United States Office of Air Quality EPA-450/3-83-007 

Environmental Protection Planning and Standards December 1983 Agency Research Triangle Park NC 2771 1 

Air 

\ 

Guideline Series 

Control of Volatile 

Organic 

Compound 

~quipment Leaks 

from Natural 

GadGasoline 

Processing Plants 

Guideline Series 

Control of Volatile Organic 

Compound Equipment Leaks 

from Natural Gas/Gasoline 

Processing Plants 

Emission Standards and Engineering Division 

U.S. ENVIRONMENTAL PROTECTION AGENCY 

Office of Air, Noise, and Radiation 

Office of Air Quality Planning and Standards 

Research Triangle Park, North Carolina 2771 1 

December 1983 
GUIDELINE SERIES 


The guideline series of reports is issued by the Office of Air Quality Planning and Standards 

(OAQPS) to provide information to state and local air pollution.control agencies; for example, to 

provide guidance on the acquisition and processing of air quality data and on the planning and 

analysis requisite for the maintenance of air quality. Reports published in this series will be 

available - as supplies permit - from the Library Services Office (MD-35). U.S. Environmental 

Protection Agency, Research Triangle Park, North Carolina 2771 1, or for a nominal fee, from the 

National Technical Information Service, 5285 Port Royal Road, 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 Avail able 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 

(concl uded) 

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 Draft CTG Comments .... 0-1 

Table 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 


Table 


5-2 

5-3 

5-4 

5-5 

5-6 

LIST OF TABLES 

Page 

Base1 ine 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 Quarterly Monitoring .............. 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 ti a1 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 ....... 5-14 

LIST OF TABLES 

(concluded ) 

Tab1 e 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 Incl uded and Excl uded 


in Vessel Inventories for Model Plant 

Development. .................... B-4 


Number of Components in Hydrocarbon 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 for Three 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-Gas01 ine 

Processing. . . . . . . . . . . . . . . . . . . . . 2-2 


Figure 2-2 Diagram of a Simp1 e 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 Re1 ief Valve . . . . . . . 2-7 


Figure 3-1 Compressor Distance Piece Purge System. . . . . . . 3-15 


Figure 3-2 Cost-Effectiveness of Quarterly Leak Detection 

and Repair of Valves with Varying Initial Leak 

Frequency . . . . . . . . . . . . . . . . . . . . . 3-18 


Figure 3-3 Cost Effectiveness of Quarterly Leak Detection 

and Repair of Valves for Low Production 

Volume Units. . . . . . . . . . . . . . . . . . . . 3-23 

METRIC CONVERSION TABLE 

EPA pol icy is to express 31 1 qeasirrernenti Agency docmencs in 

metric units. List~d below are metric units us~d in t~isragort ,vi:h 

conversion factors to obtain equivalent Englisn ~nitr. A list 3f 

prefixes to metric units is a1 so prsent~d. 

To Convert Mu1ti ply Sy

Metric Unit Conversion iact~r 

centimeter (ciil) inc9 :in.) 

meter (m) feet (ft.) 

liter (1) g.S. ;alion (;al) 

cubic meter ( m 3 ) 1.5. gallon (la:) 

cubic fleter (m 3 ) 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 tip1 icaiion 

Pref ix Factor 

tera 10l2 

gigs 10 

mega lo5 

ki 1o 10 

centi 10-~ 

milli lom3 

mi cru 10-~ 

viii 
1.0 INTRODUCTION 

The Clean Air Act Amendments of 1977 require each State in which 

there are areas in which the national ambient air quality standards 

(NAAQS) are exceeded to adopt 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 to demonstrate 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 to submit a further revised SIP 

by July 1, 1982. 

Section l72(a) (2) and (b) (3) of the Clean Ai r Act require that 

ramattainment area SIP's include reasonably available control tech~iology 

(RACT) requirements for stationary sources. As explained in the "General 

-

Presmhle fnr Propnc~d Rulemki ng ov Approval of State !mp! ewntatioo

Plan Revisions for Nonattainment Areas," (44 FR 20372, April 4, 1979) 

for ozone SIP's, EPA permitted States to defer the adoption of RACT 

regulations on a category of stationary sources of volati 1 e organ; c 

compounds (VOC) unti 1 after EPA pub1 ished a control techniques guideline 

(CTG) for that VOC source category. See also 44 FR 53761 (September 17, 

1979). This delay allowed the States to make more technically sour,d 

decisions regarding the application of RACT. 

A1 though CTG documents review existing inf ormati on and data coiicerni ng 

the technology 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 is to provide State and local air pollution 

control agencies with an initial information base for proceeding with 

their ow assessment 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 is first gath2red in the field 

directly from gas we1 1s 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 in certain instances for removal of water, 

sul fur 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 facil ities 

engaged in the 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 finGiithe 6ef f 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 

In this document, fugitive emissions from gas plants are considered 

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

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

VOC emi ssi ons are defined as nonmethane-nonethane hydrocarbon emissions. 

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

The fol l..owi ng sources are considered in this chapter: pumps, compressors, 

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

gas-operated control val ves. These source types are described be1 ow. 
I Field Gas Gathering Systems ( 

Fie1 d Compression i 

1 

Fractiana tion of I Natural Gas Liquids 

Sul fur 

Recovery 

+ 

r J 1' 

I Sal es Pmduc ts 

(ethane, propane, f so-butane, butane, natural gas01 ine, etc. 1 ) 

Gas Treating 

' Sweetening and Dehydration (H9. C02, and H20 Remval ) A 

Separation of Natural Gas 

Llqutds from Field Gas . 

Figure 2-1. General Schematic of Natural Gas-Gas01 I ne Pmcessi ng . 

2-2 

Dry Gas 

- to Sales J 
2.2.1 Pumps 

Pumps are used in gas plants for the niove~nent of natural gas liquids. 

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

types, such as the posi tive-di splacement , reciprocating and rotary 

action, and special canned and diaphragm pumps, may a1 so be used. 

Natural gas liquids transferred by pumps can leak at the point of contact 

between the moving shaft and stationary casing. Consequently, a1 1 pumps 

except the canned-motor and diaphragm type require a seal at the point 

where the shaft penetrates the housing in order to isolate the pump's 

interior from the atmosphere, 

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

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

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

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

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

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

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

by a lubricant that flows between the packing and the shaft. 2 

Fluid 

End 

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

Mechanical seals are limited in application to pumps with rotating 

shafts and can further be categorized as single and dual mechanical 
seals. There are many variations to the basic design of 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 , reci procating , and rotary. The centri fugal 

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 

whi 1e rotary compressors util ize rotating elements such as 1obed impel lers 

or sliding vanes. 

As with pumps, seal ing 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 el iminates 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 suppl i ed to the seal faces. Mechanical seal s can achieve the lowest 

leak rates of the types identified above, but they are not suitable for 

a1 1 processing condi ti 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 metal 1 ic packing plate and 

nonmetal 1 ic partially compressibl e (i e., GRAFFOIL,~TEFLON R ) 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, re1 ief, and check valves. All except the re1 ief 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 

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

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

source of fugitive mi ssions. 

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 packi ng materi a1 s incl ude graphi te, graphiteimpregnated fibers, and tetrafluoroethylene polymer. The packing materi al 

used depends on the valve appl ication and conf iguraton.6 These conventional 

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

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

7 seal. 

2.2.4 Pressure Re1 i ef Devices 

Engineering codes requi re that pressure-re1 ievi ng devices or systems 

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

a1 lowable working pressure of the vessel . The most common type of 

pressure-re1 ieving device used in process units is the pressure re1 i ef 

val ve (Figure 2-5). Typical ly, re1 i ef valves are spring-l~aded and 

designed to open when the process pressure exceeds a set pressure, 

a1 lowing 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 re1 ief 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 re1 i evi ng 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 

a1 lowing 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 re1 ief valve. 

2.2.5 Open-Ended Lines 

Some valves are instal led 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 normal ly instal led between mu1 ti-use 

product lines to prevent products from collecting in cross-tie lines due 
STEM Y 

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


Process Slde 

gure 2-5. Diagram of a spri ng-1 oaded re1 ief valve. 
to valve seat leakage. In addition to valve seat leakage, an incompletely 

closed valve could result in VOC emissions to the atmosphere. 

2.2.6 Fl anqes and Connections 

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

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

requi re isolation or removal . Connections are a1 1 other nonwel ded 

fittings that serve a similar purpose to flanges, that also allow bends 

in pipes (ells), joining two pipes (coup1 ings), or joining three or four 

pi pes (tees or crosses ) . The connections are typical ly threaded. 

Flanges may become fugitive emission sources when leakage occurs 

due to improperly chosen gaskets or poorly assembled flanges. The 

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

flanges in some services unde'rgo; this results in the 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 at gas 

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

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

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

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

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

some instances where highly pressurized field gas is used as the operating 

medi urn for emergency control valves. However, these valves are sel dom 

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 at six natural 

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

International under contract to the Arneri can Petroleum 1nsti tute,ll and 

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

Basel ine fugitive emission factors were developed from these data,'' and 

are presented in Table 2-1. The factors represent the average baseline 
Tab1 e 2-1. BASELINE FUGITIVE EIIISSION FACTORS FOR 

GAS PLANTS (kg/day) 

Component Emi ss ion factor 95% Confidence interval 

Val ves 0.18 (0.48) 0.1 - 0.3 (0.2 - 1) 

Re1 ief val ves 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 seal s 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) 

connect ions 

xx = VOC emission values. 

(xx)= Total hydrocarbon emission values. 

b~ompressor seal emission factors from Reference 12 were not used 

because the data base included dry gas compressors (which are not subject 

to RACT). The mission factors shown are a weighted average of wet gas 

and natural gas 1 iquids compressor seals as developed in Reference 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 1iquids 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 mu1 tiplying 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) 0 
2.4 REFERENCES 

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

July 14, 1980. p. 88. 

2. Organic Chemical Hanufacturing , Vol ume 3 : Storage, Fugitive, and 

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

Protection Agency. Off ice of Air Qua1ity Planning and Standards. 

Emission Standards and Engineering Division. Research Triangle 

Park, North Carol ina. EPA-450/3-80-025, December 1980. 

3. Nelson, W.E. Compressor Seal Fundamental s. Hydrocarbon Processing, 

-

56(12):91-95. 1977.

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

Texas. March 10, 1981. Compressors and seals at gas plants. 

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

Resul ts of a telephone survey concerning the use of pneumatic 

control valves at gas plants. 

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

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

7. Temp1 eton, 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 Pol 1 ution Control District, County of Los Angeles, 

California. April 1958. 37 p. 

9. McFarl and, 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 Pub1 ication 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) for these 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 

appl icable 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, a 
potential leak from the component is indicated. The rate of leakage 

may be subjectively determined by the observer by determining the 

number of bubbles formed over a specified time period. In addition, 

soaping may also serve as a preliminary screening technique, in that 

the number of equ ipment components otherwise subject to instrument 

monitoring may be reduced to only those components for which bubbles 

were detected. Soaping is not appropriate for very hot sources, 

a1 though ethylene glycol can be added to the soap solution to extend 

the temperature range. This method is also not suited for moving 

shafts on pumps or compressors, since the motion of the shaft may 

cause entrainment of air in the soap solution and indicate a leak when 

none is present. In addition, the method cannot generally be applied 

to open sources such as relief valves or vents without additional 

equipment. 

The use of portable hydrocarbon detection instruments is the best 

individual survey method for identifying leaks of VOC from equipment 

components because it is appl icable to a1 1 types of sources. EPA 

Reference uethod 21, Determination of Volatile Organic Compound Leaks, 

speci fi es the procedures for instrument moni tori ng. This method 

incorporates the use of a portable analyzer to detect the presence of 

volatile organic vapors at the surface of the interface where direct 

leakage to atmosphere could occur. This sampling traverse is called 

"moni toring" in subsequent descriptions . A measure of the hydrocarbon 

concentration of the sampled air is displayed in the instrument meter. 

The approach of this technique assumes that if an organic leak exists, 

there will be an increased vapor concentration in the vicinity of the 

leak, and that the measured concentration is generally proportional to 

the mass emission rate of the organic compound. 

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 in assessing the appl icabil ity and effectiveness 

of each method. 

