment employed toderive one-of the model inputs as discussed inthe AID." The accuracy of the judgment was approxinated by the comparison of the LDAR model and the ABCD model control efficiencies 

### 9 forvalves, as: Valve LDAR Model LDAR Control ABCD Model Control Effectiveness Control Effectiveness

# - (Effectiveness) 

## x

# \

Valve ABCD Model 

# i

Control Effectiveness

. 

### Enissions reduction efficiencies are presented inTab1e 3-4, as are controlled emission factors. The control1 ed emissions factors are calculated as:
Control1ed Emission Emission = Base1ine 

# - ne x Reduction

# 1

Factor Factor Efficiency using the baseline emission factors inTable 2-2. 3.2 EQUIPMENTSPECIFICATIONS Fugitive emissions may be reduced by using process equipment designed to prevent leakage. Equipment specifications are considered here only for control of emissions from control valves and open-ended lines. 3.2.1 Gas-Operated Control Valves VOC emissions from pneumatic control valves result when field gas or flash gas isused as the operating medium. These emissions can be eliminated by switching tothe use of compressed airor nonVOC gas such as methane. This will require installation of an aircompression system and/or reconnection.of the appropriate pressure supply lines. 3.2.2 Open-Ended Lines Fugitive emissions from open-ended lines are caused by leakage through the seat of a valve upstream of the open end of the line. Fugitive emissions from open-ended 1ines can be control1 ed by instal1ing a cap, plug, flange, or second valve tothe open end of the line. In the case of a second valve, the upstream valve should always be closed firstafter the use of the valves. Each time the cap, plug, flange,
or second valve isopened, any VOC which has leaked through the first valve seat will be released. The control efficiency will depend onTable 3-4. CONTROLLED EMISSION FACTORS FOR QUARTERLY LEAK DETECTION AND REPAIR

Baseline Control Control1 ed Equipment Emission 

### actor^ Efficiency Emission Factor Item (kg/day) (X) (kg/day

## 1
Valves 0.18 (0.48) Re1 ief Val ves 0.33 (4.5) Compressor Seals 6.4 (18) Pump Seals 1.2 (1.5)

xx = VOC emissions factor (xx) = THC emission factor

a~rom Tab1e 2-2. 

### b~rorn LDAR Model. Reference 8. '~rornABCD Model

## , corrected as described inSection 3.1.3.5. Reference 9. d~ef erence 5.such factors as frequency of valve use, valve seat leakage, and material that may be trapped inthe cap or plug. Annual VOC emissions from a 1

eaking open-ended va1 ve are approximately 100 kg.lo Assuming that open-ended lines are used an average of 10 times per year, that 

### 0.1 kg of trapped organic material is released when the valve isused, and that a11 of the trapped organics released are emitted to atmosphere, the annual emissions from closed off open-ended 1ines would be 1kg. This would be a 99 percent reduction inemissions. Due to the co'nservative nature of these assumptions, a 100 percent control efficiency has been used to estimate the emission reductions of closing off open-ended lines. 3.2.3 Compressor Seals Centrifugal and rotary compressors are both driven by rotating shafts. Emissions from these types of compressors can be controlled by the use of mechanical seals with barrier fluid (liquid or gas) systems or by the use of liquid film seals. In both of these types of seals, a fluid is injected into the seal at a pressure higher than the internal pressure of the compressor. In this way, leakage of the process gas to atmosphere is prevented except when there is a seal failure. As inthe case of pumps, seal fluid degassing vents must be controlled with a closed vent system to prevent process gas from escaping from the vent. Reciprocating compressors involve a piston, cylinder, and drive-shaft arrangement. Since the shaft motion is linear, a packing gland arrangement is normally employed to prevent leakage around the moving shaft. This type of seal can be improved by inserting one or more spacer rings into the packing and connecting the void area or areas thus produced to a collection system through vents inthe housing. This is referred to as a "scavenger" system. As with other fugitive emission collection systems, these vents must be control1 ed 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. As shown in Figure 3-1, these leaks can be controlled by enclosing the distance piece area and installing suitable piping to vent the emissions eitherto a flare, a plant process heater, or back into a low pressure point inthe process.13 For the latter two cases, an auxilliary compressor may be required tocompress the vent stream toa usable 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. Obtaining a good seal atthe 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., 2 to 5 psig). Block valves should also be installed inorder to close vent 1 ines during compressor shutdown periods. This will prevent hydrocarbon vapors from entering the work place and air fro3 entering the vent systern during compressor maintenance. There may be instances where retrofitting of such a vent control system to a compressor distance piece may be infeasible for safety reasons. Therefore, the application of this preventive program as a retrofitwill have to be evaluated on a case-by-case basis

# . 3.3 OTHER CONTROL STRATEGIES This section discusses two fugitive emission control strategies forvalves other than the quarterly leak detection and repair procedures discussed above. These strategies are 1 imi ted inapplication to valves, because the other component types (pumps, compressors, and re1ief valves) are relatively few innumber. The statistics used in estimating the effectiveness of the alternative strategies are inappropriate for small populations of components. For example, it isdifficult to .quantify a "low leak frequency" inreference to a population of six pumps at a medium-sized gas plant. There are also differences between valves and other component types inthe way that leaks occur. Valves develop leaks slowly over time with small percent emission increases
over a given time interval. Other component types, however, may leak atvery low levels over a long period of time prior to a sudden equipment failure that results ina very high emission rate. Therefore, leak history of individual components other than valves may not be a good indicator of the likelihood of a leak inthe future. This is an important consideration when selecting an appropriate rnonitoring frequency for a particular component type.These strategies should be considered a1ternatives to quarterly leak detection and repair to a1low process units the flexibility to meet a level of performance using control procedures considered most appropriate by that process unit. Process units which currently have relatively few leaking valves because of good design or existing control procedures would be most 1ikely to benefit from these strategies ifthey were included in regulations adopted by a State agency. Thus, these a1ternative control strategies might be included inState regulations
as a1ternative standards to quarterly 1 eak detection and repair. Before implementing one of these a1ternative control strategies, however, an owner or operator should be required to notify the Director of the State agency. 3.3.1 General The emission reduction and annualized cost of a quarterly leak detection and repair program depend inpart on the number of valves found leaking during inspections. Since about 95 percent of the conponents to be monitored ina gas plant are valves, most of the cost of detecting leaks in a process unit can be attributed to valves. In general, few leaks mean VOC missions are low. Consequently, the amount of VOC emissions that could be reduced through a leak detection and repair program and the product recovery credit associated with the program would be small. As a result, the annualized cost of a leak detection and repair program for a process unit increases as the number of leaks detected and repaired decreases. As the percent of valves found 1 eaking decreases the product recovery credit decreases. The direct cost for monitoring, however, remains the same because the number of valves which must be monitored remains the same. Therefore, the cost effectiveness (annualized cost per megagram of emissions controlled) of a leak detection and repair program varies with the number of valves (or the percent of valves) which leak within a process unit. The cost effectiveness for a quarterly leak detection and repair program for valves appears reasonable for leak percentages of 14 about one percent or higher as shown in Figure 3-2. A process unit averaging about one percent of valves leaking will sometimes have less than one percent of valves leaking and sometimes have
more than one percent leaking. Statistically, if a process unit averaged
one percent of valves leaking, then the percent of valves found leaking 3-17C I r 2 4 6 8 10
Leak Frequency (Percent)

Figure 3-2. Cost-effectiveness of Quarterly Leak Detection and Repair of Valves With Varying Initial Leak Frequency
during a random inspection would exceed two percent less than five percent of the time. Two percent of valves found leaking isa reasonable criterion tojudge the applicabi1ity of a1ternative control strategies for valves. 3.3.2 A1lowable Percentage of Valves Leaking A State regulation incorporating an alternative control strategy based on an "allowable percentage of valves leaking" would require a process unit to limitthe number of valves leaking at any time toa certainpercentage of the number of valves tobe monitored. As discussed above, it appears that two percent of valves leaking represents a reasonable performance level for an allowable percentage of valves leaking. This type of regulation would require the owner or operator to conduct a performance test at least once ayear by the applicable test method. Additional performance tests could be requested by the State. A performance test would consist of monitoringall valves. All components other than valves would be subject toquarterly leak detection and repair. The percentage of valves leakingwould be determined by dividing the number of valves for which a leak was detected by the number of valves monitored including known leaks that are awaiting shutdown repair. If the results of a performance test showed that the percentage of valves leakingwas greater than the performance level of two percent of valves leaking, then the process unit would be in violation of the State regulation. Incorporatingthis type of alternative control strategy inthe State regulation would provide the flexibi1ity of a performance standard. Compliance with the regulation could be achieved by the method deemed most appropriate by the plant. The plant could implement the quarterly leak detection and repair program for valves tocomply with the regulation
or it could implement a program of their choosing for valves tocomply with the performance level inthe regulation. 3.3.3 Alternative Work Practice for Valves A State regulation incorporating an alternativo control strategy for valves based on "skip-period" monitoringwould require that a plant attain a "good performance level" on a contin~al basis interms of the percentage of leaking valves. As discussed above, it appears that two percent of valves 1 eaking represents a "good performance 1

eve1

# ." This type of regulationwould requirethe owner or operator to begin with imp1ementation of a quarterly 1 eak detection and repair program for valves. Ifthe desired "good performance level" of two percent of valves leaking was attained for valves for a certain number of consecutive quarters, then one or more of the subsequent quarterly leak detection and repair periods for these valves could be skipped.

### This strategy isgenerally referred to as "skip-period" monitoring. All other components would be subject 

### to quarterly leak detection and 

### repair interval

### s. If 

### implementation of the quarterly leak detection and repair program showed that two percent or less of the valves were leaking for



## - i consecutive quarters, then 

### rn quarterly inspections may be skipped.



## - If 

### the next inspection period also showed that the "good performance level

### " was being achieved, then 

## mquarterly inspections could be skipped again. When an inspection period showed the "good performance level

### " was 

### not being achieved, then quarterly inspections of valves would be reinstituted. If

# Lconsecutive quarterly inspections then showed again that the good performance level .was being achieved, then



## - m quarterly inspections could be skipped again. As mentioned above, two percent of valves leaking represents a good level 

### of performance. Table 3-5 

### illustrates how "skip-period" monitoring might be implemented in practice. In 

### this case, the "good performance level" must be met for five consecutive quarters (i=5) before three quarters of leak detection could be skipped (m=3). If 

### the quarterly leak detection and repair program showed that two percent
or less of the valves in a plant were leaking for each of five consecutive quarters, then three quarters could be skipped following the fifth quarter in which the percent of these valves leaking was less than the "good performance 1 eve1

# ." After three quarters were skipped, a11 

### valves woulJ 

### be monitored again on the fourth quarter. Another possible skip program would a11 ow semi-annual monitoring following two consecutive quarters atless than the good performance level. This strategy would permit a plant that has consistently demonstrated itismeeting the "good performance level" to monitor valves annually instead of quarterly. Using this approach, a plant could optimize labor and capital costs to achieve the good level 

### of performance by developing and implementing its own leak detection and repair procedures
or instal1

### ing valves with lower probabi1

### ities of 1

### eaking. Compared 

### to
a standard based on an "a1lowable percentage of valves leaking,

### " where not achieving the good performance level would be a violation of the State regulation, the penalty under the "a1ternative work practice" standard would only be a return to routine quarterly monitoring.

### Table 3-5. 

### ILLUSTRATION OF



### Quarterly Leak rate 1

### eak of valves detection during period period 

### (I) SKIP-PERIOD MONITORING~



### Quarterly

action

taken (monitor vs. skip)

monitor 

### monitor monitor monitor monitar monitor skip 

### skip skip moni

### tor monitor monitor monitor monitor monitor skip skip skip moni

### tor skip skip skip monitor Good performance 1

### eve1 achieved?

No Yes 1 

### Yes 2 

### Yes 3 

### Yes 4b 

### Yes 5



# - 1



# - 2



### Yes 1 

### Yes 2 

### Yes 3 

### Yes 4b 

### Yes 5



# - 3d 

### Yes 4



## - 3d 

### Yes 4 

### ai=5,m=3, 

### good performance level b~i-fth consecutive quarter below 2 

### percent means 3 

### quarters of monitoring may be skipped. 'percentage of 

### leaks above 2 

### percent means quarter1y 

### monitoring 

### reinstituted. d~ercentage of leaks below 2 

### percent means 3quarters of monitoring nay be skipped

# . of 

### 2 

### percent.3.4 OTHER CONSIDERATIONS This section identifies and discusses other considerations that a State agency may wish to address when drafting a regulation. These considerations include components which are difficult to monitor, small process units, and unit turnarounds. 3.4.1 Diffi cult-to-moni torComponents Some valves may be difficultto monitor because access tothe valve bonnet is restricted or the valves are located inelevated areas. These valves might be monitored by the use of a ladder or scaffolding. Valves which could be monitored by the use of a ladder
orwhich would not require monitoring personnel to be elevated higher than two meters should be monitored quarterly. However, valves which require the use of scaffolding orwhich requirethe elevation of monitoring personnel higher than two meters above permanent support surfaces might be exempted from quarterly monitoring providedthey are monitored annually

# . 3.4.2 Small Process Unit The net annual cost and emission reduction of performing a quarterly leak detection and repair program isprincipally related tothe number of equipment pieces ina gas processing plant. Ingas plants with very small throughputs it is reasonable to assume that VOC emissions

- would not become a large percentage of the gas processed regardless of the number of pieces of equipment involved. Further, small non-complex gas plants are often manned with a minimum number of operators so that outside personnel may need to be used to performthe monitoring. Figure 3-3 shows the cost effectiveness of a quarterly leak detection and repair program as a function of gas plant throughput based on these considerations.15 Based on this curve, States may wish to consider exempting from the RACT requirements non-complex gas plants (plants that do not fractionate the mixed natural gas liquids) that have design throughputs of less than 10 million scfd. 3.4.3 Unit Turnarounds A State agency might wish toconsider a provision inits regulations which would allow the agency Director to order an early unit shutdown for repair of leaking components incases where the percentage of5,000

4,000

3, OOC

2,001



### Plant Throughput (MMscfd)

~igure 3-3. 

### Cost Effectiveness of QuarterlyLeak Detection and Repair for Small Gas Plants

### leaking components awaiting repair atunit turnaround becomes excessive. Use of such 

### a provision, however, must be carefully considered in terms of the emissions reduction achievable and the costs to the process unit in production down-time and repair cost. A1ternative methods of treating delay of repair could a1so be considered by a State or local agency in reducing the cumulative number of unrepairable equipment components. For instance, delays of repair to the next scheduled process unit shutdown (or turnaround) could be allowed under circumstances where itis technically infeasible to repair the component in-placelon-1ine (i.e., without a unit shutdown)
or where rep1acement parts hpve been depleted from once-sufficient inventory. By requiring records of delays and reasons for delays, State enforcement officers would be supplied with the data necessary 

### to determine compliance.3.5 REFERENCES
Memorandum. Rhoads, T.W., Pacific Envi ronmental Services, Inc., toK.C. Hustvedt, EPA/CPB. Gas Plants CTG: Pump Repair Emissions Estimate. December 21, 1982. Teller, James H. Advantages Found inOn-Line Leak Sealing. Oil and Gas Journal

### ,- 77(29):54-59, 1979. DuBose, D.A., 3.1. Steinmetz, and G.E. Harris. Radian Corporation, Austin, Texas. Frequency of Leak Occurrence and Emission Factors for Natural Gas Liquid Plants. Final Report. Prepared for U.S. Envi ronmental Protection Agency. Research Triangle Park, North Carolina. EMB Report No. 80-FOL-1. July 1982. Memorandum. Henning, T.J., TRW to VOC/Onshore Production Docket. April 2, 1982. Cumulative Distribution of Mass Emissions and Percent Sources with Respect toScreening Value for Relief Valves. Memorandum. K.C. Hustvedt, EPA:CPB, toJames i.Durham, EPA:CPB, Revised Gas Plant Compressor Seal Emission Factor. February 10, 1983. Letter w/enclosures from H. H. McClure, Texas Chemical Council, toW. Barber, OAQPS, EPA. June 30, 1980. Lee, Kun-chieh, et a1

# . Union Carbide Corporation. A Fugitive Emission Study ina Petrochemical Manufacturing Unit. Paper presented at annual APCA meeting. Montreal, Quebec. June 22-27, 1980. Memorandum. Rhoads, T.W., Pacific Environmental Services, Inc., to Docket A-80-20-B. Evaluation of the Effects of Leak Detection and Repair on Fugitive Emissions inthe Onshore Natural Gas Processing Industry using the LDAR Model. November 1, 1982. Memorandum. Rhoads, T.W., Pacific Environmental Services

### , Inc., toDocket Number A-80-20-6. Calculation of Controlled Emission Factors for Pressure Relief Valves and Compressor Leaks. November 1, 1982. Fugitive Emission Sources of Organic Compounds. Additional Information on Emissions, Emission Reduction, and Costs. U. S. Envi ronmental Protection Agency. EPA-450/3-82-010. Apri1 1982. Tichenor, B.A., K.C. Hustvedt, and R.C. Weber. Controlling Petroleum Refinery Fugitive Emissions Via Leak Detection and Repair. Symposium on Atmospheric Emissions from Petroleum Refineries. Austin, Texas. EPA-600/9-80-013. November 6, 1979.12. VOC Fugitive Emissions in Petroleum Refining Industry-Background Information for Proposed Star,dards. U.S. Environmental Protection Agency, Research Triangle Park, NC. EPA-450/3-81-015a. November 1982. 13. Memorandum. K.C. Hustvedt, EPA:CPB;to James F. Durham, EPA:CPB, Cost Basis for Compressor Vent Control System. February 23, 1983. 14. Memorandum. Dimnick, Fred, EPA/SDB, to K.C. Hustvedt, EPAICPB. Natural Gas/Gasoline Processing LDAR Model Results. January 24, 1983. 15. Memorandum. T.W. Rhoads, Pacific Environmental Services, Inc., to K.C. Hustvedt, EPAICPB. Cost Effectiveness of RACT as a Function of Throughput for Srnzll Gas Plants. December 20, 1982.4.0 ENVIRONMENTAL ANALYSIS OF RACT

This chapter discusses the environmental impacts that would result from implementing reasonably available control techno1ogy (RACT), which is presented inSection 4.1. The primary emphasis isa quantitative assessment of VOC emissions inthe absence of RACT (base1ine emissions) and after implementation of RACT. The impacts of RACT upon water pollution, solid waste, and energy consumption are also addressed inthis chapter. 4.1 REASONABLY AVAILABLE CONTROL TECHNOLOGY 

### (RACT) PROCEDURES RACT procedures include weekly visual inspection of pumps and quarter1 y monitoring of pumps, valves, compressors, and re1ief valves

# . Relief valves should be monitored and repaired if necessary after they have vented tothe atmosphere. Routine instrument monitoring isnot necessary for flanges and connections. Any component that appears to be leaking on the basis of sight, smell, or sound should be repaired. Inaddition, difficult-to-monitor valves may require less frequent than quarterly monitoring. Except when the open end is inuse (e.g., relief valves and double block and bleed valves), open-ended lines should be sealed with a second valve, a blindflange, a cap, or a plug. Inthe case of a second valve, the upstream valve should be closed first after each use. Compressor seal

### s should be monitored quarterly, however, some plant owners and operators may experience difficulty in reducing VOC concentrations to less than 10,000 ppmv. Moreover, repair of compressor seals often necessitates a potential or complete process unit shutdown because compressors are general1y not spared. Consequently, plants may find it preferable to install a compressor vent control system (see Section 3.1.2.2). However, retrofitting existing compressors with these systems may pose a safety problem. Because of the problems associated with quarterly monitoring orwith

### instal1 ing 

### equipment controls in certain cases, RACT 

### for compressors, therefore, will be determined on a case-by-case basis. Quarterly monitoring should be performed according to EPA 

### Reference Method 21, 

### and a source is considered leaking if monitoring results in
an instrument meter reading equal to or greater than 10,000 ppmv. 

### As discussed in Section 3.1.1, a soap solution may be applied to certain equipment as a preliminary screening technique for leakage. A 

### soap score equivalent 

### to 10,000 ppmv 

### is not specified in this guideline document because soap scoring is not applicable to all source types (see Section 3.1.1) and because itinvolves a subjective evaluation of bubble formation over 

### a specified period of time. However, states may wish to allow plant owners or operators to use the soap score method based on' a correlation between soap scoring and instrument readings for sources where soap scoring is applicable. Leaking components should be tagged and repaired within 15 days. In those instances where a leak cannot be repaired within 15 days because of interference with plant operations, the leak should be repaired at the next 1ine shutdown. RACT 

### should apply only to equipment containing or contacting a process stream with a VOC 

### concentration of 1.0 percent by weight or more. The purpose of this cutoff is to exclude equipment in product natural gas service, which contains much less than 1.0 

### percent by weight VOC. 

### Equipment with process streams containing relatively low percentages of VOC 

### (i.e., between 1.0 and 10 percent) contribute a significant portion of-total emissions from natural gas plants and, therefore, are subject to RACT 

### requirements. RACT 

### does not apply to equipment operating under vacuum and equipment in heavy 1 iquid service. An equipment component is in heavy liquid service if the percent evaporated is less than 10 percent at 150°C as determined by ASTI1 Method D-86. 

### RACT 

### does not apply to wet gas service reciprocating compressors in plants that do not have a VOC 

### control device such as a flare or a continuously burning process heater or boiler. Further, due to the high cost effectiveness of monitoring in small plants, plants with 

### less than lOMMcfd capacity that do not fractionate natural gas liquids are exempt from the RACT 

### monitoring requirements.4.2 AIR POLLUTION Implementation of RACT would reduce fugitive emissions of VOC from gas plants significantly. There are no adverse VOC emission impacts associated with RACT. 4.2.1 Development of Emission Levels To estimate the VOC emission level associated with RACT, control efficiencies and emission factors were determined for each type of component (e.g., valves, pumps). The base1ine emission factors for process equipment, which represent emissions inthe absence of RACT,
were previously presented inChapter 2 (Table 2-1). Controlled emission factors were developed for valves, pressure re1ief valves, pump seals and compressor seals that would be controlled by the implmentation of
a leak detection and repair program. Control efficiencies and controlled emission factors for pressure relief valves and compressor seals were derived from the ABCD model correction factors and the leak detection and repair (LDAR) model as discussed inChapter 3. Control efficiencies and controlled emission factors for valves and pump seals were derived directly fran the LDAR model as described inChapter 3. For RACT requirements specifying equipment controls (i .e., open-ended 1 ines)

### , it isassumed that zero emissions result from the controlled source. The controlled emission factors for each component type are presented inTable 3-4. Incalculating the total VOC fugitive emissions from model plants controlled under RACT, the control1ed emission factors were mu1tip1 ied by the number of pieces of equipment for each model plant given in Table 2-2. An example calculation for estimating emissions from model plant B under RACT isshown inTable 4-1. Total annual model plant emissions for each component type are presented inTable 4-2 for both baseline and RACT levels of control. 4.2.2 Emission Reduction The emission reduction expected from the imp1ementation of RACT
can be determined for each model plant. The emission reduction is the difference between the fugitive emissions before RACT is implemented and the fugitive emissions after RACT is implemented. These emissionsTable 4-1. EXAMPLE CALCULATION OF VOC FUGITIVE EMISSIONS FROM HODEL PLANT B UNDER RACT

C o n t r o l 1 ed Number of emission sources in factor, Total emissions, model pl anta kgldaylsource kg/day Component (N) (N x E)

- - Val ves 750 0.041 (0.11)~ 31 (82) Re1 ief valves 12 0.12 (1.4)~ 1.4 (17) Open-Ended 1ines 150 0.0 (0.0)~ 0 (0) Compressor seals 6 1.1 (3.41~~~ 6.6 (20) Pump seals 6 0.50 (0.63)~ 3.0 (3.8) Flanges and connections 3,000 0.011 (0.026)~ 33 (78) Total Emissions

xx = VOC emission values. (xx) = Total hydrocarbon emission values. aFrom Table 2-2. '~romTable 3-4. Controlled emission factors are derived from the baseline

emission factors inTable 2-1. C~ssurnes installationof second valve, blind flange, cap, or plug with 100 percent control efficiency. d~ased on leak detection and repair. Installationof a compressor vent control system would achieve 100 percent control efficiency.C Tab1e 4-2. ANNUAL VOC EMISSIONS ON A COMPONENT TYPE BASIS FOR EACH MODEL 

## PLANT^

Emissions undeg Emissiops under base1ine control

### , Mq/yr RACT, Mq/yr Model plant Model plant Component type A B C A B
Valves 16 (44) 49 (130) 160 (440) 3.7 (10) 11 (30) 37 (100) Re1ief valves 0.47 (6.6) 1.5 (20) 4.7 (66) 0.18 (2.0) 0.53 (6.1) 1.8 (20) Open-ended lines 6.2 (9.5) 19 (29) 62 (95) 0 Wd 0 

## md 0 (old Cou~pressorseals 4.6 (13) 14 (39) 46 (130) 0.8 (2.5)e 2.4 (7.4)e 8.0 (~5)~ Pun~pseals 0.88 (1.1) 2.6 (3.3) 8.8 (11) 0.37 (0.46) 1.1 (1.4) 3.7 (4.6) Flanges and connections 4.0 (9.5) 12 (28) 40 (95) 4.0 (9.5)f 12 (28jf 40 (951f

