OAR Box 1127 

Prepped by Ollie Stewart 

Document Number: 

10) ll-C-5 

Docket Number: 

A-84-44 

Printed 4/18/2008 2:39:33 PM Sheet 10 of 95 

p.1 
P.2 

'" ir 

IDENTICAL LETTERS SENT TO CURRENT ROSTER OF COMMITTEE (LIST ATTACHED TO OFFICAL FILE) 

\ A- B4- 44-

August 5, 1986 %-t-s 

Dear Committee Member: 

As indicated in my letter of July 31, 1986, the next meeting of the 

National Air Pollution Control Techniques Advisory Committee (NAPCTAC) is 

scheduled for September 17 and 18, 1986, at the Sheraton University 

Center in Durham, North Carolina. A copy of the agenda for the meeting 

is enclosed; the current roster for the NAPCTAC is shown on the back of 

the agenda. If you have any changes to the roster, please call Mary Jane 

Clark. 

Enclosed are the draft preamble/regulation and background document 

for the revision of the asbestos national emission standards for hazardous 

air pollutants. Also, enclosed are the draft Federal Register notices 

and background documents for the reviews of the new source performance 

standards for primary aluminum and refinery fuel gas. 

The remainder of the materials to be discussed at the meeting will 

be mailed next week. Your travel information was mailed on July 31, and 

I suggest that you make your flight reservations as soon as possible in 

order to take advantage of special air fares. 

For your information, a block of rooms is being held at the Sheraton 

until September 7 for use by those who wish to stay where the meeting is 

being held; the telephone number is (919) 383-8575. The Sheraton does 

provide a courtesy airport limousine. 

Please call Mary Jane Clark at (919) 541-5571 if you need additional 

information or will be unable to attend. 

Sincerely, 

A 

\ Jack R. Farmer 

Chairperson 

National Air Pollution Control 

Techniques Advisory Committee 

7 Enclosures 

OAQPS: ESED: OD: MJClark: mjclark, rm 741, NCM, x5571 (MD-13): 7/31/86 

bcc: Bill Maxwell, ISB/ESED 

Debbie Stackhouse, SDB/ESED (3 copies: SDB file and 2 for docket) 

John Copeland, ISB/ESED 

Sims Roy, SDB/ESED (4 copies: SDB file, contractor, and 2 for docket) 

Larry Elmore, ISB/ESED 

Gail Lacy, SDB/ESED (3 copies: ISB file and 2 for docket) 
P.3 

August 1986 

U.S. ENVIRONMENTAL PROTECTION AGENCY 

NATIONAL AIR POLLUTION CONTROL TECHNIQUES ADVISORY COMMITTEE 

Chairperson 

Mr. Jack R. Farmer 

Director, Emission Standards and Engineering Division (MD-13) 

Office of Air Quality Planning and Standards 

U. S. Environmental Protection Agency 

Research Triangle Park, North Carolina 27711 

(919) 

FTS: 

541-5571 

629-5571 

COMMITTEE MEMBERS 

Mr. Thomas M. Allen, P.E. 

Associate Di rector 

Division of Air Resources 

New York State Department 

of Environmental Conservation 

50 Wolf Road - Room 128 

Albany, New York 12233-0001 

(518) 457-7230 

Mr. Robert H. Col lorn, Jr. 

Chief, Air Protection Branch 

Environmental Protection Division 

Department of Natural Resources 

Floyd Towers East - Room 1162 

205 Butler Street, S.E. 

Atlanta, Georgia 30334 

(404) 656-6900 

Dr. Thomas H. Goodgame 

President 

Environmental and Chemical 

Consulting Engineers, Inc. 

Post Office Box 914 

Alamogordo, New Mexico 88310 

(505) 434-4353 

Ms. Linda E. Greer 

Staff Scientist, Toxic Chemicals Program 

Environmental Defense Fund 

1616 P Street, N.W.-Suite 150 

Washington, D. C. 20036 

(202) 387-3500 

Ms. Karen M. Hanzevack 

University of North Carolina 

3 Dartford Court 

Chapel Hill , North Carolina 27514 

(919) 493-7438 

Mr. Robert P. Miller 

Chief, Air Quality Division 

Michigan Department of Natural Resources 

Stevens T. Mason Building, Box 30028 

Lansing, Michigan 48909 

(517) 373-7023 

Mr. Robert M. Morford 

Vice President and General Manager 

Western Precipitation Division 

Joy Manufacturing Company 

Post Office Box 2744-Terminal Annex 

Los Angeles, California 90051 

(818) 240-2300, extension 502 

Mr. Andrew H. Nickolaus 

Senior Environmental Control Consultant 

Engineering Division 

E. I. du Pont de Nemours & Company, Inc. 

Post Office Box 2626 

Victoria, Texas 77902 

(512) 572-1277 

Mr. Roger D. Randolph 

Supervisor, Air Quality Control Program 

Tulsa City-County Health Department 

4616 East 15th Street 

Tulsa, Oklahoma 74112 

(918) 744-1000, extension 320 

Mr. William M. Reiter 

President 

Cape Environmental Associates, Inc. 

Post Office Box 2162 

Ocean City , New Jersey 08226 

(609) 398-6506 

Dr. Edward S. Rubin 

Director, CEES 

Professor of Mechanical 

Engineering and Public Policy 

Carnegie-Mellon University 

Schenley Park 

Pittsburgh, Pennsylvania 15213 

(412) 268-2491 
P.4 

DRAFT 

ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Part 60 

[AD-FRL ] 

REVIEW OF STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES 

PETROLEUM REFINERIES 

AGENCY: Environmental Protection Agency (EPA) 

ACTION: Review of Standards for Petroleum Refinery Fuel Gas 

SUMMARY: Under Section 111 of the Clean Air Act, EPA is required to 

review standards of performance for new, modified, or reconstructed 

stationary sources every 4 years. A review of the existing standards of 

performance for petroleum refineries (40 CFR 60, Subpart J) has been 

completed. The review indicates that no revision to that portion of 

the standard relating to refinery fuel gas is necessary at this time. 

However, the Agency is investigating the application of a continuous 

emission monitor for measuring the sulfur concentration in treated refinery 

fuel gas. When this measurement technique is decided upon and a FEDERAL 

REGISTER notice is proposed for the continuous monitoring, any necessary 

changes to the subpart (resulting from use of the continuous monitors) will be 

accomplished concurrently. 

ADDRESSES: Document: The document "Review of New Source Performance 

Standards for Petroleum Refinery Fuel Gas" (EPA report No. EPA ) 

may be obtained from the U.S. EPA Library (MD-35), Research Triangle 

Park, North Carolina, 27711, telephone number (919)541-2777. 
P.5 

Docket. A docket, number A-84-44, containing information considered 

by EPA during the review, is available for public inspection between 

8:00 a.m. and 4:00 p.m., Monday through Friday, at EPA's Central Docket 

Section (A-130), West Tower Lobby, Gallery 1, 401 M Street, S.W., 

Washington, D.C. 20460. A reasonable fee may be charged for copying. 

FOR FURTHER INFORMATION CONTACT: For further information and 

interpretations of applicability, compliance requirements, and reporting 

aspects of the standards, contact the appropriate Regional, State, or 

local Office contact as listed in 40 CFR 60.4. For further information 

concerning the technical aspects of this review, contact Mr. Wm. Larry 

Elmore, Industrial Studies Branch, Emission Standards and Engineering 

Division (MD-13), U.S. Environmental Protection Agency, Research Triangle 

Park, North Carolina 27711, telephone (919) 541-5595. For further information 

concerning the policy aspects of this review, contact Ms. Gail K. Lacy, 

Standards Development Branch, Emission Standards and Engineering Division 

(MD-13), U.S. Environmental Protection Agency, Research Triangle Park, 

North Carolina 27711, telephone (919)541-5578. 

SUPPLEMENTARY INFORMATION: 

I. Background 

New source performance standards (NSPS) for petroleum refineries 

were proposed by the EPA on June 11, 1973 (38 FR 15406) and promulgated 

on March 8, 1974 (30 FR 9308). One portion of these standards regulates 

sulfur dioxide (SO2) emissions from combustion devices capable of burning 
P.6 

refinery fuel gas. Refinery fuel gas i s defined as any gas which i s 

generated at a petroleum refinery and which i s combusted. Fuel gas also 

includes natural gas when the natural gas i s combined and combusted in 

any proportion with a gas generated at a refinery . 

This NSPS allows the owner/operator two options to control SO2 

emissions from combustion devices capable of burning refinery fuel gas. 

One option i s to control the hydrogen sulfide (HgS) concentration in 

refinery fuel gas to 230 milligrams/dry standard cubic meter (mg/dscm) 

[0.10 grains/dry standard cubic foot (gr/dscf)] prior to being burned in 

a combustion device. The other option allows for control of SO2 emissions 

from the refinery fuel gas combustion device without controlling the H2S 

concentration i n the refinery fuel gas. The Agency i s not aware of any 

refinery that utilize s thi s latte r option. 

As required by Section 111(a)(1) of the Act, the promulgated standards 

reflec t application of "the best technological system of continuous 

emission reduction which (taking into consideration the cost of achieving 

such emission reduction, any non-air qualit y health and environmental 

impact and energy requirements) the Administrator determines has been 

adequately demonstrated." For convenience, thi s is referred to as "best 

demonstrated technology" or "BDT." 

Section 111(b)(1)(b) of the Act requires the EPA t o review and, i f 

appropriate, revise NSPS, at least every 4 years. The principal purpose 

of such review and appropriate revisions i s to ensure that the standards 

reflec t a current assessment of BDT. 
P.7 

The review of the refinery fuel gas standard has been conducted by 

contacting EPA regional offices, State agencies, the American Petroleum 

Institute, companies subject to the NSPS, and control equipment vendors. 

Information was collected on the number and location of facilities subject 

to the NSPS, control equipment performance and costs, and testing and 

monitoring data. From these sources, a document was prepared covering 

the current status of control technology with emphasis on units subject 

to the NSPS compliance test data, monitoring systems employed, and costs 

and cost effectiveness for a control system. 

II. Findings 

A. Industry Information 

The "affected facility" is defined as any combustion device that is 

capable of burning refinery fuel gas. The exact number of fuel gas combustion 

devices subject to this standard is unknown because the control devices 

treat gas distributed to many fuel gas combustion devices. According to 

information obtained by EPA's Stationary Source Compliance Division, 

54 petroleum refineries have become subject to that portion of 

the standard relating to combustion of refinery fuel gas since 1975. 

Trade journals were also reviewed for information on new refinery 

construction projects. During the 1980-1985 period, there were 42 

construction projects that involved H2S control systems at petroleum 

refineries. 

The overall petroleum refinery industry has experienced negative growth. 

From January 1981 to December 1985, a total of 112 refineries have been 
" "! 

shut down bringing the total of operable refineries to 191. The petroleum 

refining industry continues to make long-term adjustments in response to 

the slow down in product demand, shifts in the product mix, and the 

declining quality of crude oil supplies. These adjustments have resulted 

in the expansion of existing refineries which may lead to new, modified, 

or reconstructed fuel gas combustion devices. In order to comply 

with the NSPS, refineries are continuing to install new H2S control 

systems or expand existing H2S control capacity. 

B. Emission Control Technology. 

In order to comply with the refinery fuel gas H2S concentration 

limit, the owner/operator of the affected facility has the option of 

either reducing the H2S concentration prior to burning the refinery fuel 

gas in the affected facility or treating the SO2 emissions from the 

affected facility. Presently, all known affected facilities control SO2 

emissions by reducing the H2S concentration in the refinery fuel gas 

prior to being burned. Two processes are being used to comply with this 

NSPS: the alkanolamine process and the LO-CAT® process. (Mention of trade 

names or commercial products is not intended to constitute endorsement or 

recommendation for use.) 

The vast majority of the control units used to remove H2S are 

alkanolamine systems. In this process, refinery fuel gas containing H2S 

contacts the alkanolamine in an absorber unit. The H2S is removed from the 

refinery fuel gas and the treated gas is then used as fuel elsewhere in the 

refinery. The alkanolamine solution is regenerated by steam stripping in 
P.9 

a regenerator. The steam is condensed and the separated H2S is piped to 

a sulfur recovery unit. The regenerated alkanolamine is recycled to the 

absorber unit. 

The LO-CAT® process removes H2S from refinery fuel gas by using an 

aqueous catalyst which is circulated in a closed loop between the absorber 

and the oxidizer vessel. In the absorber the H2S gas is absorbed very 

rapidly into the catalyst solution where it is immediately oxidized to 

precipitate elemental sulfur. Partially reduced catalyst solution is 

regenerated in the oxidizer vessel by direct contact with compressed air. 

Sulfur formed in the absorber vessel circulates with the catalyst solution 

and the particles grow to the 10-20 micrometer range. The larger sulfur 

particles settle out of the catalyst solution in the oxidizer vessel and 

are pumped to a melter then to a storage vessel. 

The review did not find any demonstrated technologies for controlling 

emissions that achieve better control than the technologies just described. 