3.1.2.1 Pumps. In many cases, it is possible to operate a spare 

pump while the leaking pump is being repaired. Leaks from packed 
seals may be reduced by tightening the packing gland. At some point, 

the packing may deteriorate to the point where further ti yhtening 

would have no effect or possibly even increase fugitive emissions from 

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

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

leaking seal can be repaired or replaced. Dismantling pumps may 

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

The maximum amount of VOC released to atmosphere 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 f ran pump repai r were quantified assuming the VOC contained 

between the block valves is approximated by 2 m of '10 cm pipe. As 

such, a conservative estimate of pump repair emissions is 8.6 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 to a closed system as much as possible prior to repacking or seal 

replacement to minimize spi 1 lage emissions, however, even with spi 1 lage, 

repair will result in an emission reduction. 

3.1.2.2 Compressor Seals. As discussed in Chapter 2, there are 

three types of compressors used in natural gas plants: centrifugal, 

rotary, and reciprocating. Centri fugal and rotary kompressors are 

driven by rotating shafts whi le reciprocating compressors are driven 

by shafts having a linear reciprocating motion. In either case, 

fugitive emissions occur at the junction of the moving shafts and the 

stationary casing, but the kinds of controls that can be effectively 

applied depend on the type of shaft motion involved. 

Repair of leaking compressor seals may be accomplished ifthere 

is a 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 repai r. 

3.1.2.3 Relief Valves. In general, relief valves which leak 

must be removed in order to repair the leak. In some cases of improper 
reseating, manual re1 ease of the val ve 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, it may be preferable to instal 1 a second block valve and 

re1 ief valve for use when the first re1 ief valve is under repair. An 

even safer a1 ternative is to instal 1 a three-way valve with para1 lel 

relief systems so that one of the two relief systems is always open. 

Some re1 ief valves may be difficult to monitor. A state or local 

agency may wish to require 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 it may 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 

a1 low 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, it may 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. In some cases, leaks from 

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

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

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

is made. Most flanges and connections cannot be isolated to petmi t 

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

small amounts of VOC (Tab1 e 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 at which maintenance 

is required is called 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 in routine 

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 in maintenance costs are not likely to be large compared 

to the high credits to be realized from product recovery. In addition, 

the monitoring instruments presently in use for fugitive emission 

surveys have a maximum meter reading of 10,000 ppm. Add-on dilution 

devices are available to extend the range of the meter beyond 10,000 ppm, 

but these dilution probes are inaccurate and impractical for fugitive 

emissions monitoring surveys. Other considerations for selection of 

the action level are component specific. 

For valves, the selection of an action level for defining a leak 

is a tradeoff between the desire to locate all significant leaks and 
Table 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) 

Re1ief val vesL 

Compressor seals b,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. 

'~eference 4. 

d~ased on a weighted average of compressor seals in wet gas and natural 

gas liquids service. Reference 5. 
to ensure that mi ssi on 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 to achieve essenti a1 ly 

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 

1eve1 . 

For pump and compressor seals, selection of an action level is 

different because the cause of leakage is different. Compared to 

valves which generally hdve zero leakage, most seals leak to a certain 

extent whi 1 e operating normally. The routine 1eakage is generally 

low, so these seals would tend to have low instrument meter 'readings. 

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

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 seal s have low instrument meter readings, and the bul k 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 

inspection will result in leaking sources being found and fixed sooner. 

The leak occurrence and recurrence correction factor for quarterly 

inspections is estimated to be 90 percent. The estimated percentages 

of components found leaking with quarterly inspections are given in 

Tab1 e 3-2. 

3.1.3.3 Allowable Interval Before Repair. If a leak is detected, 

the equipment should be repaired within a certain time period, The 

allowable repair time should reflect an interest in eliminating 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 in overall plant maintenance scheduling. The 

determination of this a1 lowable repair time will affect emission 

reductions by influencing the length of time that leaking sources are 

allowed to continue to erni t pollutants. Some of the components with 

instrument readings in excess 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 is 98 percent. The emissions which 

occur between the time the leak is detected and repair is attempted 

are increased with longer a1 lowabl e repair interval s. 

3.1.3.4 Achievable Emission Reduction. Repair of leaking components 

will not always result in complete emission reduction. To estimate 

the emission reduction from repair of equipment, it was 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 val ves, 

pressure relief valves, and compressor seals is derived from the 

average emission rates of these components above 10,000 ppmv and at 

1,000 ppmv as shown in Table 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 a1 lya Quarterly Inspections 

Val ves 

Re1ief Val ves 

Compressor Seals 

Pump Seal s 

a 

Approximate f ract ion of components havi ng an i nst rument readi ng 

equal to or greater than 10,000 ppmv prior to repair. 

b 

Reference 3. 

Reference 8. 

d 

Reference 9. 

e 

Annual percent recurrence factors have been applied for quarterly 

inspections for re1ief val ves and compressor seals to determine 

the percentage of sources maintained. It is assumed that 10 percent 

of sources initially detected are found with quarterly monitoring, 

therefore, the annual average is calculated as: 0.10 x 4 = 0.4. 

The estimated annual percentage of components found leaking at quarterly 

inspections is calculated as: 

Estimated percentage of Percent of 

components found leaking = components ) ,0.4 

with quarterly inspecti ons (1 eaki ng 

\initially 

f 

Reference 5. 
Table 3-3. AVERAGE EMISSION RATES FRO14 COIIPONENTS ABOVE 

10,000 ppmv AND AT 1,000 ppmv 

Average emi ssion Average emi ssi on 

rate from sourcesa rate from sourc6s 

above 10,000 ppmv, at 1,000 ppmv, Percentc 

Compoqent type kg/day kg/day reduction 

Val ves 0.86 (2.3) 0.015 (0.017) 98 (99) 

Compressor Seal s d 18 (39) 0.36 (0.78) 98 (98) 

Re1ief val ves 1.3 (18.2) 0.141 (0.146) 83 (99) 

xx = VOC emission values. 

(xx) = Total hydrocarbon val ues. 

a~rnission factor for leaking sources. Calculated by mu1 tiplying the 

base1 ine emission factor (Table 2-1) tines the percent emissions 

with instrument readings greater than 10,000 ppmv (Tab1 e 3-l) , divided 

by the percent components with instrument readings greater than 

10,000 ppmv (Table 3-2). 

b~ssurned emission 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 in emissions due to successful on-1 ine 

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 

in this document are calculated using both models. The first model 

(the computer leak detection and repair (LDAR) model lo) is applied to 

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

recently available data on leak occurrence and recurrence and data on 

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

for relief valves and compressor seals. Therefore, a second model 

(The ABCD model ) is applied to re1 ief valves and compressor seals. 

The ABCD model can be expressed mathematical ly by the fol lowing 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 to account for emissions which occur between detection 

of a leak and subsequent repair; that is, repair is not 

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 re1 ief valves and compressor 

seals, however, have been modified to correct for the accuracy of the 
engineering judgment employed to derive one-of the model inputs as 

discussed in the AID." The accuracy of the judgment was approxinated 

by the comparison of the LDAR model and the ABCD model control efficiencies 

9
 for valves, as: 

Valve LDAR Model 

LDAR Control ABCD Model Control Effectiveness 

Effectiveness - (Effectiveness) Control x \ Valve ABCD Model i Control Effectiveness . 

Enissions reduction efficiencies are presented in Tab1 e 3-4, as 

are controlled emission factors. The control 1 ed emissions factors are 

calculated as : 

Control 1ed Emission 

Factor 

Emission = Base1 

Factor 

ine - ne x Reduction 

Efficiency 1


using the baseline emission factors in Table 2-2. 

3.2 EQUIPMENT SPECIFICATIONS 

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 resul t when field gas 

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

eliminated by switching to the use of compressed air or nonVOC gas 

such as methane. This will require installation of an air compression 

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. 

Fugi tive emissions from open-ended 1i nes can be control 1 ed by instal 1ing 

a cap, plug, flange, or second valve to the open end of the line. In 

the case of a second valve, the upstream valve should always be closed 

first after the use of the valves. Each time the cap, plug, flange, 

or second valve is opened, any VOC which has leaked through the first 

valve seat will be released. The control efficiency will depend on 
Table 3-4. CONTROLLED EMISSION FACTORS FOR QUARTERLY 

LEAK DETECTION AND REPAIR 

Bas el ine Control Control 1 ed 

Equi pment Emission actor^ Efficiency Emission Factor 

Item (kg/day ) (X) (kg/day 1 

Val ves 0.18 (0.48) 

Re1ief 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~romTab1 e 2-2. 

b~rornLDAR Model. Reference 8. 

'~rorn ABCD Model , corrected as described in Section 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 in the cap or plug. Annual VOC emissions from a 

1 eaki ng 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 is used, and 

that a1 1 of the trapped organics released are emitted to atmosphere, 

the annual emissions from closed off open-ended 1 ines would be 1 kg. 

This would be a 99 percent reduction in emissions. 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 in the 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 in the housing. This is referred 

to as a "scavenger" system. As with other fugitive emission col lection 

systems, these vents must be control 1 ed to prevent fugitive emissions 

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

el iminate emissions from reciprocating compressors enti rely, 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 instal ling suitable piping to vent the emissions either 

to a flare, a plant process heater, or back into a low pressure point 

in the process.13 For the latter two cases, an auxill iary compressor 

may be required to compress the vent stream to a usable pressure. 

Purging the distance piece with natural gas could be performed to keep 

the enclosure above the upper explosive limit and to ensure a nonexplosive 

atmosphere. 

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

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

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

Block valves should also be instal led in order 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 

sys tern 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 appl ication 

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

a case-by-case basis . 3.3 OTHER CONTROL STRATEGIES 

This section di scusses two fugitive emission control strategies 

for valves other than the quarterly leak detection and repair procedures 

discussed above. These strategies are 1 imi ted in appl ication to 

valves, because the other component types (pumps, compressors, and 

re1 ief valves) are relatively few in number. The statistics used in 

estimating the effectiveness of the alternative strategies are inappropriate 

for small populations of components. For example, it is difficult to 

.quantify a "low leak frequency" in reference to a population of six 

pumps at a medium-sized gas plant. There are also differences between 

valves and other component types in the 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 

at very low levels over a long period of time prior to a sudden equipment 

failure that results in a 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 in the future. This is an 

important consideration when sel ecting an appropriate rnoni tori ng 

frequency for a particular component type. 
These strategies shoul d be considered a1 ternatives to quarterly 

leak detection and repair to a1 low process units the flexibil ity 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 1 ikely to benefit from these strategies 

if they were included in regulations adopted by a State agency. Thus, 

these a1 ternative control strategies might be included in State regulations 

as a1 ternative standards to quarterly 1 eak detection and repair. 

Before implementing one of these a1 ternative 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 annual ized cost of a quarterly leak 

detection and repair program depend in part on the number of valves 

found leaking during inspections. Since about 95 percent of the conponents to be monitored in a 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 resul t, the annual ized 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 (annual ized 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 

3-17 
C I r 

2 4 6 8 10 

Leak Frequency ( Percent) 

Fi gure 3-2. Cost -effecti veness of Quarterly Leak Detection and Repai r 

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 is a reasonable 

criterion to judge the appl icabi 1ity of a1 ternati ve control strategies 

for val ves. 

3.3.2 A1 lowable 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 limit the number of valves leaking at any time to a certain 
percentage of the number of valves to be 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 a year by the applicable test 

method. Additional performance tests could be requested by the State. 

A performance test would consist of monitoring all valves. All components 

other than valves would be subject to quarterly leak detection and 

repair. The percentage of valves leaking would 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 leaking was greater than the performance level of 

two percent of valves leaking, then the process unit would be in 

violation of the State regulation. 

Incorporating this type of alternative control strategy in the 

State regulation would provide the f lexi bi 1 ity 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 to comply with the regulation 

or it could implement a program of their choosing for valves to comply 

with the performance level in the regulation. 

3.3.3 Alternative Work Practice for Valves 

A State regulation incorporating an alternati vo control strategy 

for valves based on "skip-period" monitoring would require that a 

plant attain a "good performance level" on a contin~al basis in terms 

of the percentage of leaking valves. As discussed above, it appears 

that two percent of val ves 1 eaki ng represents a "good performance 

1 eve1 ." 

This type of regulation would require the owner or operator to 

begin with imp1 ementati on of a quarterly 1 eak detection and repai r 

program for valves. If the 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 is generally referred to as "ski p-period" monitoring. 