Total 32 (84) 98 (250) 320 (840) 9.0 (24) 27 (73) 90 (240)

xx = VOC emission values. (xx) = Total hydrocarbon emission values.
a~ssu~~es 365 dayslyear operation. b~missions inthe absence of RACT. From Table 2-2. CControlled emission factor (Table 3-4) x number of components (Table 2-2) x 0.365 (conversion from kg/day to Mg/yr). d~ssumesi n s t a l l a t i o n o f second valve, blind flange, cap, or plug with 100 percent control efficiency. e~ased on quarterly leak detection and repair. However, i n s t a l l a t i o n o f a compressor vent control system would achieve 100 percent control efficiency. f~o controls are specified except repair iffound leaking.are presented as "totals" inTable 4-2. The average reduction in emissions for the model plants after RACT is implemented is 71percent for VOC and for total hydrocarbons. 4.3 WATER POLLUTION A1though fugitive emissions of VOC from gas plant equipment primarily impact atmospheric VOC emissions, they also impact water qua1 ity. In particular, leaking components hand1ing 1iquid hydrocarbon streams increase the waste load entering wastewater treatment systems. Leaks from equipment can contribute to the waste load by entering drains via runoff. Implementation of RACT should reduce the waste load on wastewater treatment systems by preventing equipment 1 eaks into the wastewater system; therefore, no adverse water pollution impact isexpected. 4.4 SOLID WASTE DISPOSAL The quantity of solid waste generated by the implementation of RACT would be insignificant. The solid waste generated would consist of used valve packings and cmponents which are replaced. 4.5 ENERGY Implementation of RACT isexpected to require littleor no energy consumption at gas plants. Instead, implementation of RACT will save energy by reducing emissions to atmosphere of methane, ethane, and VOC. Table 4-3 shows the amount of energy to be saved on a component basis from implementation of RACT interms of joules and in barrels of crude petroleum. Table 4-4 shows the total energy saved per model plant.rc a't OLaJ 3- m t'4.6 REFERENCES 1. DOE Flonthly Energy Review. January 1981. DOE/EIA-0035 (8l/Cll). 2. Nelson, W.L. Petroleum Refinery Engineering. McGraw-Hi 11 Book Company, Inc. New York, 1958. p. 32. 3. Perry, R.H., and C.H. Chilton, eds. Chemical Engineers' Handbook, Fifth Edition. McGraw-Hill Book Company, New York. 1973. p. 9-16.5.0 CONTROL COST ANALYSIS OF RACT

The costs of imp1ementing reasonably available control techno1ogy (RACT) for controlling fugitive emissions of volatile organic compounds (VOC) from equipment leaks at gas plants are presented inthis chapter. Capital costs, annualized costs, and the cost effectiveness of RACT
are presented. These costs have been developed for the individual equipment pieces and model plants presented inChapter 2. To ensure a common cost basis, Chemical Enqineerinqcost indices are used to adjust costs to June 1980 do1lars. As discussed inSection 4.1, RACT for compressor seals isquarterly leak detection and repair. Inmany instances, however, a compressor vent control system would be installed. For the purpose of estimating RACT cost impacts, Sections 5.1 through 5.4 are based on quarterly leak detection and repair for compressors. Additionally, compressor vent control costs are discussed inSection 5.5. Capital costs for the vent control system are included inTable 5-1. 5.1 BASIS FOR CAPITAL COSTS Capital costs represent the total cost of starting a leak detection and repair program inexisting gas plants. The capital costs for the implementation of RACT include the purchase of VOC nonitoring instruments, the purchase and installation of caps for all open-ended lines, the purchase and i n s t a l l a t i o n o f a compressor vent control system, and initial leak repair. The cost for initial leak repair is included as a capital cost because it is expected to be greater than leak repair costs insubsequent quarters and isa one-time cost. The basis for these costs isdiscussed below and presented inTable 5-1. 5.1.1 Cost of Monitoring Instrument The cost of a VOC monitoring instrument includes the cost of two instruments.. One instrument is intended to be used as a standbyspare. The cost of $4,600 for a portable organic vapor analyzer was

3 obtained from a manufacturer. 1 5.1.2 Caps for Open-Ended Lines

. Fugitive missions from open-ended 1ines can be controlled by installing a cap, plug, flange, or second valve to the open end. Any one of these pieces of equipment is included inthe definition of a "capNfor an open-ended line. For the purposes of this analysis, the cost of a cap for an open-ended 1 ine is based on a cost of 

### $43 for a one-inch screw-on type globe valve.' Line sizes 1 arger than 2" can be fittedwith a reducer, or as an alternative, can be equipped with a 4 blind flange at a similar cost. A charge of $18 for one hour of labor is added to the $43 as the cost for instal1ing one cap. Therefore, the total capital cost for installing a cap on an open-ended line is $61. 5.1.3 Initial Leak Repair The implementation of RACT 

### will begin with an initial inspection which will result inthe detection of leaking components. The number of initial leaks isexpected to be greater than the number found in subsequent inspections. Because in itia1 1 eak repair isa one-time cost, it istreated as a capital cost. The number of initial leaks
was estimated by multiplying the percentage of initial leaks per component type by the number of components inthe model plant under consideration. The repair time for fixing leaks is estimated to be 16 hours for a pump seal, 1.13 hours for a valve, and 40 hours for a compressor seal

# ." l4 These requirements are presented inTable 5-2. The initial repair costs given inTable 5-3 were determined by taking the product of the number of initial leaks, the repair time, and the hourly 1 abor cost of $18. 5.2 BASIS 

### FOR ANNUAL COSTS Annual costs represent the yearly cost of operating a leak detection and repair program and the cost of recovering the initial capital investment. This includes credits for product saved as the result of the control program. The basis for the annual costs isgiven inTable 5-4.

### 5.2.1 Leak Detection Labor The implementation of RACT 

### requires visual and instrument monitoring of potential sources of fugitive VOC 

### emissions. The monitoring 1 abor-hour requirements forRACT 

### are presented in

### Table 5-5. 

### The labor-hour requirements were calculated by taking the product of the assumed number of workers to monitor a component (1 for visual, 2 

### for instrument), the time required to monitor, the number of components in a model plant, and the number of times the component ismonitored each year. The monitoring times for the various components are 0.5 minute for visual inspection, 1minute for valves, 5 

### minutes for pump 

### and compressor seals, and 8 

### minutes for re1ief valves.' Monitoring labor costs presented in Table 5-6 were calculated based on a charge of $18 per hour. 5.2.2 Leak Repair Labor Labor isneeded to repair leaks which develop after initial repair. The estimated number of leaks and the labor-hours required for repair are given in Table 5-5. The repair time per component is the
same as presented for initfa1 leak repair. Leak repair costs presented in Table 5-6 

### were calculated based on a charge of $18 per hour. 5.2.3 Maintenance Charqes and Miscellaneous Costs The annual maintenance charge for caps,is estimated to be five percent of their capital cost.'' Annual maintenance costs i

### nclude pump 

### seal replacement costs at $140 per pump seal repair.14 The annual cost of materials and labor for maintenance and calibration of monitoring instruments is estimated to be $3000.11y12y13 

### An additional mi

### scel1aneous charge of four percent of capital cost for taxes, insurance, and capital related associated administrative costs is added for the monitoring instruments and caps. 5.2.4 Administrative Costs Administrative and support costs associated with the implementation of leak detection and repair are estimated to be 40 

### percent of the sum of monitoring and leak repair labor costs. The administrative and 

### support costs include record-keeping and reporting requirement costs.Capital Charges The lifeof caps for open-ended lines isasswed to be tenyears and the life of monitoring instruments isassumed to be sixyears. The cost of repairing initial leaks was amortized over a ten-year period since it isa one-time cost. The capital recovery cost isobtained from annualizing the installed capital cost for control equipment. The installed capital cost is annualized by using a capital recovery factor (CRF). The CRF isa function of the interest rate and useful equipment lifetime. The capital recovery can be estimated by mu1tiplying the CRF

### -by the total installedcapital cost for the control equipment. This equation for the capital recovery factor is:

CRF = i(1

### + i)" 

### (1 

### + 

## 11"- 1 where i = interest rate, expressed as a decimal n = economic lifeof the equipment, years. The interest rate used was ten percent. The capital recovery factors and other factors used toderive annualized charges are presented in Table 

### 5-4. Recovery Credits The reduction of VOC fugitive emissions results insaving a certain amount of VOC which would otherwise be lost. The value of this VOC isa recovery credit which can be counted against the cost of
a leak detection and repair program. The recovery credits for each model plant are presented inTable 5-5. The VOC saved isvalued in June 1980 dollars at$192/Mg, using a price of 40~/~allon~~ of LPG and a specific gravity of 0.55.'~ The methane-ethane saved isvalued in June 1980 dollars at$61/Mg, using a price of $1.46/11cf1' and an assumed composition of 80% methane and 20%ethane at standard temperature and pressure. An example calculation of product recovery credits is presented inTable 5-7 based on Model Plant B. Model Plant recovery credits are summarized inTable 5-8. 5.3 EMISSION CONTROL COSTS OF RACT This section presents the emission control costs of implementing RACT for each of the three model plants. Both the initial costs and the annualized costs are included. 5-45.3.1 Initial Costs The cost of initially implementing RACT consists of capital costs and initial leak repair. The cost of $9,200 for two monitoring instruments isthe same for all model plant sizes. The capital costs for caps for open-ended lines are annualized on the basis presented inTable 5-4. 5.3.2 Annualized Costs The annualized RACT control costs includes the initial leak detection repair costs, annual leak detection cost, and product recovery credits, as previously discussed. Tab1e 5-9 presents the annualized costs for the model plants. The net annualized costs to implement RACT range from $3,300 for Model Plant A toa cost savings of $17,000 for Model Plant C. 5.4 COST EFFECTIVENESS OF RACT Cost effectiveness isthe annual cost per megagram of VOC controlled annually. The cost effectiveness of RACT for each model plant isthe net annual cost for implementing RACT divided by the emission reduction achieved under RACT. The cost effectiveness of implementing RACT forthe modei plants ispresented inTable 5-9. The cost effectiveness for Model Plant A is$140/Mg VOC reduction, and a cost credit of $28/Mg and $74/Mg for Model Plants B and C, respectively. The cost effectiveness for each individual component covered by RACT ispresented inTable 5-10 based on Model Plant 6. The cost of a monitoring instrument cannot be attributed toany s ngle type of component since a11 components are monitored by the instrument

# . Therefore, the cost for each component does not inc ude the cast of the monitoring instrument. The instrument cost is ncluded, however, inthe model plant cost effectiveness. 5.5 ANALYSIS OF COMPRESSOR VENT CONTROL SYSTEM COS The cost to install a compressor vent control system isdependent upon several factors: (1) the type of compressor (reciprocating, centrifugal), (2) the presence of an existing VOC control debice (flare, process heater), and (3) the type of process fluid being compressed (wet gas or natural gas liquids). Product recovery credits
are not included inthe compressor vent control system cost analysison the assumption that recovered emissions would be flared. However, the recovered emissions could be routed toa process heater resulting ina credit for the captured emissions at their fuel value. The type compressor is important because reciprocating compressors may require additional control equipment toensure the safety of the vent system. A1so, reciprocating compressors would require instrumentation for the purge gas system. Hence, the control costs for a reciprocating compressor are treated separately from a centrifugal compressor. The vent control system relies upon the venting of captured emissions toa VOC control device; therefore, inthe absence of an existing control device, additional costs would be incurred. Further, the individual compressor control costs are dependent upon the number of compressors per plant due tofixed and variable costs associated with the vent control system. Capital and annualized costs of the compressor vent control system are presented inTable 5-11. The cost effectiveness of the vent control system isdependent upon the factors previously discussed plus the service a compressor is in. The compressor emission factor presented inTable 2-1 isbased on compressors innatural gas liquids (NGL) and wet gas service. Individually, these emission factors are 0.7 Mglyr for wet gas service compressor seals and 5.5 Mg/yr for natural gas liquids service compressor seals. Table 5-11 also presents the cost effectiveness of compressor vent control systems under the scenarios discussed.Table 5-1. CAPITAL COST DATA (June 1980 dollars)

1. Monitoring Instruments 2 instruments (Foxbgro OVA-108) O $4,6001 instrument Total cost is $9,20O/plant 2. Caps for Open-Ended Lines Based on cost for 5.1 cm screw-on gate valve, rated at 17.6 kg/cm2 (250 psi) water, oil, gas (w.o.gt) pressure. June 1981 cost is$46.50b, June 1980 cost is

# 8 percent less at $43. Retrofit installation = 1hour at $18/hour 

# . Total cost is $6l/line. 3. Compressor Seal Vent Control System A. Centrifuqal Compressor Seal P ipi nqe
5m 2.5cm pipe @$2.82/m $ 14.10 

### 5m 

### 5.lm pipe @ $6.50/m 32.50 1 5.lcm x 2.5cm tees 

### O $8.16 8.16 1 2.5cm block valves @ $24.63 24.63 1 2.5cm elbows 

### O $6.22 6.22 1 pressure a1arm @ 9.90 9.90 Total manifold pi ping 

## $96

,Labor

10m of pipe = 0.33 hr for installation 30m/hr/crew 0.25 hr for set-uplbreakdown 0.5


## - hr for fabrication 1.08 hours/crew 1.08 crew hrs. x

# crew x $18.00/hr =

Subtotal $ 154 Contingency 

### - 15 Total 

## $170 f 

### - B. Reciprocatinq Compressor Seals COSTS FOR EACH COMPRESSOR SEAL Incremental Cost for Double Distance Piece $2,500 Contingency 250

Total $2,750Table 5-1. CAPITAL COST DATA (June 1980 do1lars) (continued)

Distance Piece Pipi nq

. 

### - Material 2.5cm piping

## - 31m @ $2.821111 $ 90 2.5cm check valve 

## - 1 

### 0 $80 80 2.5cm block valve 

## - 2 

### 0 $25 50 Mi sc. Flanyes, Fittings, etc. Labor Subtotal Contingency Total
FIXED COSTS Instrumentation for Purge Gas

- Materia1 Oi1 Seal Pot Supply Regulator 350 2.5crn Block Valve 

## - 2 @ $25 5 0 2.5cm Piping

## - 8m O $2.82/rn 20 Misc. Flanges, Fittings, Etc. Labor $ 550 Subtotal Contingency Tota 1
C. Flare Cost of Flare Contingency 667 Total

### Table 5-1. 

### CAPITAL COST DATA (June 1980 do1lars) (concluded)



### D. Piping 

### to Flare

. - 

### Material Inlet line from ~orn~ressor 

### to Flare

# - lOOm 

### of 5.

### lcm pipe @ 

### $6.50/m Ruptured disk and 

### holder Misc. Flares, Fittings Misc. Costs for Pipe Supports

Labor Subtotal $3,350 Contingency Total

a~ne instrument used as 

### a spare. Cost is based on Reference 1. 

### b~eference 2. 

### 'cost adjustment based 

### on the economic indicators for pipe, valves, and



### fittings in April 1980 (final) vs. April 1981 (preliminary). Reference 3.

f~ef erence 8.Table 5-3. INITIAL LEAK REPAIR COSTS (June 1980 do1lars)

Initial Repair Costs Initial Annualized Repgir For Model Unitsa Costs for Model Units Source type A B C A B C Valves 920 2,700 9,200 210 620 2,100 Re1i ef Val vesC 0 0 0 0 0 0 Compressor Seals 680 2,000 6,800 160 460 1,600 Pump Seals 200 580 2,000 46 130 460 TOTAL 1,800 5,300 18,000 420 1,200 4,200 aFrom Table 5-2, Labor Hour Requirements for Initial Leak Repair. Cost =

hours 

### x $18.00 per hour. b~nitial annualized repair costs for model units = Initial repair cost

### x capital recovery factor x 1.4. The capital recovery factor (CRF) for model units isdetermined through the equation:

where 

### n = 10 years and-i = 10 percent. Therefore, the CRF = 0.163. '~ecauseof safety requirements, these leaks are corrected by routine

maintenance at no additonal 1 abor requirments. Reference 9.Table 5-4. BASIS FOR ANNUALIZED COST ESTIMATES

Capital recovery factor for capital charges o Caps on open-ended lines 0.163 x capitala o Monitoring instruments 0.23 x capitalb Annual maintenance charges o Caps on open-ended lines o Monitoring instruments o Replacement pump seals Annual miscellaneous charges (taxes, insurance, administration) o Caps on open-ended lines 0.04 x capitalC o Monitoring instruments 0.04 x capitalc Labor charges $18/hourf Admini strati ve and support costs 0.40 x (monitoring + for implementing leak detection repair labor)c and repair Annualized charge for initial (estimated number of

leak repairs leaking components per model unit x repair time) x $18/hrf x 1.4c x 0.1639 Recovery credits o Nonmethane-nonethane hydrocarbons (VOC) $1921~~~ o Methane-ethane 861 /Mgl

aTen year life, ten percent interest. Reference 11. bSixyear life, ten percent interest. Reference 11.

C;Reference 11. dIncludes materia1s and labor for maintenance and calibration.

Reference 11. Cost index = 242.7/209.1. References 12 and 13. eReference 14. f 'From Table 5-2. Includes wages plus 40 percent for labor-related

administrative and overhead costs. Cost (june 1980). Reference 4. '~nitialleak repair amortized for tenyears at ten percent interest. hBased on LPG price of 40+/gal Ion for June 1980 and specific gravity of

0.55. References 15 and 16. i Based on natural gas price of k$1.46/Mcf for June 1980 and assumed composition of 80% methane and 20%ethane at standard temperature and pressures. Reference 17.Table 5-6. ANNUAL LEAK DETECTION AND REPAIR COSTS~ (June 1980 do1lars)

Leak Detection Costs Repair Costs For Model Units For Model Units Source type A B C 

### A B C Valves 590 1,800 5,900 940 2,900 9,400 Re1 ief Valves 7 7 i30 7-70 

## ob ob ob Compressor Seals 23

. 72 230 270 790 2,700 Pump Seals 41 130 390 230 680 2,300 TOTAL 730 2,200 7,300 1,400 4,400 14,000

a~rcm Table 5-5, Annual Leak Detection and Repair Labor Requirements for RACT. Cost = hours x $18.00 per hour. b ~ e c a u s e o f safety requirements safety re1iefvalve leaks are repaired by

routine maintenance at no additional cost. Reference 9.I Table 5-7. EXAMPLE CALCIJLATION OF PRODUCT RECOVERY COST CREDITS FOR MODEL PLANT B

Recovered Elnissions (rlq/yr)

### a Recovered Product Value ($/yr)b Component Type VOC Methane-ethane VOC Methane-ethane Total

Valves Re1iefvalves Open-ended lines

in Compressor seals
A UI Pump seals


### TOTAL 71 105 13,700 6,400 20,100 aFrom Table 4-3. b~ased on an average price of $192/Mg for VOC and $61 for methane-ethane. (See footnotes i and 

### j in Table 

### 5-4).

### Table 5-9. ANNUALIZED CONTROL COSTS FOR FIODEL 

### UNITS (thousands of June 1980 

### do1lars)
Model Plant Cost Item A B 

### C


### Annualized Capital Costs A. 

### Control Equipmenta 1. 

### Monitoring Instrument 2. 

### Caps forOpen-Ended 

### Lines B. 

### Initial Repairsb 

### Operating costsC A. 

### Maintenance Charges 1. 

### tlonitoring Instrument 2. 

### Caps for Open-Ended 

### Liaes 3. 

### Replacement Pump Seals B. Mi

### scel1 aneous Charges (taxes insurance, administration) 1. 

### Monitoring Instrument 2. 

### Caps forOpen-Ended Lines C. 

### Labor chargese 1. 

### Monitoring Labor 2. 

### Leak Repair Labor 3. 

### Administrative and Support Total Annualized Cost Before Credit Recovery Credi

### tsf 

### Net Annualized Cost VOC 

### Emission Reduction (Flg/yr)

### 9 Cost-Effectiveness ($/Mg 

### VOC 

### Emission Reduction) (xx) = 

### cost savings

a~rom Tables 5-1 

### and 5-4. b~rorn Table 5-3. 

# asis is for cost estimates presented in Table 5-4. d~alculated as: Estimated number of pump seal leaks per year (Table 5-5) x $140.


### e~rom Table 5-6. f~rom Tab1e 5-8. g~rom Table 4-4.

### ;? 9% LCLL LL-LLLL m a u u *
C) I V)m 0 UV

C 

# - m m UI .- I Pln m V V)

w 

# -- ma u mOIY E wo .c L CLL 2; CO mm 

# -. Pln

-9 VI m h m-w L Y w m =.E
V) X Y 0 EL Pa 59 L Y VIVIC * VI

Y 0 C 

### 5

## g

'C L 0Y

ul w Cula r w vr L Y 

### ZL

0 Cb 0 wul -0 I mv ln nTable 5-11. COSTS AND .COST-EFFECTIVENESS FOR COMPRESSOR VENT CONTROL SYSTEM FOR MODEL PLANT B

Control Capital Annual Emission Cost Compressor Device Compressor CostC costd Reduction Effectiveness Typea ~resentb Service (Sl.000) (b1.000Iyr) (Hgly I.) (SIMg)
Centrifugal Yes wet gase 4.7 NGL~ wet gas NGL Reciprocating Yes wet gas 29.0 7.3 NGL

no wet gas 36.0 9.1 4.2 2,200 NGL 33.O 280

a Centrifugal compressors are driven by rotating shafts while reciprocatingcompressors are driven by shafts having a linear motion. bu~es" indicates that a control device ispresent at the plant. The cost of a control device (flare) has been added to the compressor vent control system costs for plants without an existing control device. C Costs based on Table 5-1. d Costs annualized as shown inTable 5-4. e Wet gas means field gas with an average VOC content of 10 percent by weight. fNatural gas liquids (NGL) consist of mixed liquids separated from wet gas (i-e.. liquidpetroleum gas).5.6 

### REFERENCES
Telephone conversation. Michael A1

### exander, 

### TRW, with 

### Pls. M. 

### Fecci of Analabs/Foxboro. March 23, 1982. Price of .Century Systems OVA-108 in July 1980. Telephone conversation. Michael Alexander, 

### TRW, with 

### ?lr.Harris of Dillon Supply, Durham, N.C. 

### June 17, 1981. Price of gate val ves. Economic Indicators. Chemical Engineering. Vol

# . 88 #12. June 15, 1981. p. 

### 7. Letter with 

### attachments from Texas Chemical Council to Walt Barber, U.S. 

### EPA. June 30, 1980. Telephone conversation. Michael A1exander, TRW, 

### with Danny Keith, 

### Dillon Supply Co., Raleigh, N.C. 

### June 15, 1981. Costs of valves, pipes, and fittings. Telephone conversation. Tom Norwood, Pacific Environmental Services, Inc., with 

### P. 

### Marthinetti, Ingersoll Rand. Distance Piece Price, December 8, 1982. McMahon, Leonard A., 

### 1981 Dodge Guide. Annual Edition No. 13, McGraw-Hill Publishing Co. Memorandum. K.C. 

### Hustvedt, 

### EPA, to J.F. Durham, 

### EPA. Cost basis for compressor vent control system. February 23, 1983. Letter with attachments from J.M. Johnson, Exxon Company, U.S.A., to Robert 

### T. Walsh, U.S. 

### EPA. July 28, 1977. Erikson, D.G., and V. 

### Kalcevic. Hydroscience, Inc. Organic Chemicals Manufacturing Industry. Volume 111, Report No. 

### 2: Fugitive Emissions 

### EPA 45013-80-025. September 1980. Environmental Protection Ag-ency. Control of Volatile Organic Compounds Leaks from Petroleum Refinery Equipment. EPA-45012-78-036, OAQPS No. 1.2-111. June 1978. Economic Indicators. Chemical Engineering, Vol

# . 86 #2. January 15, 1979. Economic Indicators. Chemical Engineering

### ,Vol

# . 87 #19. September 

### 22, 1980. Fugitive Emission Sources of Organic Compounds 

# - Additional Information on Emissions, Emission Reductions, and Costs. 

### EPA 450/3-82-010, Apri1 1982.15. Telephone conversation. T. Hennings, TRW, with Editor, Oilgram News. February 25, 1981. Price of LPG on June 16, 1980. 16. Nelson, W.L. Petroleum Refinery Engineering, McGraw-Hill Book Company, Inc. New York 1958, 

### p. 32. 

### 17. DOE Monthly Energy Review. January 1981. DOE/EIA-OO35(81/01). p. 88.

### APPENDIX A 

### EMISSION SOURCETEST DATAAPPENDIX 

### A EtlISSION SOURCE TEST DATA

The purpose of Appendix A isto summarize the fugitive emission test data that have been collected at six natural gaslgasoline processing plants (see Table 

### A-1) by EPA and industry. Two gas plants were tested under contract to the American Petroleum Institute (API), and four gas plants were tested under contract to EPA. All six gas plants were screened for fugitive emissions using either portable hydrocarbon detection instruments, soap solution, or both. Instrument screening (using EPA's proposed Method 21) was performed at all four of the EPA-tested plants (Plants 3, 4, 5, and 6). The instruments were calibrated with methane. Soap screening (using the method described inReference 1) was performed atthe two API-tested plants and at'three of the EPA-tested plants. Selected components were measured for mass emissions at both of the API-tested plants (Plants 1and 2) and attwo of the EPA-tested plants (Plants 5 and 6). These mass emission measurements were used indevelopment of emission factors for gas plant fugitives, which are presented in Table 2-1. A study of maintenance effectiveness at production field tank batteries was also performed by 

### API. These data are discussed in Section A.2. A.l PLANT DESCRIPTION AND TEST RESULTS One API-tested gas plant was of the refrigerated absorption type, and the other was a cryogenic plant. Descriptions and schematics of the plants are provided inReference 1. Ofthe four EPA-tested plants, the first tested was a solidbed adsorption type (Reference 2). Natural gas 1

iquids are removed by adsorption onto silica gel, then stripped from the bed with hot regeneration gas and condensed out for sales. There
were three adsorption units, of which only one was operating. This unit had a capacity of 60 MMSCFD (million standard cubic feet per day), and

### was operating between 33 

### and 55 MMSCFD during the testing period. The second unit was shut down 

### and depressurized, and therefore 

### not tested. The third unit was also not operating, but 

### itwas under natural gas pressure and was tested. The second EPA-tested plant was of the cryogenic type (Reference 3). 