Analyses of the cost of the technologies upon which the standard is based 

showed that the costs remain reasonable. Therefore, the EPA concludes that 

the technology on which the standard is based is still appropriate. 

C. Achievability 

Data for'fifteen compliance tests were obtained from nine different 

refineries. All of the test data that were submitted were from refineries 

that use an alkanolamine process system to remove the H2S from the refinery 

fuel gas. Compliance test results for the H2S concentration in refinery 

fuel gas ranges from 2.97 mg/dscm to 119.43 mg/dscm (the NSPS is 230 mg/dscm), 
P.10 

No compliance test data were obtained for a LO-CAT® system; however, 

one refinery with such a system has installed a continuous H2S monitor. 

According to information submitted by the refinery , the H2S concentration 

of the refinery fuel gas treated by the LO-CAT® system ranges from 

28.4 mg/dscm to 71 mg/dscm. 

The H2S concentration limi t for refinery fuel gas was originall y 

based upon the alkanolamine technology. As already described, thi s review 

found that alkanolamine systems are stil l applicable to al l plants 

and can achieve the emission limi t at a reasonable cost. 

The LO-CAT® technology has been installed at two refineries and also i s 

capable of complying with the standard. 

Review of the compliance data suggest the possibilit y of lowering the 

emission limit . However, with the present emission limit , owners and operators 

wil l continue to use the technology design on which the standard i s based in 

order t o stay below the limit . Also, since EPA has not proposed and promulgated 

specifications for the continuous monitors, there i s no long-term data from 

certifie d continuous emission monitors to determine whether a lower H2S 

concentration limi t can be maintained on a continuous basis. Therefore, the 

EPA has concluded that retaining the current NSPS emission level i s appropriate, 

at thi s time. 

D. Cost Impacts 

Information on the capital and annualized costs of control units used to 

remove H2S was supplied by refineries subject t o the NSPS and a vendor of the 

control equipment. The cost effectiveness of controlling the H2S concentration 
P.11 

i n refinery fuel gas was estimated for four model unit sizes [amine treatment: 

5.08, 10.16, 50.8 and 101.6 megagram/day (Mg/D); LO-CAT® 1.02, 2.03, 5.08 

and 10.16 Mg/D] at three H2S concentrations (1%, 5% and 10% H2S) for both 

types of control systems. For the alkanolamine system with a Claus sulfur 

recovery unit , the cost effectiveness (January 1985 dollars ) ranges from 

$222/Mg of SO2 for the 5.08 Mg/D plant t o a credit of $11.5/Mg of SO2 

for the 101.6 Mg/D plant. The cost effectiveness (January 1985 dollars) for 

the LO-CAT® system ranges from $98/Mg to $440/Mg of SO2 removed for the 

10.16 and the 1.02 Mg/D plant respectively. 

E. Test Requirements 

The regulation requires facilitie s subject to the H2S concentration 

limi t to monitor the pollutant with a continuous emission monitor. 

However, thi s requirement i s not presently in effect because the EPA has 

not established performance specifications fo r H2S continuous emission 

monitors. In 1980, the EPA studied H2S continuous emission monitors but 

did not find any that were acceptable. Recently, the Agency contacted 

various State and local agencies and petroleum refineries in an attempt 

to collect any existing data for H2S continuous emission monitors. The 

conclusion of thi s study was that insufficien t data exist t o establish 

performance specifications for H2S monitors. A recommendation resulting 

from thi s NSPS review i s that EPA develop an alternative method of continuously measuring the sulfur concentration in treated refinery fuel gas. 

One method.that EPA wil l consider i s the use of continuous SO2 monitors. 
P.12 

III. Conclusions 

Based on the above findings, the EPA concludes that the.level of 

control required by the NSPS for petroleum refinery fuel gas reflects 

BDT considering economic impacts. Therefore, no changes in the standards 

are being made. Revisions to the monitoring requirements of the standard 

are appropriate and EPA will investigate alternatives for measuring the 

sulfur concentration in refinery fuel gas. If the investigations reveal 

that an alternative technique is reasonable, the Agency will propose this 

technique and any changes in the regulation necessitated by the continuous 

monitoring technique in the FEDERAL REGISTER. 

IV. Miscellaneous 

Publication of this review was preceded by consultation with appropriate 

advisory committees, independent experts, and Federal departments and 

agencies. 

This regulation will be reviewed again in 4 years as required by the 

Clean Air Act. This review will include an assessment of such factors as 

the need for integration with other programs, the existence of alternative 

methods, enforceability, improvements in emission control technology, 

and reporting requirements. 

The information generated by the monitoring recordkeeping and reporting 

requirements of the standards is necessary and reasonable and will continue 

to be used by EPA to ensure compliance with the NSPS. The total annual 

burden associated with these requirements is estimated to be 12,599 personhours per year for all respondents. Under the standards, the data collected 
P.13 

by the affected industry would be retained a minimum of 2 years and made 

available for inspection as necessary. 

The reporting and recordkeeping associated with the reviewed standards 

have current approval of the Office of Management and Budget (OMB) under 

Section 3504(h) of the Paperwork Reduction Act of 1980, 44 U.S.C. 3501 et_ 

seq., and have been assigned OMB control number 2060- . Expiration 

date of the information collection requirements is . 

The Regulatory Flexibility Act of 1980 requires that the adverse 

impact of Federal Regulations on small businesses be identified. The Act 

requires the completion of a Regulatory Flexibility Analysis in those 

instances when small business impacts are possible. None of the refineries 

presently subject to the refinery fuel gas NSPS are unreasonably affected 

by the standard. Based on the cost analysis, economic impacts on new 

small refineries are expected to be small. It is the Administrator's 

determination that the standard will not have a significant economic 

impact on a substantial number of small businesses. Accordingly, a small 

business impact analysis has not been prepared. 

V. List of Subjects in 40 CFR Part 60 

Air pollution control, reporting and recordkeeping requirements, 

intergovernmental regulations, and petroleum refineries. 

Date Assistant Administrator for 

Air and Radiation 

10 
« •> 

* 

United States Office of Air Quality 

Environmental Protection Planning and Standards JULY 1986 

Agency Research Triangle Park NC 27711 

Air l 

Review of 

New Source 

Performance 

Standards for 

Petroleum RefineryFuel Gas 

P 14 

Preliminary Draft 

.ra-r, "af :wryrri.njMgain:T.st •liEHi.'srrrg'E;. 
P.15 

NOTICE 

This document has not been formally released by EPA and should not now be construed to represent Agency 

policy. It is being circulated for comment on its technical accuracy and policy implications. 

Preliminary Draft 

Review of New Source Performance 

Standards for Petroleum Refinery Fuel Gas 

Emission Standards and Engineering Division 

U.S. ENVIRONMENTAL PROTECTION AGENCY 

Office of Air and Radiation 

Office of Air Quality Planning and Standards 

Research Triangle Park, NC 27711 

July 1986 
P.16 

TABLE OF CONTENTS 

Page 

1. SUMMARY 1-1 

1.1 CONTROL TECHNOLOGY 1-1 

1.2 ECONOMIC CONSIDERATIONS AFFECTING THE NSPS 1-1 

2. CURRENT STANDARD 2-1 

2.1 NEW SOURCE PERFORMANCE STANDARDS 2-1 

2.2 LEGISLATIVE HISTORY 2-12 

2.3 STATE REGULATIONS 2-15 

2.4 OTHER FEDERAL REGULATIONS 2-16 

2.5 REFERENCES 2-18 

3. INDUSTRY DESCRIPTION 

3.1 BACKGROUND INFORMATION 3-1 

3.2 INDUSTRY CHARACTERIZATION 3-4 

3.3 EMISSIONS FROM COMBUSTION OF REFINERY FUEL GAS 3-8 

3.4 SELECTION OF REFINERY COMBUSTION DEVICES FOR NSPS CONTROL 3-10 

3.5 REFERENCES 3-10 

4. STATUS OF CONTROL TECHNOLOGY 4-1 

4.1 ALKANOLAMINE PROCESS SYSTEM 4-1 

4.2 THE LO-CAT® HYDROGEN SULFIDE OXIDATION PROCESS 4-8 

4.3 FACILITIES SUBJECT TO THE NSPS 4-12 

4.4 COMPLIANCE TEST RESULTS 4-13 

4.5 EMISSION MONITORING 4-15 

4.6 REFERENCES 4-16 
P.17 

Page 

5. MODEL PLANTS 5-1 

5.1 MODEL PLANTS AND CONTROL SYSTEMS 5-1 

5.2 EMISSION REDUCTIONS 5-2 

6. COST ANALYSIS 6-1 

6.1 INTRODUCTION 6-1 

6.2 AMINE TREATMENT WITH CLAUS SULFUR RECOVERY 6-2 

6.3 LO-CAT® PROCESS 6-6 

6.4 COST-EFFECTIVENESS 6-16 

6.5 COST COMPARISON 6-23 

6.6 REFERENCES 6-24 
P.18 

1. SUMMARY 

1.1 CONTROL TECHNOLOGY 

Currently, petroleum refineries are using two types of control 

technologies, the alkanolamine or the LO-CAT® system, to comply with the 

hydrogen sulfide (H2S) concentration limit (230 mg/dscm) of this new 

source performance standard (NSPS). Data for fifteen compliance tests 

were obtained from nine different refineries. All of the test data are 

from refineries that use an alkanolamine system. The compliance test 

results range from 2.97 mg/dscm to 119.43 mg/dscm. 

No compliance test data were obtained from a LO-CAT® system; however, 

one refinery with such a system has installed a continuous H2S monitor. 

According to information submitted by the refinery, the H2S concentration 

ranges from 20 ppmv to 50 ppmv and averages 30 ppmv (NSPS is 162 ppmv). 

The review did not find any demonstrated technologies for controlling 

emissions that achieve more control than the alkanolamine or the LO-CAT® 

systems. 

1.2 ECONOMIC CONSIDERATIONS AFFECTING THE NSPS 

Another primary issue involving review of the NSPS is the cost of 

controls. The cost effectiveness of controlling the H2S concentration in 

refinery fuel gas was estimated for four model plant sizes at three H2S 

concentrations for both types of control systems. For most of the new NSPS 

units, the costs of control per unit of sulfur dioxide (SO2) removed will 

be less than those discussed in this section. The cost effectiveness 

ranges from $201 per ton of SO2 to a credit of $23.9 per ton of SO2 for 

the alkanolamine system with a Claus sulfur recovery unit. The cost 

effectiveness for the LO-CAT® system ranges from $89 per ton to $399 per 

ton of SO2 removed. 
P.19 

2. CURRENT STANDARDS 

This chapter presents and discusses the current regulations for air 

pollutant emissions from refinery fuel gas combustion devices. Federal 

regulations for new sources, other Federal regulations, and State regulations 

(for exisi ting and new sources) are all addressed in order to give an overall 

picture of the regulatory structure for this emission source category. The 

focus, however, is on the new source performance, standards (NSPS) for sulfur 

dioxide emissions from refinery fuel gas combustion devices. 

A summary of the NSPS is first presented, followed by detailed discussions 

of the specific requirements, definitions, and specifications of the NSPS. 

This is followed by a brief description of other Federal and State regulations 

that may also affect existing and new sources in this category. 

2.1 NEW SOURCE PERFORMANCE STANDARDS 

2.1.1 Background 

New source performance standards regulate emissions of air pollutants 

from new, modified, and reconstructed facilities in various industrial categories. 

The regulations establish emission limits and require emission performance 

testing, continuous monitoring, and periodic reporting. The authority for 

the NSPS regulations is granted to the U.S. Environmental Protection Agency 

(EPA) under Section 111 of the Clean Air Act.1 

The regulation for fuel gas combustion devices in petroleum refineries 

is listed in Subpart J of 40 CFR 60, (Code of Federal Regulations; Title 40 -

Protection of Environment; Part 60 - Standards of Performance for New 
P.20 

2-2 

Stationary Sources; Subpart J - Standards of Performance for Petroleum Refineries) 

Subpart J addresses specific requirements for this source category, but 

Subpart J also incorporates the general requirements for any NSPS. These 

general requirements are listed in Subpart A (General Provisions) of 40 CFR 60. 

Other sources of air pollution emissions from petroleum refineries are 

also regulated under the new source performance standard regulatory program. 

Subpart J also regulates sulfur dioxide emissions from Claus sulfur recovery 

plants, and sulfur dioxide, carbon monoxide, and particulate emissions from 

fluid catalytic cracking unit catalyst regenerators. Subpart H regulates 

sulfuric acid mist and sulfur dioxide emissions from sulfuric acid plants. 

Volatile organic compound (VOC) emissions from storage vessels for petroleum 

liquids are regulated under Subparts K and Ka. Subpart GGG regulates VOC 

emissions due to leaks from process equipment. 

2.1.2 Summary of the NSPS for Refinery Fuel Gas Combustion Devices 

New source performance standards were promulgated by the EPA on March 8, 

1974, limiting emissions of sulfur dioxide (SO2) from new, modified and 

reconstructed fuel gas combustion devices at petroleum refineries. No significant changes have occurred since then. These standards apply to an affected 

facility which commences construction or modification after June 11, 1973. 