All other components would be subject to quarterly leak detection and 

repai r 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 m quarterly 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 L consecutive 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, a1 1 

valves woul J be monitored again on the fourth quarter. Another possible 

skip program would a1 1 ow semi-annual monitoring foll owing two consecutive 

quarters at less than the good performance level. 

This strategy would permit a plant that has consistently demonstrated 

it is meeting 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 instal 1ing valves with lower probabi 1 i ties of 1eaking. Compared to 

a standard based on an "a1 lowable percentage of valves leaking, " where 

not achieving the good performance level would be a violation of the 

State regulation, the penal ty under the "a1 ternative work practice" 

standard would only be a return to routine quarterly monitoring. 
Table 3-5. ILLUSTRATION OF 

Quarterly Leak rate 

1eak of valves 

detection during 

period period (I) 

SKIP-PERIOD MONITORING~ 


Quarterly 

act i on 

taken 

(monitor vs. skip) 

moni tor 

mon i tor 

monitor 

monitor 

moni tar 

monitor 

ski p 

skip 

skip 

mon i tor 

monitor 

monitor 

moni tor 

moni tor 

monitor 

skip 

skip 

skip 

mon i tor 

skip 

skip 

skip 

monitor 

Good 

performance 

1eve1 

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-fthconsecutive quarter below 2 percent means 3 quarters of monitoring may 

be skipped. 

'percentage of leaks above 2 percent means quarter1y moni tori ng reinstituted. 

d~ercentage of leaks below 2 percent means 3 quarters of monitoring nay be 

ski pped . 

of 2 percent. 
3.4 OTHER CONSIDERATIONS 

This sect ion identifies and di scusses other considerations that a 

State agency may wish to address when drafting a regulation. These 

considerations include components which are di ffi cult to 

monitor, small process units, and unit turnarounds. 

3.4.1 Diffi cult-to-moni tor Components 

Some val ves may be difficult to monitor because access to the 

valve bonnet is restricted or the valves are located in elevated 

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 

or which would not require monitoring personnel to be elevated higher 

than two meters should be monitored quarterly. However, valves which 

require the use of scaffolding or which require the elevation of 

monitoring personnel higher than two meters above permanent support 

surfaces mi ght be exempted from quarterly moni tori ng provided they are 

monitored annual ly . 3.4.2 Small Process Unit 

The net annual cost and emission reduction of performing a quarterly 

leak detection and repair program is principally related to the number 

of equipment pieces in a gas processing plant. In gas 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 perform the 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 to consider a provision in its regulations 

which would allow the agency Director to order an early unit shutdown 

for repair of leaking components in cases where the percentage of 
5,000 

4,000 

3, OOC 

2,001 

Plant Throughput (MMscfd) 

~i gure 3-3. Cost Effectiveness of Quarterly Leak Detection 

and Repair for Small Gas Plants 
leaking components awaiting repair at unit 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. 

A1 ternative methods of treating delay of repair could a1 so 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 it is technically infeasible 

to repair the component in-placelon-1 ine (i .e., without a unit shutdown) 

or where rep1 acement parts hpve been depl eted from once-suff ici ent 

inventory. By requiring records of delays and reasons for delays, 

State enforcement officers would be suppl ied with the data necessary 

to determine compl i ance. 
3.5 REFERENCES 

Memorandum. Rhoads, T.W., Pacific Envi ronmental Services, Inc., 

to K.C. Hustvedt, EPA/CPB. Gas Plants CTG: Pump Repair Emissions 

Estimate. December 21, 1982. 

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

and Gas Journal , -77(29) :54-59, 1979. 

DuBose, D.A., 3.1. Steinmetz, and G.E. Harris. Radian Corporation, 

Austi n, 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 to Screening Value for Relief Valves. 

Memorandum. K.C. Hustvedt, EPA:CPB, to James i.Durham, EPA:CPB, 

Revised Gas Pl ant Compressor Seal Emi ssi on Factor. February 10, 

1983. 

Letter w/enclosures from H. H. McClure, Texas Chemical Council, 

to W. Barber, OAQPS, EPA. June 30, 1980. 

Lee, Kun-chieh, et a1 . Union Carbide Corporation. A Fugitive 

Emission Study in a 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 in the Onshore Natural Gas 

Processing Industry using the LDAR Model. November 1, 1982. 

Memorandum. Rhoads, T .W., Paci f ic Envi ronmental Servi ces , Inc., 

to Docket 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, Emi ssi on Reduction, and Costs. U. S. 

Envi ronmental Protection Agency. EPA-450/3-82-010. Apri 1 1982. 

Tichenor, B.A., K.C. Hustvedt, and R.C. Weber. Control ling 

Petroleum Refinery Fugitive Emissions Via Leak Detection and 

Repai r. Symposium on Atmospheri c Emissions from Petroleum Refineries. 

Austin, Texas. EPA-600/9-80-013. November 6, 1979. 
12. VOC Fugi ti ve Emissions in Petroleum Refining Industry-Background 

Informati on for Proposed Star,dards. U.S. Envi ronmental Protection 

Agency, Research Tri angle 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 avail able control techno1 ogy 

(RACT), which is presented in Section 4.1. The primary emphasis is a 

quantitative assessment of VOC emissions in the absence of RACT (base1 ine 

emissions) and after implementation of RACT. The impacts of RACT upon 

water pollution, solid waste, and energy consumption are also addressed 

in this chapter. 

4.1 REASONABLY AVAI LABLE CONTROL TECHNOLOGY ( RACT ) PROCEDURES 

RACT procedures include weekly visual inspection of pumps and 

quarter1 y moni toring of pumps, valves, compressors, and re1 ief valves . Relief valves should be monitored and repaired if necessary after they 

have vented to the atmosphere. Routine instrument monitoring is not 

necessary for flanges and connections. Any component that appears to 

be leaking on the basis of sight, smell, or sound should be repaired. 

In addition, difficult-to-monitor valves may require less frequent 

than quarterly monitoring. Except when the open end is in use (e.g., 

relief valves and double block and bleed valves), open-ended lines 

should be sealed with a second valve, a blind flange, a cap, or a 

plug. In the 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 general 1y 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 or with 
instal 1 i ng equipment control s 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 it involves 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 1 ine 

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 base1 ine emission factors for 

process equipment, which represent emissions in the absence of RACT, 

were previously presented in Chapter 2 (Table 2-1). Control led emission 

factors were developed for val ves, pressure re1 ief val ves, pump seal s 

and compressor seals that would be control led 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 in Chapter 3. Control efficiencies 

and control led emission factors for valves and pump seals were derived 

directly fran the LDAR model as described in Chapter 3. For RACT 

requirements specifying equipment control s (i .e., open-ended 1 ines) , 

it is assumed that zero emissions result from the controlled source. 

The control led emission factors for each component type are presented 

in Table 3-4. 

In calculating the total VOC fugitive emissions from model plants 

controlled under RACT, the control1 ed emission factors were mu1 tip1 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 is shown in Table 4-1. Total annual model plant 

emissions for each component type are presented in Table 4-2 for both 

baseline and RACT levels of control. 

4.2.2 Emission Reduction 

The emi ssi on reduction expected from the imp1 ementation 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 emissions 
Table 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 planta kgldaylsource kg/day 

Component (N) (N x E) 

- -

Val ves 750 0.041 (0.11)~ 31 (82) 

Re1ief val ves 12 0.12 (1.4)~ 1.4 (17) 

Open-Ended 1ines 150 0.0 (0.0)~ 0 (0) 

Compressor seal s 6 1.1 (3.41~~~ 6.6 (20) 

Pump seals 6 0.50 (0.63)~ 3.0 (3.8) 

Fl anges and connections 3,000 0.011 (0.026)~ 33 (78) 

Total Emi ssi ons 

xx = VOC emission values. 

(xx) = Total hydrocarbon emi ss ion val ues. 

aFrom Table 2-2. 

'~rom Table 3-4. Controlled emission factors are derived from the baseline 

emission factors in Table 2-1. 

C~ssurnes instal lation of second valve, blind flange, cap, or plug with 

100 percent control efficiency. 

d~ased on leak detection and repair. Instal lation of a compressor vent 

control system would achieve 100 percent control efficiency. 
C 

Tab1 e 4-2. ANNUAL VOC EMISSIONS ON A COMPONENT TYPE BASIS FOR EACH MODEL PLANT^ 

Emissions undeg Emissiops under 

base1 ine 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) 

Re1 ief 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~pressor seals 4.6 (13) 14 (39) 46 (130) 0.8 (2.5)e 2.4 (7.4)e 8.0 (~5)~ 

Pun~p seals 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 in the absence of RACT. From Table 2-2. 

C Controlled emission factor (Table 3-4) x number of components (Table 2-2) x 0.365 (conversion from kg/day to Mg/yr). 

d~ssumes i 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~ocontrols are specified except repair if found leaking. 
are presented as "totals" in Table 4-2. The average reduction in 

emissions for the model plants after RACT is implemented is 71 percent 

for VOC and for total hydrocarbons. 

4.3 WATER POLLUTION 

A1 though fugitive emissions of VOC from gas plant equipment 

primarily impact atmospheric VOC emissions, they also impact water 

qua1ity. In particul ar, leaki ng components hand1 ing 1 iquid 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 equi pment 1 eaks 

into the wastewater system; therefore, no adverse water pollution 

impact is expected. 

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 packi ngs and cmponents which are replaced. 

4.5 ENERGY 

Implementation of RACT is expected to require little or 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 in terms of joules and in barrels of 

crude petroleum. Table 4-4 shows the total energy saved per model 

pl ant. 
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 imp1 ementing reasonably avail able control techno1 ogy 

(RACT) for controlling fugitive emissions of volatile organic compounds 

(VOC) from equipment leaks at gas plants are presented in this 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 in Chapter 2. To ensure a 

common cost basis, Chemical Enqineerinq cost indices are used to 

ad just costs to June 1980 do1 lars. 

As discussed in Section 4.1, RACT for compressor seals is quarterly 

leak detection and repair. In many instances, however, a compressor 

vent control system would be instal led. For the purpose of estimating 

RACT cost impacts, Sections 5.1 through 5.4 are based on quarterly 

leak detection and repair for compressors. Additional ly, compressor 

vent control costs are discussed in Section 5.5. Capital costs for 

the vent control system are included in Table 5-1. 

5.1 BASIS FOR CAPITAL COSTS 

Capital costs represent the total cost of starting a leak detection 

and repair program in existing gas plants. The capital costs for the 

implementation of RACT include the purchase of VOC noni toring 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 in subsequent quarters and is a one-time cost. The basis for 

these costs is discussed below and presented in Table 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 standby 
spare. 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 1 ines can be control led by 

installing a cap, plug, flange, or second valve to the open end. Any 

one of these pieces of equipment is included in the definition of a 

"capN for 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 

fitted with 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 instal 1ing 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 in the detection of leaking components. The number 

of initial leaks is expected to be greater than the number found in 

subsequent inspections. Because in itia1 1 eak repair is a one-time 

cost, it is treated 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 in the 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 in Table 5-2. 

The initial repair costs given in Table 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 credi ts for product saved as the resul t of 

the control program. The basis for the annual costs is given in Table 5-4. 
5.2.1 Leak Detection Labor 

The implementation of RACT requires visual and instrument monitoring 

of potential sources of fugitive VOC emi ssions. The monitoring 1 abor-hour 

requirements for RACT 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 is monitored each year. 

The monitoring times for the various components are 0.5 minute for 

visual inspection, 1 minute for valves, 5 minutes for pump and compressor 

seals, and 8 minutes for re1 ief 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 is needed 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 include 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 addi ti onal mi scel 1aneous 

charge of four percent of capital cost for taxes, insurance, and 

capital related associated administrative costs is added for the 

monitoring i nstruments 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- keepi ng and reporti ng requi rement costs. 
Capital Charges 

The life of caps for open-ended lines is asswed to be ten years 

and the life of monitoring instruments is assumed to be six years. 

The cost of repairing initial leaks was amortized over a ten-year 

period since it is a one-time cost. 

The capital recovery cost is obtained from annualizing the installed 

capital cost for control equipment. The installed capital cost is 

annualized by using a capital recovery factor (CRF). The CRF is a 

function of the interest rate and useful equipment lifetime. The 

capital recovery can be estimated by mu1 tiplying the CRF -by the total 

installed capital 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 life of the equipment, years. 

The interest rate used was ten percent. The capital recovery factors 

and other factors used to derive annualized charges are presented in 

Table 5-4. 