### Feed gas to the plant is compressed and then chilled. Natural gas liquids are condensed out and split into two streams: ethanelpropane and 

### butane-plus. The cryogenic plant was operating at its rated capacity of 30 

### MMSCFD. The third €PA-tested plant was of the refrigerated absorption type (Reference 4). 

### There were three absorption systems for removal of natural gas liquids. The liquids were combined and sent 

### to a single fractionation train. The fractionation train separated the liquids into ethane, propane, iso-butane, butane, and debutanized natural gasoline. Testing was performed 

### on the fractionation train and on the largest absorption system. The absorption system that was tested was operating at450 

### MMSCFD, near its capacity of 500 MMSCFD. The fourth EPA-tested plant was also of the refrigerated absorption type (Reference 5). 

### ~he're were two para1lel absorption trains, and one fractionation train. Natural gas liquids were fractionated into ethane/ propane, propane, iso-butane, butane, and debutanized natural gasoline streams. The plant was operating at approximately 450 

### MtlSCFD, about half of its rated capacity of 800 MMSCFD. A 

### summary of the instrument screening data collected at the four EPA-tested plants ispresented in Table A-2. 

### A 

### summary of the soap screening data collected atthe two API-tested plants and at all of the EPA-tested plants is presented in Table A-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 of'each type of canponent tested and the percent emitting. The soap screening data are not tabulated for each plant but 

### are instead ,summarized by 

### soap score. A 

### complete tabulation of the soap screening data by plant and by soap score is provided in Reference 6. A.2 

### INDUSTRY VALVE 

### MAINTENANCE STUDY 

### The API 

### study that developed the gas plant data presented in Section also included 

### a study of maintenance. Gate valves in gas and condensate, A- 3

### service in oil and gas production field tank batteries were studied. The sources were monitored with soap scoring at intervals over a 9-month period. The results of an analysis of this data show that monthly leak
occurrence was 1.3 percent, monthly leak recurrence was 1.6 

### percent, and leak repair effectiveness was 100 

### percent

# .' These results compare favorably with the 1.3 percent monthly leak occurrence and recurrence and 90 percent repair effectiveness used to analyze leak detection and repair control effectiveness. Maintenance was performed 

### on a portion of the valves studied. The industry study results,were not specifically used here, however, because (1)

### the data were gathered in tank batteries which, based on API 

### data, appear to have different leak characteristics, (2) 

### very few valves were studied (25 

### total data points), and (3) 

### a soap score value of 3was used todefine a leak rather than a meter reading 

### of 10,000 ppm.

### Table A-1. 

### GAS PLANTS 

### TESTED FOR 

### FUGITIVE ENISSIONS~


### Data Plant col1

### ecti

### on Plant process Principal screening

No. sponsor tY Pe method(s) used

- - - 

### 1 AP

### I Refrigerated Absorption Soaping 2 AP

### I Cryogenic Soaping 3 

### EPA 

### Adsorption Instrument, Soaping 4 EPA 

### Cryogenic Instrument, Soaping 5 

### EPA 

### Refrigerated Absorption Instrument, Soaping
6 

### EPA 

### Refrigerated Absorption Instrun~ent b


### a~ef erence 6. 

### b~ess than 50

### components were soap screened atplant #6.--- ------ Table A-2. INSTRUMENT SCREENING FOR EPA-TESTED GAS PLANTS~

Flanges and

Re1ief valves Opcn-ended 1ines Ca~pressor seals Puclp seals connect ions No. Percent No. Percent No. Percent No. Percent No. Percent Tested 10.000pp11v Terted 10.000pp1:1v Tested 10.000pptnv Tested 10.000ppn1v Tested 10.000ppn1v

-----

. .----- --- -.--- .----- . - - --- --

10 90.1) 45 15.6 0 0.0 1 0.0 223 5.4..... TableA-3. SOAP SCREENING DATA FOR API-TESTED AND EPA TESTED GAS PLANTS~

Relief valves

-...--..... ,I of Nu111her Total

"III(lode5 0.1,it.j II.U.I two 41'1-tested planls ~MI foul- EPA-tested plants. Reference 6.A.3 REFERENCES FOR APPENDIX A
1. Eaton, W. S., et a1

# . Rockwell Corporation. Fugitive Hydrocarbon Emissions from Petroleum Production Operations. API Publication No. 4322. March 1980. 2. Harris, S. E., Radian Corporation. Fugitive VOC Testing at Houston Oil and Minerals Smith Point Plant. U.S. EPA, ESEDIEMB Report No. 80-OSP-1. October 1981. 3. Harris, G. E., Radian Corporation. Fugitive VOC Testing at the Amoco Hastings Gas Plant. U.S. EPA, ESED/EMB Report No. 80-OSP-2. July 1981. 4. Harris, G. E., Radian Corporation. Fugitive VOC Testing at the Texaco Paradis Gas Plant, Volume I and 11. U.S. EPA, ESEDIEMB Report No. 81-OSP-7. July 1981.
5. Harris, G. E., Radian Corporation. FugitiveTest Report at the Gulf Venice Gas Plant, Volume I and 11. U.S. EPA, ESEDIEMB Report No. 80-OSP-8. September 1981. 6. DuBose, D. A,, J. I. Steinmetz, and G. E. Harris, Radian Corporation. Data Analysis Report: Emission Factors and Leak Frequencies for Fittings inGas Plant. Final Report. U.S. EPA, ESEDIEMB Report No. 80-FOL-1. July 1982. 7. Memorandum, Hustvedt, K.C., EPA to Durham, J.F., EPA "API/Rockwell Maintenance Data". December 9, 1982.APPENDIX 8 MODEL PLANTSAPPENDIX B MODEL PLANTS

The purpose of this appendix isto present mode1 plants. The model plants were selected to represent the range of processing complexity in the industry. They provide a basis for determining environmental and cost impacts of reasonably avai 1 able control techno1ogy (RACT)

# . B.l DEVELOPrIENT OF MODEL PLANTS There are a number of different process methods used at gas plants: absorption, refrigerated absorption, refrigeration, compression, adsorption, cryogenic

# - Joule-Thompson, and cryogenic-expander

# .' Process conditions are expected to vary widely between plants using these different methods. However, available data show that fugitive emissions are proportional to the number of potential sources, and are not related to capacity, throughput, age, temperature, or pressure.2 Therefore, model plants defined for this analysis represent different levels of process complexity (number of fugitive emission sources), rather than different process methods. Inorder to estimate emissions, control costs, and environmental impacts on a plant specific basis, three model plants were developed. The number of components for each model plant isderived from actual component inventories performed atfour gas plants. Two of the plants
were inventoried during EPA testing, and two were inventoried during testing by Rockwell International under contract to the American Petroleun Institute. The model plants are based on four rather than on all six of the plants presented inAppendix A because two of the plant visits did not obtain information on vessel or equipment inventories. Nevertheless, the four plants for which vessel and equipment inventory data were obtained are representative of the range of plant complexity found in the natural gas processing industry.

### Cmplexity of gas plants can be indexed by means of calculating ratios of component populations to a more easily counted population. For gas plants, number of vessels appears to be best suited to this need. Example types of equipment included and excluded in

### vessel inventories are listed in Table B-1. 

### The vessel inventories for the industry-tested gas plants are taken from the sitediagrams and descriptions provided in the API/Rockwe?1 

### reports5and the vessel inventories from the EPA-tested plants were performed during the testing. These vessel inventories and the component inventories are shown in Table 3-2. 

### Table B-3 

### shows the ratios of numbers of components to numbers of vessels atthe four gas plants. The mean and standard deviation of the four ratios is also shown in Table B-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 cf' 

### \~essels is based on the vessel inventories shown in Table B-2. 

### The low end of the range, 10 vessels, is approximately equivalent 

### tothe number of vessels that are accounted for in one of the three process trains at the EPA-tested plant A. 

### It is assumed that there are existing gas plants with 

### a similar configuration to the EPA-tested plant A, 

### that have only one process train. The high end of the range, 100 vessels, is slightly larger than the number of vessels at the industry-tested plant A. 

### Since this was 

### the largest of the plants tested, itappears reasonable to use this as a guide in calculating the number of 

### components at the largest model plant. The middle model plant has 30 

### vessels. This is approximately the same number of vessels as at three of the four plants tested, and appears that itmay be representative of a common gas plant size. The three model plants and their respective number of components are shown in Table B-4.Table B-1. EXAMPLE TYPES OF EQUIPMENT INCLUDED AND EXCLUDED INVESSEL INVEN-TORIES FOR MODEL PLANT DEVELOPMENT

Included Exc1 uded
1. Absorption/Desorption Units a. Absorbers 1. Compressors, Pumps b. Scrubbers c. Dehydrators d. Stabi

### 1izer e. Stripper 2. Piping Systems a. Manifold/header systems b. Valves, flanges, connections, c. Meters, gauges, control equip etc. ment 2. Adsorption Units 3. Glycol, 1 ube oi1, water storage 3. 

### Distillation/Fractionation Units a. Demethanizer b. Deethanizer 4. Any equipment associated with swe or sulfur recovery processes etening

c. Depropanizer d. Splitter e. Flash Drum/Tank f. Stills
4. Heating/Cooling Units a. Heaters b. Chillers c. Heat Exchangers d. Reboilers e

# . Condensers f. Coolers 5. Drums/Tanks a. Separator b. Surge c. Gas d. Oil e. Accumulator f. KnockoutTable 8-3. RATIOS OF NUMBERS OF COMPONENTS TO NUMBERS OF VESSELS~

€PA Tested Plants Industry Tested Plants Average .Standard Deviation A B A B Ratio of Ratio

Valves 16.4 18.0 37.0 30.5 25.5 9.9 Re1 ief Val ves 0.5 0.4 0.2 0.3 0.4 0.1 Open-Ended Lines 2.0 2.1 7.4 6.9 4.6 3.0 Compressor Seal

### s 0.0
w 

## & Pump Seals 0.0 Flanges and 49.4 48.0 170.8 121.2 97.4 59.7 Connections
a~ased on data presented inTable 8-2.Table 8-4. FUGITIVE VOC EMISSION SOURCES FOR THREE MODEL GAS PROCESSING PLANTS

Number of components Flodel plant Node1 plant Model plant A B C component typea (10 vessels) (30 vessels) (100 vessels)
Valves Re1 ief Valyes Open-Ended Lines Compressor Seals Pump Seals Fl anges and Connections
a~umber of Components based on average ratios presented inTable 

### 8-3.B.2 

### REFERENCES


### 1. Cantrell

## ,A. 

### Worldwide Gas Processirig. Oi

### 1 and Gas Journal

## , July 14, 1980. p. 

### 88. 

### 2. Assessment of Atmospheric Emissions from Petroleum Refining

## , Volume 3, 

### Appendix B. 

### EPA 

### 600/2-80-075c, April 1980. Pages 266 

### and 280. 3. Hustvedt, K.C., memo toJames F. 

### Durham, Chief, Petroleum Section, OAQPS, U.S. EPA. 

### Preliminary Test Data Summaries of EPA Testing atHouston Oil and Minerals Smith Point Gas Plant and Pmoco Production Hastings Gas Plant. March 19, 1981. 4. Eaton, W.S., Rockwell International

## , letter to

### D. Markwordt, OAQPS, U.S. EPA. Component Inventory Data from Two 

### API-Tested Gas Plants. September 11, 1980. 5. 

### Eaton, W.S., eta1

# .: Fugitive Hydrocarbon Emissions from Petroleum Production Operations. API Publication No. 4322. March 1980.

### APPENDIX C PUBLIC COMMENTSThis appendix presents the public comments received by the EPA on the draft CTG. Table C-1 summarizes the respondents and lists their correspondin number used to identify commenters inthe Summary of Public eomments and Responses presented inAppendix 

### D.

Table 

### C-1. LIST OF COMMENTERS ON THE

DRAFT CTG FOR NATURAL GASIGASOLINE PROCESSING PLANTS

Comment Date

Number Company Commenter of Comment 1 ARC0 Oil & Gas Company L.E. Bartlett March 9, 1982 2 Ci ties Service Company D.V. Trew March 9, 1982 

### 3 Columbia Gas System M.J. Atherton March 9, 1982 Service Corporation 4 Southern California G.M. Gardetta March 9, 1982 Gas Company 5 Michigan Consolidated S.E. Kurmas March 10, 1982 Gas Company 

### 6 Texas Oil & Gas Company J.W. Boley March 10, 1982 

### 7 Texas 

### AirControl R.R. Wallis March 10, 1982 Board 

### 8 American Petroleum C.T. Sawyer March 11, 1982 Institute 

### 9 Michigan Wisconsin 

### J.V. Mehta March 11, 1982 Pipe Line Company 10 Chevron R.W. Kreutzen 

### arch 12, 1982 

### 11 Anoco Production R.E. Mahaffey March 18, 1982 Company 12 Flour Engineers and S.J. Thomson March 22, 1982 Constructors, Inc.ARCO Oil and Gas Company Engineer~ng Deparlment Post Office 30x 2819 Callas. Texas 75221 i?!cphone214 557 5'5 1 Luther E. Bartlert ?.lanager O~erations ana Ena~noer!:? 5e- :%,-.JC .--..

Yr. Fred Porter Emission Standards and Engineering Division (XI-13) U. S. Environmental Protection Agency Research Triangle Park, North Carolina 27711

Be: 3raft Control Techniques Guideline (CX) for Control of Volatile Organic Compound (VOC) Equipment Leaks from Natural GasjGasoline Processing Plants

Dear Hr. Porter:
ARCO Oil and Gas Company, a Division of Atlantic Richfield Company, appreciates the opportunity to offer comments to the U. S. Environmental Protection Agency (EPA) regarding the Federal Register Notice (47 FR 3403, January 25, 1982) releasinq the draft control techniques guideline (CTG) document for control of volatile organic compound (VOC) emissions from equipment leaks in natural gas/gasoline processing plants.. .MCO Oiland Gas Company has for many years been actively involved in the production of natural gas and gasoline. We

' are particularly interested in the subject CTG which will directly affect our Company.
A task force was formed by American Petroleum Institute (MI) to consider the VOC emissions from natural gas/gasoline processing plants. ARCO Oiland Gas Company representatives participated in the preparation of comments with respect to the subject CTG on VOC emissions submitted on behalf of API, and we are in full agreement with the concerns addressed therein.
While we are infull agreement with MI'Sconcerns, we would like to emphasize .9PIfs comments regarding "Chapter 5, Control Cost Analysis." Implementation of reasonably available control technology (RXCT) will have a significant economic impact on our operations. Several incorrect assumptions appear to have been made when developing the economic analysis for the CTG document to be used in evaluating the RACT for VOC equipment leaks in gas plants. As a result the economicYr. Fred Porter Emission Standards and Engineering Division (?ID-13) 2. S. Environmental 2rotection Agency Yarch 9, 1982 ?age Two

analysis supporting this guideline suggests control of the fugitive VOC emissions will have a direct economic benefic to the operations of ARC0 Oiland Gas Company, thus justifying the proposed RACT. !te do not agree with mny gf the assumptio.ns and, therefore, do not feel the RACT has been justified. For example, the CTG economic analysis equates "front-end costs" with "capital costs" (comment 13). Capital cost has a specific economic definition and does not include operating costs. In addition, the cost analysis for the labor associated vith leak detection severely underestimates the actual cost (comment 18). A complete cost estimate must include the front-end set-up costs, depreciation on the eaui?nent, additional 

### - and other~ise unnecessary

## - ?latfonk for each inaccessible source, and maintenance on the VOC analyzer. .Although the conclusion of the draft CTG's economic analysis is that the oil and gas industry has lost significant revenue from not controlling fugitive 70C emissions (excepting the sinallest plants), ue feel the costs of implementing and maintaining the recommended practices are much greater than estimated with little if any improvement in the air quality. Consequently, we believe a net long-term loss will result from the use of the proposed RACT. This is of specific concern since the draft CTG, although published as only a guidance to the states, will serve as the basis formany of the state regulations.
We appreciate your.consideration of our concern. If it would be helpful, we would welcome an opportunity to further discuss our concerns associated with implementing the proposed RACT to control VOC emissions from natural gas/gasoline processing plants. Sincerely,

A

~dther E. BartlettCITIESSERVICEC~MPANY BOX 300 TULSA, OKLAHOMA 75102 

### March 9,1982

Emission Standards & 

### Engineering Division (MD-13) 

### Environmental Protection Agency Research Triangle Park,NC 27711 Attention Mr. Fred Porter Dear Mr. Porter: Cities Service Company is 

### the owner and operator of numerous gas processing plants and as such is concerned with 

### the proposed control technique guideline (CTC)I1Control of 

### Volatile Organic Compound Equipment Leaks from 

### Natural Gas/Gasoline Processing plant^.'^ 

### Notice of the release of this document for review was made in the Federal Register, Vol. 47,

### No. 16, January 25, 1982. On page 3-3 

### of the report, 3.1.2.2 Compressors, it is stated that the control of VOC leaks from compressor seal areas can be controlled by enclosing the compressor seal area or distance piece, and piping the emissions to a suitable combustion device. This control device could exert considerable back pressure on the 

### compressor seal. Many of the compressor seals in our gas processing plants are not designed to operate with back pressure and the use of the control device recommended can 

### cause severe mechanical problems and poten- tially a safety problem. We have no knowledge of any work- able control device and we recommend that the use of this type of a control device for gas plant compressors not be considered. The estimated reductions in emissions achievable are based on data from six processing plants. This is a very limited data base considering that there are approximately 800 plants in operation. The technology of each plant is dependent upon the age of the plant, type of process, market conditions, and the nature of the gas processed. The extrapolation of the limited data based on "Number of Vessels" is not statistically valid. Cities Service Company appreciates the opportunity to make these comments and trusts that they will be considered by the agency in order to make the final control technique guideline a more meaningful and workable document.



### -Sincerely,
'.. 

### C-5 

# ,< '. /

. '%,

. \ '-. 1.- 

### D. V. .Trew Manager, Environmental SenicesmI.. m



### March 9, 1982

Emissions Standards and Engineering Division (MI-13) 

### Environmental Protection Agency Research Triangle Park, North Carolina 27711
Dear Sirs:

### Re: ..ControlTechniques Guideline Document; Equipment Leaks From Natural Gas/Gasoline Processing Plants

Columbia 

### Gas System Service Corporation on behalf of Columbia 

### Gas System (columbiaj herewith submits comments on the above draft control techniques guideline (CTG), the release of which 

### was announced in the Federal Register of January 

### 25, 1982. Columbia 

### is one of the largest natural gas systems in the United States and 

### is composed of The Columbia Gas System, Inc., a registered public utility holdling company, a service company and eighteen operating subsidiaries. 

## he^ operating subsidiaries are primarily engaged in the production, purchase, storage, transmission and distribution of natural gas at wholesale and retail. Columbia supplies directly through 

### its retail operations, or indirectly, through other utilities, the gas requirements of about 4,200,000 customers in an area having a population of approximately l8,OOO,OOO. Columbia's service area includes large parts of the states of Ohio, Pennsylvania, Kentucky, New York, Virginia, 

### West Virginia, Maryland and the District of Columbia. Columbia serves at retail 1,890,000 customers residing in communities wid&a total population of 7,400,000.
As an owner of natural gas processing plants, Columbia has a direct interest in this CTG. Therefore, Columbia is 

### submitting the following comments.

### Emissions Standards and Engineering Division 

### (ND-13) Page 

### 2 March 

### 9, 1982

Model Plant A 

### Considerations
While the stated purpose of the CTG 

### is to provide information to state and local air pollution agencies, it 

### will 

### actually 'be used by these agencies to develop and adopt new regulatory programs for compliance with Sections 172(a)

### (2) and (b)

### (3) of the Clean Air

### Act. Thus, Columbia believes the requirements of Presidential Executive Order 

### 12291 of F'ebr~ary

### 17, 1981 

### (45 FR 

### 13193; February 

### 19, 1981) must be considered in che development of RACT 

### for natural gas/gasoline plants. Section 

### 2 of this Presidential Executive Order requires that potential benefits must outweigh costs and be maximized. In 

### this respect, EPA 

### makes no recommendations in the CTG 

### concerning the limits of applicability of RACT 

### (Reasonably Available Control Technolog;?) Co 

### natural gaslgasoline processing plants. However, the CTG 

### states that Flants of the size of the model plant A 

### will 

### incur a net annual cost for WCT of $2300, with a cost effectiveness of $115/Mg. For 

### these plants requiring conversion of pneumatic control valves from gas to air, the costs will be higher (Section 

### 5 .l.

### 5). The larger plants, model plants 

### B and C, 

### will receive a net savings ($4,200 and $24,500, respectively) and have a cost effectiveness of -$70/Hg and -$I201 Mg, respectively (Sections 

### 5.3.2 and 5.3.3)


## . Given the low 

### annual emissions of volatile organic compounds 

### (VOC), 29 Ng 

### (Table 

### 2-2), of the model plant A, 

### the annual costs and cost effectiveness for these plants dictate that these plants should not be subject to 

### the requirements of RACT. 

### Secondly, an annual emission rate of 29 "g 

### is equivalent to about 

### 32 tons/year VOC. 

### This level of enissions is less than that which.EPA 

### has defined as "significant" or 

### as a de minimis value in several regulations (for example, 40 CPR 

### ~az 

### 51, Appendix 

### 5, II.A.lO; 

### 40 CFR 52.24(f)(13);and 

### 65 FR 

### 5270542710, August 

### 7, 1980)


## . The "significant" 

### or de minimis value applicable 

### to ozone 

### is 40 tons per year of volatizorganic compounds. Finally, the smaller plants will 

### have fewer employees than larger plants. Thus, it 

### may be anticipated the proposed RACT 

### measures will 

### more severely strain their limited staff.
Based upon the above three considerations of 

### costs and benefits, emissions below "significant" or 

## - de ninimis levels and potential manpower limitations, ~olumbia recommends 

### :hat, in the.Fdissions Standards and Engineering Division (MD-13) Page 

### 3 Harch 9, 1982

CTG, plants of the size of model plant A 

### (10 vessels as defined in Appendix B) or smaller be excluded from the requirements of RACT. This exclusion, similar to the following, should be added a$ the last paragraph of Section 1.0 Introduction: Natural gaslgasoline processing plants equal to and less than the size of a model plant A 

### (LO vessels as defined in Appendix) should be excluded from the requirements for RACT. This recommendation isbased upon an analysis of costs and the low level of emissions of volatile organic compounds from such plants. Further, the CTG should point out in Section 

### 2.3 that 

### VOC emissions from the model plant A are less than those considered as "significant" or de minimis. Thus, the imposition of RACT, with its attendant costs (Section 5.0), 

### is not needed. Monitoring Instrumentation
One of the major costs for implementing RACT 

### is that for the purchase and maintenari'ce of monitoring equipment. Natural gas facilities already have portable monitoring instruments for detection.of leaks of combustible hydrocarbons as part of their safety programs. Further, this type of instrument is considerably less expensive than the monitoring instruments described in the CTG. Leak detection of combustible hydrocarbons with these instruments and knowledge of the processes before and.aftervarious components could provide an estimate of 

### VOC emissions. Use of this instrument and approach would provide the operator with a method to estimate 

### VOC emissions, to determine those components requiring repair and to measure the effectiveness of repair, but at much .less cost than the recommended type of monitoring instruments.
Columbia recommends that EPA include this type of instrument as 

### an alternative to the purchase of expensive, new instmentation for leak detection and implementing RACT.
Columbia appreciates the opportunity to comment on the CTG and trusts the above comments will be evaluated and of value to EPA.

J Xichael J. Atherton, Ph.D. C-8 Environmental AffairsC M GAROETTA E~~~ronmenlal Affairs ~arn~n~s~rator 810 SOUTH FLOWER STZEET cOS ANGELES CALIFCRNIh 90017 

# !d i SOUTH RNCALIFORNIA

## IqaS 4

MailmgAaOrc-s BOX 3249 TERMINAL AFthEX. LOS ANGELES. CALIFORNIA 90051 ,LOMPAP.!Y



### March 9, 1982



### Mr. 

### Fred Porter €mission Standards and Engineering Division (MD-13) 

### Research Triangle Park North,Carol i

### na 27711 0ear 

### Mr. Porter: Southern California Gas Comoany (

### SoCal) 

### aporeciates - . :be 

### opportunity to subnii

### t 

### the following cements on the -,nv ;!an

### mental Protection Agency's (EPA) draft control techniques guideline (CTG) document entitled "Control of VolatileOrganic Compound Equipment Leaks from Natural Gas/Gasoline Processing Plants", forreview and consideration. -

## - SoCal is

### the nation's largest natural gas distribution company. Accordingly, it 

### has a ser.ious concern regarding the applicability of the 

### proposed CTG to underground gas storage facilities. Itisnot clear from 

### the language of 

### the proposed document whether ornot the definition of a natural gas/gasoline storage operation excludes underground gas storage fields. SoCal strongly feels that a gas storageoperation should not be compared with

### conventional oi1/gas production faci1 iti

### es and gas processing plants. It

### is important to recognize that among other factors, the magnitude of 

### fugitive emissions will be dependent on the complexity and number of component processes. 

# - The liquid and gas processes performed atan underground gas storage facility are relatively few and simplewhen compared tothose ata conventional gas processing plant and oil/gas production operatiom. 