The affected facility for this standard is any fuel gas combustion 

device in a petroleum refinery. These devices are defined as any equipment 

used to burn fuel gas, such as process heaters, boilers, and flares, but some 

combustion sources in a refinery are specifically exempted in the definition. 

The regulated air pollutant is SO2. Sulfur dioxide emissions from fuel 

gas combustion devices can be controlled by reducing the hydrogen sulfide (H2S) 
P.21 

2-3 

content of the fuel gas prior to combustion or by flue gas desulfurization 

(FGD) after combustion. The standard was writ'ten with the intent to limit 

the H2S content of fuel gas, although the owner/operator has the option of 

using FGD. The standard prohibits the burning of fuel gas containing more 

than 230 mg H2S/dscm (0.10 gr/dscf) in any fuel gas combustion device; however, 

the standard does not apply to unusual situations, such as emergency gas 

releases or process upsets. Compliance is demonstrated by an initial 

performance test using EPA Method 11. Subsequent continuous monitoring of 

H2S in the incoming fuel gas is required; however, since monitor performance 

specifications have not been established yet, this monitoring requirement is 

not in effect. 

An alternative compliance option is included. Instead of controlling the 

H2S in the incoming fuel gas, the SO2 emissions may be controlled directly by 

treating the effluent gases resulting from the combustion of fuel gas. 

However, it must be shown that treating the effluent combustion gases will 

control SO2 emissions as effectively as controlling the H2S in the incoming 

fuel gas. Compliance for this option is demonstrated by an initial performance 

test using EPA Method 6, and continuous monitoring of SO2 in the effluent gas 

is required. 

The regulation also specifies a series of reporting and recordkeeping 

requirements. A refinery that has combustion devices subject to the NSPS 

is required to keep records, submit reports to EPA, and notify EPA of particular 

plans and occurrences as described in section 2.1.8. 
P.22 

2-4 

2.1.3 Applicability of Standards? 

2.1.3.1 Affected facilities. 

The NSPS is applicable to any new, modified, or reconstructed combustion 

device which commenced construction after June 11, 1973, and which burns fuel 

gas in a petroleum refinery. 

Petroleum is defined as, 

"the crude oil removed from the earth and the oils derived from 

tar sands, shale, and coal." 

A petroleum refinery is defined as, 

"any facility engaged in producing gasoline, kerosene, distillate 

fuel oils, residual fuel oils, lubricants, or other products 

through distillation of petroleum or through redistillation, 

cracking or reforming of unfinished petroleum derivatives." 

The EPA's definition of a petroleum refinery is thus interpreted broadly to 

encompass shale oil refineries, solvent refined coal plants, one-step topping 

plants, and small re-refining operations. 

Fuel gas is defined as, 

"any gas which is generated at a petroleum refinery and which is 

combusted. Fuel gas also includes natural gas when the natural 

gas is combined and combusted in any proportion with a gas 

generated at a refinery. Fuel gas does not include gases 

generated by catalytic cracking unit catalyst regenerators and 

fluid coking burners." 

The specific exemption is included for gases generated by these particular 

processes because it is impractical to control the SO2 emissions that would 

result from burning the H2S in these gases. These off-gases contain relatively 

low levels of H2S and contain very high levels of carbon dioxide, making it 

difficult to reduce the H2S concentration further in conventional amine 

treating units. However, if these exempted, off-gases are combined with fuel 
P.23 

2-5 

gas from another part of a refinery, then the combined gas stream would be 

subject to the NSPS limit if it is combusted in a new combustion device. 

Natural gas refers to pipeline standard natural gas (meeting specifications 

of < 0.25 grains H2S / 100 scf). Thus, if natural gas is purchased and burned 

exclusively in a combustion device, then H2S content of the gas will necessarily 

be below the NSPS limit. If natural gas is mixed with refinery generated 

fuel gas, then the combined stream is considered "fuel gas" and its H2S 

concentration must be under the NSPS limit prior to combustion in a new source. 

A fuel gas combustion device is defined as, 

"any equipment, such as process heaters, boilers and flares used 

to combust fuel gas, except facilities in which gases are 

combusted to produce sulfur or sulfuric acid." 

There are two reasons for including the specific exemption for combustion 

devices used to produce sulfur or sulfuric acid. First, the combustion in 

this case is a step in the chemical conversion process, and the resulting 

post-combustion stream is considered a process stream that undergoes further 

processing, not an effluent stream. Second, there are separate NSPS's limiting 

air emissions from these processes. (Sulfuric acid plants are regulated 

under Subpart G; Claus sulfur recovery plants under a different part of 

Subpart J.) 

2.1.3.2 Applicability date. 

The NSPS applies only if the construction or modification commenced 

after June 11, 1973, (the date of the original proposal of the regulation). 

The term "commenced" is defined in the General Provisions to 40 CFR 60, 

(Section 60.2), 
P.24 

2-6 

"Commenced means that an owner or operator has undertaken a 

continuous program of construction or modification or that an 

owner or operator has entered into a binding agreement or 

contractual obligation to undertake and complete, within a 

reasonable time, a continuous program of construction or 

modification." 

Thus, a fuel gas combustion device that existed prior to the proposal on 

June 11, 1973, and has not been significantly changed or altered since then 

would not be regulated under the NSPS. 

2.1.3.3 Modification. 

While NSPS are intended primarily for newly constructed facilities, 

existing sources can become subject to an NSPS through either "modification" 

or "reconstruction." These terms are defined in detail in the General Provisions for Part 60, (40 CFR 60.14 and 40 CFR 60.15). 

An existing fuel gas combustion device becomes subject to the NSPS under 

the modification provision if there is any physical or operational change 

that causes an increase in the emission rate. A number of clarifications, 

exemptions, and exceptions to the modification provision are listed. The 

following actions by themselves are not considered to be modifications: 

° routine maintenance, repair, and replacement 

° production increases achieved without any capital expenditure 

° production increases resulting from an increase in the hours 

of operation 

° use of an alternative fuel if the existing facility was 

originally designed to accommodate such an alternative use 

° addition or replacement of equipment for emission control (as 

long as the replacement does not increase emissions) 

° relocation or change of ownership of an existing facility. 
P.25 

2-7 

Also, the addition or modification of one facility at a source will not cause 

other unaltered facilities at that source to become subject to the NSPS. 

Specifically, for petroleum refineries, if one fuel gas combustion device is 

added or modified, then only that particular device must meet the NSPS; the 

other existing combustion devices throughout the refinery are not affected. 

2.1.3.4 Reconstruction 

An existing facility becomes subject to the NSPS upon reconstruction 

regardless of any change in the rate of emissions. Reconstruction is defined 

as the replacement of components of an existing facility to the extent that 

the cumulative fixed capital cost of the new components exceeds 50 percent 

of the cost that would be required to construct a comparable entirely new 

facility. 

2.1.4 Controlled Pollutant 

The NSPS limits emissions to the atmosphere of SO2 from the exhaust of 

refinery combustion devices which burn fuel gas. Although the regulated air 

pollutant is SO2, the SO2 emissions to the atmosphere are not regulated directly, 

Instead SO2 emissions are controlled indirectly by regulating the amount of 

H2S in the incoming fuel gas. 

2.1.5 Exceptions to the Emission Standard 

The standard prohibits the burning of fuel gas containing more than 230 

mg H2S/dscm (0.10 grain/dscf) in any new, modified, or reconstructed combustion 

device. The H2S content of the incoming fuel gas can be reduced in three 

ways - by using sweeter crude with a lower sulfur content, by pretreatment of 

the fuel gas before combustion in an acid gas treating unit, and by blending 

natural gas with the fuel gas. Although this mixing dilutes the H2S concentration without reducing overall SO2 emissions, the blending of natural gas with 
P.26 

2-8 

fuel gas is not considered a circumvention of the standard, because this is 

often normal and necessary refinery operating practice. Natural gas is used 

as auxiliary fuel since many refineries require more gas than they generate. 

Also, natural gas is used to ensure a constant flow of fuel to processes, 

while the amount of refinery generated fuel gas may vary with operating 

conditions or upsets in other process units. 

The standard does not apply to unusual situations, such as emergency gas 

releases due to process upsets. Process upset gas is defined as, 

"any gas generated by a petroleum refinery process unit 

as a result of start-up, shut-down, upset, or malfunction."3 

Start-up, shut-down, upset, and malfunction considerations are defined in the 

General Provisions for 40 CFR Part 60. The combustion of process upset gas 

in a flare, or the combustion in a flare of process gas or fuel gas which is 

released to the flare as a result of relief valve leakage is specifically 

exempted from this regulation. However, flares which burn a continuous 

process gas stream are subject to the NSPS regulations. 

2.1.6 Testing Requirements 

The owner or operator of a fuel gas burning device subject to NSPS 

is required to conduct performance tests within a specified period after 

start-up, and thereafter from time to time as may be specified by the EPA. 

These performance tests are required in order to demonstrate that the standards 

are being met by the new device. General testing and reporting requirements 

are listed in the General Provisions, (Section 60.7), while testing details 

specific to this source category are found in Subpart J, (Section 60.106). 

The initial test of performance of a facility must be conducted within 

60 days after the facility first achieves its maximum intended rate of operation. 
P.27 

2-9 

However, if the intended rate of operation is not achieved within 120 days of 

initial start-up, the initial test must nevertheless be conducted within 180 

days of start-up. Thirty days must be allowed for prior notice to the EPA, 

to allow the Agency to designate an observer to witness the test. 

To demonstrate compliance with the standard limiting the amount of H2S 

in the fuel gas prior to combustion, EPA Reference Method 11 is used to 

determine the concentration of H2S. A performance test consists of 3 runs, 

with each run consisting of 2 samples. Samples are taken at approximately 

one-hour intervals with a minimum sampling time of 10 minutes per sample. 

The arithmetic mean of the three runs constitutes the value used to determine 

whether the facility is in compliance. (Necessary modifications in the 

details of the test methods may be made, if approved in advance by the EPA.) 

A written report of the test is to be furnished to the EPA. 

2.1.7 Monitoring Requirements 

The regulation requires a continuous H2S monitor on the fuel gas line at 

the inlet to each combustion device that is subject to the NSPS. When a 

refinery has several fuel gas combustion devices having a common source of 

fuel gas, monitoring may be done at one location instead of each combustion 

device having a separate monitor. This situation is common in many refineries 

where a centralized acid gas treatment plant treats H2S rich gases from 

several refinery process units and then routes the treated exit gases to 

combustion devices throughout the refinery. Excess emissions are defined as 

any 3 hour period when the integrated (or arithmetic) average concentration 

of H2S in the fuel gas exceeds the standard of 230 mg H2S/dscm. 
P.28 

2-10 

The monitoring system must continuously monitor and record the H2S 

concentration. Under the General Provisions (Section 60.13), "continuous" is 

defined to mean that the monitoring system must complete at least one cycle 

of operation (sampling, analysis, and data recording) for each successive 

15-minute period. The owner or operator must install, calibrate, maintain, 

and operate the continuous monitor according to the requirements which are 

detailed in the subpart and the general provisions. Also, the continuous 

monitoring system must satisfy the performance specifications in Appendix B 

of 40 CFR 60. 

The EPA has not yet developed instrument performance specifications for 

H2S continuous monitoring systems. Therefore, refinery combustion devices 

subject to the NSPS are effectively exempt from the H2S monitoring requirements 

until EPA establishes performance specifications for an H2S monitor. 

2.1.8 Recordkeeping and Reporting Requirements 

A refinery that has combustion devices subject to the NSPS, is required 

to keep records, sqbmit certain reports to EPA, and notify EPA of certain 

plans and occurrences. 

One-time "notification" reports concerning the start of construction or 

reconstruction, anticipated and actual startup dates, and physical or operational 

changes to existing facilities are required so that the EPA will be able to 

identify affected sources. In addition, other records and reports are necessary 

to enable the EPA to identify sources that may not be in compliance with the 

standard. These include initial performance test results, quarterly reports 

of excess emissions, and retaining records of plant upsets and excess emissions 

for 2 years. Details of these requirements are listed in the General Provisions 

(40 CFR 60.7). 
P.29 

2-11 

2.1.9 Option for an SOp Emission Limit 

Sulfur dioxide emissions from fuel gas combustion devices can be controlled 

by reducing the H2S in the incoming fuel gas or by reducing the SO2 in the 

exhaust gases. The standard was written with the intent to limit the H2S 

content of fuel gas, and all of the refinery sources subject to the NSPS to 

date are currently reducing SO2 emissions by pretreatment of the fuel gases 

to remove the H2S. 

However, the regulation includes a second, alternative provision which 

allows the burning of fuel gas with a higher H2S content provided the effluent 

gases are treated to reduce the SO2 emissions. This flue gas desulfurization 

would probably be accomplished with an add-on air pollution control device. 

In case this emission control option is selected, the regulation sets forth a 

parallel set of emission standards and testing, monitoring, reporting, and 

recordkeeping requirements. Because no refinery has yet elected the FGD 

options, the alternative provisions in the regulation will not be discussed 

in detail in this report. 