Recovery Credi ts 

The reduction of VOC fugitive emissions results in saving a 

certain amount of VOC which would otherwise be lost. The value of 

this VOC is a 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 in Table 5-5. The VOC saved is valued 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 is valued 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 in Table 5-7 based on Model Plant B. Model Plant recovery 

credits are summarized in Table 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. 

5-4 
5.3.1 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 

is the same for all model plant sizes. The capital costs for caps for 

open-ended lines are annualized on the basis presented in Table 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. Tab1 e 5-9 presents the annual ized 

costs for the model plants. The net annualized costs to implement 

RACT range from $3,300 for Model Plant A to a cost savings of $17,000 

for Model Plant C. 

5.4 COST EFFECTIVENESS OF RACT 

Cost effectiveness is the annual cost per megagram of VOC controlled 

annually. The cost effectiveness of RACT for each model plant is the 

net annual cost for implementing RACT divided by the emission reduction 

achi eved under RACT. 

The cost effectiveness of implementing RACT for the modei plants 

is presented in Table 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 indi vidual component covered by 

RACT is presented in Table 5-10 based on Model Plant 6. The cost of a 

monitoring instrument cannot be attributed to any s ngle type of 

component since a1 1 components are monitored by the inst rument . Therefore, the cost for each component does not inc ude the cast of 

the monitoring instrument. The instrument cost is ncluded, however, 

in the model plant cost effectiveness. 

5.5 ANALYSIS OF COMPRESSOR VENT CONTROL SYSTEM COS 

The cost to install a compressor vent control system is dependent 

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 in the compressor vent control system cost analysis 
on the assumption that recovered emissions would be flared. However, 

the recovered emissions could be routed to a process heater resulting 

in a credit for the captured emissions at their fuel value. 

The type compressor is important because reciprocating compressors 

may require additional control equipment to ensure the safety of the 

vent system. A1 so, reciprocating compressors would requi re 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 to a VOC control device; therefore, in the 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 to fixed and variable costs associated 

with the vent control system. Capital and annualized costs of the 

compressor vent control system are presented in Table 5-11. 

The cost effectiveness of the vent control system is dependent 

upon the factors previously discussed plus the service a compressor is 

in. The compressor emission factor presented in Table 2-1 is based on 

compressors in natural 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 ins truments ( Foxbgro OVA-108) 

O $4,6001 ins trumen t 

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 = 

1 hour at $18/hour . Total cost is $6l/line. 

3. Compressor Seal Vent Control System 

A. Centri fuqal Compressor Seal P i pi nq e 

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 a1 arm @ 9.90 9.90 

Total mani fol d 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 hou rs/crew 

1.08 crew hrs. x crew x $18.00/hr = 

Subtotal $ 154 

Cont ingency -15 

Total $170 

f - B. Reciprocatinq Compressor Seals 

COSTS FOR EACH COMPRESSOR SEAL 

Incremental Cost for Double Distance Piece $2,500 

Conti ngency 2 50 

Total $2,750 
Table 5-1. CAPITAL COST DATA (June 1980 do1 lars) 

(continued) 

Distance Pi ece Pi pi 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. Fl anyes, Fittings, 

etc. 

Labor 

Subtotal 

Contingency 

Total 

FIXED COSTS 

Instrumentation for Purge Gas -

Materi a1 

Oi 1 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 

Conti ngency 

To ta 1 

C. Flare 

Cost of Flare 

Contingency 667 

Total 
Table 5-1. CAPITAL COST DATA (June 1980 do1 lars) 

(concluded) 

D. Piping to Flare . -

Material 

Inlet line from 

~orn~ressorto Flare - lOOm of 5. lcm pi pe 

@ $6.50/m 

Ruptured disk and 

holder 

Misc. Flares, Fittings 

Misc. Costs for 

Pipe Supports 

Labor 

Subtotal $3,350 

Conti ngency 

Total 

a~neinstrument used as a spare. Cost is based on Reference 1. 

b~eference2. 

'cost adjustment based on the economic indicators for pipe, valves, and 

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

f~eference 8. 

Table 5-3. INITIAL LEAK REPAIR COSTS 

(June 1980 do1 lars) 

Initial Repair Costs Initial Annualized Repgir 

For Model Uni tsa Costs for Model Units 

Source type A B C A B C 

Val ves 920 2,700 9,200 210 620 2,100 

Re1 i ef Val vesC 0 0 0 0 0 0 

Compressor Seal s 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 

a From 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 

uni ts is determined through the equation: 

where n = 10 years and- i = 10 percent. Therefore, the CRF = 0.163. 

'~ecause of safety requirements, these leaks are corrected by routine 

maintenance at no addi tonal 1 abor requi rments. 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 inst ruments 0.23 x capitalb 

Annual mai ntenance charges 

o Caps on open-ended lines 

o Moni tori ng inst ruments 

o Replacement pump seals 

Annual mi scel laneous charges 

(taxes, insurance, administration) 

o Caps on open-ended lines 0.04 x capitalC 

o Monitoring instruments 0.04 x capitalc 

Labor charges $1 8/hourf 

Admi ni strati ve and support costs 0.40 x (moni tori ng + 

for implementing leak detection repai r labor)c 

and repair 

Annualized charge for initial (estimated number of 

leak repai rs leaki ng 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 

a 

Ten year life, ten percent interest. Reference 11. 

b 

Six year life, ten percent interest. Reference 11. 

C;

Reference 11. 

d 

Includes materi a1 s and labor for maintenance and calibration. 

Reference 11. Cost index = 242.7/209.1. References 12 and 13. 

e Reference 14. 

f 

'From Table 5-2. Includes wages plus 40 percent for labor-related 

admini strati ve and overhead costs. Cost (june 1980). Reference 4. 

'~nitial leak repair amortized for ten years at ten percent interest. 

h 

Based 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 do1 lars) 

Leak Detection Costs Repair Costs 

For Model Units For Model Units 

Source type A B C A B C 

Val ves 590 1,800 5,900 940 2,900 9,400 

Re1ief Val ves 7 7 i30 7-70 ob ob ob 

Compressor Seals 23 . 72 230 270 790 2,700 

Pump Seals 4 1 130 390 230 680 2,300 

TOTAL 730 2,200 7,300 1,400 4,400 14,000 

a~rcmTable 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 re1 ief valve 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 Elni ss ions (rlq/yr) a Recovered Product Value ($/yr) b 

Component Type VOC Methane-ethane VOC Methane-ethane Total 

Valves 

Re1 ief val ves 

Open-ended lines 

in 
 Compressor seals A 


UI 

Pump seals 

TOTAL 71 105 13,700 6,400 20,100 

a From 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 do1 lars) 

Model Plant 

Cost Item A B C 

Annual ized Capi tal Costs 

A. Control Equipmenta 

1. Monitoring Instrument 

2. Caps for Open-Ended Lines 

B. Initial Repairs b 

Operating costsC 

A. Maintenance Charges 

1. tloni toring Instrument 

2. Caps for Open-Ended Liaes 

3. Replacement Pump Seals 

B. Mi scel 1 aneous Charges (taxes 

insurance, admi ni stration) 

1. Monitoring Instrument 

2. Caps for Open-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 Tab1 e 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 m 

Y OIE 

.c wo L 

CLL 

2; 

CO 

mm -. 

Pln 

-9 

VI 

m- m h 

L Y w w m 

=.E 

V) X Y 0 EL 

Pa 5 9 L 

Y VI VIC 

* Y VI 

0 C 

5 g 'C L 0 Y 

ul w C ula 

r w vr 

L Y 

ZL 

Cb 0 

0 

wul 

-0 I mv ln n 
Table 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 Reduct ion 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 reciprocating compressors are driven by shafts having a linear 

motion. 

bu~es" indicates that a control device is present at the plant. The cost of a control device (flare) has been added to the 

compressor vent control system costs for plants without an existing control device. 

C 

Costs based on Table 5-1. 

d 

Costs annualized as shown in Table 5-4. 

e 

Wet gas means field gas with an average VOC content of 10 percent by weight. 

f 

Natural gas liquids (NGL) consist of mixed liquids separated from wet gas (i-e.. liquid petroleum gas). 
5.6 REFERENCES 

Telephone conversation. Michael A1 exander, TRW, with Pls. M. Fecci 

of Anal abs/Foxboro. March 23, 1982. Price of .Century Systems 

OVA-108 in July 1980. 

Telephone conversation. Michael Alexander, TRW, with ?lr. Harris 

of Dil lon 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 conversati on. Michael A1 exander, TRW, with Danny Kei th, 

Dillon Supply Co., Raleigh, N.C. June 15, 1981. Costs of valves, 

pipes, and fittings. 

Telephone conversation. Tom Norwood, Pacific Envi ronmental 

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. Wal sh, 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 Petrol eum Refinery Equi pment. 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 - Addi tional 

Information on Emissions, Emission Reductions, and Costs. 

EPA 450/3-82-010, Apri 1 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 SOURCE TEST DATA 

APPENDIX A 

EtlISSION SOURCE TEST DATA 

The purpose of Appendix A is to 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 in Reference 1) was performed 

at the two API-tested plants and at'three of the EPA-tested plants. 

Selected components were measured for mass emissions at both of the 

API-tested plants (Plants 1 and 2) and at two of the EPA-tested plants 

(Plants 5 and 6). These mass emission measurements were used in development 

of emission factors for gas plant fugitives, which are presented in 

Table 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 in Reference 1. Of the four EPA-tested plants, the 

first tested was a sol id bed 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 it was under natural gas 

pressure and was tested. 

The second EPA-tested plant was of the cryogenic type (Reference 3). 

Feed gas to the plant is compressed and then chilled. Natural gas 

liquids are condensed out and split into two streams: 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 

at 450 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 para1 lel 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 is presented in Table A-2. A summary of the soap 

screening data collected at the two API-tested plants and at all of the 

EPA-tested plants is presented in Table A-3. (Only a very small amount 

of soap screening data were col lected at Plant 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 3 was used to define a leak rather than a meter 

readi ng of 10,000 ppm. 
Table A-1. GAS PLANTS TESTED FOR FUGITIVE ENISSIONS~ 

Data 

Plant col 1ect i on Plant process Pri nci pal screening 

No. sponsor tY Pe method(s) used - --

1 AP I Refrigerated Absorption Soaping 

2 AP I Cryogenic Soapi ng 

3 EPA Adsorption Instrument, Soaping 

4 EPA Cryogenic Instrument, Soaping 

5 EPA Refrigerated Absorption Instrument, Soaping 

6 EPA Refrigerated Absorption Ins trun~ent b 

a~eference 6. 

b~ess than 50 components were soap screened at plant #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 
..... 

Table A-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.Itwo 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 Iand 11. U.S. EPA, ESEDIEMB 

Report No. 81-OSP-7. July 1981. 

5. Harris, G. E., Radian Corporation. Fugitive Test Report at the 

Gulf Venice Gas Plant, Volume Iand 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 in Gas 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 PLANTS 
APPENDIX B 

MODEL PLANTS 

The purpose of this appendix is to 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 techno1 ogy (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 - Joul e-Thompson, and cryogeni c-expander .' Process condi tions 

are expected to vary widely between plants using these different methods. 

However, available data show that fugitive emissions are proportional to 

the number of potential sources, and are not related to capacity, throughput, 

age, temperature, or pressure.2 Therefore, model plants defined for 

this analysis represent different levels of process complexity (number 

of fugitive emission sources), rather than different process methods. 

In order to estimate emissions, control costs, and environmental 

impacts on a plant specific basis, three model plants were developed. 

The number of components for each model plant is derived from actual 

component inventories performed at four gas plants. Two of the plants 

were inventoried during EPA testing, and two were inventoried during 

testing by Rockwell International under contract to the American Petrol eun 

Institute. The model plants are based on four rather than on all six of 

the plants presented in Appendix 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. 
Cmplexi ty 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 site diagrams and descriptions provided in the API/Rockwe? 1 reports5 and the vessel inventories 

from the EPA-tested plants were performed during the testing. These 

vessel inventories and the component inventories are shown in Table 3-2. 