### In order to demonstrate 

### the basis for itsconcern, SoCal has provided 

### the following sumnary of the 

### facilities which could be impacted and has compared 

### these to traditional qas processing plants and oil/gas production operations. SoCal operates six underground storage fields located in Honor Rancho, Aliso Canyon, Playa del Rey

### ,Montebello, East Whittier and Goleta. The gas withdrawal capacity ranges from 1.5 billion cubic feet 

### per day to72 

### million cubic feet per day. The larger gas storage fields operate to

### meet peak winter load demand while smaller fields are

### Ltr. to F. 

### Porter dated 3/9/83 Page two usually used to

### meet daily peak load demands. Therefore, operations at SoCal's larger storage fields are seasonal compared to conventional oi1 / 

### gas production fields

### where production 

### is usuallycontinuous throughout theyear. SoCal's gas storage fields are depleted oil or dry gas fields, and any oil production 

### is obtained primarily due to re?ressurization of the 

### field to store gas. Coincident oil production from these underground gas storage fields isnot significant. The 

### gas tooil ratios in SoCal's operations range from 90,000 to 766,000 cubic feet per barrel of

### oi 1 produced. This issignificantly higher than the reported gas to oil ratio of 1,000 cubic 

### feet per barrel of oil produced from conventional oil/gas production operations. A.

### high gas tooil ratio clearly imp1ies a smaller scale of oil treatment"operations and'consequently resul

### ts in significantly lower fugitive emissions. Figure 1 (attached)represents a simplified flow sheet of 

### the gas withdrawal process in 

### a typical underground gas storage field. 

### In 

### generai

# . gas injection, withdrawal and dehydration operations are similar at a11 SoCal's storage fieldswith 

### the exception of Playa del Rey where there is no dehydration. Oi

### 1 treatment (stabi1

### ization) and oi1 /condensate storage areother operations where additional HC 

### gas isgenerated and the 

### methods of processing orhandling 

### this gas varies from field to field. At

### Montebello and Playa del Rey, this gas 

### is directly delivered into 

### the low pressure distribution ortransmission pipeline system. AtHonor Rancho, it 

### is 

### -delivered to an oil company gasoTine plant forfurther processing. AtA1

### iso Canyon, the gases arecompressed and then 

### the liquid fractions (gas01ine) areremoved in a Hydrocarbon Recovery Unit (HRU). Itis important to note that thevolume of HC 

### gases generated atoil treatment and storage operations represent only a small fraction of the total natural gas processed. To study the composition .of the aforementioned gas streams, one should refer toTable 4 

### (attached). The compositions of non-methane and non-methane 

# ' plus non-ethane 

### were obtained from actual field test data. The table also

compares SoCal's data with the average gas analysis reported in the 

### emission factor table of theAPI/Rockwell report

# - "Fugitive Hydrocarbon Emissions froKPetroleum Production Operations", March 1980. The non-methane and nonmethane plus non-ethane hydrocarbons present in SoCal's 

### wet gas range from 5.26 to 8.47 

### percent by volume and 1.54 to 2.21 percent by volume respectively. Conversely, an average composition of similar

### wet gas reported in 

### the API 

### study contains 22.93 percent by volume non-methane hydrocarbon and 18.4 percent by volume non-methane plus non-ethane HC. 

### This difference clearly indicates that fugitive emissions of reactive hydrocarbons from an underground gas storage operation are significantly lower than a conventional oil/gas production faci1i

### ty. The low concentration of non-methane ornon-methane plus non-ethane hydrocarbons in SoCal's

### wet gas 

### is not 

### mere coincidence.

### Ltr. toF. 

### Porter dtd. 

### 3/9/82 

### Page three

In a conventional oil/gas production operation the gas withdrawn is unprocessed and contains significant amounts of higher fractions of the HC 

### species containing ethane, propane, butane and 

### natural gasoiine. However, in SoCal 's operations the gas injected is commercial natural gas which only contains small amounts of higher hydrocarbons and consequently very littleof the higher hydrocarbon fractions are picked up 

### when this gas is withdrawn. Conventional gas processing plant operations on the other hand, involve removal of methane, ethane, propane and 

### butane from the balance of the species present in 

### an unprocessed natural gas. The remaining liquid is.piped 

### to refineries or chemical processing plant. Two types of gas plants are primarily u~ilized in the field today



# -- absorption and cryogenic plants. The absor2tion plant is based upon the physical principle that natural gasoline is readily absorbed into low molecular- !.,eiqht oils 

### called lean oil before absor;ltior, and fat or 

### rich oil after absorption. When the temperature of the rich oil 

### is raised and the pressure is reduced, the absorbed light hydrocarbons are driven 

### out of the oil selectively. Cryogenic gas plants operate on the basis that natural gasolines will 1

### iquify when the temperature islowered and the pressure increased. Chilling is usually accomplished by use of propane refrigerati

### on. The hydrocarbon species are selectively distilled from the cold natural gasolines. None of the processes described above fit SoCal's underground gas storage operations. Only atAliso Canyon does SoCal remove higher hydrocarbon fractions in a HRU. 

### The Hydrocarbon Recovery Unit utilizes a simple process of compression which causes liquifiable species to condense under pressure. Furthermore, at Aliso Canyon no attempt ismade to 

### separate the liquid hydrocarbon fractions as is usually done in a gas processing plant. Thus, because of the significantly fewer processing steps used in SoCal's facilities, one can only conclude that a valve count and consequently, fugitive emissions from a conventional gas processing plant will be significantly higher than SoCaI's underground gas storage fields.
CONCLUSIONS AND 

### RECOMMENDATIONS Fugitive emissions from underground storage fields operations are predominantly natural gas which contains very littlereactive hydrocarbon and the magnitude of such emissions should be significantiy lower than a conventional oi1/gas production operation 

### or a gas processing plant. Therefore, SoCal strongly recomnends that the definition of natural gas/ gasoline processing plant should be redefined 

### to exclude underground gas storage facilities. Sincerely, GMG:avs Attachments

### March 10, 1982

Emissions Standards and Engineering Division Environmental Protection Agency Research Triangle Park, Xorth Carolina 27711 Attention: 

### Mr. Fred Porter Dear Si

### r: 

### Michigan Consolidated Gas Company is a natural gas utility currently sarvicing in excess of one million residential, industrial 3nd 

### corn

### mercial customers. Although Michigan Consolidated does not 3perats any gas processing plants, as defined by your department, the operation of such plants does have an indirect impact on the cost 

### of natural gas ~o 

### our customers. Therefore, Michigan Consolidated believes that the Draft Guide1ine Series for the Control of Volati1

### e Organic Compounds Equipment Leaks from Natural Gas/Gaso'lineProcessing Plants imposes excessive financrbmi thout real izing significant air qua1ity gains



## . Michigan Consolidated dispute's the premisemade in the guidelines that Volati1 

### e Organic Compound (VOC) 1

### eaks are not being adequate1y detected by industry (Section 3.1.1

# .)


# . For economic reasons and, more importantly, safety reasons extensive precautions are taken 

### to detect and repair all but

### the most insignificant sources. A1though visual, audible, and olfactory methods are the primary safeguards, itis not uncommon to supplement these methods with oxygen and hydrogen sulfidemonitors. Sincemany of the major sources (pumps, compressors, etc.) 

### as identified in the guidelines are frequently located inside buildings where emissions are confined, early 1eak detection becomes even more important. Therefore, Michigan Consolidated be1ieves that fugitive VOC 

### emissions from natural gas processing plants are adequately controlled and further regulation would prove overburdensome. Michigan Consolidated a1so disagrees with the methods used in estimating current emissions from processing plants. Fugitive sources vary signif

## - i cantly aepending on 

### a variety of conditions


# . These include: system pressure, equipment age, climate, past maintenance, gas composition (as itaffects corrosivity) and a mu1

### titude of other factors. To assume that these emissions are simply a function of the number of valves, pumps and flanges ata facility isa gross oversimplification. A1though, the guidlines mention the fact that repairing most fugitive sources will require venting the gas to the atmosphere, they do not include this as a source in either their emission estimates 

### or in 

### the computation of recovery cost credits. Since repairing many insignif

## - icant 1 eaks will require blow down of potentially 1

### arge portions of the system, significant emission reduction benefits and recovery cost credits arequestionable.

i2ir natural gas is your nost ~conomicol ;brm of energy

. . . leas2 he1,cc9nserL.e ir.

### March 10, 1982 Emissions Standards and Engineering Div. Attention: Mr. Fred Porter Page Two



### In conclusion, Michigan Consolidated believes that regulations resulting from the implementation of these draft guide1ines \will be economically burdensome to our natural gas customers whi1

### e resulting in insignificant improvements to air quality. Therefore, we request that the cost/benefit aspect of these regulations be carefully reconsidered, and 

### that the deadline for corments be 

## extended allowing industry additional time 

### to further analyze these complex regulations. Sincerely

### ,

Steven 

### E. Kurmas Senior Environmental Engineer

SEK/

### slTEXAS OIL 6 GAS CORP.
-'3EiiT'< .JN!3N -3\NEq DALLAS. TEXAS 75201

JACK W. BOLEY
UbNbGER YFm L ENVIRONMENTAL ACTAIFIS



### Dear Mr. 

### Porter:
Texas Oil & 

### Gas Corp. is 

### an independent energy company that operates 

### 18 naturai gas processing plants and is processing approximately 811 million cubic feet per day (MMCFD) 

### of natural gas is responding to the referenced document. The processing is accomplished in various types of pimts, such as, turbo-expander cryogenic,refrigerated lean oil,and propane refrigeration. We believe we are quite experienced in the processing of natural gas. It is the opinion of Texas Oil & 

### Gas Corp. that prudent operations eliminat' any fugitive emissions associated with the plant processing of natural gas. The information presented in the document indicate vwious emission factors for various segnents of' a natursl gas processing slant. It is apparent that much of the informationwas ob~ained lrcm 

### a Draft Final report by Radian Corp;September 1981. Since this report is not available to Texas Oil & 

### Gs Corp. 

### here is no way to dispute or support the data baszd on the reference.
In 1979, the Environmental Protection Agency 

### (EPA;sublishecl %uidence for Lowest Achievable Emission Rate from

### -18Major Stationwy Sources of Particulates. Nitrogen Oxides,Sulfur Dioxide,or Volatiie Orgnic Cmpound~,~~ EPA-450/3- 

### 79-024. No where in that report were natural gas/gzsoline piants mentioned as amajor source. Texas Oil & 

### Gas Corp. believes the regulation of Tugitive emissions Trom natural gas plants will not prsvide a significant benefit to the environment.
Texas Oil & 

### Gas Corp. believes that there are 

### a number of flaws in the docment. The flaws as perceived by 

### T2xas Oil & 

### Gas Corp. 

### will be discussed section sy 

### section.

### Nr. 

### Fred Porter March 10, 

### 1982 Page 2



### Secsion 2.2.4 

### Pressure Relief Devices This section discusses the possibie emissions ?om rei ,,er" valve seais. No where in this section,or in is doclmenc is the ,considerationof a cLosea system discussea. 

### In mr.y 

### instznces

. 

# - > 

### pressure relis9 valves zre vented tc 3 31zct I~XE

### ~kere xy volatile orgw,ic ccmpounds (VOC)are cornbusted kdsno VOC

3. 

### wouid %e.detecteaarxxd these-devices. :rcm 

### 3perzsional xmd~;oin: seais or more properly gressure relief valve seats connoc be allowed to leak.

Secticn 2.2.7

### Gas Operatsa Zontrol Valves The ins~rment gas use5 

### for 

### process zon~rol13 

### yedcmlnizt3ly

- 

### ine~hane maschane. Neizner methane nor ethaEe 

### weincludea in fhedefinition of volaciie crgaic compour,ds,consequently there is no enviromentai impacS. 9nly 

### trxe anom~s sf my VOC 

### my be encountered. Section 2.3 SASELINE FUGITIVE 

### VOC EMISSIONS This section makes an assumption that all natural gas piants will experience the saiie type of 

### VOC emissions. The document fails to differ between the type of plant, i.e. cryogenic, lean- oil,or refrigeration, size of plant (forboth gas and liquids), and the gas composition, i.e. the amount of light hydrocarbons, will have a significant impact on fugitive emissions. Another factor that 

### was not discussed 

### was the total mix of fluids at the plant. Various hydrocarbons,amines,glycols, slop and iube oils,and condensates can be encountered at 

### any or sll natural gas 

### plants. Plats that handle the fractionated hydrcarbons by 

### tank or pipeline will also have significally aif'feren~ fugitivemissions. Section 

### 3.1.1 Individual Ccmponent Survey The monitoring for this studywas accomplished using of 

### a portable hydrocarbon analyzer. The data obtained using the portable hydrocarbon analyzer was used to develop the emissions factors. These emission factors we rates aeasured in &/Day. Texas Oil & 

### Gas Corp. questions how the 

### EPA went from a concentration,the measurement frmthe portable hydrocarbon analyzer, to the emission factorwithout measuring m 

### actual flow rate. In order to accept the emission factors 

### as stated, the method for obtaining the emission rates must be described inmore detail.

### Mr. 

### Fred Porter ~Wch 10, 1982 Page 

### 3 Section 3.1.2.2 Cb nrn~ressors The venting of fugitive eaissi~ns by ticlosing the zsmgressor seals is nct cost effective ,-adis also apwzcicna- - . nazard. 

### At the present time these missions swe allcwed tc

### disiaate 

### in the atmosphere,by enclosing a d 

### venting these missions, cne VOC air mixture would reach expiosive limits, thus crea~ing a 

### serious explosion potential. Texas Oil ii 

### Gas Csr?. questions the ability of a system,&s 

### described In this seccicr, co achieve a 15 to 20 

### ?gig pressure. It seems sgpzez shzi 2 

### sufficient exit rate would be required to cbtaiz :his ?resswe.

.

### -
.. 

### These operations may reach m 

### q~eretionzi ICGL-:oruim 

### iihere :he vent systemwill never reach the 15 to 20 

### psi5 release p-ess~re, thus trapping the VOC in the vent systm. This section mentions a wcmbus.tion devicetf to haale shese 

# -.

7 

### emissions. At these low pressures, 

### 15 to 2C 

### ?sig,a :;are is not sa2e for simiisr reason as 

### mentionee above. :/e :re 

### .zaw=e

.

### - of any type of combus~ion equipment that 

### iiculd faclli~zte che removal of these VOC from the atrnospnere. Texas 

### Gil h Gs

, , 

### suggests that the 

### EPA thrcug!!ly reevalcate xis fype 2P zon5rol 

### system. Secton 

### 3.1.3.3 Allowabie Interval Before Repair The previous Section 3.1.3.2 Inspection Interval indicates a quarterly inspection-interval. If there were a number of components in excess 

### of the 10,000

### ppmv level,the 15 day repair internal may not be met. Also, if there are sufficient fugitive emissions, the only way the 15-day repair inter~al could be met is by shuttingdown the plant. The natural gas 

### industry does not believe the economic implications of plant shutdowns have been anticipated by the EPA, Texas Oil & 

### Gas Corp. sugests that the 15-day repair interval be eliminated i.n.

### favor of,repsirkg leaking components during the next regularmaintainence period.
Texas Oil & 

### Gas Corp. strongly believes that the reguia~ion of fugitiveVOC emissions frcm natural gas/gasoline plants will not have a signiticant positive environmental impact. We suggest that the data based to evaluate these figitice emissions be expanded to insure a representative cross sec~ion of plats,noL six plants in the entire United States, is used to obtain a more accurata emission profile. The 

### EPA must consider the economic impacts in light of ihe current economic picture of the United States. 

### The increased regulation of the already overregulated Oil and 

### Gas industry will not enhace the future economic stature of the country. Very truly yours,

Manager, Safety & 

### Zhvironmental Affairs6330 HWY.290EAST AUSTIN,TEXAS 78723 JOHN L. BLAIR 5121451-5711 WILLIAMN.ALLAN Chairman CHARLESR.JAYNES Vice Chairman VITTORIO K.ARGENTO,P. E. FREDHARTMAN D.JACK KILIAN,M. 0. OTTOR. KUNZE,Ph.D.,P;E. BILLSTEWART,P.E. Exccutivc Dircctor FRANKH. LEWIS WILLIAM 0.PARISH



### March 10, 1982

Mr. 

### Fred Porter Environmental Protection Agency Emission Standards and Engineering Division (MD-13) Research Triangle Park, North Carolina 27711

9 

### Dear 

### Mr. Porter: We offer the following comments on the Jznuary 25, 

### 1982 Federal Register notice concerning a draft control techniques guideline 

### (CTG)for control of volatile organic CO~DOU~~ 

### emissions from equipment leaks from naturai gas/gasbline processing plants. From this 

### notice, it 

### is 

### our understanding that the Environnentzl Protection Agency now plans to use CTG 

### documents to provide technical and cost comparative data to state and loczl air pollution control agencies to assist in analysis of rezsonzbly available control technology (RACT) 

### for various industrial processes. We understznd that the 

### CTGrs 

### are not to be regulztory 2nd 

### will 

### not impose any new requirements.



## - We fully endorse the need for the 

### snvironmental ?rotectlsn Agency to prepare and distribu~e to state act 

### local zovernrnents technical information concsrni~g the czs: and zvailability of control technology. Such zctivity effectively supsorts stzte and local regula~ory eff~rss xithout restricting the opportunity for state ar!c local ~overnments Lo taylor regulations to meet specific ioc~l condit~ons. We encourEge continued publication of CTG1s 

### so 

### long as they are 

### informational and not regulatory.

### Mr. Fred ?orter March 10, 

### 1982

Thank you for the opportunity to comment. If you desire additional information, please call. Sincerely,

Roger R-. 

### ~all'is, Deputy Director Standards and Regulations Program



### cc: Mr. Dick Whittington, P.E., 

### Regional Administrator, U.S. 

### Environmental Protection Agency, DallasAmericanPetroleum Institute 2101

### LStreetNorthwest Washington,

### D.C.20037 202-457-7330

C.T. Sawyer Vice Prwdarl Yarch 

### 11, 1982
Mr. D. H. 

### Goodwin Emission Standards and Engineering Oivision Environmental Protection Agency 0113 13) 

### Research Trlangis ParK, NC 27711 

### Dear Mr. 

### Goodwln:
The 

### American Petroleum Institute (AEI) 

### herewith submits coinment on the 

### Control Techniques Guideline; Control of Volatile Organic Cornpound Equipment Leaks From Batural Gas/Gasoline Processing Zlants listed at 47FR 3403 

### (January 25, 1982).
API 

### maintains that this Control Technique Guideline (CTG) is 

### unwarranted since EPA has not shown the need for such guidelines. Furthermore, EPA has failed to demonstrate the effectiveness of tne control measures proposed, and has misrepresented the costs and 

### cost effectiveness. Nevertheless, in response to the January 29, 1982, 

### letter of Mr. J. R. 

### Farmer, API offers the attached comments. Our response is 

### based on extensive first hand experience with gas plants and comprehensive exgerience with fugltive hydrocarbon emissions. MI 

### sponsored the most significant fugitive emissions study on production equipment (Eaton, et 

### al, 1980j 

### wnicn nas been performed. The study included two 

### gas plants where 

### a large nuinber of components were tested. All 

### of the gas plant data were provided EPA for use in formulating this CTG. 

### In addition to sponsoring the fugitive emissions study, API has met 

### several 

### times 

### with'^^^, as tne CTG 

### was being aeveloped, to 

### offer technical advice and the benefit of operating experience. Further, API 

### presented a statement ~efore the National Air 

### Pollution Control Techniques Advisory Committee (NAPCTAC) when a preliminary draft of the CTG 

### was 

### reviewed (Koodruff, 1981). Extensive written comments 

### werc filed by API following tne NAPCTAC meeting (Sawyer, 1981). 

### In some 

### instances, EPA has accepted the API technical advice and responded to our other comments. Nevertheless, a number of serious concerns remain. Primarily, these concerns have to 

### do wlth 

### leak measurement method, transferability of information

### Faje Two



### from tns petroleuiii refinlng and cneinical industries, 

### safzt-/ and 

### economic anaiysis in supsort of tilis 

### guldellne. 3ur concerns are detalled In the attacned comments. If 

### tnere are questions on .these co~ments, contact 

### Ar. E. P. 

### CrocKstt, 202/457-7084. 

### Sincerely,

C. T. 

### Sawyer

AttacnmentsAMERICAN PETROLEUM INSTITUTE 

### Comments on Draft

- - 

### Control of Volatile Organic Compound Equipment Leaks from Natural Gas/Gasoline Processing Plants (47FR 

### 3403, January 25, 1982)



### Chapter 2 

# -- Sources of VOC 

### Einissions
1. 

### General 

# -- The process streams to which this CTG 

### applies should be clearly stated. The r.equirements of the CTG 

### should pertain to 

### slant components in 

### contact witn 

### flaids containing ICi



### or more volatile organic compounds (VOC) by 

### weight since leaks from fluids containing less than 104 VOC 

### represent deminimus



# - losses. Excluded, therefore, from the provisions of this 

### guideline would be ( 1 ) 

### compressors hand1ing only methane-e thane and (2) 

### other equipment 

### in.hydrocarbon service where the VGC 

### content 

### is low. Additionally, components installed on lines operating at negative gauge pressure should be exempted .from this CTG, 

### since leakage from tile component 

### is impossible. Otherwise valuable time and resources will 

### be expended nonitoring components having

no actual potential to leak to the atnosphere.
Chapter 3 

## -- Emission Control Technicues



### . . 

### 2. 

### General 

## -- Chapter 3 

### is 

### ,::red alaost 5ntir~1-7 from ;he CTG 1 

### for fugitive VOC 

### emissions from chenical aanufactiring 

### iEPA 198 1 

### !

- . 

### which is 

### based on studies of chemical ?lane and reilner17 

### 2rscssses. There 

### is no technical basis for the 

### transferabiiity of chemical

### 2lant or refinery VOC 

### emissions data to naturai gas/gasoline ?recessing 

### zlants because (1) 

### the 2rocesses are different, (2)



### no description 

### is provided of =he statistical analysis of the Zmissi~n 

### Source Test aata !

### CTG Appendix A;

### to 

### demonscrate leaks

were from gas-liquizs handling ,-~rnponents,i3) 20 

### derivation 

### is provided of confidence limits 

### to establish the correctness of the predictions and, !4) 

### no comparison is 

### supplied of gas ?lant data
with 

### the other study data. Following =re some of the critical issues which must be addressed by 

### the Agency 

### in the CTG 

### to demonstrate their recommendations have technical merit:



# - ( 1) 

### What 

### is the repeatability of the instrument reading? (2) 

### What 

### is the accuracy of the instruement reading? (3)What 

### is the source of the estimate that after repair, 10 

### percent of the original number of sources develop leaks each quarter? (4) 

### What 

### is the basis for the recommendation to isolate and purge a pump before repair? 

### Is. this 

### feasible? (5) 

### Why 

### is quarterly monitoring required for all valves, pumps and relief valves when existing data [Eaton,

## et



# - al. 19801 dispute this monitoring frequency? 

### (6)Why 

### is a 15 day (98%) repair interval recommended as opposed to a 5 

### day (99%)

### or a 30 

### day (963)? (7)

### What is 

### the basis for the assumption that leak repair reduce emissions to 1000 

### ppm? The above 4PI 

### concerns are not addressed by EPA 

### in the CTG. 

### Specifically, ETA 

### is silent on the accuracy and repeatability of the instrument readings. Recent field testing shows the
average error made by 15 

### people screening 28 leaks using a hydrocarbon detection instrument was 6j,OOO 

### ppm. This 

### represents

### modern gas plants are cryogenic piants. On the other hand, refineries and chemical plants operated atelevatd temperatures. The feed 

### to a refinery 

### is -different than the feed to a gas plant. In fact the gas plant product 

### is gas liquids i

### nataral gasoline) which 

### is one. of the inlet streams to a refinery. The inlet to the gas 

### plant 

### is natural gas and its 

### entrained (vapo

### rized) 

### 1iquids. Further, the vaporized hydrocarbon liquids in a refinery process are different than in a gas 2iant since the mixture 

### is 

### more complex. The mix 

### is nore complex *because of the 

### presence of heavier hydrocarbons with greater VOC 

### emissions resulting from the higher tempsrature and pressures inherent with



### a refinery. 

### EPA has not addressed these differences in the CTG. Thus, without supporting data, technology transfer 

### is questionable atbest.

4. 