The NSPS does not set a specific SO2 emission limit if this alternative 

approach is followed. Instead, the source must calculate and determine an 

equivalent SO2 emission level that would control SO2 emissions as effectively 

as complying with the standard for H2S concentration in the fuel gas. Because 

the inlet fuel gas streams, operating conditions, and parameters may vary for 

each combustion device, an equivalent SO2 emission limit would probably need 

to be calculated for each affected facility on a case-by-case basis. The 

information must be submitted to the EPA for approval. 
P.30 

2-12 

Compliance for this option is demonstrated by a performance test using 

EPA Methods 1, 2, and 6 for determining the sampling site, volumetric flowrate, 

and SO2 concentration. Continuous monitoring of the SO2 concentration in the 

effluent is also required in the regulation. Since EPA has listed performance 

specifications for continuous SO2 instruments (in Performance Specification 2 

of Appendix B to 40 CFR 60), these monitoring requirements are in effect and 

must be carried out. Excess emissions are defined as a 3-hour period when 

the average SO2 concentration exceeds a predetermined level that was previously 

calculated and approved for that particular combustion source. The testing, 

monitoring, recordkeeping, and reporting requirements are similar to those 

discussed for the H2S concentration standard, and details are listed in 

Subpart J and the General Provisions. 

2.2 LEGISLATIVE HISTORY 

Standards of performance for air emissions from petroleum refineries 

were first proposed on June 11, 1973 (38 FR 15406) and promulgated on 

March 8, 1974 (39 FR 9308). Since then, there have been 3 proposed and 

8 final rulemakings which affected the standard for sulfur dioxide emissions 

from fuel gas combustion sources in refineries. These rulemakings consisted 

of minor clerical corrections, changes to the monitoring requirements, and 

changes to the definition of fuel gas. A listing and brief summary of these 

is given in Table 2.1. 

2.2.1 Changes to Definitions 

The definitions of "fuel gas" and "fuel gas combustion device" were 

changed to clarify the original intent of the regulation and to match the 

conventional nomenclature used in the industry. These formal changes to 
P.31 

2-13 

TABLE 2.1 

LIST OF RULEMAKINGS AFFECTING NSPS FOR 

REFINERY FUEL GAS COMBUSTION DEVICES 

DATE 

06-11-73 

03-08-74 

09-11-74 

10-06-75 

FEDERAL REGISTER 

CITATION 

38 FR 15406 

39 FR 9308 

39 FR 32852 

40 FR 46250 

TYPE OF 

ACTION 

Proposal 

Final 

Proposal 

Final 

SUMMARY OF ACTION 

07-25-77 

08-17-77 

03-03-78 

10-04-76 

03-15-78 

03-12-79 

42 FR 37936 

42 FR 41424 

43 FR 8800 

41 FR 43866 

43 FR 10866 

* 

44 FR 13480 

Final 

Final 

Final 

Proposal 

Fi nal 

Final 

03-03-80 

12-01-80 

45 FR 13991 

45 FR 79452 

Proposal 

Final 

Original regulation limiting SO2 

emissions and including testing, 

monitoring, and reporting requirements. 

1 

Added universal monitoring and reporting 

requirements to General Provisions, 

(40 CFR 60.7 & 60.13). \ 

Eliminated monitoring requirements 

for H2S in fuel gas; revised 

monitoring requirements for SO2 in 

exhaust gas. 

Clarification, adding applicability 

date to the definition of the 

affected facility. 

Clerical change to revise statuatory 

authority citations for clarity. 

Clerical change to amend statuatory 

authority citations per Clean Air 

Act Amendments of 1977. 

Re-added monitoring requirements for 

H2S in fuel gas. 

Change definition of "fuel gas" and 

"fuel gas combustion device" to 

clarify when an incinerator-waste 

heat boiler is affected by! the NSPS. 

Change definition of "fuel gas" to 

clarify which gaseous fuels are 

covered by NSPS, particularly when 

'• ....*.._•.! _._•• •: ~ « iif,,.i ««« n "natural gas" is a "fuel gas1 
P.32 

2-14 

the regulation were initiated in part as a response to several questions 

which had arisen concerning applicability determinations. Since the changes 

were merely clarifying the original intent of the regulation, these changes 

did not have a significant impact on emissions. 

2.2.2 Monitoring 

The original standard included requirements for the monitoring of the 

H2S at the inlet or SO2 at the outlet of a fuel gas combustion device. At 

the time, however, no guidance or instructions were provided on how to conduct 

the monitoring, and so sources were temporarily exempted from monitoring. 

(Incidentially, this approach was taken for all of the early NSPS regulations 

covering several industries because no monitoring guidelines had been set by 

EPA at the time for any pollutant.) 

Major changes and additions to monitoring requirements were issued a 

short time later (proposed 9/11/74 and promulgated 10/6/75). These changes 

added overall monitoring and reporting requirements to the General Provisions 

for all NSPS's and set forth detailed performance specifications for SO2 

monitoring instruments. Concurrently, there were coordinating revisions 

to the SO2 monitoring requirements in Subpart J for the exhaust gases from 

refinery combustion devices. At the same time, all monitoring requirements 

for H2S levels in the inlet gases were eliminated because specifications for 

those instruments had not yet been set. Then, this approach was reversed in 

a later rulemaking (proposed on 10/4/76 and promulgated on 3/15/78), when 

monitoring requirements for H2S in the fuel gas were reinstated; however, 
P.33 

2-15 

since detailed performance specifications for H2S monitors have not been 

promulgated, the H2S monitoring requirements still do not have to be carried 

out. The overall result of these actions and current status of requirements 

for H2S monitoring is that universal, general monitoring requirements and 

guidelines are in place but specific, detailed requirements for H2S monitors 

have not yet been determined. Thus, no H2S monitoring is required at this 

time. 

2.3 STATE REGULATIONS 

2.3.1 State Regulations for Existing Sources 

A review of State regulations has shown a wide variation in the types of 

regulations, degree of stringency, and methods of enforcing the limitations. 

Many States have several forms of regulations, each applying to a different 

fuel or type of source, and do not necessarily conform to or parallel the 

NSPS format. For example, with regard to source category, the NSPS specifies 

fuel gas combustion devices in petroleum refineries, whereas a State regulation 

may specify a different source category: petroleum refinery combustion 

sources; a combustion source in any industrial facility; combustion sources 

that burn gaseous fuels. 

State regulations may limit emissions of SO2 by limiting the H2S in the 

fuel gas (as does the NSPS), the total SO2 emissions from the combustion 

device, or the total SO2 emissions from the petroleum refinery. In general, 

SO2 emissions are limited by a regulation restricting the quantity of SO2 

emitted per unit quantity of heat input or by limiting the sulfur content of 

the fuels. In some States, the regulation specifies the maximum allowable 

ground level SO2 concentration resulting from the emissions. 
P.34 

2-16 

Sulfur dioxide regulations fall into one of the following regulatory 

formats: 

1. ppm SO2, by volume, in the effluent 

2. Pounds of SO2 per million Btu's of heat input 

3. Requirements on the sulfur content of the fuel, such as ppm HSS in 

the fuel gas or weight percent sulfur in fuel oil 

4. Ambient air quality levels similar or the same as the National 

Ambient Air Quality Standard (NAAQS) for SO2 

2.3.2 State Regulations for New Sources 

For new sources, most States have been delegated enforcement authority 

for the NSPS for the petroleum refining industry, and most have adopted the 

NSPS as written. No State has adopted an emission limit more, stringent than 

the NSPS limit of 0.10 gr H2S/dscf; although some States or local air pollution control agencies have adopted more stringent monitoring requirements. 

The Puget Sound agency (in Washington State) and three counties in southern 

California have required continuous emission monitoring with a continuous 

automated instrument even though this requirement is officially not in effect 

under the NSPS until instrument performance specifications are promulgated. 

2.4 OTHER FEDERAL REGULATIONS 

There has been additional regulatory activity since the promulgation of 

the current NSPS which affects the emissions from refinery fuel gas combustion 

sources. In addition to State regulations (for existing and new sources) and 

the NSPS, some petroleum refineries may be required to achieve more stringent 

emission levels from fuel gas combustion devices under regulations for the 

Prevention of Significant Deterioration (PSD)4 or under State Implementation 

Plans (SIP) which are subject to nonattainment review by EPA.5 

2.4.1 PSD Regulations 

If a new facility is built in an area which is attaining the NAAQS for 
P.35 

2-17 

SO2, then it falls under the PSD regulations and must use the best available 

control technology (BACT). In general, BACT determination is applied on a 

case-by-case basis and must be at least as stringent as the NSPS level. For 

this source category, the BACT emission level has been defined as equal to 

the NSPS level.6 Some State and local enforcing agencies have also used the 

PSD regulations as a means of requiring some form of emission monitoring and 

corresponding emission monitoring reports. 

2.4.2 Nonattainment Area Regulations 

If a new source is located in a nonattainment area for NAAQS for SO2, 

then emission control technology capable of the lowest achievable emission 

reduction (LAER) is required. In general, LAER is at least as stringent 

as the NSPS, but for this source category, LAER has also been defined as 

equal to the NSPS.7 

2.4.3 Other NSPS Regulations 

The NSPS under review in this study limits the SO2 emissions from all 

new, modified, or reconstructed fuel gas combustion devices, which include 

process heaters, boilers, and flares used to combust fuel gas. The air pollution 

emissions from these combustion sources may also be regulated by other 

NSPS's (either current or under development). The additional requirements 

and restrictions imposed by these other NSPS's do not affect or conflict 

with the emission reductions required by the fuel gas NSPS, but they may 

affect the planning and design of new combustion sources by refinery owners. 

A new or modified boiler which has a heat input greater than 250 million 

BTU per hour may also be subject to the provisions of Subpart D or Subpart Da 

of 40 CFR 60; the applicable subpart is based on the date of construction 

of the source and whether the source is classified as an industrial boiler 
P.36 

2-18 

or a utility boiler. These subparts limit opacity, particulate emissions, 

and N0X emissions, as well as SO2 emissions. Similarly, a medium-sized, new 

or modified boiler (100 to 250 million BTU per hour) may be subject to the 

provisions of Subpart Db, which is currently under development. 

2.5 References 

1. Clean Air Act As Amended, August 1977. 42 U.S.C. Title I—Air 

Pollution Prevention and Control. Part A--Air Quality and Emission 

Limitations; Section 111—Standards of Performance for New Stationary 

Sources. Washington, D.C. 

2. U.S. Environmental Protection Agency. Code of Federal Regulations. 

Title 40, Part 60. Sections 60.101. Office of the Kederal Kegister. 

Washington, D.C. July 1, 1985. 

3. Same as reference #2. 

4. Reference 1. Part C--Prevention of Significant Deterioration of Air 

Quali ty. 

5. Reference 1. Part D--Plan Requirements for Nonattainment Areas. 

6. U.S. Environmental Protection Agency. BACT/LAER Clearinghouse -

A Compilation of Control Technology Determinations. U.S. EPA, 

Research Triangle Park, N.C. EPA 450/3-85-016 (a-d). June 1985. 

7. Same as reference #6. 
P.37 

3. INDUSTRY DESCRIPTION 

This chapter describes a typical petroleum refinery, its various 

production processes and the range of products produced by a refinery. 

Also, the current number of operating refineries and their geographical 

location are discussed as well as the industry growth rate. Finally, 

emissions from combustion of refinery fuel gas and the rational for 

choosing refinery fuel gas for new source performance standard control 

are discussed. 

3.1 BACKGROUND INFORMATION 

A petroleum refinery transforms crude oil into a variety of useful 

products. The petroleum refining industry produces more than 2500 products 

that can be categorized into the following classes: fuel gas, gasoline, 

kerosene, fuel oil, lubricating oil, grease, wax, asphalt, coke, chemicals, 

and solvents. There is no "typical" refinery, since the number of products 

and the product mix varies widely within a refinery as well as between 

refineries. The manufacturing processes also vary depending on refinery 

age, type of technology, capacity, location, and type of crude processed. 

Petroleum refinery operations involve physical separation of components 

of the crude oil (e.g., crude distillation) and chemical conversion 

processes which transform some of the less useful components of the oil 

into more useful products (e.g., cracking of high molecular weight oils 

into lower molecular weight products such as gasoline). 

The processing sequence of a refinery is illustrated in Figure 3-1. 

The crude oil is heated and charged to an atmospheric distillation 
FIGURE 3-1 

PROCESS PLAN FOR A REFINERY 1 

DRT CAS 

•-FUEL CAS 

CM 

I 

CO 

OLEFIRS TO 

CTDUCAL 

* - KEROSENE 

•-LICHT FUEL 

OIL 

DIESEL 

FUEL 

HEAVT FUEL 

•-COKE 
P.39 

3-3 

tower where it is separated into several light, intermediate, and heavy 

fractions. The bottoms from the tower are sent to a vacuum distillation 

unit for further separation. The bottoms from the vacuum still are 

thermally cracked in a coker to produce a wet gas, coker gasoline, 

and coke. A portion of the bottoms from the vacuum still may be processed 

into asphalt. Gas oils from the atmospheric and vacuum distillation 

units are used as feedstocks for the catalytic cracking and hydrocracking 

units. These units convert the gas oils to gasoline and distillate fuel. 