Table B-3 shows the ratios of numbers of components to numbers of vessels 

at the four gas plants. The mean and standard deviation of the four 

ratios 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 to the number of vessels that are 

accounted for in one of the three process trains at the EPA-tested plant 

A. It is assumed that there are existing gas plants with a similar 

configuration to the EPA-tested plant A, that have only one process 

train. The high end of the range, 100 vessels, is slightly larger than 

the number of vessels at the industry-tested plant A. Since this was 

the largest of the plants tested, it appears reasonable to use this as a 

guide in calculating the number of components at the largest model 

plant. The middle model plant has 30 vessel s. This is approximately 

the same number of vessels as at three of the four plants tested, and 

appears that it may 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 

IN VESSEL INVEN-TORIES FOR MODEL PLANT DEVELOPMENT 

Incl uded Exc 1 uded 

1. Absorption/Desorption Units 

a. Absorbers 

1. Compressors, Pumps 

b. Scrubbers 

c. Dehydrators 

d. Stabi 1 izer 

e. Stripper 

2. Piping Systems 

a. Mani fold/header systems 

b. Valves, flanges, connections, 

c. Meters, gauges, control equip

etc. 

ment 

2. Adsorption Units 3. Glycol, 1 ube oi 1, water storage 

3. Distillation/Fractionation Units 

a. Demethani zer 

b. Deethani zer 

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. Knockout 

Table 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 

Val ves 16.4 18.0 37.0 30.5 25.5 9.9 

Re1ief 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 in Table 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 

Re1ief Val yes 

Open-Ended Lines 

Compressor Seal s 

Pump Seals 

Fl anges and Connections 

a~umber of Components based on average ratios presented in Table 8-3. 
B.2 REFERENCES 

1. Cantrell , A. Worldwide Gas Process irig. 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 to James F. Durham, Chief, Petroleum Section, 

OAQPS, U.S. EPA. Preliminary Test Data Summaries of EPA Testing 

at Houston Oil and Minerals Smith Point Gas Plant and 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., et a1 .: Fugitive Hydrocarbon Emissions from Petroleum 

Production Operations. API Publication No. 4322. March 1980. 
APPENDIX C 


PUBLIC COMMENTS 

This 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 in the 

Summary of Public eomments and Responses presented in Appendix D. 

Table C-1. LIST OF COMMENTERS ON THE 

DRAFT CTG FOR NATURAL GASIGASOL INE 

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 Consol idated S.E. Kurmas March 10, 1982 

Gas Company 

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

7 Texas Air Control 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?!cphone 214 557 5'5 1 

Luther E. Bartlert 

?.lanager 

O~erationsana 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 Oil and 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 Oil and 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 in full agreement with MI'S concerns, 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 economic 
Yr. 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 

Oil and 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 for many 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 

~dtherE. Bartlett 
CITIESSERVICEC~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 Senices 

m I.. m 

March 9, 1982 

Emissions Standards and Engineering Division (MI-13) 

Environmental Protect ion Agency 

Research Triangle Park, North Carolina 27711 

Dear Sirs : 

Re: ..Control Techniques 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~ary17, 

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 volatiz organic 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 is based 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.after various 

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 Affairs 
C M GAROETTA 

E~~~ronmenlal Affairs 

~arn~n~s~rator 

810 SOUTH FLOWER STZEET cOS ANGELES CALIFCRNIh 90017 

!d i 

SOUTH RN CALIFORNIA IqaS 4 

Mailmg AaOrc- s BOX 3249 TERMINAL AFthEX. LOS ANGELES. CALIFORNIA 90051 

,LOMPAP.!Y 

March 9, 1982 

Mr. Fred Porter 

€mi ssion Standards and Engineering Division (MD-13) 

Research Tri angle Park 

North,Carol i na 2771 1 

0ear Mr. Porter: 

Southern Cal iforni a Gas Comoany ( SoCal ) aporec i ates - . :be 

opportunity to subnii t the following cements on the -,nv ;! anmental Protection Agency's (EPA) draft control techniques 

guideline (CTG) document entitled "Control of Volati le Organic 

Compound Equipment Leaks from Natural Gas/Gasoline Processing 

Plants", for review 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. It is not clear from the language of the proposed 

document whether or not the definition of a natural gas/gasoline 

storage operation excludes underground gas storage fields. 

SoCal strongly feels that a gas storage operation should not 

be compared with conventional oi 1 /gas production faci 1 i ti 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 at an underground gas 

storage facility are relatively few and simple when compared 

to those at a conventional gas processing plant and oil/gas 

production operati om. 

In order to demonstrate the basis for its concern, 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 bill ion cubic feet per day 

to 72 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 oi 1 / 

gas production fields where production is usual ly continuous throughout 

the year. 

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 is not significant. The gas to oil ratios in SoCal's operations range from 90,000 to 766,000 cubic feet per barrel of oi 1 produced. 

This is significantly 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 to oil ratio clearly imp1 ies 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 a1 1 

SoCal's storage fields with the exception of Playa del Rey where there is 

no dehydration. Oi 1 treatment (stabi 1ization) and oi 1 /condensate storage 

are other operations where additional HC gas is generated and the methods 

of processing or handling this gas varies from field to field. At Montebello 

and Playa del Rey, this gas is directly delivered into the low pressure 

distribution or transmission pipeline system. At Honor Rancho, it is 

-delivered to an oil company gasoTine plant for further processing. At A1 iso 

Canyon, the gases are compressed and then the liquid fractions (gas01 ine) 

are removed in a Hydrocarbon Recovery Unit (HRU). It is important to note 

that the volume of HC gases generated at oil 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 to Table 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 the API/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 faci 1 i ty. The low concentration of non-methane 

or non-methane plus non-ethane hydrocarbons in SoCal 's wet gas is not mere 

coincidence. 
Ltr. to F. 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 little of 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 gasol ines will 1 iquify when the temperature is lowered 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 at Aliso 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 is made 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 little reactive hydrocarbon 

and the magnitude of such emissions should be significantiy lower than a 

conventional oi 1/gas production operation or a gas processing plant. 

Therefore, SoCal strongly recomnends that the definition of natural gas/ 

gasol ine processing plant should be redefined to excl ude underground gas 

storage facilities. 

Sincerely, 

GMG:avs 

Attachments 


March 10, 1982 

Emissions Standards and Engineering Division 

Envi ronmental Protection Agency 

Research Triangle Park, 

Xorth Carol i na 2771 1 

Attention: Mr. Fred Porter 

Dear Si r : 

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

Guide1 i ne Series for the Control of Vol ati 1e Organic Compounds Equipment 

Leaks from Natural Gas/Gaso'lineProcessing Plants imposes excessive 

financrbmi thout real izing significant air qua1 i ty gains . 

Michigan Consol idated di spute's the premi se made in the gui del ines that 

Vol ati 1 e Organic Compound (VOC) 1eaks are not being adequate1 y 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. A1 though visual, audible, and 

olfactory methods are the primary safeguards, it is not uncommon to 

supplement these methods with oxygen and hydrogen sul fide monitors. 

Since many 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 Consol idated be1 ieves that fugitive VOC emissions from 

natural gas processing plants are adequately controlled and further 

regulation would prove overburdensome. 

Michigan Consol idated a1 so disagrees with the methods used in estimating 

current emissions from processing plants. Fugitive sources vary si gni f - i cantly aependi ng on a variety of conditions . These i ncl ude: system 

pressure, equipment age, cl imate, past maintenance, gas composi tion (as 

it affects corrosivity) and a mu1 ti tude of other factors. To assume 

that these emissions are simply a function of the number of valves, 

pumps and flanges at a facility is a gross oversimplification. 

A1 though, the guidl ines 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 repai ring many i nsi gni f - icant 1 eaks will require blow down of potentially 1 arge portions of the 

system, significant emission reduction benefits and recovery cost credits 

are questionable. 

i2ir natural gas is your nost ~conomicol ;brm of energy . . . leas2 he1,c c9nserL.e ir. 
March 10, 1982 

Emi ssions Standards and Engineering Div. 

Attention: Mr. Fred Porter 

Page Two 

In conclusion, Michigan Consolidated believes that regulations resulting 

from the implementation of these draft guide1 ines \will be economically 

burdensome to our natural gas customers whi 1e resul ti ng 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 Engi neer 

SEK/ sl 
TEXAS 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 information was 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 


a major 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 


,consideration of 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 kds no VOC 3.
 wouid %e.detectea arxxd 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~rol 13 yedcmlnizt3ly

ine~hane ma schane. Neizner methane nor ethaEe we includea in 


fhe definition 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 (for both 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~ 


fugitive missions. 


Section 3.1.1 Individual Ccmponent Survey 


The monitoring for this study was 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 frm the 


portable hydrocarbon analyzer, to the emission factor without 


measuring m actual flow rate. In order to accept the emission 

factors as stated, the method for obtaining the emission rates 


must be described in more 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 ,-ad is 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~eretionziICGL-:oruim iihere :he 

vent system will 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 10,000ppmv 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 shutting down 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 regular maintainence period. 


Texas Oil & Gas Corp. strongly believes that the reguia~ion of fugitive VOC 

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 Affairs 
6330 HWY. 290 EAST 

AUSTIN, TEXAS 78723 

JOHN L. BLAIR 5121451-5711 

WILLIAM N. ALLAN 

Chairman 

CHARLES R. JAYNES 

Vice Chairman 

VITTORIO K. ARGENTO, P. E. 

FRED HARTMAN 

D. JACK KILIAN, M. 0. 

OTTO R. KUNZE,Ph. D., P; E. 

BILL STEWART,P. E. 

Exccutivc Dircctor 

FRANK H. 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 277 11 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, Dallas 
American Petroleum Institute 

2101 L Street Northwest 

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 2771 1 

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 ~eforethe 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, conta ct Ar. E. P. 

CrocKstt, 202/457-7084. 

Sincerely, 

C. T. Sawyer 

Attacnments 
AMERICAN 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 hand1 ing only me thane-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 1 from ;he CTG

for fugitive VOC emissions from chenical aanufactiring i EPA 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~nSource Test aata !CTG Appendix A; to demonscrate leaks 

were from gas-liquizs handling ,-~rnponents, i 3) 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 at elevatd 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 (vapor ized) 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 at best. 

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 repeatabiii ty; 

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 at gas 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 hydrocarbon detector 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 90 ten tially 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 diff icul 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 resill ts 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 ine thod 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 be tween 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 ficul t 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-28 
6. 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-hold - gas 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 manuf acturer. 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~hand 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 at plants where repair crews may only 

be' available two or three days per week. 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-30 
10. Paqe 4-2, 4 .Of last 7aragrapn -- "A his 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 

9e troleum/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 zz 
Zeveiop 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 tas2 ing . 

-

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 

first year 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-32 

16. 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 . 

~lantsalready use compressed air does not constitute justif ication 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 (letter from 

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-33 

with 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 approxima tel;~ $3.50/source ( i 96 1 

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 unnecessary 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, cost 
of 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 $1 2O/'repairea valve and 8 1 COO/ 

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 nearly twice 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 creai ts 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 inforna tion. 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 

Eaton, W. S., -et -al. [I 9801 . Fugitive ayarocarbon Einissions 

From Petroleum Production Operations. XPI Publication 4322, 

March, 1980. 

Woodruff, X. J., [I 9811 . Phillips Petroleum Company, Statemefit 

on Behalf of the American Petroleum Institute before the 

National Air Pollution Control Techniques Xaviscry Committee, 

Raleigh, NC, April 29, 1981. 

Sawyer, C. T., [1981]. Letter to The 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&P OPEAATIC)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: jk 

Emission 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, are being 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 in nine states. Michigan Wisconsin and its 

subsidiary ANR Production Company are also engaged in exploration for 

gap and oil in the major 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 for non-methane/nonethane hydrocarbons 

(VOCfs) will be 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 facilities because the quantity of non-methane/non-ethane hydrocarbons is very small for natural gas gathering plants. 

There are leak prevention and control procedures in place at most 

natural gas plants in compliance with minimum federal safety standards. 

The proposed technology in this document will be 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 in most instances, proposed control 

techniques are already in practice, at our facilities. 

Michigan Wisconsin would like to thank you for providing 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 the majority of the emission factors developed in 

this document should not be used to judge performance of these facilities. 