### Page 3-2, 

### second full paragra~h 

# -- The CTG 

### states without support the portable hydrocarbon detection instrument 

### is the Sesc
survey method. The soap score method 

### is discussed in the CTG in

a negative and superficial manner. There 

### is no discussion 

### in the CTG of the limitations of the VOC 

### analyzer. Some of the limitations,of the detection instrument which must be dealt with

, 

### are: Extreme delicacy the instrument;

o Sensitivity to correct calibration;

o Weight and inconvenience of the instrument;



### o Poor repeatabiiity;



### o Lack of denonstrated accuracy 

### C-26 ,- -,-0 o Time delay 

### in achieving a reading: and Difficulty 

### in receiving timely repairs. The hydrocarbon detector 

### is cumbersome and difficult to handle atgas plants. Many gas plant components are ac elevated locations not accessible from platfoms. or example, 

### relief valves are located on top of fractionating columns. The need to access these gas plant valves 

### is infrequent. Thus, platforms are



## .. , not installed on the columns. Also, tile col?imns are smai, in diameter, 

### i.e., two to four feet at the top. Thus, space for a platform, piping and valves.

### is limi tea. uoniioriilg of rlsvated components with a hydrocarbondetector at a gas plant requires 

# - the inspector 

### to climb the colurcn with the detector over his or her shoulder. At the top of the column ;he detector 

### inust be brought to the front of the operator, the probe moved about the surface of the 90tentially leaking component, and reaaings taker: while standing on a ladder 50 

# - 80 feet above the ground. This acrobatic challenge 

### is not impossible to perform, but i=

### is difficul

### t, dangerous and time consuming. The documented difficulty that 

### a woman operator experienced 

### in handling the instrunent 

### in a training program, along with her lack of zonfidence 

### in the method, 

### is related 

### in Attachent A. During the training aiogran,
15 particigants measured 28 leaks ( four times each). To assess variation 

### in reaaings, caiculations 

### were nade 

### for (7; maximum OVA reading, and (2) the aosoiute difference becxeen minimum OVA reading the maximum and minimin readings. The resillts avericed cv~rall the leaks are 210 

### for the ratio and 6jOOO ?prn 2s hexane 

### for :he C-27 i

# --

-- difference. The OVA'S were all calibrated immediateiy ?rior to the field work. This 

### demonstratzs the lack of repeatability of the instrument. It 

### also brings into serious question the accxracy of instrument rsadings.


### =I has consistently advocated dse of the soap score method

as an effective, simple, econcmic screening inethod as demonstrated by Eaton, et al. ( 1980. ) 

### The only place where soap scoring is not aaglicable is 

### on rotating and reciprocating equipment. Rotating equigment refers to liquid pnps in 

### gas plants. Eaton, et al. (1980) 

### shows liquid leaks are small. EPA

\ 

### data does not demonstrate this- 

### fact since their study did not differentiate between liquid and gaseous leaks. Additionally,
EPA 

### indicates leaks from reciprocating compressors need not be monitored, since most modern compressors are provided with 

### closed distance pieces which will 

### be vented. Thus, 

### the alleged advantages of the instrument monitoring technique 

### are not iltilized in practice. We urge EPA 

### to adopt the soap score method as the principal leak detection technique since the instrument technique 

### is known to be non-repeatable.

5. 

### Page 3-3, 3.1.2.1, 

### last sentence

# -- Isolating the pump and

, 

### flushing it 

### of VOC prior to pumps repacking or seal replacement 

### is vague and dif

### ficult 

### to understand. Addi

### t.ionally, the flushing
fluid 

### must be disposed. It cannot be returned to the 2rocess
stream. Thus, 

### flushing does not appear practical, and the
sentence should be deleted. C-286. 

### Page 3-3, 3.1.2.2 

# -- Collection and combustion of emissions from the compressor seal area 

### is impractical, unsafe, and not
cost effective. Reducing the compressor seal concentration level below 10,000 

### ppm by repair is 

### very difficult and often impractical based on experience during the API 

### maintenance study. Although compressor seal areas are frequently enclosed and vented outside of the compressor building (S2.2.2), 

### these vents are unrestricted in most Natural Gas/Gasoline Plants unless hydrcgen sulfide is 

### present. In some cases it 

### is also dangerous, if not impossible, to



# - enclose the distance piece to-holdgas pressure from 

### a leaking packing. For example, one compressors model will 

### not hold over 5 

### psi pressure without blowing the metal cover off the distance piece according to the manufacturer. The potential also exists, in some cases, for pressurized hydrocarbons to pass through the engine crank case seal and enter the crank case thus 

### creating an explosion hazard. The fact that 80%

### of the gas content 

### is non-reactive methaneethane makes these systems different from the typical refinery
compressor systems used as the reference case. In gas plants
this 

### emission source represents only 2.65 of the 

### VOC emissions (Table 4-2) 

### and the cost of control, 

### in a safe manner, 

### is unreasonably high. Additional block valves, a pressure control valve, and a pressure relief valve between the compressor and the first block valve are ail required for a safe connection of this vent line to 

### a flare line. The assumed naterials and labor 

### C-29

### in Table 5-1 are deficient and both are about ane-half 3f 

### the real cost when allowances are made for 2ressure relief valves,
pressure control valves, unions and the actual installation labor. The result

### is a capital cost of about $7 

### 1,000 in 

### a Yodel "Cn plant to collect 7..3 rnegagrams of 

### VOC anr.uall._~.This 

### amounts
to 19,5% 

### of the RACT 

### capital cost to eliminate only 2.53 of the


### VOC emissions from gas/gasoline p1an.t~. The 

### VOC emission elimination cost of $1,507 

### per megagram 

### is unreasonably ni~h and chis control technique should not be considered UCT. 

### Compressors * 

### should be 

### exempt from.contro1, or the action level raised to a reasonably attainable level. .-


### 7. 

### Page 3-8, 3.1.3.3 

# -- The CTG 

### specifies 15 

### days for required repair without explanation. This could represent as few as nine scheduled work days atplants where repair crews may only be' available two or three days perweek. The repair of all leaks detected within fifteen days may be impossible. A 30 

### day rzpair period would be more appropriate. 8. 

### Page 3-16 

# -- There 

### is a numbering error on pages 3-16 and 3-17. 

### Paragraphs 3.2.1, 3.2.2, and 3.2.3 should be 3.3.1, 3.3.2 and 3.3.3. Our comments are based on the numbers shown in the

, 

### CTG.
Chapter 4 

# -- Environmental Analvsis of XACT 9. 

### Page 4-1, 

### second paragraph 

# -- The soap score nethod should be adopted as the principal leak detection method as discgssed in
comment 4 

### above. 

### C-3010. Paqe 4-2, 4 .Of last 7aragrapn 

## -- " Ahis paragraph is nisLaadin5 

### in casting doubt on the viability of soap score monitoring. Further, 

### it 

### is not likely an acceptable correlation between soap

scores and instrument readings will Se established since the instrument readings are not repeatable. Accordingly, this paragraph should be deleted from the CTG.

11. Paqe 4-9, Table 4-6 

# -- This table is 

### in error. 3ecovered
energy for open-ended lines should 5e mrrected to 250 

### Ssi crude 9etroleum/yr equivalent.
Chapter 5 

# -- Control Cost Analysis of WCT 12. Page 

### 5-1, 5.1 

# -- The econoaic analysis has ecuated "fr3nt end costs'' with "capital costs." Capital cost has an extremely limiting economic definition which does not allow the inclusion of operating cost. Only the 

### VOC analyzer and che 

### ai?ing of the
compressor seal emission should be defined as capital c~sts.

### Ths remaining costs incurred are classified as exaenses. Ex?ense and capital costs cannot be combined without sing an amortization schedule for the life of 

### the capital aurchases.

13. Page 5-1 

### , 5.1.1 

# -- The estimated cost Lor za~ping open flow lines 

### is based on the ?rice of a one-izchcrsw-on :yse 

### lobe valve. EPA assumed that any larger line size can ;e reaucad :3

. -. one inch. Nornally, gas lines are sFec;zlz 

### sizes for 

### a reasor. (e.g., the hose size 

### ts be attached)

### , and :>erefore zac zct '5~ reduced arbitrarilli. Accorting ro CTG hgpecci,:~.I. ':=bL? A-2, 

### ,



### . - 721 open-ended lines were 

### f3si. Tkose iaza zsu-s se 

### :s?c zzZeveiop a distribution of Line sizes and choose an appr3priats
average valve zost rather than nak? questiscable assumptions. In the economic analysis, the double valving of an openended line has been assumed tg be a capital cost. Installed equi2ment costs of less than S250 are rarl::~ considered to be a capital cost. In fact, both the valves and Labor 

### ts install the
double valves are ex?ense costs. In addition, the estimated cost of adding che valves to open-ended lines yas lncerestimaced due
to the omission of miscellaneous costs, l.g., record keeping, vehicle use, source identification and tas2ing

# .

- 14. Page 5-4, 5.1.4 

# -- There 

### is a discrepancy between 43 hours for a pump seal repair and Table 

### 5-2 which shows 11 hours for ,repair for the same seal.

15. Page 5-4, 5.1 .4 

# -- The statement: "Because initial leak repair 

### is a one-time cost, it 

### is treated as a capital cost." 

### is not correct because a one time expenditure 

### is not a correct criteria to define a capital cost. The initial leak repair 

### is a one time operating cost and 

### must be included 

### in the initial cost of emissions reduction, not distributed over a raasonable time period as proposed. For example, reducing the financial the first year's repair cost 

### is distributed over ten years forcing a reduced impact. The emissions reduction realized during the 

### firstyear will not, however, be saved each year as assumed. Each year's cost 

### must be cornpar2d against each year's corresponding Senef

### its to deterinine the cost effectiveness of 2ACT. 

### C-3216. 

### Page 5-4, 5.1.5 

# -- RACT 

### for the ?recess 

### controls and actuators has been defined as conversion to compressed air. With no estimate of VOC 

### emissions saved and no economic analysis, there 

### is no support for this RACT. 

### The expectation that most gas

. 

### ~lants already use compressed air does not constitute justifi

### cation for RACT.

17. 

### Page 

### 5-6, 5.2.1 

# -- The cost analysis for the labor associated with leak detection severely underestizates the actual cost. Whether it 

### requires one minute for VOC 

### sampling of a valve or 5 

### minutes is 

### a function of such factors as the plant configuration, the monitoring method, the per%nnel, the weather, and the location of the component. While there 

### is no current evaluation of this activity for gas plants, the reference cited (letterfrom
J. M. 

### Johnson, Exxon, 1977) 

### is not appropriate for gas plants and
out of date. The 

### information contained in that letter was aeternined for refineries for an entirely different purpose. An API 

### member company has obtained recent and realistic cost information from independent firm performing VOC 

### monitoring. These firms have identified the cost per source tested. A1 

### though contracting the monitoring to a third party may be slightly higher (

### assume 15 

### percent profit) than performing the monitoring
program internally, these costs include all of the associated hidden costs and overhead. Typical bids 

### from contractors who regularly perform this 

### service vary from $1.80/source/sampl ing for an unsophisticated system with 100,000 

### to 200,000 

### fugitive

sources to S5.6O/source/sampl ing 

### for a computerized data system, 

### C-33with 

### the majority 

### in the $2 

### to $4 

### range. A 

### S4/source/samplinc Is

a reasonable contractor cost, assuming 15 

### 2ercent is profit. Deducting contractor profit, it 

### is 

### possible for an operat~r to monitor his 

### own 

### VOC sources for approximatel;~ $3.50/source ( i 961 

### dollars). This 

### estimate does not include leak repa'ir; resampiinc after the repair; or initial design, acquisition or implementation of the monitoring network. The development and implernentation of 

### a new monitoring program will 

### be about equal 

### to =he 

### first year sampling cost for smaller gas plants ( 

### such as Wael Plant A) 

### and percent of the first 

### year's cost for larger gas plants

# - plus the cost of the -instrumentation. 

### In brief, the estimated cost of solely maintaining a monitoring program 

### is 5 

### to 6 

### times the estimate cited 

### in the 

### CTG, assuming $3.50/source/sample and referring to Table 5-4. First 

### the approximations for man time are extremely low. In 

### addition, front-end set-up costs; depreciation on the equipment; and maintenance on the 

### VOC analyzer 

### must be included. Furthernore, the cost analysis 

### must include the cost of the otherwise unneces
### sary platforms for each inaccessible source. If other options

are implemented, such as mobile platforms, then the tine and cost required to sample each valve 

### must be included 

### in the economic analysis.

18. 

### Page 5-6, 5.2.2 

## -- The estimate for leak repair costs consider only the labor of actually repairing the valve or ?urn?. Omitted is 

### a number of associated hidden costs such as record keeping, use of a 

### vehicl?, 

### ?revisions for inaccessiSilicy, costof repair parts, loss of production, and overtime factor. 

### If the
gas plant 

### is keeping sufficient records to take advantage of the statistical relief of Section 3.3, the costs are further increased. Although actual cost of repair is facilicy dependent, 

### a raailstic estimate of maintenance costs arp $12O/'repairea valve and 8 1COO/ repaired 

### pump. Relief valves ars included 

### in the number of
valves. Even if the valve only requires reseating, qualified maintenance personnel 

### inusc serforn che funcrlon and ihe cnolce 

### cf personnel 

### is not optional, especially under unlon contracts.

19. Paqe 5-10, 

### 5.2.6 

# -- Using 1981 dollars for recovery credits,
realistic estimates are nearlytwice what 

### is quoted 

### in the CTG 

### in 

### value per gallon and one and a half times that per nCF. The

error in these approximations 

### is partly due to the assumption /

.- 

## - that all the 

### VOC 

### is propane. The recover-ed VOC 

### is 6 lSs/gal rather than 4 lbs/gal if the correct product density for propane 

### is used. Therefore, the value of the recovery creaits ger Yq 

### is $146 not $210.

20. Page 5-10, 5.3 

# -- In section 5.3 :he "cost" of %ACT has keec estimated. The conclusion, based on erroneous issumptions discussed above, 

### is (with the exception of the sinaildst ?lints) the petroleum industry has losc signiEicant rPvenue due to rhe lack of controlling the VOC emissions. In reelicy =he COSZi ~f implementinq and naintaininq the-reccmme.?ded control 2f VOC emissions from a gas planc ire ;reactr than 

### escixeztd and 2 net long-t2rm loss will result from zne ;se 

### cf -.his ?.ACT zssec 2: the above cost infornation. 

### C-35

### A~gendix3 

# -- Yodei Plants
21. 

### ?age 

### B-1 

## , 3.1 

# -- The three model slants were develo~ed from questionable data. A11 

### four shouid be included in the analysis the reason for including only four tested plants the vessel and component inventories should ce zx?lained. Final selec=ion by 

### ?9I of txo plants was based or; naximizing the 

### number of components at sites 

### for emission measurements. The resulting
A?: 

### component inventories at the tested 

### ?lm:s ar? ~nusually large and thus of questionable value ln

### developing model 2lant configurations.References


### et

## - Eaton, 

### W. S., 

## - al. [I9801

# . Fugitive ayarocarbon Einissions From Petroleum Production Operations. XPI Publication 4322, March, 1980. Woodruff, X. J., [I9811

# . Phillips Petroleum Company, Statemefit on Behalf of the American Petroleum Institute before the National AirPollution Control Techniques Xaviscry Committee, Raleigh, NC, April 29, 1981. Sawyer, C. T., [1981]. Letter toThe National 

### Air ?ollution Control Techniques Advisory Committee, May 15, 1981. EPA [19813

## , Guideline Series, Control of Volatile Organic Coumound Fugitive Enissions from Synthetic Organic Chemical, ?olper, and Resin Manufacturing Equipent. Radian [ 19801

## , Assessment of Atnospheric Einissions from 2e troleurn Refining.(REV.5-78]


### Shell

## Oil Company Interoffice Memorandum



### FEBRUARY 5, 

### 1982

FROM: SENIOR ENVIRONNENTAI; ANALYST 

### PACIFIC DIVISION, VENTUIW 

### SENIOR ST.WF SNVIRCWEN'TAL 

### S?SCIXLIST 

### WESTERN E&POPEAATIC)NS



### On January 25, 1982, I 

### attended a Rockwell Interzatlonal 

# -

.. -.. 

### school to learn 

### how co operas2 33 31" 

# . -.GCE,Z -LS= r3 

### ;ass 

### on my inpressions of the instrurent. First, 

### you cannot get the same ze=suremect ?dice. 14y 

### inspection partner and I 

### seleom agreee on a reaeia~, sY7e2 though our measurements were taken seconds apart. 

### In fact, after comparing our readings, we 

### would each

.

# - - take a second measurement, thereby ending up with four drrzerenc answers. I 

### would add that the weather conditions were calm. Wind would have only aggravated the situation. Second, the OVA 

### weighs about 15 pounds. Ny shoulders and neck area began to throb after 30 

### minutes or so. Further, the bulk and weightof the instrument caused some safety problems when I 

### had to stand near the edge of a ?latfgrn, tending to pull 

### me backward and naking it 

### 2ifficult 

### to 'xrn 

### around. Third, it 

### is necessary 

### to check tne entire clrcumferer?co, 

### of a component and record the highest reading. 

### In nany cases it 

### was impossible to do so due to the size of the probe and the equipment spacing. This situation requires two ?eople



# -- one to hold the meter and the other to read it. 

### In such tight quarters, the two peopie are apt to get 

### in each other's way and are forced into some interesting gymnastics. Also, the OVA 

### itself tends to free swing into the equipment while the inspector tries to maneuver the probe, risking damage to this 

### very sensitive instrument and anything

, 

### nearby. In view of these problens, ws
.

### would not tx?ect anyone 

### to take ineasuror,en-cs from posl=ions that .iould be 

### hazardous such as ladders.

### In snort, I 

### found that 

### compietly xnreliable. explosion-proof.

S.

### S. 

### Walker
SSW:

### jkEmission Standards and Engineering Division (>lD-13) Environmental Protection Agency Research Trianglt Park, Yorth Carolina 17711 Attention: 

### Mr. Jack R. Farmer Re: Control Techniques Guideline Document Equipment Leaks from Yatural GasiGasoline Processing Plants Dear 

### Mr. Famer: The following comments, on che referenced document, arebeing submitted by Michigan Wisconsin Pipe Line Company (Michigan Wisconsin) which owns and operates an extensive interstate natural gas transmission and underground storage system. Michigan Wisconsin transports gas from producing fields in the Oklahoma-Texas Panhandle area, ~ouislana and offshore in the Gulf of Mexico and through-connecting pipelines from Canada to 52 distributing utilities innine states. Michigan Wisconsin and its subsidiaryANR Production Company are also engaged in exploration for gap and oil in themajor gas prone areas of the South, Southwest, Rocky ~Yountains,Michigan, Offshore in the Gulf of Mexico and in Western Canada. We have carefully reviewed the above referenced report, which 

### is clearly well researched and we are in agreement with many of the proposed control techniques. However, there are certain requirements which toncern us and we have concentrated our comments.on these requirements. Emission factors presented in this document are based on natural gas liquid processing plants, gasoline plants and natural gas liquid fractionation plants. For natural gas gathering plants and natural gas dehydrating plants, emission factors fornon-methane/nonethane hydrocarbons (VOCfs) willbe much smaller because the ratio of methane and ethane to, total hydrocarbons is much larger for these facilities. The costs of implementing Reasonably Available Control Technology (RACT) for controlling fugitive emissions of Volatile Organic Compounds (VOC) cannot be justified, for such facilitiesbecause the quantity of non-methane/non-ethane hydrocarbons is very small fornatural gas gathering plants. There are leak prevention and control procedures inplace at most natural gas plants in compliance with minimum federal safety standards. The proposed technology in this document willbe repetition in most instances and increase regulatory burden.Costs projected for converting from natural gas to compressed air actuated control valves should also include costs for the air compressor. Compressed air is generally not available at most small natural jas compressor stations, natural gas gathering and dehydration plants. The cost cannot be justified for remote locations, which are not sources of laqe quantities of 

### VOCTs. Cost of a portable VOC analyzer is reported to be $4,600 by the report. "The annual cost of materials and labor for maintenance and calibration of monitoring instruments is estimated to be S3,000.1f The combined cost of $7,600 per year is very large com~ared to currently practiced technology of leak detection, which employs visual, olfactory or audible means for the purpose. Based on our past experience in controlling leaks and successful operation of natural gas processing/compression facilities, a Table comparing our current practice and proposed tecnniques is attached for comparison. The table will show that inmost instances, proposed control techniques are already inpractice, atour facilities. Michigan Wisconsin would like to thank you forproviding this opportunity to comment on this document. We believe that the present techniques employed by natural gas liquid removal, dehydration, and compression facilities are adequate and themajority of the emission factors developed in this document should not be used tojudge performance of these facilities.

-- Sincerelyyours,

Jitendra V. Nehta, Environmental Engineer

Attachment

cc: Messrs. J. P. Cencer V. D. Lajiness R. J. Lecznar P. B. Thompson Mrs. 

### M. L. Webster File

### nwmn 

## Chevron

## U.S.A.Inc.



# u 555Market

### Streer.San Francisco. Cal~fornia

# . Phone (415)894-3041

X \;I311.AdGress. ?O. ~ C 3063.3an F-anc~sco. CA ?4119

3.'N.Kreutzen :?qerai Manager i?wronmenra~ Aifa~rs

March 12, 1982

DraftCTG forNatural Cas/Gasoline Processine Plants

\Ar. Jack 

### R. Farmer, Chief Chemicalsand Petroleum Branch EmissionStandardsand Engineering Division (.M

### D- 13) Officeof Air Quality Planningand

Standards 

### U.S. Environmental ProtectionAgency ResearchTriangle Park, North Carolina 27711
Dear

### Mr. Farmer: Chevronis happy tocommentonthedraftCTGfor naturalgas/gasoline processingplants. Wenoteconsiderable similaritybetween thisdocumentandthedraftNSPS forVOCemissions, upon which wecommentedlastNovember 

### 16. Thereareenoughdifferences betweenthetwo drafts,however, towarrantour offering

### a new setof comments. Section2.2.7 Gas-Operated ControlValves
No actualemission factors

### aregiven for thesevalves, nor any indication of how manyuse compressedairvs. "field gas." If the"field gas"isnaturalgas, very littlenonmethanelnonethane hydrocarbonwillbepresent. Table2-2 BaselineEmission fromModel Plants The baseline emissionsarebased upon theemission factorsin Table

### 2-1. Althougn the 

### 95%confidenceintervalforthesefactorsisextremelv large(generallya facsorof fiveor more), therearenoerrorestimatesforthetotalbaseline emissions. What aretheconfidencefiguresonthesenumbers? Section

### 2.3 BaselineFugitiveVOC Emissions Estimatingcomponentsby ratioing tomajor equipmenthasmerit. However, ratioing componentstoallvesselspooled together (columns,heatexchangers,anddrumsltanks)is anoversimplification, asdemonstratedby Table 8-3. Com~aring theaverageratioof flangesandconnectionstovessels(97.4) andthestandarddeviationof the ratio(59.7) showsthecorrelation issometimespoor. Thisisalsoconfirmed5v thedisparate ratios reported

# - about

### 50 fortheEPA-tested plants and about'150 fortheindustrv-~ested plants. 

### C-43Mr. Jack 

### R. Farmer, Chief Page

### 2 March 

### 12, 1982

Section3.1.1 Individual Comoonent Survev Thissection failstornen~ion theconsiderable problems associated with maintaining and operatinga portablehydrocarbon analyzer. They aretemperamentalprecision instruments sensitivetoheat,humiditv, and theTvpe of gasbeing sampled. qeliableilserequires thoroughpersonnel training and carefulmaintenance and calibration procedures. For example,theinspectionand maintenanceprogram in Chevron'sEl Sequndorefinery requires onefull-time person tomaintain and servicethedetectors. Even if thesametypeof instrumentsarecalibratedand used sideby side,reproducible resultscanbeelusive. This hasbeen Chevron'sexperience 21our Ventura County,Californiaproduction facilities. Thepoint is thatportablehydrocar~on analyzersareverv trickv,and heirrequired use couldbeaconsiderableburden on smalleroperators. Vonitorinqrequirementsfor unsafe anddifficult TOreach componentsshouldreceivespecialconsideration. Atthe

### least,this CTGshould includethe attachedstatementtaken from the draftCTGon "Control of Volatile OrganicCompound FugitiveEmissions from SyntheticOrganicChemical,Polymer,and Resin ManufacturingEquipment" (August, 1981). Section-3.1.2.1 Pumps
Itisstatedthatapumpshouldbeisolatedfromtheproce'ssand flushedof VOC

### as much 

### aspossible prior torepackingor

### sealreplacement. Thereason fordoing thiswouldbeto' assurethatthetemporary VOCemissionsfromrepairdo not exceedtheemissionsfrom theoriginal leak. Webelievethatinpracticethiswould benearly impossibletodo. EPA shouldconsider theprospect that theemissionsresultingfromtherepairof 

### apumpleak could offsetanylong-term benefits, dependingontheextentof theoriginalleak. Section3.1.2.2 Compressors
Wemusttakestrongexception 

### to thecontrolstrategydiscussedherefor reciprocating compressors. Thereareseriousphysical and safetyconsiderationsassociatedwith enclosing compressor sealsinthemanner suggested. Rather thandetailtheseissukshere,letme referyou to

### K. 

### C. Hustvedtof your RTPfacility, whoisveryfamiliarwiththeissues raised by industrywhen 

### a similar strategywasproposed for refineries. Table2-2 assignscompressorsonly 3%of thetotalgasplantemissions. In view of the seriousproblemsassociated with controllingtheseemissions, we stronglyurgethatthis strategy bedropped. Section3.1.3.2 InspectionInterval ThedraftCTGapparently considersonly quarterlyinspection intervals. 