The gasoline from these units is fed to a catalytic reformer to improve 

the octane number and then blended with other refinery streams to make 

gasolines for marketing. 

The wet gas streams from the distillation, coker, and cracking units 

are combined and fractionated into fuel gas, liquified petroleum gas, and 

unsaturated and saturated branched chain and straight chain, light 

hydrocarbons containing from three to five carbon atoms. The fuel gas is 

used as fuel in the refinery furnaces. The straight chain saturated 

hydrocarbons are blended into gasoline. The unsaturated hydrocarbons and 

the branched chain hydrocarbons, primarily isobutane, are processed in an 

alkylation unit. In the alkylation unit the unsaturated hydrocarbons 

react with isobutane to form isoparaffins which are blended into gasoline 

to increase the octane. 

The middle distillates from the crude unit, the coker unit, and the 

cracking unit are blended into diesel and jet fuels and furnace oil. 

Heavy vacuum gas oils and reduced crude oil from some crudes can be 

processed into lubricating oils, waxes, and grease. 
P.40 

3-4 

3.2 INDUSTRY CHARACTERIZATION 

As of January 1, 1985, there were 191 operable refineries in the 

United States with total crude oil distillation capacity of 15.1 million 

barrels per calendar dayf/ and 15.9 million barrels per stream day.jV 

Table 3.1 lists the number of operating refineries along with the total 

crude capacity located in each State. These refineries are distributed 

among 35 states, with 79 refineries (41 percent) being concentrated in 

the three major refining States of Texas, California, and Louisiana. 

These three States account for an even higher percentage (57 percent) of 

the total U.S. crude oil refining capacity. Texas alone accounts for 

approximately 27 percent of the total crude oil refining capacity, while 

Louisiana and California account for about 15 percent each. 

In addition, there are four operating refineries in Puerto Rico, Virgin 

Islands, Guam, and the Hawaiian Foreign Trade Zone with a combined crude 

capacity of 771,000 barrels per calendar day.2 Because these are territories 

and not formally part of the United States, these refineries are usually 

not included in industry studies and figures for the U.S.; however, these 

refineries are regulated under federal EPA new source performance standards. 

£/ Barrels per calendar day (b/cd): the average volume a refinery unit 

processes each day including downtime used for turnarounds. This is actual 

total volume for the year divided by 365. 

]V Barrels per stream day (b/sd): the amount a unit can process 

running at full capacity under optimal crude and product slate conditions 

for short periods. 
P.41 

OPERATING 

State 

Alabama 

Alaska 

Ari zona 

Arkansas 

California 

Colorado 

Delaware 

Georgia 

Hawaii 

Illinois 

• Indiana 

Kansas 

Kentucky. 

Louisiana 

Maryland 

Michigan 

Minnesota 

Mississippi 

Montana 

Nevada 

New Jersey 

New Mexico 

North Dakota 

Ohio 

Oklahoma 

Oregon 

Pennsylvania 

Tennessee 

Texas 

Utah 

Virginia 

Washington 

West Virginia 

Wisconsin 

Wyoming 

Total 

REFINERIES 

No. 

Plants 

1 

4 

1 

4 

30 

3 

1 

2 

2 

8 

5 

7 

2 

16 

1 

4 

2 

5 

6 

1 

5 

3 

2 

5 

5 

1 

8 

1 

33 

6 

1 

7 

2 

1 

6 

191 

3-5 

TABLE 3.1 

IN THE U.S. (AS OF JANUARY 

b/cd 

80,000 

138,930 

5,000 

69,170 

2,265,098 

94,700 

140,000 

28,800 

109,500 

946,000 

431,300 

338,000 

218,900 

2,188,793 

14,200 

119,400 

204,143 

362,400 

147,500 

4,500 

503,000 

63,050 

62,800 

515,700 

374,000 

15,000 

658,700 

57,000 

4,145,900 

154,950 

51,000 

410,550 

16,500 

39,000 

162,778 

15,136,262 

:

 : ,- p " • 

1, 1985)3 

Crude Capacity 

b/sd 

81,300 

142,910 

5,263 

70,950 

2,381,417 

98,500 

150,000 

32,000 

118,426 

1,003,550 

445,500 

352,383 

226,000 

2,280,958 

14,947 

126,094 

211,220 

383,104 

154,147 

4,700 

533,210 

66,000 

65,400 

540,000 

390,394 

15,789 

691,300 

60,000 

4,385,273 

161,868 

53,000 

427,543 

17,000 

40,000 

168,052 

15,898,198 
P.42 

3-6 

Since January 1, 1981, a net total of 101 refineries have been shut 

down with a total capacity of 2.5 million barrels per calendar day. 

(Table 3-2 and Table 3-3). During 1984, a total of 26 refineries were 

shut down and 2 refineries were started up resulting in a net decrease of 

24 plants with an associated loss in crude distillation capacity of 

0.5 million barrels per calendar day. The majority of these closings 

occurred at refineries with crude distillation capacity of 30,000 barrels 

per calendar day or less. These closings accounted for a net reduction 

of 19 facilities. Refineries with crude distillation capacity greater 

than 30,000 barrels per calendar day showed a net reduction of 5 

facilities during 1984. 

Refinery utilization (actual production vs. production capacity) 

peaked at 78.2 percent in August 1984; the average rate for the year rose 

to 76.2 percent, from the previous year's average of 71.7 percent.4 

Total downstream charge capacity on January 1, 1985, stood at 28.3 

million barrels per stream day, a net decrease of 0.4 million barrels per 

stream day. Downstream charging capacity includes the following processes: 

vacuum distillation, thermal operation, catalytic cracking (fresh and 

recycled), catalytic reforming, catalytic hydrocracking, and catalytic 

hydrotreating. New construction at existing refineries and the start-up 

of previously closed refineries was more than offset by the nearly 0.7 

million barrels per stream day capacity closed during 1984. The most 

significant declines were in vacuum distillation and catalytic reforming, 

dropping 2 percent and 4 percent, respectively. However, during the 

year, downstream charge capacity increased 3 percent for catalytic cracking 

(recycled) and nearly 11 percent for catalytic hydrocracking.5 
P.43 

3-7 

TABLE 3-2 

Number of Operable Refineries in the U.S.6>

7»8»9>10 

Year 

1981 

1982 

1983 

1984 

1985 

Total 

303 

273 

225 

220 

191 

TABLE 3-3 

Crude Oil Distillationll,12,13,14,15,16 

(Thousands of Barrels per Calendar Day) 

U.S. Capacity 

Puerto Rico 

Virgin Islands and Guam 

Hawaiian Foreign Trade Zone 

1981 1982 1983 1984 1985 

18,465 17,669 16,157 15,862 15,136 

228 255 244 121 121 

714 744 559 558 588 

68 68 60 60 62 
_ _ _ P.44 

3-8 

Refiners project that total downstream charge capacity may drop to 

28.1 million barrels per stream day by 1986. However, the downstream 

processing mix i s not projected to change appreciably from January 1 , 

1985, levels . Al l major downstream refinery processes, except catalyti c 

hydrotreating, are expected to fal l below current year levels.l ' 

Refinery receipts of crude oi l averaged 12.2 million barrels per day 

during 1984, up 0.5 million barrels per day from 1983. This increase 

represented a reversal of the downward trend that started in 1979. 

Receipts of domestic crude oi l averaged 8.8 million barrels per day and 

foreign averaged 3.3 million barrels per day. Most of the increase 

in refinery receipts of crudie oi l was from domestic sources, rising from 

8.6 million barrels per day during 1983 to 8.8 million barrels per day 

during 1984. Foreign crude receipts also rose during 1984, reaching 3.3 

million barrels per day from 3.2 million barrels per day during 1983.18 

3.3 EMISSIONS FROM COMBUSTION OF REFINERY FUEL GAS 

An integrated refinery uses energy equivalent to about 10 percent 

of the total energy content in the crude oi l i t processes.*9 The fuel 

requirements of any one refinery depends on the nature of the feed, the 

final product yiel d and the level of the individual product quality . Al l 

of the refinery's energy needs could be derived from it s own crude oi l 

feed, usually refinery fuel gas and residual oil , but most refineries are 

designed to use available supplemental fuels such as natural gas. 

Figure 3-1 illustrate s a modern refinery , the various processes and 

their respective products. As indicated in Figure 3-1 , several refinery 

processes produce refinery fuel gas as a by-product. After removing the 
P.45 

3-9 

H2S, the refinery fuel gas is burned in various combustion devices (boilers 

and heaters) located throughout the refinery. Based on five plant surveys 

and trip reports, there do not appear to be any particular processes or 

combustion devices in which refineries utilize refinery fuel gas as a fuel. 

The number of combustion devices and the various processes in which refinery 

fuel gas is burned varies greatly from one refinery to another. 

Since all crude oil contains some amount of sulfur, the refinery 

fuel gas produced by the various processes will also contain sulfur. The 

sulfur content of crude oil ranges from less than 0.1 percent to greater 

than 5 percent sulfur by weight. Sulfur in the refinery fuel gas will be 

in the form of hydrogen sulfide (H2S), carbonyl sulfide, mecaptan sulfur plus 

Ci and C2 sulfides. As the sulfur concentration of the crude oil increases, 

so does the concentration of H2S and other sulfur compounds in the refinery 

fuel gas. Combustion of refinery fuel gas containing H2S produces sulfur 

dioxide (SO2). Thus, when untreated refinery fuel gas derived from crude 

oil with a high sulfur content is burned in the various process combustion 

sources, substantial quantities of SO2 will be emitted to the atmosphere. 

As discussed in Chapter 2, the new source performance standard 

prohibits the burning of refinery fuel gas containing more than 230 mg 

H2S/dscm (0.10 gr/dscf) in any combustion device that burns refinery fuel 

gas. The combustion of process upset gas in a flare, and process gas or 

refinery fuel gas released to a flare from relief valve leakage is exempt 

from this standard. 

The alternative to the 230 mg H2S/dscm refinery fuel gas standard is 

that an owner or operator may elect to treat the gases resulting from the 
3-10 

combustion of refinery fuel gas so as to limit the release of SO2 to the 

atmosphere. The EPA Administrator must be satisfied that treatment of 

the combustion gases controls SO2 emissions as effectively as compliance 

with the H2S standard. 

The standard is equivalent to a SO2 content of approximately 

20 gr/100 scf of refinery fuel gas burned. Burning such fuel will result 

in a concentration of 15 to 20 parts per million SO2 in the combustion 

products.^O 

3.4 SELECTION OF REFINERY COMBUSTION DEVICES FOR NSPS CONTROL 

Combustion devices that burn refinery fuel gas were originally selected 

for NSPS development because of their potential to emit sulfur dioxide (SO2) 

in significant quantities. At the time of the NSPS development, (in the 

early 1970's) the nationwide emissions of SO2 were estimated to be 28 million 

tons per year. It was estimated that in 1970 approximately 0.8 million tons 

of sulfur dioxide were emitted from petroleum refineries.21 The background 

study for the original NSPS predicted an overall emissions reduction for 

controlled sources of 95 percent. 

3.5 REFERENCES 

1 . Laster L.L., 1973. Atmospheric Emissions from the Petroleum Industry. 

National Environmental Research Center, Research Triangle Park, N.C. 27711. 

NTIS, Springfield, Virginia. PB-224-040. 

2. National Petroleum Refiners Association. U.S. Refining Capacity. 

Washington, D.C. July 1 , 1985. 

3. Contrell, A. Annual Refining Survey. Oil and Gas Journal. Page 122. 

March 18, 1985. 

4. Same as reference #2. Page iii . 

5. Same as reference #2. Page iii . 

6. Contrell, A. Annual Refining Survey. Oil and Gas Journal. Page 112. 

March 30, 1981. 
P.47 

3-11 

7. Contrell, A. Annual Refining Survey. Oil and Gas Journal. Page 130. 

March 22, 1982. 

8. Contrell, A. Annual Refining Survey. Oil and Gas Journal. Page 130. 

March 21, 1983. 

9. Contrell, A. Annual Refining Survey. Oil and Gas Journal. Page 112. 

March 26, 1984. 

10. Same as reference #3. Page 123. 

11. Same as reference #6. 

12. Same as reference #7. 

13. Same as reference #8. 

14. Same as reference #9. 

15. Same as reference #3. Page 123. 

16. Same as reference #2. 

17. Same as reference #2. Page V. 

18. Same as reference #2. Page V. 

19. 1985 HPI Market Data. Hydrocarbon Processing, page 26. 

20. Background Information for Proposed New Source Performance Standards: 

Asphalt Concrete Plants, Petroleum Refineries, Storage Vessels, 

Secondary Lead Smelters and Refineries, Brass or Bronze Ingot 

Production Plants, Iron and Steel Plants, and Sewage Treatment 

Plants. U.S. Environmental Protection Agency. Research Triangle 

Park, N.C. Publication Number APTD-1352a. June 1973. Page 27. 