-- Sincerely yours, 

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 555 Market Streer. San Francisco. Cal~fornia . Phone (415) 894-3041 

\;I311 .AdGress. ?O. ~ C 3063. X 3an F-anc~sco.CA ?41 19 

3. 'N.Kreutzen 

:?qerai Manager 

i?wronmenra~ Aifa~rs 

March 12, 1982 

Draft CTG for Natural Cas/Gasoline 

Processine Plants 

\Ar. Jack R. Farmer, Chief 

Chemicals and Petroleum Branch 

Emission Standards and Engineering Division (.MD- 13) 

Office of Air Quality Planning and 

Standards 

U.S. Environmental Protection Agency 

Research Triangle Park, North Carolina 277 1 1 

Dear Mr. Farmer: 

Chevron is happy to comment on the draft CTG for natural gas/gasoline processing plants. 

We note considerable similarity between this document and the draft NSPS for VOC emissions, upon which we commented last November 16. There are enough differences 

between the two drafts, however, to warrant our offering a new set of comments. 

Section 2.2.7 Gas-Operated Control Valves 

No actual emission factors are given for these valves, nor any indication of how many use 

compressed air vs. "field gas." If the "field gas" is natural gas, very little nonmethanelnonethane hydrocarbon will be present. 

Table 2-2 Baseline Emission from Model Plants 

The baseline emissions are based upon the emission factors in Table 2-1. Althougn the 

95% confidence interval for these factors is extremelv large (generally a facsor of five or 

more), there are no error estimates for the total baseline emissions. What are the confidence figures on these numbers? 

Section 2.3 Baseline Fugitive VOC Emissions 

Estimating components by ratioing to major equipment has merit. However, ratioing 

components to all vessels pooled together (columns, heat exchangers, and drumsltanks) is 

an oversimplification, as demonstrated by Table 8-3. Com~aring the average ratio of 

flanges and connections to vessels (97.4) and the standard deviation of the ratio (59.7) 

shows the correlation is sometimes poor. This is also confirmed 5v the disparate ratios 

reported - about 50 for the EPA-tested plants and about '150 for the industrv-~ested 

plants. C-43 

Mr. Jack R. Farmer, Chief 

Page 2 

March 12, 1982 

Section 3.1.1 Individual Comoonent Survev 

This section fails to rnen~ion the considerable problems associated with maintaining and 

operating a portable hydrocarbon analyzer. They are temperamental precision instruments 

sensitive to heat, humiditv, and the Tvpe of gas being sampled. qeliable ilse requires 

thorough personnel training and careful maintenance and calibration procedures. For 

example, the inspection and maintenance program in Chevron's El Sequndo refinery requires 

one full-time person to maintain and service the detectors. Even if the same type of 

instruments are calibrated and used side by side, reproducible results can be elusive. This 

has been Chevron's experience 21 our Ventura County, California production facilities. 

The point is that portable hydrocar~on analyzers are verv trickv, and heir required use 

could be a considerable burden on smaller operators. 

Vonitorinq requirements for unsafe and difficult TO reach components should receive special consideration. At the least, this CTG should include the attached statement taken 

from the draft CTG on "Control of Volatile Organic Compound Fugitive Emissions from 

Synthetic Organic Chemical, Polymer, and Resin Manufacturing Equipment" (August, 

1981). 

Section -3.1.2.1 Pumps 

It is stated that a pump should be isolated from the proce'ss and flushed of VOC as much 

as possible prior to repacking or seal replacement. The reason for doing this would be to' 

assure that the temporary VOC emissions from repair do not exceed the emissions from 

the original leak. We believe that in practice this would be nearly impossible to do. EPA 

should consider the prospect that the emissions resulting from the repair of a pump leak 

could offset any long-term benefits, depending on the extent of the original leak. 

Section 3.1.2.2 Compressors 

We must take strong exception to the control strategy discussed here for reciprocating 

compressors. There are serious physical and safety considerations associated with enclosing 

compressor seals in the manner suggested. Rather than detail these issuks here, let me 

refer you to K. C. Hustvedt of your RTP facility, who is very familiar with the issues 

raised by industry when a similar strategy was proposed for refineries. 

Table 2-2 assigns compressors only 3% of the total gas plant emissions. In view of the 

serious problems associated with controlling these emissions, we strongly urge that this 

strategy be dropped. 

Section 3.1.3.2 Inspection Interval 

The draft CTG apparently considers only quarterly inspection intervals. EPA should seriously consider annual inspections, since quarterly inspections are practical only for a relatively small number of major components (like compressors). Even in Los Angeles, which 

generally has the toughest hydrocarbon control regulations in the nation, inspection with a 
Mr. Jack R. Farmer, Chief 

Page 3 

'vlarch 12, 1982 

detector is required annually for pumps, valves, and flanges, and quarterly for compressors. 

More frequent inspections are not judged cost effective. 

Section 3.1;3.3 Allowable Interval Before Fiepair 

The report suggests that 15 davs is reasonable to allow a plant operator enough time to 

obtain repair parts. While often true for readily available parts, this time is much too 

short for difficult-to-get parts. Allowing sixty davs in such special cases is more reasonable. 

Section 3.3 Other Control Strategies 

It is suggested that if less than 2% of the valves are found to be leaking, then the operator 

may skip inspections. We feel this a good concept, but it should be extended. The CTG 

still requires that inspections be carried out on a yearly basis. We believe that if data 

indicate a longer time interval would maintain a leak rate of less than 2%, then this inspection interval should be used. In addition, we can see no reason not to apply this concept to 

other fittings as well as valves. 

The subsections in section 3.3 are misnumbered. 

Chapter 4.0 Environmental Analysis of RACT 

This chapter could be improved considerably by looking at other inspection intervals. We 

thought the corresponding information in the NSPS was much more comprehensive and 

generally pretty accurate (with certain exceptions noted in our earlier letter). We would 

encourage you to add some of this information to the CTG. 

It is interesting to compare the values given in Tables 4-2 and 4-3 with Chevron's Los 

Angeles area refinery experience. The inspection and maintenance program for valves at 

our El Segundo refinery (10,000 ppm cutoff, annual inspection) yields a reduction 

efficiency of about 6596, not too far from the entry in Table 4-3 for quarterly inspections. 

On the other hand, our I&M program for compressors (quarterly inspections) yields about a 

35% reduction. The 100% reduction noted in Table 4-2 is not realistic (see our comment 

on section 3.1.2.2). 

Chapter 5.0 Control Cost Analysis of RACT 

We have some concerns about the costs that were used in estimating the cost effectiveness 

of the CTG. 

a. We currently would estimate the cost of labor to be $23.00 per hour rather than $13.00 

per hour (28% higher). 
.Mr. Jack R. Farmer, Chief 

Page 4 

March 12, 1982 

b. We do not believe a venting system could be installed on compressor seals for $700.00 

(pa e 5.10). National Air Oil Company estimates the cost of their smallest flare TO 

be 4 8,000. This would not include the cost of piping to each seal. 

Cost effectiveness numbers are given for a RACT program i'nvolving quarterly ins~ections. 

While these numbers are somewhat open to questions, for the reasons given earlier, rhe 

lack of incremental cost effectiveness calculations is a serious omission. What is the 

incremental cost effectiveness for annual or monthly inspections versus quarterly, for 

example? 

We hope these comments are helpful. For your information, we are attaching a copy of a 

technical paper given last November, which describes Chevron's experience with IJcM 

programs at our El Segundo, California refinery. If you wish to discuss our comments 

further, please contact Michael Foster of my staff at (415) 894-6107. 

Very truly yours, 

MSF:rdg 

Attachments 
ATTACHMENT 

The following statement is from the Draft CTG: "Control of Volatile Organic 

Compound Fugitive Emissions from Synthetic Organic Chemical, Pqlymer, and 

Resin Manufacturing Equipment" (August, 1981, page 3-29). 

Unsafe and Difficult to Reach Components 

Some components might be considered unsafe to moniror because process conditions include extreme temperatures or pressures. A State agency may wish to 

require less frequent monitoring intervals for these c o m p o n e n t s b e c a u s e of the 

potential danger which may be presented to monitoring personnel. For example. 

some pumps might be -monitored at rimes when process conditions are such thar 

the pumps are not operating under extreme temperatures or Fressures. 

Some valves may be difficult to reach because access to the valve bonnet is 

restricted or the valves are located in elevated areas. These valves might be 

reached by the use of a ladder or scaffolding. Valves which could be reached by 

the use of a ladder or which would not require monitoring personnel to be 

elevated higher than two meters might be monitored quarterly. However, valves 

which require the use of scaffolding or which require the elevation of monitoring 

personnel higher than two meters above permanent support surfaces might be 

monitored annually, for example. 
Clayton 2. ?rreeberro 

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 Quality Management District (SC&?4D> 3stab;ishing 

several regulations to reduce emissions of hydroczrSon, zn 3zone ?rlcursor. 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 

.,- effective 1. 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 modif ications. 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 Chev r.onfs 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 hydr ocarbon emissions have been cont rolled. These include tanks, 

oil/wat er separators, valves, flanges, pumps, and cornp ressors. Yet, 

the Basin is still nonattalnment for oz one. Whiie xob lle sources 
represent Tore than halhf the hydrocarSon e~isslonsIn the Szsin, 

Chevron expects additionai controls co be ~nposeci 3~ staslonzry 

sources. Such measures ~1115e mre exge?slve 2nd SICficl~ltts L~.zlement 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. m. --yese e~iss'sr ~stiz~zes 

include reduction crediss for ex1s:ing cor.'vrol xezsures, szch 2s 

secondary seals on floating roof tanks, various mocif Lcatl3ns tc bulk 

loading facilities, and limitations on the use of paints and organic 

solvents. Fugitive emissions are by far tke larges: -emainlz g S~CYZO 

category of hydrocarbon emissions within the ref L~.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&%ns from 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 add itlon to the two most significant rul?s c~vering valves, 

flange s, pumps, and compressors, there are six sther ~312siimlZLng 

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. - .. 

- irnpac t 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 h ey 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~ 


Tanks1 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 


eff'ect. 


3~eeTable 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~oreduction 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, zcrpressors which leak. In addition, lee rates 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 in heavy liquid ' service have ve rg 

low fugitive hydrocarbon emissions, and so they are exempt. Ethane 

,and methane are exempt because they do not contribute significantly cc, 

photochemical smog. .- Also, any stream 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 ?ressure >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 >3 drops per minute. 

- Gaseous hydrocarbon concentration ->10,000 ppm 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-~est2sted are counted, Sut only those wi:h enission :oncent rat ions 

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~sxay. 

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~eInspect ion reiuirements added May 1980. 

*~larl~eresults 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 ;resznc program. For example, the incremental css t effec:l.ier.ess sf 

1 - zdding the heavy liquid valves to the program waul? Se ~bcczGJ/-Z G : 4r 

7 - hydrocarbon controlled, which is currently not consl>iered tconomi:z,-; 

justified by most regulatory agencies and indus t ~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~ndb;; 

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 >3 drops/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 and each 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 sed rmlLtenance grcg~amis 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 

:he cost effectiveness of the rule Indicates th2~tlls ~ ~ costs 1 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 is not 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 es timatiDg fugitive missions generally invcl-~esfour 

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. rof lneyies. 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 emiss ion 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 program for 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 Ref ineries (November 1979, 

Austin, Texas). 
Amoco Production Company 

16825 Worthchase Grwe 

2.2s; Sff~ce32x -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 Carol ina 27711 

Attention: Fred Porter 

Re: Control Techniques Guide1 i ne Document 

Equipment Leaks from Natural Gas/Gasol ine Plants 

In accordance with the notice contained in the January 25, 1982 Federal 

Regi ster, Amoco Production Company (USA) we1 ccmes thi s 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-Industry has an interest in keeping fugitive 

emissions to a minimum. 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 detai 1ed monitoring and 

record keeping proposed in the CTG document. A much more cost effective 

procedure could be based on ambient concentration monitoring at or near the 

plant boundary. Such a system would 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 to reduce the 

concentration to normal 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 to reach the less accessible points 

around small valves and flanges. This will likely make sampling less than 

precise and subject to varying di 1 ution effects. 
a 


Page 2 

Comments for the specific parzgraphs of the 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 to be 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 di oxi de. 

Re: 3.1.2.2 Compressor 

Page 3-3 

Instal lation 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 possi bl e without rather extensive rodi f i caci cn 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 shoul d 

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 

re1 ief valve removal and removal of such valves nay reaui re ;arge 

hydrocarbon emissions while depressing the vessel and/or its , operating system and requi re expendi ture of hundred of do11ars 

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 site to facilitate re1 ief valve removal. In 

these cases, costs of thousands of dollars per valve can be 

expected. 
gel iei vzlves thus 1ocated wi 11 be difficult to noni tor and 

checking at 1 to 3 years interva7s (depending upon the service) 

is suggested. 