### EPAshould seriouslyconsiderannualinspections, sincequarterlyinspectionsarepracticalonly fora relatively smallnumber of majorcomponents(like compressors). Evenin Los Angeles, which generally hasthetoughesthydrocarboncontrolregulations in thenation, inspection with aMr. Jack 

### R. Farmer,Chief Page3 'vlarch 12, 1982

detectorisrequired annuallyforpumps, valves, andflanges, andquarterlyfor compressors. More frequent inspections arenotjudged cost effective. Section3.1;3.3 Allowable Interval BeforeFiepair The report suggeststhat 15davsisreasonable toallow 

### a plant operatorenoughtimeto obtainrepairparts. Whileoftentrueforreadily available parts, thistimeis much too shortfordifficult-to-get parts. Allowing sixtydavsin such specialcasesis morereasonable.Section

### 3.3 OtherControlStrategies
It is suggestedthatif lessthan2% of thevalvesarefound tobeleaking,then the operator may skipinspections. We feelthisa goodconcept, butitshouldbeextended. TheCTG still requiresthatinspectionsbecarriedouton

### ayearlybasis. We believe thatif data indicate

### a longer timeintervalwould maintain

### a leakrateof lessthan2%, thenthisinspectionintervalshouldbeused. In addition,wecanseenoreason nottoapplythisconceptto otherfittings

### aswell

### asvalves. The subsectionsin section

### 3.3 

### aremisnumbered. Chapter4.0 EnvironmentalAnalysis of RACT Thischaptercouldbeimproved considerablyby looking

### atotherinspectionintervals. We thoughtthecorrespondinginformationin theNSPS wasmuch morecomprehensiveand generallyprettyaccurate(withcertainexceptionsnoted in ourearlierletter). We would encourageyou toadd someof thisinformationtotheCTG.
Itisinterestingtocomparethevalues givenin Tables4-2 and

### 4-3 with Chevron's Los Angelesarearefineryexperience. Theinspection andmaintenanceprogram forvalves

### at our

### El Segundorefinery (10,000ppmcutoff, annual inspection)yieldsa reduction efficiencyof about6596, nottoo farfromtheentryinTable4-3 for quarterlyinspections. Ontheotherhand, our

### I&Mprogram forcompressors (quarterlyinspections)yieldsabout

### a 35%reduction. The 100%reductionnoted in Table4-2 isnotrealistic (seeourcomment onsection 3.1.2.2). Chapter 5.0 ControlCostAnalysisof RACT
Wehavesomeconcernsaboutthecoststhatwereused in estimatingthecosteffectiveness of theCTG.

a. Wecurrentlywould estimate thecostof labortobe$23.00 perhour ratherthan $13.00 perhour 

### (28%higher)..Mr. Jack

### R. Farmer, Chief Page4 March 12, 1982

b. 

### Wedonotbelievea ventingsystemcouldbeinstalled on compressor sealsfor $700.00 (pa 

### e 5.10). NationalAir OilCompany estimates thecostof their smallest flare TO be 8,000. Thiswould not includethecostof pipingtoeach seal. 

# 4

Cost effectivenessnumbersaregiven for

### a RACTprogram i'nvolving quarterlyins~ections. Whilethesenumbersaresomewhatopentoquestions, for thereasonsgiven earlier,rhe lack of incrementalcosteffectivenesscalculations

### is a seriousomission. What isthe incrementalcost effectivenessforannualor monthly inspections versusquarterly, for example?

Wehopethesecommentsarehelpful. For your information, weareattachinga copy 

### of a technicalpaper givenlastNovember, which describesChevron'sexperiencewith IJcM programsatour

### El Segundo,California refinery. If you wish todiscussour comments further,pleasecontactMichaelFosterof my staff at(415)894-6107. Very trulyyours,

MSF:rdg AttachmentsATTACHMENT

ThefollowingstatementisfromtheDraftCTG: "Controlof VolatileOrganic Compound FugitiveEmissionsfrom Synthetic Organic Chemical, Pqlymer, and Resin Manufacturing Equipment" (August, 1981,page 3-29). Unsafe and Difficult toReach Components
Somecomponentsmight be consideredunsafetomoniror becauseprocessconditions includeextremetemperaturesor pressures. A Stateagency may wish to require lessfrequentmonitoringintervalsforthesec o m p o n e n t s b e c a u s eof the potentialdanger which maybepresented tomonitoringpersonnel. For example. somepumpsmightbe-monitoredatrimeswhen process conditionsaresuch thar thepumps

### arenot operatingunder extremetemperaturesorFressures. Somevalves maybedifficult toreachbecause

### access tothevalvebonnet is restrictedorthevalvesarelocatedinelevatedareas. Thesevalves mightbe reached

### by theuseof 

### a ladderor scaffolding. Valveswhich couldbereachedby theuseof a ladderorwhich would not requiremonitoring personneltobe elevatedhigherthantwo metersmightbemonitored quarterly. However, valves which requiretheuseof scaffoldingorwhich requiretheelevationof monitoring personnel higherthantwo metersabove permanent supportsurfacesmightbe monitored annually,forexample.

### Clayton 

### 2. ?rreeberr o 

### Chevron Zesearch 

### Corncan7 3ic!mond, Celifornia



### :or ,resentatior, 

### at the 

### n ,;;:hE Xeetlng Lr. !iew 

### 9rlea.n.s or. 

### Xovember 

### 8-12, 

### 1981. 7

### ABSTRACT 

## -----.---

This 

### paper discusses the 

### ?fTecc of txo lns?ect:on and mainteriance

(I & Y) 

### programs for reducing fugitive hydrocarjcn emissisns at 

### Chevron's refinery in El 

### Segundo, California. Two I & 

### P, reguiations, 3ne covering valves and flanges and the other covering pumps and comgressors, have been imposed on this refinery by the South Coast Air 

### Guality Management District. First-hand experience Ln neeting these regulations is 

### presented along with estimates of hydroca~bon enisslo~ reductions and estimates of the cost effectiveness of 

### the reg~la- :ions. The paper 

### also explains how to estimate fugitive hydrocarbon emissions for 

### new facilities, which 1s 

### necessary to obtain zonstruc- :Ion permits.

### SUMMARY



## . . 

### Ozone levels in the South Coast Air 

### Basin, which Inc~zee ?zr:s of 

### fo~r 

### counties in the Los Angeles Area, currently 2xceed the naticrzl ambient 

### air quality standard for ozone. This has resulted in the South Coast Air QualityManagement District (SC&?4D> 

### 3stab;ishing several regulations to reduce emissions of hydroczrSon, zn 3zone ?rl

### cursor. Consequently, Chevron's El Segundo Refinery hzs had severa; years of experience with two SCAQMD regulations resxi-izg 

### ins?ectioc and maintenance (I & 

### M) programs--one rcr vel7:es 2-6 flazges 

### 2x3 

### another for pumps and compressors. 3zsea on t5is 

### ex;erience azd the
I 

### use of the emission factors from a recent Rzaian FegorT, results indicate that the valve I & 

### M 

### program currently achieves 

### z nef economic return. The effect of the flange I & +! 

### progrzm hzs 

### not yet been completely evaluated, but it 

### currently appears to be less ccst .,- 1. 

### effective than the valve program. Tke scr? 

### an,< cs~9resscr

,

# - ',?



### .. 

### program has a significant net cost ($i-$2/1S hydrocarbon con:rslled: Secause of the higher maintenance cost involved In 

### re?lzcing pump and compressor seals. Proposed future regulations are esthzted t~ 

### be much more costly (perhaps $5/lb); therefore, industry must continue--Yo provide input to regulatory agencies to ensure that the nost cost effective controls 

### are implemented. Chevron's experience with I & 

### ~--~ro=rams has proven to be an asset in 

### obtaining construction permits from regulatory agencies. An accurzte prediction of the fugitive emission control programs has 

### provided significant emission information which can now be used to develop more valid estimates of emissions from proposed new facilities. INTRODUCTION Under the Clean Air 

### Act, the South Coast Air Basin xust meet the ozone standard. This will 

### require further reduction of hydrocarbon enissions. In addition, many states are adopting New Source Perfornance Standards which include fugitive emission controls and which 

### will affect almost 

### all new facilities or major modifications. Thus, operators :n ozone nonattainment areas are being confronted with the need to participate in the development of new regulations to ensure that the most cost-effective controls are used first.

- 

### At 

### Chevr.onf s El 

### Segundo Refinery

## , which 

### is located In the South Coasu Air 

### Basin, controls on hydrocarbon emissions have been coming into effect over the past 25 years. During this time, many major sources of hydrocarbon emissions have been controlled. These include tanks, oil/water separators, valves, flanges, pumps, and cornpressors. Yet, the Bas

### in is still 

### nonattalnment for ozone. Whiie xoblle sources

### represent Tore than halhf the hydrocarSon e~isslonsIn 

### the Szsin, Chevron expects additionai controls co be 

### ~nposeci3~ 

### staslonzry sources. Such measures 

### ~111 5e 

### mre exge?slve 2nd SICficl~lt 

### ts L~.zle

### ment than those in the past. 

### OVERVIEW OF 

### ONE REFINERY'S HYDROCARBON EMISSIONS

t A 

### summary of the estimattd hydrocarjcn emissl3ns E3r Cke~r3~~ 

### s El 

### Segundc 3efinery is shown on Table 

### I. --yese e~iss'sr~stiz~zes m. 

### include reduction crediss for ex1s:ing cor.'vrol xezsures, szch 2s 

### secondary seals on floating roof tanks, various mocifLcatl3ns tc bulk loading facilities, and limitations on the use of paints and organic solvents. 

### Fugitive emissions are by 

### far tke 

### larges: -emainlzg S~CYZO 

### category of hydrocarbon emissions within the refL~.ery.

.A! 

### breakdown of the various fugiti-~e ~zlssisn sou~c2s Is skzxn 

### cx Tzble 11. 

### Unless otherwise noted, the emlsslon esthates 2re Szszd on 

### emissions factors from a study of refinery :ugi?ive enlssL3~scer? '27 

### Radian Corporation. Even with the fl~giti~e emission consrols ccrrently in place, the emissions Cron valves, flanges, gumzs, and compressors account for approximately 

## 86% of the f.otal "ugitive hyarocarbon erniss&%nsfrom the refinecy. The emissions shown ?or gas 

### ad light liquid valves include credit for a

# - 65% reduction from the uncontrolled value based on the results of the exlstLng I h 

### M 

### program. ?ic 

### reduction credit 

### was assumed for the flange i & M 

### program since It 

### kzs not yet been completely evaluated. 

### The emissions from iight l:quld 

## pumps and hydrocarbon gas compressors were reduced Sy 

### 35; from the uncontrolled value. The 

### 35%reduction was estinated by 

### SCAQMD. 3ot5 the 

### valve and flange rule and the pump and ccmpressor rule apply 

### :~z hydrocarbon gas and light. liquid streams only. The SCAQMD 

### defines 

### r light 

### liquid to be 

### a hydrocarbon liquid with a Zeid .Jzeor gress~re



# - >1.55 psia. 

### El Segundo Refinery's 

### I & 

### M programs for valves ane flanges and for pumps and compressors wLll be 

### discussed In detail below. In additlon to the two most significant rul?s c~vering valves, flanges, pumps, and compressors, there are six sther ~312s

### iimlZLng fuglti

### ve hydrocarbon emissions which have 3een passed 3y :he 

### SCACMC. These rules regulate sources such as oll/wzter separators, Sulk 1025- 

### ing of organic liquids, gasoline transfer and dlspensl~g operzsicns,

-. 

### vacuum producing devices, relief valves, and process turnarounds. 

# -

-.. 

### irnpact 

### of these other rules has 

### not been neerly as signiCicant 2s :he 

### Impact of the valve and flange rule or the pump ~nl compressor rzle, 

### and t hey will

### not be 

### discussed in detzil in this paper. This ;~?er will 

### d

### iscuss on the valve and flange rule and Ske 

### gun? and compressir rule.

### Table 

### I Refinery Kydrcczr3cn

. 

### Emission 

### Suxmzry



## : or' Emksslon Source 

### Total 

# I 

# I Cornbusticr Sources- 

# 'I
~olvents/~r~anics~
Tanks

### 1 

# I 

# I Total

l~asedon 

### EPA's "Compliance of Air

Pollutant Emission Factors, 

### AP-42, effective April 

### 1981. '~ased on South Coast Air Quality



### Management District emission factors with current controls in 

### ef

### f'ect.
3~ee Table 

### I1 for emlssion basis.

### Tzble 

### II

-4 

### Fuaitive Eaisslon Suninarv' $ 

### of Total Z of Total 3ef;ne ry

Fugitive HydrocarSon Fugitive Emission Source Emissions Enissions ~lzn~es~ Valves 

### Gas and Light ~i~uid3 

### ~5 Heavy ~i~uid~

~orn~ressors~ ?umps Light 5iquid4 J

### 5 2 , OCO 

### Heavy ~i~uid6 

### 700 Relief Valves 

### 200
900 Cooling ~ower~ 

### 1,500 Drains 

### 1,700 Total

'unless otherwise noted, calculations are based on Radian

emission factors for nonmethane hydrocarbons. 2~o reduction credit 

### is assumed for the flange 

### I & 

### M 

### program since the program 

### is not yet completely evaluated. 

### 3~ 

### 65%reduction is 

### applied to hydrocarbon gas and light

liquid valves to account for the I & 

### M 

### program. The method for calculating the percent reduction 

### is outlined in Reference 2. 4~ 

### 351 reduction 

### is applied to account for the I & 

### M 

### program. 5~l~ht liquid is 

### any liquid with Reid vapor pressure

# - >l.55 psia. 6~eavy liquid 

### is any compound with Reid vapor pressure (1.55 ~sia. 7based on emission factors from EPA Publicztlon AP-il2

(October 

### 1977).-

# - PHILOSCPYY OF THE 

### RULES During the development of the !ralve ind flange 

### rule 2r.d she ?urn? 

### a7.r; 

### compressor rule, two significantly different agproaches were 

### ?r3- posed. The first, which was put forth by 

### :tie reguiatory ~ge~cles, stressed enforcement of the rule. The basic concern 

### wzs hcw 

### to ensKr? that companies were 

### complying with the rule. So the agencies prorjcszd that any leak found by an agency inspector would be a violation. However, this concept could create major Droblens for inductry since

& -! 

### it 

### is 

### impossible 

### to stop all equipment leaks. At 

### any given 

### d-ne, there will

### be,some fraction .or-the valves, i'larges, ?urn?s, zcr

### pressors which leak. In addition, leerates are varia3le--a ?:ace 3' 

### equipment may not be leaking one day 

### but be leaking the next $a?. 

### These facts must be recognized in the rule aeveiopmer,t process. Therefore, the industry approach 

### was that the rules should require repair of all leaking equipment within a certain time 

### period. ;. 

### leakfound by an agency inspector is 

### not 

### a violation, Sut i: xst be 

### repaired. A 

### rule of this sort achieves the desired enissior. r?.'Uuc:isr. 

### through inspection and directed maintenance without ?ecalizing an 

### operator for expected occurrences beyond his control. This is 

### tke approach which finally prevailed.


### VALVE AND 

### FLANGE RULE The valve and flange rule requirements are shown in Table 

### 111. The 

## 1.55 psia RVP 

### limit makes 

### a split between naphtha and kerosene which is 

### the same split made by Radian Corporation in their studies of fugitive emissions .l Valves and .flanges inheavy liquid '

### service have verg 

### low fugitive hydrocarbon emissions, and so they are exempt. Ethane ,and methane are exempt because they do not contribute significantly cc,

.

### - photochemical smog. Also, anystream containing more than 801 

### hydrcgen is 

### exempt. Currently, every valve and flange subject to the rule must be inspected annually with 

### a portable hydrocarbon detector. This requires 

### a full-time three-man team in the field plus additional support people. The three-man team inspects and makes the first attempt to repair every leak found. The team consists of:
1. 

### Operator 

# - Identifies applicable valves and flanges and records the data. 

### Assists in securing a valve for repack1r.g or replacement.
2. 

### Technician 

# - Operates and services the hydrocarbon analyzer.

### SCAQMD Valve and Flange Rule Summarv



# - Applies 

### to hydrocarbon gas and liquid streams i./l.~i: 

### ?,eid vapor ?res

### sure 

## >1.55 psia, except methane and ethane. Inspection Requirements



# - Two complete valve inspections during the 

### first year.



# - One complete valve inspection each year there&':?-.

.r nn 

## - One complete flange inspection each ye27 efZect:-~e ?ay 

### Ly~O.



## - Reinspect each leaking valve three months 

### zf:er re?eirs are 

### completed. Leak Definition



# - Llquid leakage 

### at rate 

### >3drops per minute.



# - Gaseous hydrocarbon concentration

## - >10,000ppm 

### at the source. Repair Requirements



# - Repair to nonleaker status (<10,000ppm) within two working days.



# - Nonrepairable valves or f'langes must be vented to pollution control device or 

### a variance obtained. Recordkeeping Flequirements



# - Maintain records of 

### valve inspections for 

### one year.



# - Make records available to the District upon request.



# - No records required for 

### flange inspections. Exemptions



# - Natural 

### aas valves and 

### flanges.



# - Hydrogen valves and flanges (

### >80%

## x2)

# .



# - Inaccessible valves and flanges.

### C-55

### 3. Mechanic 

## - ?e?form necessa-y ~a2ns2n~nce.
Tke :em 

### is equipped with 

### a Century :SV.l.-108 

### hydrocarSon melyzer. This znzlyz3r satisf:es the Instrment ??rfsrrr!ance stznda~5s imposed 3y SCAQMD. 

### In the field, the technician measures the hydrocarSon concentration 

### at the ssupce with the analyzer. The operator records the data. All 

### val-~est2s

### ted are counted, Sut only those wi:h 

### enission :oncent 

### rations great?? than 10,OGO ppm nave <etzl:z< 

### szta r-ecorced fo identify then (e.g., 

### plant, size, type, service, Leak zcncent-atio~;. A 

### bright orznge numbered tag is 

### attached to each of these vzl:ies. These tzgs help the inspection teams reiocate the leakers durlng :he quarterly reinspections. The mechanic on the team attempts to repair a leaker as soon as it is

L a 

### - - found. Since the izspection team is 

### sL;li In the 2re2, 

### the regaired valves are reinspected immediately. Co~slderable f~llowup maintenance tize 

### is reduced by streamlining the repair 2nd reinspection ?rogran in th~s 

### xay. Some valves and flanges are inaccessible. These are the vaives and flanges which cannot be 

### inspected or repaired without excessive ccst and effort. Based on this crite-pion, less than 45 of the valves and flanges are considered inaccessible. There are two additional full-time technicians involved with this program, one who performs the reinspections with a hydrocarbon analyzer and another who handles the recordkeeping duties. All 

### of the records required by this' rule are kegt on a computer. The computer greatly reduces the labor spent in data comp:la:ion and data handling. In addition, the computer provides 

### a tickler file which flags any special action, such as reinspection of a repaired leak. The results of the 

### I & 

### M 

### programs to date are shown in Table IV. 

### The first complete inspection showed that 

### 4.3% of the valves subject to the rule were leaking in excess of 10,000 ppm. The leak rate durI3g the second inspection six 

### months later 

### was 2.2%. 

### The third and fourth inspections, which were done at 12-month Intervals, showed an average of 

### 2.8% leakers. Based on this average leak rate and the emission factors from the Radian reportl, the calculated emission reduction from valves is 

### currently about 19,000 

### lb/day. This results in a net economic return assuming a hydrocarbon value of $O.lO/lb. If 

### Chevron were to use the emission factors from EPA Publication AP-42 (October 

### 19771, which are signifLcantly lower than the newer ~adianl factors, the estimated hydrocarbon savings would not offset the cost of the program.

### Table IV 

### Valve and Flange Inspection 

### Results

C I - 

### Inspectlon Period No. Valves Ins~ected No. 

### Valves Leaking 

### % Values Leaking No. ~1;anges Inspected 

### No. Flanges Leaking 

### % Flanges Leaking January-June 1979 July-December 

### 1979 1980
1981



### '~lan~e Inspection reiuirements added 

### May 

### 1980. *~larl~e results Include only process units inspected after May 1980.


### -

### Some new regulations currently being.consieeree '27 SC.i.GY2, 

### suc5 5s 

### including heavy liquid valves in tne I & ?! 

### grog~axan6 

### i?cr?asizg :-2 

### inscection frequency, would be 

### much less cost ?ffls:L.~e :EX 

### :ne ;re

### sznc program. For example, the incremental 

### csst 

### effec:l.ier.ess 

### sf

1 - GJ/-Z G : 

### zdding the heavy liquid valves to the program waul? 

### Se ~bccz4r

7 

### - hydrocarbon controlled, which 

### is currently not consl>ieredtconomi:z,-; justified by most regulatory agencies and indust~y

## . PUMP AND 

### COMPRESSOR 

### RULE The current rule requirements for pumps 2nd congressc-s ?re S:-,CXF 

### Ln Table V. 

### This rule applies to pumps 

### in iiyht l:qulQ servl2e 

### 226 c9;- 

### pressors in hydrocarbon gas service. The affected re:'i~..erjr stocks zr? 

### the same stocks.as those covered by the valve and flan.ge rLle. In the case of the pump and compressor rule, there are 

### :we !<inds 

### cf

. . . 

### leaks--visible leaks and leaks detectacle only .A;;? 

### z .?;;c?ocz.-3cr: . 

### analyzer. Visible leaks are defined 

### as a visiSle mlst 

### or three drops/minute of liquid leakage. The early versLo~ of :his 

### xi?, .x?iz:? 

### has been in place for several years, required only chat 

### zl; pumps u.2 

### compressors subject to.the rule be inspected once a shift 

### for visible leaks and that 

### all leaks must be repaired. Any visiSle lezk fo~nd b;; 

### a District inspector 

### is an immediate rule violation. Since the rule 

### was first passed in 

### 1976, there have been many changes In the area of fugitive emission control. There has been an improvement in technology available to control and quantify the emissions 2s 

### well 

### as a vast improvement in the understanding of fugitive ernissions. Fugitive emissions are known to be much more significant thzr. 

### was originally thought. The need for further hydrocarbon reduction l e d . t o the deve1opmer.t of another inspection requirement for pumps and compressors which 5ecarne effective Ju1.y 1, 

### 1981. In addition to the inspections for visible leaks, each pump must be 

### inspected annually and each compressor must be inspected quarterly with 

### a portable hydrocarbon detector. Any pun? or compressor with 

### a concentration greater than 10,000 ppm at the sezl must be repaired. If 

### a leaking pump or compressor has 

### a spare, it 

### must be shut down within two days; if 

### it is 

### not spared, repairs may oe deferred until the next unit shutdown. A 

### leak found by 

### Distrlc? personnel with 

### a hydrocarbon detector must be repairad, but it 

### is 

### not 

### a violation.

### Table V SCAQND 

### Pump and Conpressor Rule 

### Cumnary
Applicability



# - Purnps/compressors handling hydrocarbon gas 

### or liquid with Reid vapor pressure 

### >1.55 psia, except rnetha~e and ethane. Requirements Visible Leaks



# - Maintain purnps/compressors so there is 

### no visible vapor ieakage or visible liquid leakage 

### >3drops/rninute.



# - Any visible leak greater than the above ilxits found by Distric: personnel 

### is a violation.



# - Inspect purnps/compressors for .,risible leaks once/shift. 

### Invisible Leaks



# - Inspect each pump annually andeach compressor quarterly with portable detector. Repair any leak >10,000 

### ppm, measured 1 

### crn from 

### seal.



# - For unspared equipment, minimize leakage within one day and repair 

### at next shutdown.



## - For spared equipment, take it 

### out of service ~ithin 

### 48 hours and put spare in service. If 

### the spare leaks, one ?uzp must be ragairei within 

### 15 days.



# - Repair requirements: 1. 

### Repair to <10,000 

### ppm, if 

### possible. 2. If, 

### after repair, leak registers >75,000 pprn (10,000 pprn after July 1, 

### 19821, then leak must be 

### vented to pollution control device 

### or variance obtained. Must be repaired or replaced at 

### next shutdown. Exemptions

-



# - Pumps under 1 

### brake horsepower.



# - Pumps/compressors with applicable hydrocarbon content (20:.



# - Pumps with double seals.

### The rule covering the annual inspections with 

### a hydrocarbon detector uses 

### a phased approach to allow industry time to attain compliance. Currently, the goal is to repair aii leaks to below the 10,000 pprn 

### threshold. Current mechanical seal repair practices are not sophisticated enough to ensure that 

### all seals can be made to satisfy the 10,000 ppm limit. 

### Thus, during the first year the rule is 

### in place, leakage must only be reduced to 75,000 ppm. If 

### -the leakage exceeds 75,000 ppm, 

### a variance must be obtained or the emissLons vented to an air po'llution control device. After the first 

### year, the 

### .limit 

### becomes 10,000 ppm instead of 75,000 ppm. The purpose of this 

### two-step approach is 

### to allow industry one year to gather data on seal reliability and repairability. If 

### the data show that enough pumps cannot meet the 10,000 pprn leakage limit, then the rule mzy be modified. Chevron is 

### currently gathering data on the leak rates of the 513 pumps and 

### 29 

### cornpressGrs subject to the 

### current ~12.

### These punps 2nd 

### compressors are the second largest source of our refinery's fugitive emissions. Preliminary data indicate that about 20% of the punps do not meet the 10,000 ppm limit. 