21. National Air Pollutant Emission Estimates, 1940-1982. U.S. EPA, 

RTP, N.C. EPA 450/4-84-028. December 1984. 
4. STATUS OF CONTROL TECHNOLOGY 

This chapter discusses the control techniques being used to meet the 

new source performance standards (NSPS). In order to comply with the 

hydrogen sulfide (H2S) emission requirements (230 mg/dscm, 0.10 gr/dscf) 

of this NSPS, the owner/operator of the affected facility has the option 

of either reducing the H2S concentration prior to burning the refinery 

fuel gas in the affected facility or treating the sulfur dioxide (SO2) 

emissions from the affected facility. At this time, all known affected 

facilities control SO2 emissions by reducing the H2S concentration in the 

fuel gas prior to being burned. 

A review of the literature, the Environmental Protection Agency 

(EPA) compliance data system, discussions with refinery personnel, trade 

organizations, local, State, and EPA regional agencies reveals that two 

processes are being used to comply with the NSPS. These two systems are 

the alkanolamine process system and the LO-CAT® system. These processes 

are discussed below. 

4.1. ALKANOLAMINE PROCESS SYSTEM 

The first commercially available alkanolamine was tri ethanol amine (TEA) 

which was used in early natural gas treating plants. As other members of 

the alkanolamine family were introduced into the market, they were evaluated 

as possible acid gas absorbents.^ Alkanol amines are categorized as being 

primary, secondary, or tertiary, depending upon the degree of substitution 

of the central nitrogen atom by organic groups. Structural formulas for 

the various alkanolamines are presented in Figure 4-1. Two commercially 

utilized primary amines are monoethanolamine (MEA) and diglycol amine (DGA), 
P.49 

4-2 

each shows single substitution of organic groups at the central nitrogen 

atom. Two commercially available secondary amines are diethanolamine (DEA) 

and diisopropanolamine (DIPA). The two secondary amines show double 

substitution of organic groups at the central nitrogen atom. A triple 

substitution of organic groups at the central nitrogen atom is possible, 

hence the tertiary amines: triethanolamine (TEA) and methyldiethanolamine 

(MDEA). 

Alkanolamines are weak organic bases with each one of the amines 

illustrated in Figure 4-1 having at least one hydroxyl group (OH) and one 

amino group. In general, it can be considered that the hydroxyl group 

serves to reduce the vapor pressure and increase the water solubility, 

while the amino group provides the necessary alkalinity in water solutions 

to cause the absorption of acidic gases.2 As crude oil is processed the 

following acid gases are formed and can be found in untreated refinery 

fuel gas: hydrogen sulfide (H2S), carbon dioxide (CO2), and carbonyl 

sulfide (COS). These compounds are considered to be acid gases because 

when dissolved in an aqueous medium, they dissociate to form weak acids. 

The acid gas and amine base will combine chemically to form an acid-base 

complex called a salt, thus removing the acid gas from the process stream.3 

The principal reactions of the alkanolamines with H2S are listed in 

Table 4-1. The reactions shown in Table 4-1 proceed to the right at low 

temperatures and to the left at higher temperatures. This is the reason 

that H2S can be absorbed by alkanolamine solutions at ambient temperatures. 

At elevated temperatures (as exist in the stripper column), the reactions 

are reversed with the sulfide and carbamate salts being decomposed and the 

acid gases released in the stripper column.4 
PjjQ 

4-3 

FIGURE 4-1 

MOLECULAR STRUCTURES OF COMMON GAS TREATING AMINES5 

Primary Amines: single substitution of organic group at the nitrogen atom 

Monoethanolamine (MEA) Diglycolamine (DGA) 

MW = 61 MW = 105 

H. H 

:N-CH2-CH2-0H J>-CH2-CH2-0-CH2-CH2-0H 

H' 

Secondary Amines: double substitution of organic group at the nitrogen atom 

Diethanolamine (DEA) Diisopropanolamine (DIPA) 

MW = 105 MW = 133 

HO-CH2-CH2-N-CH2-CH2-OH H0-CH-CH2-N-CH2-CH-0H 

H CH3 H CH3 

Tertiary Amines: triple substitution of organic group at the nitrogen atom 

Triethanolomine (TEA) Methyldiethanolamine (MDEA) 

MW --- 149 MW = 119 

HO-CH2-CH2-N-CH2-CH2-OH HO-CH2-CH2-N-CH2-CH2-OH 

CH2-CH2-0H CH3 
P.51 

4-4 

TABLE 4-1 

PRINCIPAL REACTIONS OF ALKANOLAMINES WITH HYDROGEN SULFIDE5 

Primary Amines 

2RNH 2 + H 2 S <::::::::::> (RNH3 )2 S 

(RNH 3 ) 2 S + H 2 S <::;::::::> 2RNH3 HS 

Secondary Amines 

2 R2 NH + H 2 S <:::::::::> (R 2 N H 2 ) 2 S 

( R 2 N H 2 ) 2 S + H 2 S <:::::::::> 2R 2 N H 2 H S 

Tertiary Amines 

2 R3 N + H 2 S <:::::::::> (R3 NH)2 S 

( R 3 NH) 2 S + H 2 S <:::::::::> 2R3 NHHS 

R = C2H4OH 
P.52 

4-5 

Various literature sources indicate that as alkanolamines were 

developed and field tested, the primary and secondary amines displaced 

TEA. Triethanolamine was displaced largely because of its low H2S capacity 

(resulting from higher equivalent weight), its low reactivity (as a 

tertiary amine), and its relatively poor stability.7 Information obtained 

via plant visits and contacts with petroleum refineries indicate that 

primary and secondary amines are indeed the principle types of amines 

used in alkanolamine process systems. However, one refinery responded 

that it used MDEA, a tertiary amine. Also, two of the five refineries 

that were visited are considering switching from DEA to MDEA because 

of its selectivity for removing only H2S and the associated reduction in 

energy needed to regenerate the MDEA.8,9 

The general process flow for an alkanolamine processing plant is 

shown in Figure 4-2. The process flow scheme varies little, regardless 

of the aqueous amine solution used to remove H2S. The primary pieces of 

equipment of concern are the absorber column and stripper column, together 

with the associated piping, heat exchange, and separation equipment. 

The sour refinery fuel gas containing H2S will nearly always enter 

the alkanolamine process plant through a separator (not shown) to remove 

any free petroleum liquids and/or entrained solids. The sour gas then 

enters the bottom of the absorber column and flows upward through the 

absorber in intimate counter-current contact with the aqueous amine 

solution. The H2S is removed and sweetened gas leaves the top of the 

absorber and flows to another separator (not shown) to remove any amine 

solution and/or entrained solids that are carried over with the exiting 

refinery gas. 
P.53 

4-6 

FIGURE 4-2 

ALKANOLAMINE TREATING UNIT 10 

SOUR PROCESS GAS 

WATER 

AMINE 
P.54 

4-7 

Lean amine solution from the bottom of the stripper column is pumped 

through an amine-amine heat exchanger and then through a water or aircooled exchanger before being introduced to the top tray of the absorber 

column. The amine moves downward through the absorber counter-current to 

the sour gas, and absorbs H2S from the gas stream. Rich amine solution 

flows from the bottom of the absorber through the amine-amine heat 

exchanger and then to the top of the stripper column. 

The amine-amine heat exchanger serves as a heat conservation device 

and lowers total heat requirements for the process. The rich solution 

flows downward through the stripper in counter-current contact with vapor 

generated in the reboiler. The reboiler vapor (primarily steam) strips 

the acid gases from the rich solution. The acid gases and steam leave 

the top of the stripper and pass through a condenser, where the major 

portion of the steam is condensed and cooled. The acid gases are separated 

in a separator and sent to the sulfur recovery unit. The condensed steam 

is returned to the top of the stripper column as reflux or a slip stream 

is bled off to control the ammonia concentration in the top of the stripper 

column to help maintain the amine system water balance. 

Rich amine solution leaves the bottom of the absorber at an elevated 

temperature due to the heat of reaction released when acid gases react 

with the amine. The amine cooler serves to lower the lean amine temperature 

to the 100°F range. Higher temperature on the lean amine solution will 

result in excessive amine losses through vaporization and also lower acid 

gas carrying capacity in the solution because of temperature effects. 
P.55 

4-8 

4.2 THE LO-CAT® HYDROGEN SULFIDE OXIDATION PROCESS 

The LO-CAT® process, a process based on a liquid-phase-oxidation 

technique originated by Humphreys and Glasgow (London), was developed to 

provide an isothermal process for carrying out the modified Claus reaction.H 

H2S + 1/2 02 > H20 + S° 

The LO-CAT® process has two basic designs: aerobic, which absorbs H2S 

from air laden streams, and anaerobic, used when the gas stream has 

littl e or no oxygen present. The anaerobic application is used in treating 

refinery fuel gas. Figure 4-3 is a flow diagram of an anaerobic LO-CAT® 

H2S oxidation process used to treat refinery fuel gas. 

The LO-CAT® process removes sulfur by using a proprietary catalyst 

that consists of an aqueous solution of chelated iron , buffered with soda 

ash (Na2C03), potassium hydroxide (KOH) or any other common alkal i to a 

pH of about 8. The LO-CAT® catalyst solution is circulated in a closed loop 

between the absorbers and the oxidizer vessel. Sour gas passes through 

an inle t gas scrubber to remove entrained liquids and enters the absorber 

at lin e pressure through a specially designed venturi prescrubber. The 

gas passes upward through a low liquid-fille d vessel, an absorber, in 

which the sour gas contacts the LO-CAT® catalyst solution flowing downward. 

In the absorbers the H2S gas is absorbed very rapidly into the catalyst 

solution where i t is immediately oxiidized to precipitate elemental sulfur. 

The following chemical reactions take place in the absorber vessel: ^ 

(1) H2S Absorption 

H2S + H2O — > H£S (aqueous) + H2O 

(2) Firs t Ionization 

H2S (aqueous) > H+ + HS" 
4-9 

FIGURE 4-3 

FLOW DIAGRAM OF A LO-CAT SYSTEM 13 
P.57 

4-10 

(3) Second Ionization 

HS* > H+ + S= 

(4) Oxidation of Sulfide 

2Fe+ + + + S= > 2Fe++ + S° 

Sweet gas with less than 100 ppm H2S leaves the absorber vessel and 

passes through a sweet gas scrubber (not shown in Figure 4-3) to guard 

against mist carryover before entering the fuel system. 

Active LO-CAT® catalyst solution enters the absorber column at the top 

and flows downward through the vessel counter-current to the gas flow. The 

spent solution leaves at the bottom of the vessel. Partially reduced 

solution is regenerated in the oxidizer vessel by direct contact with 

compressed air. 

Regeneration of the LO-CAT® solution in the oxidizer vessel involves the 

following reactions;!4 

(5) Oxygen Absorption 

O2 + H2O - — > 2(0) (aqueous) + H2O 

(6) Regeneration of Iron 

2Fe++ + 0 (aqueous) + H20 — > 2 Fe+ + + + 2 (0H)_ 

Overall, the reaction is 

(7) H2S + 0.5 02 > H2O + S° 

The air used to generate the catalyst solution is supplied by an air 

blower to an air sparger grid near the bottom of the oxidizer. The spent 

air, with a small fraction of the oxygen removed, leaves the top of the 

oxidizer vessel and discharges to the atmosphere. 
P.58 

4-11 

The circulating catalyst solution, which contains elemental sulfur 

in a slurried form, flows from the absorber back to the oxidizer through 

a solution cooler which removes heat generated by the exothermic reactions 

in the absorber. Sulfur formed in the absorber vessel circulates with 

the solution and the particles grow to the 10-20 micrometer range. The 

larger particles settle out of the bulk solution, flow in the bottom of 

the oxidizer vessel, and are flushed out the oxidizer vessel as a slurry 

of 10 to 20 percent by weight of sulfur. The sulfur slurry is pumped at 

approximately 100 psig through a special non-plugging heat exchanger or 

melter, where it is heated to 270°F by 50 psig steam. The aqueous catalyst 

solution/molten sulfur mixture formed in the melter is fed through steam 

jacketed piping to a steam jacketed separator vessel. Molten sulfur is 

withdrawn from the separator vessel to a molten sulfur storage tank or a 

sulfur pit where it is stored for ultimate shipment by truck or rail car. 

The clarified catalyst solution leaves the sulfur settler through a 

back pressure control valve set at about 75 psig. The bulk of the solution is 

returned to the settler vessel and then to the absorber/oxidizer circuit. 

In the oxidation of H2S to sulfur, some side reaction takes place which 

may be represented by the equation:15 

(8) 2HS~ .+• 1.5 02 > H2 S2 03 

This reaction reduces the pH of the scrubbing solution, and Na2C03, 

KOH, or other alkaline salt must be added to maintain the pH of the solution 

v 

in the 8-8.5 pH range. This leads to a gradual buildup of sodium thiosulfate 

(Na2S203) or similar water-soluble sulfur-containing salts in the solution. 