The construction of re1 ief 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 unreal i stic since even a minor leak 

into the re1 ief valve stack aay., over a period of time, displace 

all or part of the air and result in a high hydrocarbon 

indication, particulzrly if the hydrocar~on vapor is heavier than 

air. 

5.1.3.3 Allowable Interval Before hair 

Page 3-8 

The time interval for repair of a leak after its discovery 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 wi 11 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 to order 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 to use 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 first valve, only that 

it's release is controlled. The technique then becomes of 

questi onabl e val ue. 

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 to flanges 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 1 i nes . Thi s 

seems to be 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 materi a1 s , i .e. , no charges 

are shown for pipe support material. Costs at the eler 

plants, especially where attendance is minimal, 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 1 minute per valve is estimated. 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. At the point of maximum 

readout, the Probe is held stationary for at least twice the 

instrument response time. ,Once this has been noted (record 

keeping is required) the operator procedes to the next valve. 

Considering a1 1 the cal ibration time, instrument warmup, care and 

maintenance of the instrument and associated gas supplies, as 

we1 1 as the testing procedure, the time required could easi 1y 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/Y 
SOUTHERN CALIFORNIA DIV1S;ON 

3333 M1CHELSC)N DRIVE 

IRVINE. CALIFC3IJIA 927313 

TELEPHONE: (714)975-2003 

TELEX: 6924% 

Mr. Jack R. Farmer 

Chief Chemical s and Petrol eum Eranch 

Emissions Standards and Engineering Division 

U.S. Environmental Protection Agency 

Research Triangle Park, North Carol ina 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 guide1 ines 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 trul y yours, I 

!,li7 1iam 1.1. Hathaway 

Vice President, Process Engineering 

Senior Manager, Envi ronmenial Engineer in: 

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 of the draft control techniques gui del ine (CTG) 

document for control of volatile organic compound (VOC) emissions from 

equipment leaks in natural gaslgasol ine processing plants (gas plants) 

in the Federal Register (47 FR 3403). Public comments were requested 

on the draft CTG and comments were received by industry representatives 

as listed in Table D-1. The comments that were submitted, along with 

response to these comments, are summarized in this appendix. This 

summary of comments and responses serves as the basis for revisions 

made to the draft CTG. 

D.l GENERAL 

Cment : 

One commenter (5) requested that the comment period be extended 

to give industry more time to further analyze these complex regulations. 

Response : 

The CTG incorporates p.ublic comments from the preliminary draft 

CTG (March 1981) presented to the National Air- Pol 1 ution Control 

Techniques Advisory Committee (NAPCTAC) in April 1981 and comments 

received on the draft CTG (December 1981) that was announced in the 

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 in the CTG as applicable. EPA has 

been working with industry since the inception of the gas plants 

NSPS/CTG projects in December of 1979. Therefore, there has been 

ample time for public comment. 
D.2 NEED FOR CTG 

Comment : 

One commenter (8) questions in general, the need for the standard 

stating that EPA has failed to demonstrate the effectiveness of the 

control measures proposed and has misrepresented the costs and cost 

effecti veness. 

Response : 

National Ambient Ai r Qua1 ity Standards (NAAQS) (Section 109 of 

the Clean Air Act) set a ceiling for public exposure to criteria 

pol lutants by establishing an ambient concentration level that must 

not be exceeded anywhere in the United States. This control techniques 

guidelines document will provide guidance to States and air pollution 

control agencies for RACT-based provi si ons appl icab1 e to gas plant 

faci 1 ities to reduce significantly volatile organic compound emissions 

to achieve and maintain NAAQS for ozone. The CTG environmental and 

cost impacts are based upon actual field studies in gas 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 in the following sections. 

Comment : 

Another commenter (9) wrote that leak prevention and control 

procedures are already in place at most natural gas plants in compliance 

with mi nimum federal safety standards. Proposed requi rements are 

repetitious and burdensome. 

Response : 

The commenter is apparently referring to occupational safety 

requi rements which have different purposes and may result in di fferent 

envi ronmental benefits. Present industry practices (e.g., enclosing 

compressor distance pieces and venting emissi ons outside of a compressor 

house) may reduce occupational exposures, but they do not necessari ly 

reduce the mass emissions to the atmosphere. The data base upon which 

these recommendations are made is from plants in compliance with 

existing rules. These data show gas plants have significant emissions 

and that cost-effective controls wi 11 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 effecti veness (benefits don't 

outweigh c~sts per Executive Order 12291). 

Response: 

In Section 4.1 a small plant cutoff is recommended based on cost 

effectiveness of RACT. Small plants may need to rely upon outside 

personnel to perform the 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 

si gni fi cant emi ssi ons , therefore, EPA has not exempted these sources. 

However, it seems reasonable that at some low percentage of VOC, 

sources would have very 1 imi ted VOC emission reduction potential. 

Therefore, dry gas equipment (less than 1 weight percent VOC) are exempt 

from RACT as described in Section 4.1 

Comment : 

A commenter (4) noted that the liquid and 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 is no 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 

in Section 4.1 exempts equipment at underground storage facilities and 

equi pment which operate under vacuum servi ce. 
D.4 CONTROL TECHNOLOGY 

D.4.1 Compressors 

Comment : 

One commenter (8) wrote that reducing VOC emissions from compressors 

below 10,000 ppmv is difficult and impractical. 

Res~onse: 

EPA recognizes that compressor repair to achieve 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 repai r would be requi red (unless a 

vent control system is installed) in those instances where repair can 

achieve VOC emission concentrations below 10,000 ppmv. Centrifugal 

compressors may operate in tandem, one in service while the other 

serves as a spare. In such 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 to operate 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 

ai r mi xture coul d reach expl osi ve 1imi ts. Enclosing compressors would 

requi re extensi ve modi fi cati on whi ch would be expensi ve and requi re 

s igni f icant 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 to a 

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 ,revised to 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 is either 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 to a 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 in the draft 

CTG are based on emi ss.i on measurements from open reci procat ing 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 to atmosphere. The data base also includes dry 

gas compressors, which are exempt from RACT requirements. The gas 

plants compressor seal emission factors have, therefore, been revi sed.l 

Using the revised emission factors in the model plants (see Table 2.2), 

compressor s e a l s contribute approximately 14 percent of total erni ssi ons . For the actual equipment counts found during API and EPA testing, 

compressor VOC emi ssions ranged from 0-42 percent and averaged 13 per'cent .2 

Therefore, compressor emissions are significant and emission control 

is considered. 

D.4.2 Leak Detection and Repair Methods 

Comment : 

Two commenters (8 and 10) wrote that isolating a pump and purging 

before repai r (repacking or seal rep1 acement) is not practical . Flushing fluid disposal is a problem. Another commenter (9) further 

questioned whether emissions resulting from pump repai r 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 is not included in emissions estimates or in 

computing recovery credits. 

Res~onse: 

Process industry pumps are now routinely isolated and purged 

prior to repair. Flushing fluid is routed to the oily storm sewer for 

treatment and disposal. This fluid is expected to be a small percentage 

of total plant waste. RACT does not mandate purging pumps prior to 

repair although a pump would normally be emptied prior to repair. 
Even ifthe pump were not purged and all process fluid in a pump were 

allowed to evaporate to atmosphere as a result of pump repair, these 

emissions are approximately equivalent to the mass emissions released 

to atmosphere by a leaking pump over a 3-day period, 9 kg. This would 

not offset the long-term benefits of RACT. 

The final comment is based on RACT requiriig shutdown and purge 

for repair of leaking equipment. The draft CTG included a provision 

that required repair of a1 1 leaks within one year of detection. RACT 

has been revised. such that repai rs requiring a unit shutdown may be 

delayed until the next scheduled shutdown. As such, RACT no longer 

requires yearly turnaround for repair of these equipment leaks. 

However, as discussed in Section 3.4.3, a State agency might wish to 

consider a provision in its regulation which would a1 low the Agency 

director to order an early unit shutdown for repai r of leaking components 

in cases where the percentage of leaking components awaiting repair at 

unit turnaround becomes excessive. 

Comment : 

Commenters (3 and 9) stated that facilities already have portable 

monitoring instruments (for safety purposes) that are effecti ve 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 requi red use can place a f i nanci a1 burden on small faci 1ities. 

Response : 

Facilities may use any instrument as long as it satisfies the 

requi rements specified in Reference Method 21. EPA recognizes that 

moni tori ng inst ruments wi 11 requi re periodic mai ntenance and has 

accounted for instrument mai ntenance in the annual cost of implementi ng 

the leak detection and repair program, including the cost of a spare 

instrument. Nevertheless, EPA agrees that small faci 1ities (plants 

with few equipment pieces) may incur higher costs per emission reduction 

and, therefore, as noted in Section 4.1 and D.3, small plants are 

exempted from RACT. 

Coimnent: 

One comnenter (8) wrote that soap sco~ing should be a1 lowed as a 

VOC detection method. 
Response: 

Soaping is pemi tted as a preliminary screening technique on 

certain equipment pieces as discussed in Section 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 requi re hard to get parts. 

Response : 

The 15-day repair interval was selected for RACT because it 

a1 lows operators sufficient time to accompl is-h repairs whi 1 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 in handling 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 

or during the next scheduled process unit turnaround. 

C omment : 

Another commenter (10) stated that unsafe and di ff icul t-to-moni tor 

components should be considered. 

Response: 

Guidelines are included in the 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 in gas plants. 

Comment: 

Two commenters (8 and 10) wrote that EPA should consider annual 

inspections because existing data (Eaton, 1980) dispute quarterly 

noni toring for a1 1 val ves, pumps, and re1 ief val ves. Quarterly inspect ions 

are practical only for a relatively small number of major components 

(e.g. compressors). 

Response: 

EPA data and models presented in the 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 to be reasonable as discussed in Chapter 5. 

The Eaton data, as discussed in Appendix A, support the data used in 

the analyses. 

Comnt: 

For the "skip-period" monitoring alternative work practice for 

val ves, one commenter (10) suggested that EPA shoul d a1 1 ow 1 ess frequent 

than. annual inspections for valves if data indicate that a 1 onger 

interval would keep the leak rate less than 2 percent. This concept 

should apply to other fittings as well as valves. 

Response : 

In developing skip-period monitoring, EPA did not consider inspection 

intervals longer than one year. In skip-lot sampling theory it is 

assumed that failures do not accumulate with time. For skip period 

monitoring, it is likely that leaks that occur will not be detected 

and wi 11 accumulate. EPA does not feel it.is reasonable to a1 low 

leaks to accumulate for greater than one year.4 Facilities with very 

low leak percentages may,, however, elect to comply with the allowable 

percent leaking alternative. 

"Skip" monitoring is not allowed for other sources because there 

are not enough other sources present for the statistics of skip monitoring 

to apply. In addition, 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 in leak 

rates. Consequently, no matter how many consecutive successful inspecti~ns 

are performed, there is little assurance that a low leak rate would 

continue if skipping were a1 1 owed. 

Comment : 

The same commenter (10) a1 so questioned emissions reduction 

estimates stating that 100 percent emission reduction (Table 4-2) for 

compressor controls is not realistic. Chevron's leak detection and 

repair program of quarterly inspections reduces emi ssi ons by 35 percent. 
Response : 

The assumption that compressor controls reduce emissions by 

100 percent is based on enclosing compressors and venting emissions to 

a control device rather than on leak detection and repai r 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 to a control 

device will result in essentially 100 percent control. 

Comnent : 

Another cormenter (11) remarked that achievi ng zero emissions 

from relief valves is difficult due to the metal-to-metal seat construction. Testing relief valves for leaks by using hydrocarbon detectors 

may be unrealistic because even minor leakage into the relief valve 

stack might give a high hydrocarbon reading, particularly ifthe 

hydrocarbon vapor is heavi er than ai r. 