### We are unable to predict at this tbne how many of these pumps can be made to satisfy the 10,000 ppm limit 

### by repairing or replacing their seals. The 

### emission reductions due to the elimination of visible leaks have not yet been quantified. The annual inspection program with 

### a leak detector is 

### in 'its Infancy, and changes are still being made to improve the effectiveness of the-program. The limiting factor on the rate of which pumps and compressors can be inspected 

### is the rate at which they can be repaired in the Machine Shop. Preliminary data indicate that about 100 

### of the affected pumps can be expected to leak, so an average of eight to nine pumps must be repaired every month. This could be as much 

### as a 25% 

### increase in the number of pump repairs previously required and is 

### a significant increase in maintenance requirements. Whenever possible, the inspection program is 

### scheduled so that any seal 

### .repairs can be done when 

### a pump is 

### sent to the shop for other maintenance.
A 

### major concern 

### is how to control emissions from old reciprocating compressors, many of which have been in service for more than 40 years. If 

### the leakage cannot be reduced to less than 10,000 

### pprn, then the distance piece must be enclosed and vented to 

### a closed systen or the compressor must be replaced. Ultimately, several old compressors nay have to be replaced since venting to 

### a closed system is 

### sometimes impractical.

### One other feature of the refinery sedrmlLtenance grcg~am

### is worth mentioning There is 

### one f~ll-time mechanical seal technician whose job is zo inspect and test every seal before 1: 

### Is l;.sialled. 

### The iechnician replaces any defective parts or repairs i 

### LzakLng aew seal. Once 

### a seal 

### is installed, the technician retests tne seal fp,r leakage before the pump is 

### reinstalled in the fieid. This approacA greatly improves the quality control for rnecnaniczl seal repairs 

### anC repiacements. SO 

### far it 

### has not been possible LO 

### caiculate precls'iy 5ce 

### Cosi effectiveness for the seal 

### i & W 

### proyram. 

### .A very rough 

### est~inate of 1 

### :he cost effectiveness of the rule Indicates th2~ tlls ~ ~ 

### costs 2 

### $1-$2ilb of hydrocarbon emission reduced. This includes a credit of $O.lO/lb for the recovered hydrocarbon. The pump and compressor rule 

### is less cost effective than the valve and flange rule due to the high ccsc 

### of 

### re9lacing seais. EFFECT ON 

### MAJOR 

### NE'J 

### PROJECTS Fugitive hydrocarbon emissions are playing an increasingly significant role in obtaining construction permits for major new projects, especially in nonattainment areas for ozone. For some large construction projects, 

### as many as 

### a hundred sgparate permits may be required. However, the most critical permits are usually 

### air permits. In order to obtain an 

### air permit to construct 

### a new facility or modify 

### an existing plant, the applicant first must supply 

### a valid estimate of the emission 

### rate of each pollutant from his new project. Since it 

### can sometimes take several years from the inception of a project 

### to get final permit approval, the permit application with emission estimates must be submitted as early 

### as possible to avoid costly construction delays. The applicant usually must apply for permits long before detailed process designs are available, which puts a severe strain on the engineering staff to come up 

### with valid equipment counts of fugitive sources (e.g., valves and pumps) before any detailed designs are complete. Here 

### is where the applicant can draw from his past experience with 

## I & 

### M 

### programs for 

### similar plants to estimate the number of fugitive sources within the new project.
A 

### quick guess of fugitive emissions 

### isnot acceptable. Care must be taken 

### to develop an accurate estimate of emissions from 

### a project because overestimating or underestimating can severely impact the permitting of 

### a project. If the applicant underestimates the emissions from his project, this will 

### reduce the project's predicted 

### air ~uality impact; however, when the operator wants to 

### start up his 

### new plant, he may find that the permitting agency will 

### only allow him 

### ts

### operate 

### a fraction of the pumps 

### in the plant. Then the oge~~tor either has 

### to delay startup until he can renegotiate a new permit or operate only a portion of 

### the plant. 

### I3 the 

### applicmt ovsrestirnates the emissions, this will 

### overstate the project's impact; pernit approval will be 

### more difficult to obtain. For example, 

### in nonatsainment areas, the applicant would have to develop more emission offs?ts than necessary, since the emission increases from his 

### project hzve Seen overestimated. 

### In permitting 

### of new ..pro jeets, the need fgr 

### an ezrly 

### valid estizate 05



# - emissions is 

### now obvious. kstinating poPluzant emlsslor.~Frcn ;c;:E~, 

### sources, such 

### as furnace stacks, is 

### relativeiy simple skce :h:s 

### involves 

### a st~aightforward engineering calculation., i3ut predic~ing fugitive emissions is 

### somewhat 

### less accurate; however, the procedure is 

### becoming more standardized as more data oecomes avallaSle. 

# - ,he procedure for estimatiDg fugitive 

### missions generally invcl-~es 

### four basic steps as outlined oelow.
1. 

### Obtain Design Data 

### This includes equipment counts (e=g.

### , valves and pumps)\, cooling tower rate, waste 

### water effluent Pate, product loadlng rates, and tankage information. Equipment counts-are usually the most diff~cult to predict. Since permitting requires such large lead times, final pip~ng and instrumentation diagrams are usually not available for develo~ing accurate equipment counts. The applicant has to estimate the equipment counts based upon actual equipment counts for 

### similar existing process units or based upon the Radian report1 which quotes 

### average equipment-counts for many typical process units from 13 U.S. 

### roflneyies. 

### It Is advisable for the 

### applicant to have his 

### engineering star: review these equipmenc counts for reasonaoleness ~efore tne Infornztion 

### is submitted to the permitting agency. Some agencies nay require 

### an adjustment in the permit after the new plant starts up Sased U~CC 

### the I & 

### M 

### prograrn for that new plant. Therefore, to avoid any surprises, such as being required to supply extra emission offsets affer startup, the emission estimate in a permit application should be 

### as accurate 

### as possible. 2. 

### Select Emission Factors Emission factors are average measured emission rates per ea*uiprr.ent unit. For example, the 

### Radian report states the emission factor for 

### light liquid valves Is 0.024 

### 1b/hr valve. Developing valid ernissL3n factors usually requires sampling very large populations 

### of similar 

### sources. It 

### appears that the most widely accepted fugitive faczors currently are those quoted in the Radian repor?l.-

## - 3. .4gree on Control Efficiency

n 

### Emission factors are usually quoted on an mconzrolled bzsls. ~ke 

### appiicant and the permitting agency then have co agree on the coct~ol efficiencies to assume the specific types or' 

### conci-ol mechanisms. ?ermitting agencies usually have set standard concrol efficiencies for frequently used controls. It 

### is 

### advisable for the applicant to contact the permitting agency before submitting his application In order tc resolve what contra1 efficiencies to use 2nd to zvoid surprises later when the application 

### is reviewed. 4. 

### Calculate the Emission Rates By the time the applicant gets to Step 4, about gC; 

### of the work of estimating emissions 

### is done. The actual calculation step is 

### quite straightforward and easy. It 

### simply involves 

### nultl?lying tc31tker the 

### numbers from Steps 1, 

### 2, 

### and 

### 3. As 

### an exaiiiple, fcr ernlssions from light liquid valves in a typical hydrocracker, we have: Equipment Units = 

### 380 Light Liquid Valves (Basis: 

### 3adian Report) Emission Factor = 

### 0.024 Lb/Hr Valve (Basis: Radian Report) Control Efficiency = 

### 65% (Basis: El Segundo I & ?4 

### Program)
Emission 

### Rate = 

### (Equipment Units)(Ernission Factor)(l-Efficiency)

= 

### 3.2 Lb/Hr Hydrocarbon

The major problem in estimating fugitive emissions is 

### not the final calculation step. The problem is 

### almost always 

### the first step where the applicant has to develop quite specific design data (e.g., valve counts) early 

### in the project schedule when the overall scope of the project 

### is usually preliminary and subject to change. Trying to determine exact equipment counts for 2 

### proposed 2roJect xnile stlll 

### 1z 

### the design phase 

### is extremely difficult. 3ut for the sake of ~erxlzting, specific numbers must be supplied; this is 

### where experi3nce witz I & 

### M 

### programs for existing fugitive sources becomes a significant asset.
CONCLUSIONS In summary, several years of' experience with 

### refinery fugitlve ernission rules support the following conclusions:1. 

### The dzta from the valve I & 

### M progrzn currently show 

### a net economic return due to ?educed stock lssses when the 3aaian- emissloc factars are used. 2ecrezsing the emission fectors or increasing :he inspection frequency would adversely zff3ct :ke cost effectiveness. The flange 

### I & M 

### program has not yet been completely evaluated.
2. 

### The I & 

### M 

### programfor pumps and compressors Is 

### a relatively cost efzective program'from 

### a regulatory agency's viewpoLnt. It 

### Is an expensive program to operate, but the cost effectiveness 

### is better than most other hydrocarbon reduction strategies currently under consideration for petroleum refineries. 

### 3. Future emission reductlon rules wiil 

### be nore expensive to comply with, and the emission reductions will 

### be smaller. Industry should participate in the regulatory eevelopmect to nake sure that the most cost-effective controls are used first. All 

### sources, mobile and stationary, should be evaluated.
4. 

### Estimating fugitive emissions 

### is 

### a critlcal part of obtaining construction permits for most new projects. Current 

### I & 

### M 

### programs provide ayahable data base which helps to expedite the permitting process.

.

### - References
I. 

### Mesich, Frank C., 

### Radian Corporation, "Results of Measurement and Characterization of Atmos.pheric Emissions from Petroleum Refineries," presented at Symposium on Atmospheric Emissions from Petroleum Refineries (November 1979, Austin, Texas)

# . 2. 

### Tichenor, 

### B. A., 

### Hustvedt, K. C., 

### Weber, R. C., 

### U.S. 

### Environmental Protection Agency, "Controlling Petroleum Refinery Fugitive Emissions Via 

### Leak Detection and Repair," presented at Symposium on Atmospheric Emissions from Petroleum Refineries (November 1979, Austin, Texas).Amoco Production Company 16825Worthchase Grwe 2.2s; Sff~ce 32x-1381 4ous:sr. -axas '-2:O
Robert E. Mahaffey Manager. Plant Engmeermg ana Construct~on [USA) 

### March 18, 1982 

### Emission Standards and 

### Engineering Division ()10-13) 

### Environmental Protection Agency Research Triangle Park, North Carolina 27711 

### Attention: Fred Porter Re: Control Techniques Guide1i

### ne Document Equipment Leaks from Natural Gas/Gasoline Plants

In 

### accordance with the notice contained in the January 25, 1982 

### Federal Register, Amoco Production Company (USA) we1

### ccmes this opportunity to comment 

### on the referenced document. Amoco Production Company (USA) 

### is 

### an oil and gas exploration and 

### production company which operates 40 

### gas processing plants in the U.S. 

### The natu,ral gas/gasoline plant-Industryhas 

### an interest in keeping fugitive emissions 

### to aminimum. The economic value of the hydrocarbons and 

### the conservation of 

### a valuable natural resource as well as protection of the environment are a1

### 1 important considerations. We 

### feel the gas processing plants can maintain a low level of volatile organic emissions without the necessity of the detai1

### ed monitoring and 

### record keeping proposed in the 

### CTG document. A 

### much more cost effective procedure could be based 

### on ambient concentration monitoring 

### ator near the plant boundary. Such 

### a systemwould provide more continuous data of any releases that escape from the plant. If 

### an abnormal concentration is detected, then 

### a two step operation should be set in motion. First, the plant maintenance force would 

### be notified and 

### they would seek 

### toreduce the concentration 

### tonormal levels. Second, 

### on those occasions when the maintenance force was not imnediately successful, 

### a detailed monitoring 

### program would 

### begin. There seems to be 

### no standard concerning the sizes and 

### configuration of the sampling probe for the monitoring instrument. The probe tip

### must of necessity be quite small in order 

### toreach the less accessible points around small valves and 

### flanges. This will likely make sampling less than precise and 

### subject 

### to varying di1 ution effects.a 

### Page 

### 2



### Comments for

### the specific 

### parzgraphs ofthe 

### Guideline Document are attached 

### hereto. If 

### we can be 

### of 

### further assistance, please fee 

### free to call 

### on Dr. 

### Lyman Yarborough 

### at 713-931-2943.

R. 

### E. Mahaffey 

### LEP/pdh 221/Y

### AMOCO 

### PRODUCTION CCMPAk!Y (USA) 

### Comments Re: Ccntrol Techniques Guideline Document; Equipment Leaks from Natural Gas/Gasoline Processing Plant The sketch shown in Fig. 2-1 indicates "methane to sal-es". It is felt that this is not meant 

### tobe compositionally specific since most sales streams also contain ethane and frequently smaller quantities cf the heavier molecular weight hydrocarbon as well as some inerts; i.e., 

### nitrogen ana carbon dioxi de. Re: 3.1.2.2 Compressor Page 3-3 Installation of the additional valves (checks and blocks) will be expensive and potentially requjre downtime for installation. Operation of the vent space at a 

### pressure of 

### 15 

### to 20 

### psig will not be possible without rather extensive rodif i

### cacicn o' 

### many machines. The distance piece enclosure of 

### many nachines 

### will not stand 15 

### to 20 

### psig. The door seal may not be suitable for this type service. The pressure may force volumes of hydrocarbcns into the compressor crankcase, ruining <he lubricating oil, 

### causing engine damage and significantly increasing the danger of 

### a crankcase explosion. Compressor manufacturers could provide details about the requirements of the specific machines. To permit operation oT pressured distance pieces for most compressors would require reconstruction of the cylinder, new compressor rods repiping all the process gas side of the cylinder, and possibly modification of the compressor building floor and walls. This would be prohibitively expensive and would require significant downtime 

### on each machine. If 

### vent lines are installed from compressors, the sizing should 

### be increasqd to 1 

### 112 or 

### 2", at least for the headers, to reduce pressure buildup potential. Re: 3.1.2.3 

### Relief Valves Page 

### 3-4 

### Many vessels have been installed without block valves to permit re1ief valve removal and removal of such valves nay reauire ;arge hydrocarbon emissions while depressing the vessel and/or its

,

### operating system and require expenditure of hundred of do11

### ars

per valve. Many relief valves are installed in 

### rather inaccessibie locations. It

### would not be uncommon to require a crane be 

### brought to the plant siteto facilitate re1ief valve removal. In 

### these cases, costs of thousands of 

### dollars per valve can be expected.

### gelieivzlves thus 1

### ocated wi

### 11 

### be difficult 

### to nonitor and checking at 1

### to 3 

### years interva7s (depending upon 

### the service) is suggested. The construction of 

### re1ief valves (metal to

### metal seats) makes zero emission difficult, especially after the valve has operated one time. Testing a 

### relief valve for leaks by use of a hyarocarbon detector may be unrealistic since even a minor leak into the re1ief valve stack aay., over a period 

### of time, displace all orpart of the air and result in

### a high hydrocarbon indication, particulzrly if 

### the hydrocar~on vapor isheavier than air. 5.1.3.3 

### Allowable Interval Before hair Page 3-8 

### The 

### time interval for repair of 

### a leak after itsdiscovery is currently proposed to be 

### 15 

### days. )!e suggest that the operator be permitted more flexibility in scheduling this work. As accepted practice, most operators wi11 repair significant leaks as soon as practical after they are observed, without waiting for a specified monitoring period. The operator seeks to

### minimize leakage and prevent further damage to his equipment. However, there can be 

### a need toorder and 

### receive maintenance supplies before proceeding. For minor problems, the 15 

### day figure can be reasonable but 

### times

.- 

### of 60 

### days 

### or even much longer times should be made acceptable. There are some repairs that cannot be made without 

### a plant shutdown. The calculation 

### of 98%

### efficiency for a 

### 15 day repair period seems touse 365 

### days (1

### year) as a basis. This seems 

### to imply one leak per year per piece of equipment, wh.ich is unrealistic. Static equipment, (flanges, valves) nay be in operation for 10, 

### 20, even 30 years withcut 

### a failure 

### or leakage 

### of any kind. 3.2.2

# - Open-Ended Lines

# - Page 3-13 

### The CTG 

### advocates plugging 

### or 

### capping flanging or valving all open ended lines. Many open-ended lines are vents installed for safety purposes. Capping or plugging those lines will result in added danger to personnel and 

### equipment. Some of those 1

### ines might conceivably be routed 

### to a flare system but 

### others must be left free 

### to prevent cross contamination or back pressure against a piece of equipment. The CTG 

### recognizes that the caps or 

### plugs cannot eliminate the emissions from the firstvalve, only that it's release is controlled. The technique then becomes of questionable value. 3.3 

### Other Control Strategies Page 3-15 

### Section 3.3 

### recognizes that valves will have a 

### much lower leak frequency than compressors, pumps, and 

### relief valves and 

### suggests

### that quarterly inspections ray not 

### be necessary. This rationale is even more applicable toflanges and 

### connections and 

### the extension of time between inspections is most appropriate. Due to the low leak frequency of valves and 

### connections, it

### is suggested that these items be removed from the monizor'ng program. ~ables 4-5 and 

### 4-6 

### Energy Recovery Credits Page 4-8 and 

### 4-9 These tables allow recovery energy credits for all 

### estimated emissions (

### 100 per cent reduction) from open ended 1i

### nes

## . This seems 

### tobe an error since Section 3.2.2 had 

### recognized that much of this emission could not be stopped. In many other instances, the open ended vents would be routed 

### to flare and 

### energy recovery credits would 

### not be applicable. This error is also reflected in 

### the cost analysis of RACT 

### (Section 5). 

### Section 5.0 

### Control Cost Analysis of 

### RACT 

### Page 5-1 

### Many of the cost figures shown in 

### this section appear understated 

# ! and, 

### in addition, the costs do 

### not seem 

### to allow anything other than ideal work conditions and 

### new materia1s

## , i


# .e. 

### , no charges are shown for pipe support material. Costs at the eler plants, especially where attendance isminimal, are likely 

### to be much higher per unit of

### emission reduction. Such plants will be forced 

### to call upon outside assistance. Table 5.2 

### and 5.4 

### Labor Requirements Page 5-5 and 5-8 These tables show zero labor time and cost for relief valve repair 

### on the condition that 

### these repairs would be done by 

### routine maintenance. The repair of compressor and 

### pump 

### seals would also be done routinely as needed. It seems inconsistent 

### to charge the emission reduction program with the cost associated with one repair and 

### not another. The monitoring times shown for valves seem inordinately low. Only 1minute per valve isestimated. The instrument response time alone may be as long as 

### 30 seconds. Sampling procedure specifies moving the Probe slowly along the interface periphery while observing the instrument readout. Atthe point of maximum readout, the Probe is held stationary for 

### atleast twice the instrument response time. ,Oncethis has been noted (record keeping is required) the operator procedes 

### to the next valve. Considering 

### a11 the calibration time, instrument warmup, care and maintenance of the instrument and 

### associated gas supplies, as we11 

### as the testing procedure, the time required could easi1y 

### be 5 

### minutes or more per test. The tables of moni.toring times and 

### cost do 

### not show sampling times for flanges and 

### connections. There are generally 

### a large number of these devices in 

### the plants and 

### by 

### the very nature of

### their 

### construction, the test tine 

### per unit

### will be 

### substantially 

### greater than 

### for a valve.

L. 

## E. Petty 

### Room 579, 

### Ext. 2941 

### GP 

### I11

- 

### LEP/pdh 221/YSOUTHERN CALIFORNIADIV1S;ON 3333M1CHELSC)N DRIVE IRVINE.CALIFC3IJIA927313 TELEPHONE:(714)975-2003 TELEX: 6924%



### Mr. Jack R. 

### Farmer Chief Chemical

### s and Petroleum Eranch Emissions Standards and Engineering Division U.S. 

### Environmental Protection Agency Research Triangle Park, North Carolina 27711 

### Dear Sir: 

### He have reviewed the draft document "Control of Volatile Orcjanic Compound Equipment Leaks From Natural Gas/Gasol ine Processing Plants." We suggest that if EPA conducts periodic inspections of plants, only those facilities found not to be in reasonable compliance with guide1ines be required to compile reports and be subjected to quarterly inspection. This practice will significantly reduce the burden of paperwork and 

### costs to both 

### industry and 

### EPA and still achieve 

### the same overall goal. Thank you very much for the opportunity 

### to comment on the draft guidelines. Very truly yours, I

!,li7

### 1

### iam 1.1. 

### Hathaway 

### Vice President, Process Engineering

Senior Manager, Environmenial Engineerin: 

## 6-APPENDIX D SUMMARY AND RESPONSES TO DRAFT CTG COMMENTS

### AP,PENDIX 

### D SUMMARY AND RESPONSES TO 

### DRAFT CTG COMMENTS

On January 25, 1982, the Environmental Protection Agency (EPA) announced the re1 ease ofthe draft control techniques guideline (CTG) document for control of volatile organic compound (VOC) emissions from equipment leaks innatural gaslgasolineprocessing plants (gas plants) inthe Federal Register (47 FR 3403). Public comments were requested
on the draft CTG and comments were received by industry representatives
as listed inTable D-1. The comments that were submitted, along with response tothese comments, are summarized inthis appendix. This summary of comments and responses serves as the basis for revisions made tothe draft CTG. D.l GENERAL Cment: One commenter (5)requested that the comment period be extended togive industry more time tofurther analyze these complex regulations. Response: The CTG incorporates p.ublic comments from the preliminary draft CTG (March 1981) presented tothe National Air-Pol1 ution Control Techniques Advisory Committee (NAPCTAC) inApril 1981 and comments received on the draft CTG (December 1981) that was announced inthe Federal Register January 25, 1982 (47 FR 3403). Comments were also



## - received at the NAPCTAC meeting (July 1982) for the gas plants NSPS and these have also been addressed inthe CTG as applicable. EPA has been working with industry since the inception of the gas plants NSPS/CTG projects inDecember of 1979. Therefore, there has been ample time for public comment.D.2 NEED FOR CTG Comment: One commenter (8) questions ingeneral, the need for the standard stating that EPA has failed todemonstrate the effectiveness of the control measures proposed and has misrepresented the costs and cost effectiveness. Response: National Ambient Air Qua1 ityStandards (NAAQS) (Section 109 of the Clean AirAct) set a ceiling for public exposure tocriteria pollutants by establishingan ambient concentration level that must not be exceeded anywhere inthe United States. This control techniques guidelines document will provide guidance toStates and air pollution control agencies for RACT-based provisi ons applicab1e to gas plant faci1 ities to reduce significantly volatile organic compound emissions toachieve and maintain NAAQS for ozone. The CTG environmental and cost impacts are based upon actual field studies ingas plants and on comnents received on the draft CTG and on similar fugitive VOC control projects. Specific comments on the controls, costs, and cost effectiveness of RACT are addressed inthe following sections. Comment : Another commenter (9) wrote that leak prevention and control procedures are already inplace at most natural gas plants incompliance with minimum federal safety standards. Proposed requirements are repetitious and burdensome. Response: The commenter isapparently referringtooccupational safety requirements which have different purposes and may result indifferent environmental benefits. Present industry practices (e.g., enclosing compressor distance pieces and venting emissions outside of a compressor house) may reduce occupational exposures, but they do not necessarily reduce the mass emissions tothe atmosphere. The data base upon which these recommendations are made isfrom plants incompliance with existing rules. These data show gas plants have significant emissions and that cost-effective controls wi11 reduce these emissions.D.3 APPLICABILITY Comment: One commenter (3) argued that small plants (10 vessels or fewer) should be exempt from RACT based on cost effectiveness (benefits don't outweigh c~sts per Executive Order 12291). Response: InSection 4.1 a small plant cutoff is recommended based on cost effectiveness of RACT. Small plants may need to rely upon outside personnel toperformthe leak detection and repair program and, hence, may incur higher costs per unit of emission reduction to implement RACT than large gas plants. Section 3.4.2 provides the basis for the small plant cut-off. Comment : Another commenter (8) wrote that components with less than 10 percent VOC by weight should be excluded. Response: Based on API testing, sources with less than 10 percent VOC have significant emissions

### ,therefore, EPA has not exempted these sources. However, it seems reasonable that at some low percentage of VOC, sources would have very 1imited VOC emission reduction potential. Therefore, dry gas equipment (less than 1weight percent VOC) are exempt from RACT as described inSection 4.1 Comment: A commenter (4) noted that the liquidand gas processes performed at underground gas storage facilities are few and simple and, therefore, should be excluded from the definition of a natural gaslgasoline storage operation. Since there isno potential for leakage from components operating at negative pressure, another commenter (8) requested that these components be exempt from the CTG. Response: €PA concurs with the comments, therefore, the description of RACT inSection 4.1 exempts equipment at underground storage facilities and equipment which operate under vacuum service.D.4 CONTROL TECHNOLOGY D.4.1 Compressors Comment: One commenter (8) wrote that reducing VOC emissions from compressors below 10,000 ppmv isdifficult and impractical. Res~onse : EPA recognizes that compressor repair toachieve organics concentrations below 10,000 ppmv may be difficult and impractical for reciprocating compressors with packed seals. Therefore, alternative RACT impacts are based on compressor seal vent control systems. Nevertheless, leak detection and repair would be requi red (unless a vent control system is installed) inthose instances where repair can achieve VOC emission concentrations below 10,000 ppmv. Centrifugal compressors may operate intandem, one inservice while the other
serves as a spare. Insuch instances seal repair may be performed without need for a process unit shutdown. Comment: Several commenters (2,6,8,10,11) remarked that many compressors are not designed tooperate with back pressure against the distance piece; enclosing and venting emissions from compressor seals and the distance piece poses mechanical and safety problems. The enclosed VOC air mixture could reach explosive 1 imi ts. Enclosing compressors would requireextensive modifi cation which would be expensive and require significant downtime. Response: Many compressors are equipped with enclosed distance pieces. Enclosed distance piece emissions are generally vented outside of compressor houses; however, these emissions .can be safely vented toa VOC control device (e.g. flare). EPA has reconsidered the safety and cost aspects of venting compressor distance piece emissions. The Chapter 5 cost analysis has been ,revisedto include necessary safety equipment for a compressor distance piece purge system. However, if plant owners/operators can demonstrate that enclosing and venting emissions from distance pieces and seal packing vents iseither unsafe
or requires unreasonable cost such as replacement of the compressor,these compressors may be exempt from RACT. Most compressor seal packing vents can be vented toa VOC control device. Comment: Another commenter (10) stated that since compressor emissions represent only 3 percent of total gas plant emissions, they should not be covered. Response: The gas plant compressor seal emission factors used inthe draft CTG are based on emiss.ion measurements from open reciprocating compressor distance pieces and does not include seal vent emissions or measurement of emissions from distance pieces that are enclosed and vented outside of a compressor house toatmosphere. The data base also includes dry gas compressors, which are exempt from RACT requirements. The gas plants compressor seal emission factors have, therefore, been revised.l Using the revised emission factors inthe model plants (see Table 2.2), compressor s e a l s contribute approximately 14 percent of total ernissions