These have no deleterious effect at concentrations below 30 percent by 

weight. When the thiosulfate concentration exceeds 30 percent by weight 
P.59 

4-12 

some of the spent catalyst solution is withdrawn to a holding tank for 

disposal. The thiosulfate has a commercial value; thus, thi s solution 

can be sold and the thiosulfate reclaimed. Another means of disposal i s 

to treat thi s solution in the refinery's biological wastewater treatment 

system. 

4.3 FACILITIES SUBJECT TO THE NSPS 

In Chapter 2 the term "affected facility " was discussed and defined. 

As noted, the affected facilit y is defined as the combustion device that 

i s capable of burning refinery fuel gas and not the H2S control system. 

Information obtained from plant trip s and surveys indicates that refinery 

fuel gas is burned in combustion devices that are used in a wide variety 

of production processes within a refinery. There does not appear to be a 

tendency for refineries to use refinery fuel gas as an energy source in 

any particular production process. Thus the utilizatio n of refinery fuel 

gas wil l vary from one refinery to another. 

According to information supplied by the EPA's Stationary Source 

Compliance Division (SSCD), fifty-fou r (54) petroleum refineries have become 

subject to the H2S portion of thi s NSPS since 1975. Unfortunately, an 

accurate number of affected facilitie s within each refinery could not be 

determined. The information supplied by SSCD i s considered to underestimate 

the number of refineries and affected facilitie s subject to thi s NSPS. 

This low estimate is attributed to the fact that some State agencies that 

have authority to enforce the Clean Air Act do not report al l the refineries 

and affected facilitie s to SSCD. 

Trade journals were also reviewed for information. These sources 

report new refinery construction projects plus modification and reconstruction 
4-13 

projects that are occurring at petroleum refineries . Unfortunately, the 

manner in which the modification and reconstruction projects are reported 

does not indicate whether these projects wil l be subject to the H2S portion of 

thi s NSPS nor how many combustion sources are involved. A review of various 

trade journals from 1980 to 1985 indicates there have been construction 

projects at 42 petroleum refineries that involve either an amine treater 

unit , a LO-CAT® unit , or unspecified refinery fuel gas recovery. 

4.4 COMPLIANCE TEST RESULTS 

The Environmental Protection Agency regional offices , State agencies, 

and petroleum refineries were contacted to obtain compliance test information for new, modified, or reconstructed facilities . 

All of the test data that were submitted were from refineries that use 

an alkanolamine process system to remove the hydrogen sulfide (H2S) from 

the refinery fuel gas. No compliance test data were obtained from a 

refinery that uses the LO-CAT® system to treat sour refinery fuel gas. 

4.4.1 . Alkanolamine Process System Compliance Data1 6>

1 7 »1 8>1 9 »2 0 »2 1>2 2 »2 3 

Data for fiftee n (15) compliance tests were obtained from nine (9) 

different refineries . The results of these tests are liste d in Table 4-2. 

The new source performance standard (NSPS) for H2S is 230 mg/dscm 

(O.lOgr/dscf). Compliance test results for the H2S concentration in 

refinery fuel gas ranges from 2.97 mg/dscm to 119.43 mg/dscm. The data 

indicate that refineries are able to meet the NSPS. Also, none of the 

refineries that were contacted indicated that they were experiencing any 

problems complying with the NSPS. 
P.61 

4-14 

TABLE 4-2 

COMPLIANCE TEST RESULTS FOR ALKANOLAMINE PROCESS SYSTEMS 

Refi nery 

B 

C 

D 

E 

F 

G 

H 

I 

Date of 

Test 

2/81 

4/82 

10/82 

3/84 

7/84 

Type of 

Alkanolamine Used 

MEA/primary 

•1 H 

•1 it 

•1 I I 

II u 

7/76 

8/84 

8/84 

11/80 

11/81 

1/84 

10/84 

8/81 

6/85 

DEA/secondary 

MEA/primary 

•I it 

DEA/secondary 

DEA/secondary 

ii ii 

MEA/primary 

MEA/primary 

DEA/secondary 

DGA/primary 

Avg.H2S Concentration 

(mg/dscm) 

101 

32 

12 

57 

77 

119.43 

2.97 

8.09 

12.5 

89.2 

63.3 

105.6 

18.1 

27.7 

3.1 

NSPS = 230 mg/dscm 
4-15 

4.4.2 LO-CAT® Process System24 

Currently, the LO-CAT® treatment system is used in only two (2) 

refineries within the United States to remove H2S from refinery fuel gas. 

Only one of these refineries was operating as of January 1985. Both of these 

LO-CAT® systems are small units, less than 20 LT/D. Compliance tests have 

not been performed for either of the two LO-CAT® systems. Thus, there are 

no data for this type of system. However, one refinery has installed a 

continuous H2S monitor. According to information submitted by the refinery, 

the H2S concentration of the refinery gas treated by the LO-CAT® system 

ranges from 20 ppmv to 50 ppmv and averages 30 ppmv. The refinery reported 

no excess emissions have occurred since the LO-CAT® system became operational. 

4.5 Emission Monitoring 

The NSPS requires an H2S continuous monitoring device to be installed 

in order to determine compliance with the H2S standard of 230 mg/dscm. 

However, the EPA has not yet developed performance specifications for H2S 

continuous monitoring systems. 

In April 1979, the EPA initiated work to establish specifications 

and also to determine the durability, maintenance requirements, and data 

validity of commercially available H2S continuous emission monitors.25 

Five (5) H2S monitors were selected for evaluation. Selection criteria 

included operating principles, engineering judgment about suitability for 

use at petroleum refineries, and total cost. The performance of the five 

(5) H2S monitors tested was disappointing. The absolute agreement between 

reference Method 11 and all monitors was poor and variable in eight out 

of ten relative accuracy tests. Thus, a conclusion of the test program 
P.63 

4-16 

was that the use of H2S monitors for compliance purposes could not be 

recommended at that time nor could performance specifications for H2S 

monitors be written. Even though performance specifications for continuous 

H2S monitoring devices have not been promulgated by the EPA, some refineries 

have been required by State agencies to install an H2S continuous monitoring 

device. 

Refineries subject to the H2S portion of this NSPS that do not have a 

continuous H2S monitor are using manually collected grab samples (Draeger 

Tubes) to test the refinery fuel gas for H2S concentration. The frequency 

with which these samples are collected varies from one refinery to another 

and can range from 1 manual sample per shift to 3 manual samples per shift. 

4.6 REFERENCES 

1. Kohl, Arthur L. and Fred C. Riesenfeld. Gas Purification (Third 

Edition). Houston, Gulf Publishing Company. 1979. Page 28. 

2. Same as reference #1. Page 29. 

3. Butwell, K. F., D. J. Kubek, and P. W. Sigmund. Alkanolamine Treating. 

Hydrocarbon Processing. Page 108. March 1982. 

4. Maddox, Dr. R. N. Gas and Liquid Sweetening. Norman, Oklahoma. 

Campbell Publishing Series. 1974. Page 47. 

5. Same as reference #3. 

6. Same as reference #4. Pages 45-47. 

7. Same as reference #1. 
P.64 

4-17 

8. Memo from Elmore, William Larry, EPA, to Kenneth R. Durkee, EPA. 

January 27, 1986. Trip report for plant visit to Alliance Refinery, 

B.P. Oil Incorporated, Belle Chasse, Louisiana. 

9. Memo from Elmore, William Larry, EPA, to Kenneth R. Durkee, EPA. 

January 22, 1986. Trip report for plant visit to Tenneco Oil Refinery, 

Chalmette, Louisiana. 

10. Background Information for Proposed New Source Performance Standards: 

Asphalt Concrete Plants, Petroleum Refineries, Storage Vessels, 

Secondary Lead Smelters and Refineries, Brass or Bronze Ingot 

Production Plants, Iron and Steel Plants, and Sewage Treatment 

Plants. U.S. Environmental Protection Agency. Research Triangle 

Park, N.C. Publication Number APTD-1352a. June 1973. Page 27. 

11. Hardison, L. C. Treating Hydrogen Sulfide: An Alternative to Claus. 

Chemical Engineering. January 21, 1985. Page 62. 

12. Letter and attachments from L. C. Hardison, ARI Technologies, Inc. to 

Elmore, Larry, EPA. October 18, 1985. 

13. Same as reference #12. 

14.- Same as reference #12. 

15. Same as reference #12. 

16. Letter and attachments from Thompson, J. E., Citgo Petroleum Corporation 

to Farmer, J. R., EPA. March 15, 1985. Response to Section 114 

letter on petroleum refineries. 

17. Letter and attachments from Ballard, B. F., Phillips Petroleum Company 

to Farmer, J. R., EPA. March 21, 1985. Response to Section 114 

letter on petroleum refineries. 

18. Letter and attachments from Livermore, A. R., La Gloria Oil and Gas 

Company, to Farmer, J. R., EPA. April 9, 1985. Response to 

Section 114 letter on petroleum refineries. 

19. Letter and attachments from Mull ins, J. A., Shell Oil Company, to 

Farmer, J. R., EPA. April 9, 1985. Response to Section 114 letter 

on petroleum refineries. 

20. Letter and attachments from Cox, R. A., Texaco USA, to Farmer, J. R., 

EPA. March 29, 1985. Response to Section 114 letter on petroleum 

refineries. 

21. Letter and attachments from Dwing, E. C , National Cooperative Refijnery 

Association, to Farmer, J. R., EPA. February 21, 1985. Response to 

Section 114 letter on petroleum refineries. 
P.65 

4-18 

22. Memo and attachments from McLaughlin, N. D., EPA, to Durkee, K. R., EPA. 

February 5, 1985. Trip report on plant visit to Murphy Oil Company, 

Meraux, Louisiana. 

23. Same as reference #9. 

24. Letter and attachments from Hullinger, T. T., U.S. Oil and Refining 

Company, to Farmer, J. R., EPA. April 15, 1985. Response to 

Section 114 letter on petroleum refineries. 

25. A Study To Evaluate Carbon Monoxide and Hydrogen Sulfide Continuous 

Emission Monitors at an Oil Refinery. U.S. Environmental Protection 

Agency. Research Triangle Park, N.C. EPA-600/4-82-054. August 1982. 
P.66 

5. MODEL PLANTS AND CONTROL SYSTEMS 

5.1 MODEL PLANTS AND CONTROL SYSTEMS 

Model plants and model plant parameters are selected to represent 

the range of facilitie s that have become subject to the NSPS since it s 

promulgation in 1974 or that are likel y to be constructed, modified, or 

reconstructed in the future. The control systems applied to the model 

plants are selected to represent those control techniques that have been 

commonly installed to meet the NSPS. The model plants are defined in 

thi s chapter and a cost analysis of these model plants is presented in 

Chapter 6. 

As discussed in Chapter 4, two types of control systems are commonly 

used by refineries to control H2S in refinery fuel gas. These two systems 

are amine treater/Claus sulfur recovery units and LO-CAT® units . 

The amine treater/Claus sulfur recovery unit combination is the most 

widely used process. The LO-CAT® system is a relativel y new process that 

has been introduced since the last review of thi s standard and currently 

only two LO-CAT® units (sulfur capacity 7 and 17.35 LT/D) have been 

installed in the U.S. for H2S removal from refinery fuel gas. 

5.1.1 Model Control Systems and H?S Concentrations 

The selection and sizing of model H2S control systems is based on 

the total sulfur loading in the untreated refinery fuel gas. Six sizes 

of control units were evaluated for thi s review: 1 , 2 , 5.1 , 10.2, 50.8, 

and 101.6 Mg/D (1 , 2, 5, 10, 50, and 100 LT/D). Three H2S concentrations 

in the untreated refinery fuel gas (1 , 5, and 10 percent H2S by volume) 

were analyzed for each model plant. 
P.67 

5-2 

Tables 5-1 and 5-2 list the model plants. The amine treater/Claus 

sulfur recovery unit was modeled for the following sizes: 5.1, 10.2, 

50.8, and 101.6 Mg/D (5, 10, 50, and 100 LT/D). The LO-CAT® system was 

modeled for 1, 2, 5.1, and 10.2 Mg/D (1, 2, 5, and 10 LT/D). 

5.2 EMISSION REDUCTIONS 

This section presents the sulfur dioxide (SO2) emission reductions 

that are achieved by each model control system. The emission reduction 

for each model control system is determined by comparing the emissions 

from a control system meeting the new source performance standard (NSPS) 

versus the emissions from the baseline situation of no control. 