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 in approximately a 63 percent VOC (69 percent 

THC) emission reduction efficiency. A1 so, re1 ief val ves may be desi gned 

to utilize an elastomeric O-ring seat as a backup to the conventional 

metal -to-metal seat while any leakage is control led by the elastomeric 

O-ring seat. Relief valves with O-ring seats have been tested and 

found to be bubble tight up to over 95 percent of set pressure and to 

reseat to this condition through several cycles. Finally, Method 21 

specifies that re1 ief 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 

to a plant flare where 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 to effectively control relief valve leakage and are allowed under 

RACT. 
Comment : 

One commenter (11) expressed concern that the removal of pressure 

re1 ief val ves may result in large emi ssi ons from depressurizing vessels 

at a cost of hundreds of dollars per valve (thousands of do1 lars per 

inaccessible valve) . Response : 

Three-way valves or block valves may already be in place to 

isolate pressure re1 ief val ves for repai r on-1 ine without depressuri ng 

the unit. If so, repair within 15 days should be accomplished. 

However, if pressure 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 di fferences and gi ve supporting 

data for techno1 ogy transfer. 

Response : 

EPA recognizes that di fferences exist between chemical and refinery 

process.units and gas plants; however, these differences do not preclude 

the transfer of control technology to the gas processing industry. In 

testing conducted in ethylene plants, process conditions approximate 

that of equipment pieces in cryogenic units of gas plants. In addition, 

only a small proportion of gas plant equipment are subject to conditions 

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. In API testing of the 

natural gas production industry, the process type, operating temperature 

and pressure, and line size were determined to be unrelated to equipment 

leaks early in the testing program; therefore, the recording of these 

data was discontinued. Feedstocks and product chemical types have 

been found to be important only in terms of vapor pressure; as a 

result, heavy 1iqui ds have been exempt from routine monitoring. 

Vibrational problems and other si te-speci f i c di fferences are 

unquantifiable. 
D.4.4 Gas Operated Control Val ves 

Comment : 

One commenter (10) stated that there are no emission factors 

given for gas operated control val ves nor indication of how many are 

used. There are very little nonmethane/nonethane hydrocarbons present 

in gas operated control val ves. Simi larly, another commenter (9) 

argued that because many remote natural gas gathering stations use gas 

operated control valves, compressed air is not acceptable RACT. 

Response : 

Gas operated control valves normally use air. In those instances 

in which gas is used to operate control valves, dry gas (methane and 

ethane) is normally 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 (8 and 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 in the vessel and component inventories. In addition, the 

component inventories at the two API-tested plants are unusually large 

and of questionable val ue in devel opi ng model pl ant conf igurati ons. 

Another wrote that the method of ratioing components to all vessels 

combined (columns, heat exchangers, drumltanks) is an oversimpl i fi cati on, 

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 in Appendix B, the 

latter two plant visits did not obtain information on vessel or equipment 

inventories. The purpose of model plants i s t o characterize the range 

of processing complexity. The diversity within the gas production 

industry is represented in the four gas plants were examined and is shown 

in the three model plants selected. In addition, the cost effectiveness of 
RACT 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 to estimate the magnitude of fugitive 

emissions and the magnitude of potential emission reductions through 

the appl icat ion of reasonably avai 1able control techniques . For this 

purpose, the emissions test data obtained from gas plants indicate 

that significant emissions are re1 eased to atmosphere from 1 eaki ng 

equipment and that implementation of the RACT requirements will reduce 

these emissions.. 

Comment : 

Two commenters (5 and 6) noted that other factors should be 

considered (besides the number of components) in estimating emissions 

(e.g., system pressure, equipment age, climate, past performance, gas 

composition, differences in plant 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 in detail in 

"Fugitive Emission Sources of Organic Compounds--Additional Information 

on Erni ssi ons, Emi ssi on Reductions, and Costs ." U.S. Envi ronmental 

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 to correlate with fugitive 

emissions was the volatility and/or phase of the process stream. 

Consistent with to this finding, RACT for gas plants exempts equipment 

that contact or contain heavy liquid VOC. Other variables such as 

line temperature and pressure indicated much lower degrees of correlation. 
Comments : 

Another commenter (6) wrote that the method for obtaining emission 

rates needs to be described in more detai 1. The commenter specifical ly 

questioned how EPA deri ves emission factors from concent rations measured 

by a hydrocarbon analyzer without measuring actual flow rate. 

Response : 

Equipment emi ssi on .rates were determi ned by enclosing the emi ssi on 

sources and measuring mass emi ssi ons . The screeni ng values, si mu1 - taneously measured, were correlated to the measured leak rate. The 

derivation of emission factors is presented in "On-shore Production of 

Crude Oi 1 and Natural Gas-Fugi tive Volatile Organic Compound €mission 

Sources-Data Analysis Report Frequency of Leak Occurrence and Emi ssi on 

Factors for Natural Gas Liquid Plants ,"U.S. Envi ronmental Protection 

Agency, Research Triangle Park, N.C. EMB Report No. 80-FOL-1. July 

1982. The emi ssi on factor development method01 ogy was revi ewed by 

industry representati ves and they determi ned that EPA's methods for 

emission factor development were appropri ate.5 

Comnent : 

One comment was received (11) stating that it is wrong to assume 

that 100 percent of emissions would be reduced by controls on open-ended 

lines. In many cases, open-ended vents would be routed to a flare, and 

energy recovery credits would not be appl icab1 e. 

Response : 

Capping an open-ended line limits emissions to the amount of VOC 

trapped between the val ve and cap (whether it be a plug, second val ve, 

etc.) which is released when the 1 ine is again opened. However, by 

closing the first valve prior to capping or closing the second valve, 

the safety of the technique is ensured and emissions minimized. A 

conservative estimate of the amount of VOC trapped in the line and the 

frequency of open-ended line use, nevertheless, results in almost 

100 percent VOC control (as discussed in Section 3.2.2). RACT for 

open-ended 1ines effectively controls emi ssi ons between each time the 

line is used. 
It appears as though the commenter has incorrectly assumed that 

process vents would need to be capped. Any open-ended line that 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 (1 and 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 thei r expense in the year 

when they are incurred). 

Response : 

Although the control cost of open-ended lines and.initia1 leak 

repair could be treated as operati ng expenses because they are one-t ime 

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 to pay these initial costs. 

Comnent: 

Two comnenters (8 and 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 incl udi ng 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. In addition, 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 in implementing RACT. 
Response : 

The monitoring time 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) is based on June 

1980 do1 lars. Updating the EPA estimate to present (June 1982) do1 lars 

results in a labor rate that exceeds the rate suggested ($18 x June 1982 

Cost Index 295.91June 1980 Cost Index 210.5 = $26. Reference: Chemical 

Engineering -87(20):7 and -89(19):7). Set-up costs, equipment depreciation, 

and instrument maintenance costs are included in the 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 a1 1 weather 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 if outside 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)'-wrote that 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 to one 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 addi tional 

recordkeeping or tagging. The second valve is not subject to the 
valve 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 is the 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 blind flange 

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/repai red val ve and $10b0/repai red pump are real istic 

repair costs. 

Response : 

In Chapter 5, a $140/seal replacement cost is included in the 

cost of pump repair. The cost analysis a1 so includes annual miscel laneou! 

(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 do1 1 ars) . Administrative and support costs to implement 

RACT (0.40 x monitoring labor + maintenance labor) are also included. 

Very few valves wi 11 require repacking. Chapter 4 includes provisions 

for less frequent monitoring of difficult to monitor valves and repairs 

that cannot be completed on-1 ine. These repai rs may be delayed until 

the next scheduled shutdown. 

Comnent : 

One respondent (11) remarked that monitoring time 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.4 ated 

with it. 

Coment : 

One commenter (10) was concerned that RACT compressor controlcosts are too high in consideration of their small proportion to total 

emissions. The venting system would require extra valves for safety. 
The enti re costs for the control system will exceed $700, and the cost 

of a small flare is about $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 a1 so 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 : 

Simi 1 arly, another commenter (9) expressed concern that the cost 

of a VOC monitoring instrument, its maintenance, and calibration are 

high compared to current practices of leak detection. 

Response: 

The draft CTG has included the cost of two monitoring instruments, 

instrument maintenance calibration time, and two-man monitoring teams 

to obtain maximum cost impacts from implementation of RACT. In Chapter 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 monitoring teams may be employed and less expensive monitoring 

instruments may be purchased. Also, many equipment pieces will not 

require instrument monitoring if soaping is used as a preliminary 

screening technique. 

Comment : 

One commenter (8) pointed out that the value of recovery credits 

for VOC ($210/Mg) is incorrectly based on the assumption that all the 

VOC is propane. 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 1980 
and 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 repai r is 

cost effecti ve and represents reasonably avai 1 a b l e control techno1 ogy . In Chapter 5, Table 5-10 presents the cost effectiveness of quarterly 

leak detection and repai r for val ves, pumps, re1 ief val ves, 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) is to inform 

ai r pollution control agencies responsible for achieving and maintaining 

national ambient air qua1 ity standards of reasonably available control 

technology (RACT) . These agenci es may formul ate thei r own regul ati ons 

based upon the CTG; however, the CTG itself is not intended to evaluate 

a1 ternati ve control strategies and the incremental cost effectiveness 

between the alternatives. 
D .8 References 

Memorandum. K.C. Hustvedt EPA:CPB to James F. Durham, Revised 

Gas Plant Compressor Seal Emission Factor. February 10, 1983. 

Memorandum, Kent C. Hustvedt CPB:EPA to James F. Durham, CPB:EPA, 

Estimated Compressor Seal VOC Emissions Contribution for API and 

EPA Tested Gas Plants. March 22, 1983. 

Memorandum, K.C. Hustvedt, EPA:CPB, to J .F. Durham EPA:CPB, 

API /Rockwe1 1 Maintenance Data. December 9, 1982. 

? 

Memorandum, Kent C. Hustvedt CPB:EPA to James F. Durham CPB:EPA 

Skip Monitoring for Fugitive Emi ssion Sources. December 14, 

1981. 

L e t t e r w i t h attachment from D.A. DuBose, Radian Corporation, to 

W.E. Kel ly, EMB:EPA, July 22, .I982 - attachments are Radian and. 

TRW report, of the January 28, 1982 meeting with API on gas plant 

emission factors. 
h 

TECHNICAL REPORT DATA 

(Please read Insmcnons on rhe reverse before cornpiering) 

1. REPORT NO. 2. 3. RECIPIENT'S ACCESSION NO. 

ERA-450/ 3-&-007 

4. TITLE AND SUBTITLE 5. REPORT DATE 

Control of Volatile Organic Compound Equipment Leaks December 1983 

from Natural Gas/Gasol i ne Processi ng Pl ants- 6. PERFORMING ORGANIZATION CODE 

Gui del i ne Series 

7. AUTHOR(S1 8. PERFORMING ORGANIZATION REPORT NO. 

9. PERFCRMING ORGANIZATION NAME AND ADDRESS 10. PROGRAM ELEMENT NO. 

Office of Air Quality Planning and Standards 

Environmental Protection Agency ll. CONTRACT/GRANT NO. 

Research Triangle Park, ~orth carol ina 2771 1 ( 

12. SPONSORING AGENSY NAME AND ADDRESS 13. TYPE OF REPORT AND PERIOD COVERED 

Director of Air qua1i ty Planning and Standards 

Office of Air Qua1 14. SPONSORING AGENCY CODE ity Planning and Standards 

2. S. Envi roncental Protection !!gency EPA/ 200/ 04 

Research Triangle Park, North Carol ina 2771 1 

15. SUPPLEMENTARY NOTES 

16. AaSTRACT 

Control Technique Guidel ines (CTG) are issued for volatil e organic compound 

(VOC) equipment 1 eaks from natural gadgas01 ine processing plants 

to inform Regional, State, and local air pollution control agencies of reasonably 

avail ab1 e control technology (RACT) for development of regul ations necessary to 

attain the national ambient air quality standard for ozone. This document contains 

information on RACT environmental and cost impacts. 

- 17. KEY WORDS AND DOCUMENT ANALYSIS 

a. OESCRI PTORS b. IOENTlFIERS/OPEN ENDED TERMS C. COSaTl Field/Group 

Air Pollution 

Gas/gasol i ne Processing Pl ants 

Pollution Control . Air Po1 1 ution Control 13b 

Reasonably Avai 1 ab1 e Control Techno1 ogy Vol ati 1 e Organic Compounds (VOC) 

18. DISTRIBUTION STATEMENT 19. SECURITY CLASS (ThisReporr) 21. NO. OF PAGES 

Unclassified 173 

Un1 imi ted 120. SECURITY CLASS iThis page) 22. PRICE 

I Unclassified I 

EPA Form 2220-1 (Rev. 4-77) .PREVIOUS EDITION IS OBSOLETE 

1