# . For the actual equipment counts found during API and EPA testing, compressor VOC emissions ranged from 0-42 percent and averaged 13 per'cent.2 Therefore, compressor emissions are significant and emission control isconsidered. D.4.2 Leak Detection and Repair Methods Comment: Two commenters (8 and 10) wrote that isolating a pump and purging before repair (repacking or seal rep1 acement) is not practical

# . Flushing fluiddisposal isa problem. Another commenter (9) further questioned whether emissions resulting from pump repair might offset long-term benefits, depending on the extent of the original leak. Another commenter (5) noted that the venting of gas during repair of fugitive emission sources isnot included inemissions estimates or in computing recovery credits. Res~onse : Process industry pumps are now routinely isolated and purged priorto repair. Flushing fluid is routed tothe oily storm sewer for treatment and disposal. This fluid isexpected to be a small percentage of total plant waste. RACT does not mandate purging pumps priorto repair although a pump would normally be emptied prior to repair.Even ifthe pump were not purged and all process fluid ina pump were allowed toevaporate toatmosphere as a result of pump repair, these emissions are approximately equivalent tothe mass emissions released toatmosphere by a leaking pump over a 3-day period, 9 kg. This would not offset the long-term benefits of RACT. The final comment isbased on RACT requiriig shutdown and purge for repair of leaking equipment. The draft CTG included a provision that required repair of a11 leaks within one year of detection. RACT has been revised.such that repairs requiring a unit shutdown may be delayed until the next scheduled shutdown. As such, RACT no longer requiresyearly turnaround for repair of these equipment leaks. However, as discussed inSection 3.4.3, a State agency might wish to consider a provision inits regulation which would a1low the Agency director toorder an early unit shutdown for repair of leaking components incases where the percentage of leaking components awaiting repair at unit turnaround becomes excessive. Comment: Commenters (3and 9) stated that facilities already have portable monitoring instruments (for safety purposes) that are effective and less costly than the recommended monitors. Facilities should be allowed to use their own monitors. The recommended monitors are temperamental, sensitive to heat, humidity, and type of gas sampled, and thei

### r required use can place a f inancia1 burden on small faci1 ities. Response: Facilities may use any instrument as long as it satisfies the requirements specified inReference Method 21. EPA recognizes that monitoring instruments wi11 require periodic maintenance and has accounted for instrument maintenance in the annual cost of implementing the leak detection and repair program, including the cost of a spare instrument. Nevertheless, EPA agrees that small faci1ities (plants with few equipment pieces) may incur higher costs per emission reduction and, therefore, as noted inSection 4.1 and D.3, small plants are exempted from RACT. Coimnent: 

### One comnenter (8) wrote that soap sco~ing should be a1lowed as a 

### VOC detection method.Response: Soaping ispemi tted as a preliminary screening technique on certain equipment pieces as discussed inSection 3.1.1. Comment: Several comments (6, 8, 10 and 11) were received stating that EPA should extend the 15-day repair interval. One commenter suggested that repair should be completed during the next regular maintenance

: period, while others suggested repair within 30 days and 60 days for repairs that requirehard to get parts. Response: The 15-day repair interval was selected for RACT because it a1lows operators sufficient time to accomplis-h repairs whi1 e achieving effective emission reduction. Most repairs can be completed quickly, while a few may take up to 

### 15 days. Repair intervals beyond -15 days reduce the effectiveness of emission reductions and do not substantially improve the efficiency inhandling complex repair tasks. If repair is not technically feasible without shutting down the process unit, repair may be delayed until the equipment can be isolated for repair orduring the next scheduled process unit turnaround. Comment: Another commenter (10) stated that unsafe and difficult-to-moni tor components should be considered. Response: Guidelines are included inthe CTG for less frequent monitoring of equipment pieces that are difficult-to-monitor. Guidelines, however, do not address unsafe components because such equipment components are not found ingas plants. Comment: Two commenters (8 and 10) wrote that EPA should consider annual inspections because existing data (Eaton, 1980) dispute quarterly nonitoring for a11 valves, pumps, and re1ief valves. Quarterlyinspections
are practical only for a relatively small number of major components (e.g. compressors). Response: EPA data and models presented inthe EPA report, "Fugitive Emission Sources of Organic Compounds --*Additional Information on Emissions,
D-8

### i Emission Reductions, and Costs", EPA 45013-82-010, April 1982, (AID), show quarterly monitoring tobe reasonable as discussed inChapter 5. The Eaton data, as discussed inAppendix A, support the data used in the analyses. Comnt : For the "skip-period" monitoring alternative work practice for valves, one commenter (10) suggested that EPA should a11 ow 1 ess frequent than. annual inspections for valves ifdata indicate that a 1 onger interval would keep the leak rate less than 2 percent. This concept should apply toother fittings as well as valves. Response: Indeveloping skip-period monitoring, EPA did not consider inspection intervals longer than one year. Inskip-lot sampling theory it is assumed that failures do not accumulate with time. For skip period monitoring, it islikely that leaks that occur will not be detected and wi11 accumulate. EPA does not feel it.is reasonable toa1low leaks toaccumulate for greater than one year.4 Facilitieswith very low leak percentages may,, however, elect tocomply with the allowable percent leaking alternative. "Skip" monitoring isnot allowed for other sources because there
are not enough other sources present for the statistics of skip monitoring toapply. Inaddition, leaks from these other sources are not as predictable as leaks from valves. Valves develop leaks slowly over time with small percent increases over a given time interval, whereas .- other sources might operate with low leak rates for long periods of time and tKen fail instantaneously with sudden increases inleak rates. Consequently, no matter how many consecutive successful inspecti~ns
are performed, there is littleassurance that a low leak ratewould continue ifskipping were a11 owed. Comment : The same commenter (10) a1so questioned emissions reduction estimates statingthat 100 percent emission reduction (Table 4-2) for compressor controls isnot realistic. Chevron's leak detection and repai

### r program of quarterly inspections reduces 

### emi

### ssions by 

### 35 percent.Response: The assumption that compressor controls reduce emissions by 100 percent isbased on enclosing compressors and venting emissions to
a control device rather than on leak detection and repair programs. EPA has recalculated the impacts of RACT based on quarterly leak detection and repair (assuming gas plants can use leak detection and repair) and determined an emission reduction of 83 percent. EPA maintaiqs that enclosing and venting seal emissions toa control device will result inessentially 100 percent control. Comnent: Another cormenter (11) remarked that achieving zero emissions from relief valves isdifficult due tothe metal-to-metal seat construction. Testing relief valves for leaks by using hydrocarbon detectors may be unrealistic because even minor leakage intothe relief valve stack might give a high hydrocarbon reading, particularly ifthe hydrocarbon vapor isheavier than air. Res~onse : RACT for safety relief valves does not require zero emissions as the commenter implied. Rather, quarterly leak detection and repair is required which results inapproximately a 63 percent VOC (69 percent THC) emission reduction efficiency. A1so, re1ief valves may be designed toutilize an elastomeric O-ring seat as a backup tothe conventional metal-to-metal seat while any leakage iscontrolled by the elastomeric O-ring seat. Relief valves with O-ring seats have been tested and found to be bubble tight up toover 95 percent of set pressure and to reseat tothis condition through several cycles. Finally, Method 21 specifies that re1ief valves be monitored at (and not in)the relief valve opening (horn), so minor leakage should not be detected. Comment: One commenter (6) noted that pressure relief valves can be vented toa plant flarewhere VOC would be combusted. Response: A flare or other VOC control device (i.e., process heater, carbon adsorption unit, refrigeration unit, gas recovery compressors) can be used toeffectively control relief valve leakage and are allowed under RACT.Comment : One commenter (11) expressed concern that the removal of pressure re1ief valves may result inlarge emissions from depressurizing vessels at a cost of hundreds of dollars per valve (thousands of do1lars per inaccessible valve)

# . Response: Three-way valves or block valves may already be inplace to isolate pressure re1ief valves for repair on-1ine without depressuring the unit. If so, repair within 15 days should be accomplished. However, ifpressure relief devices cannot be isolated for repair on line, repair can be delayed until the next process unit turnaround. 

### D.4.3 Technology Transfer Comment: One commenter 

### (7) wrote that there is no technical basis for the transferability of chemical plant or refinery VOC emissions data to natural gas plants because the processes, feedstocks, operating temperature, operating pressures, vibrational problems and product compositions are different; EPA should address these differences and give supporting data for techno1ogy transfer. Response: EPA recognizes that differences exist between chemical and refinery process.units and gas plants; however, these differences do not preclude the transfer of control technology tothe gas processing industry. In testing conducted inethylene plants, process conditions approximate that of equipment pieces incryogenic units of gas plants. In addition, only a small proportion of gas plant equipment are subject toconditions which are unlike that of chemical or refinery process units. Finally, the parameters addressed by the commenter either do not affect the frequency of emissions or are unquantifiable. InAPI testing of the natural gas production industry, the process type, operating temperature and pressure, and line size were determined to be unrelated toequipment leaks early inthe testing program; therefore, the recording of these data was discontinued. Feedstocks and product chemical types have been found tobe important only interms of vapor pressure; as a result, heavy 1 iquids have been exempt from routine monitoring. Vibrational problems and other si te-specif ic differences are unquantifiable.D.4.4 Gas Operated Control Valves Comment: One commenter (10) stated that there are no emission factors given for gas operated control valves nor indication of how many are used. There are very littlenonmethane/nonethane hydrocarbons present ingas operated control valves. Similarly, another commenter (9) argued that because many remote natural gas gathering stations use gas operated control valves, compressed air isnot acceptable RACT. Response: Gas operated control valves normally use air. Inthose instances inwhich gas isused tooperate control valves, dry gas (methane and ethane) isnormally used. Since RACT exempts dry gas service equipment, the recommendation for controlling gas operated control valves is deleted from RACT. Further, the RACT recommendations are for gas plants and not for natural gas gathering stations. 

### D.5 MODEL PLANTS Comment: Two commenters (8and 10) questioned the model plants. One remarked that EPA should have included all four of the EPA-tested gas plants, or EPA should explain the reason for including only two of the plants inthe vessel and component inventories. In addition, the component inventories at the two API-tested plants are unusually large and of questionable value in developing model pl ant configurations. Another wrote that the method of ratioing components to all vessels combined (columns, heat exchangers, drumltanks) isan oversimpli fi cation, as indicated by Table 

### 0-3 of the draft CTG. Response: The model plants are based on four rather than on six plant visits because the last two EPA-tested plants were visited after the model plants were derived. Furthermore, as stated inAppendix B, the latter two plant visits did not obtain information on vessel or equipment inventories. The purpose of model plants i s t ocharacterize the range of processing complexity. The diversity within the gas production industry is represented inthe four gas plants were examined and isshown inthe three model plants selected. Inaddition, the cost effectiveness ofRACT controls are independent of the number of pieces of equipment because there are no economies of scale for leak detection and repair programs. 0.6 ENVIRONMENTAL IMPACT Comment: Two commenters (2 and 6) maintained that the test data base on which emission reduction estimates are based is limited (only 6 plants). They contended that the test data are not statistically sound and should be expanded to obtain a more representative sample. Response: Emissions test data are used toestimate the magnitude of fugitive emissions and the magnitude of potential emission reductions through the application of reasonably avai1able control techniques

# . For this purpose, the emissions test data obtained from gas plants indicate that significant emissions are re1 eased toatmosphere from 1 eaking equipment and that implementation of the RACT requirements will reduce these emissions.. Comment: Two commenters (5and 6) noted that other factors should be considered (besides the number of components) inestimating emissions (e.g., system pressure, equipment age, climate, past performance, gas composition, differences inplant type, size, total fluid mix, etc.) Response: €PA has conducted numerous equipment emissions studies at petroleum refineries, synthetic organic chemical manufacturing plants 

## ,gas plants, coke oven by-product plants, etc., as discussed indetail in "Fugitive Emission Sources of Organic Compounds--Additional Information
on Ernissions, Emission Reductions, and Costs

# ." U.S. Environmental Protection Agency, Research Triangle Park. EPA-450/3-82-010. April 1982. The major conclusions drawn from these studies are that the only equipment or process variable found tocorrelate with fugitive emissions was the volatility and/or phase of the process stream. Consistent with tothis finding, RACT for gas plants exempts equipment that contact or contain heavy liquidVOC. Other variables such as linetemperature and pressure indicated much lower degrees of correlation.Comments: Another commenter (6) wrote that the method for obtaining emission rates needs tobe described inmore detai1. The commenter specifically questioned how EPA derives emission factors from concentrations measured by a hydrocarbon analyzer without measuring actual flow rate. Response: Equipment emission .rateswere determined by enclosing the emission sources and measuring mass emissions

# . The screening values, simu1

# - taneously measured, were correlated tothe measured leak rate. The derivation of emission factors ispresented in "On-shore Production of Crude Oi1 and Natural Gas-Fugitive Volatile Organic Compound €mission Sources-Data Analysis Report Frequency of Leak Occurrence and Emission Factors for Natural Gas Liquid Plants

## ,"U.S. Environmental Protection Agency, Research Triangle Park, N.C. EMB Report No. 80-FOL-1. July 1982. The emission factor development method01ogy was reviewed by industry representatives and they determined that EPA's methods for emission factor development were appropriate.5 Comnent: One comment was received (11) stating that it iswrong toassume that 100 percent of emissions would be reduced by controls on open-ended lines. Inmany cases, open-ended vents would be routed toa flare, and energy recovery credits would not be applicab1e. Response: Capping an open-ended line limits emissions tothe amount of VOC trapped between the valve and cap (whether it be a plug, second valve, etc.) which is released when the 1 ine isagain opened. However, by closing the first valve prior to capping or closing the second valve, the safety of the technique isensured and emissions minimized. A conservative estimate of the amount of VOC trapped inthe lineand the frequency of open-ended line use, nevertheless, results inalmost 100 percent VOC control (as discussed inSection 

### 3.2.2). RACT for open-ended 1ines effectively controls emissions between each time the line isused.It appears as though the commenter has incorrectly assumed that process vents would need tobe capped. Any open-ended linethat i s i n use, a pressure relief valve, a double block and bleed line, or a process vent, would not be capped. Process vents could be routed to a flare, with no recovery credit as the commenter states, but this is not part of the requirements of RACT. D. 7 

### COST IMPACTS Comnent : Cornenters 

### (1and 

### 8) wrote that front end costs of RACT should not be combined with capital costs. For example, double valving open-ended lines and initial leak repair are front end expenses that should be considered as operating costs, and not capital costs to be amortized (and thus minimizing the impact of their expense inthe year when they are incurred). Response: Although the control cost of open-ended lines and.initia1 leak repai

### r could be treated as operating expenses because they are one-time start-up costs, for the purposes of this CTG they are treated as though they were capital costs and amortized. This assumes capital would be borrowed topay these initial costs. Comnent

### : Two comnenters (8and 10) remarked that estimates for monitoring times do not apply to gas plants and the costs are outdated. Monitoring labor charges 

### of $4/source for contractor labor and $3.50/source for plant personnel (not 

### including 1,eak repai

### r, resampl ing after repai

### r, or initial design, acquisition, or implementation of the monitoring network), as well as the current labor rate of $23/hr (as opposed to 

### EPA estimate of $18/hr) were offered. It was also argued that labor costs for leak detection should include: front end set-up cost, equipment depreciation, and instrument maintenance. Inaddition, the costs apply to ideal work conditions and new materials, and the costs at smaller plants will be much higher per emission reduction because they would have minimal attendance and would be forced to call upon outside assistance inimplementing RACT.Response: The monitoringtime estimates for plant equipment are based on the results of refinery inspections and have been corroborated in chemical plant testing. The EPA labor rate ($18/hr) isbased on June 1980 do1lars. Updating the EPA estimate topresent (June 1982) do1lars results ina labor ratethat exceeds the rate suggested ($18 x June 1982 Cost Index 295.91June 1980 Cost Index 210.5 = $26. Reference: Chemical 87(20):7 and

# - Engineering

## - 89(19):7). Set-up costs, equipment depreciation, and instrument maintenance costs are included inthe cost analysis. Leak detection costs account for field labor time only. Administrative, support, and instrument costs to implement RACT are itemized separately. The leak detection and repair costs are based on field monitoring under a11weather conditions. For model plant B, EPA's estimated costs fall within the range of costs the commenter quotes. With 750 valves maintained at 2-man-minutes per inspection and one fourth the annual instrument cost of $5,500, the cost per valve inspection is $2.67. Using the above cost indices this would update to $3.75 per source. The EPA agrees, however, that small plants may incur higher costs per emission reduction ifoutside personnel are relied upon to conduct the leak detection and repair program. Chapter 4, therefore, recommends
a small plant exemption from RACT (Section 4.1). Comment: One comnenter (8)'-wrotethat the costs for adding double valves
on open-ended lines are underestimated because these costs should include: recordkeeping, vehicle use, and source identification and tagging. In addition the commenter wrote that the cost estimate for capping open-ended 1 ines is based on the price of a one-inch screw-on type globe valve and the incorrect assumption that any lines larger than one inch can be reduced toone inch. The commenter suggested that EPA should review the 721 open-ended lines tested as r,eported in the CTG-Appendix A and base the costs on a distribution of line sizes. Response: Double valving an open-ended 1 ine does not require additional recordkeeping or tagging. The second valve is not subject tothevalve leak detection and repair requirements, but is considered as RACT. Complying with RACT, however, does not necessitate a second valve. Open-ended lines may be capped or 

### plugged. The basis for the cost estimate isthe price of a one-inch screw-on type globe valve which reflects the maximum cost likely incurred for open-ended line emissions control. Larger lines would likely have a blindflange installed at a similar cost, and smaller lines would be capped at a much lower cost. Coment: Similarly, the same commenter 

### (8) stated that leak repair costs are too low. Costs should include: recordkeeping, vehicle use, provisions for inaccessibility, repair parts, loss of'production and overtime. Cost of $12O/repaired valve and $10b0/repaired pump are realistic repair costs. Response: InChapter 

### 5, a $140/seal replacement cost isincluded inthe cost of pump repair. The cost analysis a1so includes annual miscellaneou! (0.04 x capital cost) and maintenance (0.05 

### x capital cost) costs plus
an annual calibration and maintenance cost for the monitoring equipment of $3000 (1980 do11 ars)

# . Administrative and support costs toimplement RACT (0.40 x monitoring labor 

### + maintenance labor) are also included. Very few valves wi11 require repacking. Chapter 4 includes provisions for less frequent monitoring of difficulttomonitor valves and repairs that cannot be completed on-1 ine. These repairs may be delayed until the next scheduled shutdown. Comnent: One respondent 

### (11) remarked that monitoringtime and costs are not included for flanges and connections. Resp-onse: Fl anges and connections need not be monitored routinely under RACT. Therefore, there are no monitoring time or costs assoc.4ated with it. Coment: One commenter 

### (10) was concerned that 

### RACT compressor controlcosts are too high inconsideration of their small proportion tototal emissions. The venting system would require extra valves for safety.The entire costs for the control system will exceed $700, and the cost of a small flare isabout $8000. Response: Section 5.5 presents revised control costs for contro11ing compressors based on public comments received on the enclosed compressor vent system. The cost effectiveness for the enclosed compressor vent control system a1so reflects revised emission factors for compressor seals. The revised compressor and emission factors are based on wet gas and natural gas 1 iquids compressors.l Data from dry gas service compressors was excluded because dry gas service components are exempt from RACT. Based on the revised cost effectiveness of enclosing compressors, wet gas reciprocating compressors at facilities that do not have a VOC control device are exempt from RACT. Comment: Simi1 arly, another commenter (9) expressed concern that the cost of a VOC monitoring instrument, itsmaintenance, and calibration are high compared tocurrent practices of leak detection. Response: The draft CTG has included the cost of two monitoring instruments, instrument maintenance calibration time, and two-man monitoringteams toobtain maximum cost impacts from implementation of RACT. InChapter 5, the costs of RACT including the maximum instrument costs are shown to be reasonable. Actual plant costs incurred may be much less because
one man monitoringteams may be employed and less expensive monitoring instruments may be purchased. Also, many equipment pieces will not require instrument monitoring ifsoaping isused as a preliminary screening technique. Comment: One commenter (8) pointed out that the value of recovery credits for VOC ($210/Mg) isincorrectly based on the assumption that all the VOC ispropane. Also, the value of the recovery credits is$146 if the correct product density for propane is used. Response: Recovery credits have been revised. Nonmethane/nonethane hydrocarbons
are valued at $192/Mg based on LPG price of 404/gallon for June 1980and a specific gravity of 0.55 (the original incorrect credit of $210/Mg was based on a specific gravity of 0.50). Methane and ethane
are valued at $61/Mg based on $1.46/Mcf of natural gas for June 1980, assuming a weight equivalent composition of 80 percent methane and 20 percent ethane at standard temperature and pressure. Comment: One commenter (10) stated that more frequent inspections than annual are not cost effective. Response: EPA has determined that quarterly leak detection and repair is cost effective and represents reasonably avai1 a b l e control techno1ogy

# . InChapter 5, Table 5-10 presents the cost effectiveness of quarterly leak detection and repair for valves, pumps, re1ief valves, and compressors. Comment : One commenter (10) wrote that incremental cost-effectiveness figures should be calculated for different inspection intervals. Response: The purpose of control technique guidelines (CTG) isto inform air pollution control agencies responsible for achieving and maintaining national ambient air qua1ity standards of reasonably available control technology (RACT)

# . These agencies may formulate their own regulations based upon the CTG; however, the CTG itself is not intended toevaluate a1ternative control strategies and the incremental cost effectiveness between the alternatives.D.8 References Memorandum. K.C. Hustvedt EPA:CPB toJames F. Durham, Revised Gas Plant Compressor Seal Emission Factor. February 10, 1983. Memorandum, Kent C. Hustvedt CPB:EPA toJames F. Durham, CPB:EPA, Estimated Compressor Seal VOC Emissions Contribution forAPI and EPA Tested Gas Plants. March 22, 1983. Memorandum, K.C. Hustvedt, EPA:CPB, toJ.F. Durham EPA:CPB, API/Rockwe1 1 Maintenance Data. December 9, 1982. ? Memorandum, Kent C. Hustvedt CPB:EPA toJames F. Durham CPB:EPA Skip Monitoringfor FugitiveEmission Sources. December 14, 1981. L e t t e r w i t h attachment from D.A. DuBose, Radian Corporation, to W.E. Kelly, EMB:EPA, July 22, .I982

# - attachments are Radian and. TRW report, of theJanuary 28, 1982 meeting withAPI on gas plant emission factors.h TECHNICAL REPORTDATA (Please readInsmcnonsonrhereverse before cornpiering) 1. REPORTNO. 2. 3. RECIPIENT'S ACCESSION NO. 

### ERA-450/ 3-&-007

4. TITLEANDSUBTITLE 5. REPORT DATE 

### Control of Volatile Organic Compound Equipment Leaks December 1983 

### from Natural Gas/Gasoline Processing 

### Plants- 6. PERFORMINGORGANIZATIONCODE 

### Gui

### deli

### ne Series
7. AUTHOR(S1 8. PERFORMINGORGANIZATION REPORT NO.

9. PERFCRMING ORGANIZATION NAMEANDADDRESS 10. PROGRAM ELEMENT NO. 

### Office of Air 

### QualityPlanning and Standards Environmental Protection Agency ll. CONTRACT/GRANT NO. 

### Research Triangle Park, ~orth carolina 27711 

## (

12. SPONSORING AGENSY NAMEANDADDRESS 13.TYPE OF REPORTAND PERIODCOVERED 

### Director of Air 

### qua1i

### ty Planning and 

### Standards 14.SPONSORING AGENCY CODE 

### Office of Air 

### Qua1 ityPlanning and Standards 2.S. 

### Environcental Protection !!gency EPA/

### 200/04 Research Triangle Park, North Carolina 27711
15. SUPPLEMENTARY NOTES

16. AaSTRACT 

### Control Technique Guidelines (CTG) 

### are issued for volatile organic compound (VOC) 

### equipment 1 eaks from natural gadgas01 ine processing plants to inform Regional, State, and local airpollution control agencies of reasonably availab1e control technology (RACT) fordevelopment of regulations necessary to attain the national ambient airquality standard forozone. This document contains information on RACT environmental and cost impacts.



# - 17. KEYWORDS AND DOCUMENT ANALYSIS
a. OESCRIPTORS b. IOENTlFIERS/OPEN ENDEDTERMS C. COSaTlField/Group Air 

### Pollution Gas/gasoli

### ne Processing Plants Pollution Control

. 

### Air 

### Po11 ution Control 13b Reasonably Avai1 ab1e Control Techno1ogy Volati1 e Organic Compounds (VOC)

18. DISTRIBUTION STATEMENT 19.SECURITY CLASS(ThisReporr) 21. NO. OF PAGES 

### Unclassified 173 Un1imited 120. SECURITY CLASSiThispage) 22. PRICE 

## I Unclassified 

## I EPA Form2220-1 (Rev. 4-77) .PREVIOUS EDITION ISOBSOLETE 

# 1