5.2.1 Amine Treater/Claus Sulfur Recovery Unit 

The SO2 emission reductions for the model amine/Claus sulfur recovery 

units are presented in Table 5-3. All incoming sulfur (in the form of 

H2S) in the untreated fuel gas is either routed to fuel gas combustion 

devices, converted in the Claus sulfur recovery unit to elemental sulfur, 

or emitted from the Claus unit to the atmosphere. The model amine treaters 

were designed to achieve the NSPS limit of 230 mg of H2S/dscm in the fuel 

gas stream to combustion sources, while the remainder of the H2S is sent 

to the Claus unit. The model Claus units were designed to achieve a 96.6 

percent sulfur recovery efficiency. For calculating emission reduction, 

it was assumed that the amine treater/Claus system was operating at the 

capacity of the Claus unit for 350 operating days per year. 
P.68 

5-3 

TABLE 5-1 

MODEL PLANTS: AMINE TREATER AND CLAUS SRU 

Model 1 

Sulfur 

(Mg/D) 

5.08 

10.16 

50.8 

101.6 

'lant Size 

Processed 

(LT/D) 

(5) 

(10) 

(50) 

(100) 

Fuel Gas 

H2S Cone. 

(% by Volume) 

1 

5 

10 

1 

5 

10 

1 

5 

10 

1 

5 

10 

Amine 

Efficiency 

(%) 

98.38 

99.68 

99.84 

98.38 

99.68 

99.84 

98.38 

99.68 

99.84 

98.38 

99.68 

99.84 

Claus SRU 

Efficiency 

96.6 

96.6 

96.6 

96.6 
P.69 

5-4 

TABLE 5-2 

MODEL PLANTS: LO-CAT® 

Model 

Sulfur 

(Mg/D) 

1.016 

2.032 

5.08 

10.16 

Plant Size 

Processed 

(LT/D) 

(1) 

(2) 

(5) 

(10) 

RFG 

H2S Cone. 

{* by Volume) 

1 

5 

10 

1 

5 

10 

1 

5 

10 

1 

5 

10 

Unit 

Efficiency 

{%) 

98.38 

99.68 

99.84 

98.38 

99.68 

99.84 

98.38 

99.68 

99.84 

98.38 

99.68 

99.84 
P.70 

5-5 

TABLE 5-3 

SO2 EMISSION REDUCTION USING A 

AMINE TREATER/CLAUS SULFUR RECOVERY UNIT 

Model 

System 

(Mg/D) 

Control 

Size3 

(LT/D) 

Uncontrolled SO2 

Emissions

 D»c 

(Mg/yr) 

SO2 Emission 

Reductions0" 

(Mg/yr) 

5.08 (5) 3556 3435 

10.16 

50.8 

01.6 

(10) 

(50) 

(100) 

7112 

35560 

71120 

6870 

34350 

68700 

a Model control system size (i.e., amount of sulfur processed) is based on the 

sulfur loading into the amine treater/Claus sulfur recovery unit. 

D 1 year = 350 operating days 

c 1 Mg of sulfur (S2) converts to 2 Mg of S02 emissions 

d Efficiency of the sulfur recovery unit was assumed to be 96.6% 
P.71 

5-6 

5.2.2 LO-CAT® Unit 

The SO2 emission reductions for the model LO-CAT® units are presented 

in Table 5.4. As indicated in Figure 4-3, the LO-CAT® process has no 

emission stream to the atmosphere. All the incoming sulfur (in the form 

of H2S) is either converted to elemental sulfur or routed to the fuel gas 

combustion devices. The model LO-CAT® units were designed to achieve the 

NSPS limit of 230 mg of H2S/dscm in the outlet fuel gas stream. For 

calculating emission reductions, it was assumed that the LO-CAT® unit was 

operating at capacity for 350 operating days per year. 
P.72 

5-7 

TABLE 5-4 

SO2 EMISSION REDUCTION USING A LO-CAT® UNIT 

Model Control 

System Sizea 

(Mg/D) (LT/D) 

H2S 

Cone 

{% by Vol.) 

Uncontrolled SO2 

Emissions">c 

(Mg/yr) 

712 

712 

712 

1422 

1422 

1422 

3556 

3556 

3556 

7112 

7112 

7112 

Control System 

SOo Emissions 

(Mg/yr) 

11.5 

2.3 

1.1 

2.3 

4.6 

2.3 

57.6 

11.4 

5.7 

115.2 

22.8 

11.. 4 

SO2 Emission 

Reductions 

' (Mg/yr) 

701 

710 

711 

1399 

1417 

1420 

3498 

3545 

3550 

6997 

7089 

7101 

1.016 

2.032 

5.08 

10.16 

(1) 

(2) 

(5) 

(10) 

1 

5 

10 

1 

5 

10 

1 

5 

10 

1 

5 

10 

a Model control system size (i.e. amount of sulfur processed) is based on the 

sulfur loading into the LO-CAT® unit. 

D 1 year = 350 operating days 

c 1 Mg of sulfur (S2) converts to 2 Mg of S02 emissions 
P.73 

6. COST ANALYSIS 

6.1 INTRODUCTION 

This section presents costs (i n January 1985 dollars) of model plant 

control systems necessary to meet the hydrogen sulfide (and consequently 

the sulfur dioxide) provisions of the current NSPS for refinery fuel gas. 

Two control systems are analyzed: (1) for large sources of refinery fuel gas, 

an amine treating section coupled with a Claus sulfur recovery plant; (2) for 

smaller sources, a LO-CAT® process which absorbs the hydrogen sulfide and 

oxidizes i t to elemental sulfur with the aid of an iron-based catalyst. 

(A more detailed discussion of the control systems appears in Chapter 4.) 

Capital and annualized costs are estimated for the following model plant 

sizes, al l given on a nominal sulfur basis: LO-CAT® — 1.016 Mg per day 

(1 long ton per day), 2.032 Mg/D (2 LT/D), 5.08 Mg/D (5 LT/D), and 10.16 Mg/D 

(10 LT/D); amine-Claus -- 5.08 Mg/D (5 LT/D), 10.16 Mg/D (10 LT/D), 50.8 

Mg/D (50 LT/D), 101.6 Mg/D (100 LT/D), 203.2 Mg/D (200 LT/D), 508 Mg/D (500 

LT/D) and a plant expansion from 10.16 Mg/D to 10.668 Mg/D (10 to 10.5 LT/D)*. 

(A more detailed discussion of model plants is presented in Chapter 5.) 

Cost-effectiveness is calculated for al l model plants and is discussed 

for the two model plant sizes that are common to both control systems. 

Except for the plant expansion, al l estimated costs apply to new control 

systems installed at new sources of refinery fuel gas. Note that the 

cost of Claus tai l gas treating is not considered in the analysis. 

The costs presented for the amine-Claus process are based on raw cost 

data provided in References 1 and 2. Costs for the LO-CAT® process are 

based on information from References 3, 4, and 5. Capital costs are on a 

*Note: 1 Mg/D = 1.1025 short tons/D = 0.9844 LT/D 
P.74 

6-2 

turnkey basis and thus include the purchase cost of equipment and auxiliaries, 

taxes, freight, and all necessary installation costs, as well as indirect 

costs such as engineering and supervision, construction and field expense, 

contractor fee, and contingency. Annualized costs include direct operating 

costs such as operating labor, maintenance labor, utilities, and materials, 

as well as indirect costs such as capital charges, overhead, property taxes, 

insurance, and administration. Net annualized cost is also presented, 

representing total annualized cost less the credit fpr recovered sulfur 

where applicable. The costs thus obtained are "order-of-magnitude"--i.e., 

nominally +_ 50 percent in accuracy. Because most of the operating and 

maintenance (O&M) costs have been calculated directly, their accuracy should 

approach that of a study estimate (+^30 percent). Finally, because the 

annualized costs are comprised of O&M costs and capital cost components, 

their accuracy should fall between +_ 30 and +_ 50 percent. 

6.2 AMINE TREATMENT WITH CLAUS SULFUR RECOVERY 

6.2.1 Capital Costs 

The capital costs for this combination process are estimated for 

five model plants—four new and one expansion of an existing plant. 

(Detailed model plant parameters are given in Chapter 5.) The capital 

costs for the amine treatment section were calculated from cost factors 

given in Reference 1 for gas sweetening operations. The process employs 

diethanolamine (DEA) as the absorbent. 

The capital costs for the Claus section were developed by updating the 

costs in Reference 2 via the Chemical Engineering (CE) Plant Cost Index. 

The capital cost for the 5.08 Mg/D Claus plant was extrapolated logarithmically 

from the 10.16 Mg/D model plant cost in Reference 1 (the smallest size) 

using a 0.2 exponent, in accordance with cost vs. capacity formulas presented 
6-3 

in Appendix A of Reference 1. The 0.2 exponent was found to hold in the low 

size range, based on data gathered for Claus plants in Reference 1. Costs for 

the 50 and 100 LT/D plants were updated from costs in Reference 1 for these sizes. 

Capital costs for the two sections were added together for each model 

plant and are presented in Table 6-1. The capital cost of the plant 

expansion was calculated as the incremental cost of a 10.668 Mg/D plant 

over a 10.16 Mg/D plant and does not include any retrofit costs. This 

approach was taken as an expedient to arriving at an order-of-magnitude 

cost for the expansion; it must be recognized that such an expansion would 

be a site-specific case, the cost of which could vary significantly. 

The capital costs for 200 and 500 LT/D model plants can be estimated 

by multiplying the cost of the 100 LT/D plant by a factor of two or five, 

respectively. This results from the fact that plants above 100 LT/D capacity 

are normally constructed as trains, so that their costs vary linearly with 

size. 

6.2.2 Annualized Costs 

The annualized costs associated with owning and operating the amineClaus plants are estimated for each model plant. The direct operating cost 

includes operating and supervisory labor, maintenance, supplies, utilities, 

chemicals, and catalysts. For the amine section, direct operating costs 

were calculated by means of the cost factors given in Appendix A. For the 

Claus section, the direct operating costs were developed by combining 

consumption data with unit cost data, both from Reference 2. (The latter 

are listed in Table 6-2.) The unit cost data were updated slightly by use 

of Bureau of Labor Statistics factors in most cases, such as the Producer 

Price Index. 
P.76 

6-4 

TABLE 6-1 

CAPITAL COST SUMMARY 

AMINE TREATMENT WITH CLAUS SULFUR RECOVERY 

(January 1985 Dollars) 

Cost in Thousands of Doll 

Plant, Capacity, Mg/D (LT/D) 

5.08 Mg/D (5 LT/D) 

1% H2S 

5% H2S 

10% H2S 

10.16 Mg/D (10 LT/D) 

1% H2S 

5% H2S 

10% H2S 

50.8 Mg/D (50 LT/D) 

1% H2S 

5% H2S 

10% H2S 

101.6 Mg/D (100 LT/D) 

1% H2S 

5% H2S 

10% H2S 

Expansion of 0.508 Mg/D 

(0.5 LT/D)d 

1% H2S 

5% H2S 

10% H2S 

Amine3 

110 

88.8 

84.6 

220 

178 

169 

1100 

888 

846 

2200 

1780 

1690 

10.7 

9.2 

8.5 

ars 

Sulfur 

Claus0 

2290 

2290 

2290 

2630 

2630 

2630 

4480 

4480 

4480 

6470 

6470 

6470 

25.8 

25.8 

25.8 

Totalc 

2390 

2370 

2370 

2840 

2800 

2790 

5570 

5360 

5320 

8670 

8240 

8160 

36.5 

35.0 

34.3 

a Cost developed from information in Reference 1. 

0 Cost developed from information in Reference 2. 

c Totals may not add due to rounding. 

These costs represent the incremental costs of a 10.688 Mg/D plant over 

a 10.16 Mg/D plant. 

d 
6-5 

TABLE 6-2 

ASSUMED UNIT COSTS FOR 

OPERATING COST ESTIMATION 

CLAUS SULFUR RECOVERY PLANTS3.

b

»

c 

Operating Cost Item 

Operating labor 

Supervision labor 

4300 Kp steam 

1760 Kp steam 

352 Kp steam 

106 Kp steam 

Steam condensate 

Boiler feedwater 

Electricit y 

Fuel gas 

Sulfur 

Unit Cost (Credit) 

$15.00/h 

$20.00/h 

$17.50/Mgd 

($16.25/Mg) 

($14.00/Mg) 

($11.00/Mg) 

($ 3.00/Mg) 

$ 3.60/Mg 

$15.28/Gj 

$ 4.00/Gj 

($110/Mg)e 

English Equivalent 

$ 7.94/103lb 

($ 7.37/103lb). 

($ 6.35/103lb) 

($ 4.99/103lb) 

($ 1.36/103lb) 

$ 1.63/103lb 

$ 0.055/KWh 

$ 4.22/MM BTU 

(S111.8/LT) 

3

 For Claus plant operating cost estimation, unit costs were multiplied by 

consumption factors given in Reference 2. 

0

 Unit costs were not used for operating cost estimation for the amine 

process or LO-CAT® process; operating costs for these processes were given 

in References 1 and 3, respectively, as functions of gas flowrate or plant 

capacity. 

c

 The total costs for catalysts given in Reference 2 were multiplied by 1.1 

to update them to January 1985 dollars , 

d Cost or credit depending upon model plant. 

e

 Based on the cost given for recovered (i.e. , Claus plant) sulfur, Houston 

terminal, in Chemical Marketing Reporter, January 21, 1985. 
6-6 

Most indirect costs were factored from capital costs or direct operating 

costs using appropriate factors from References 6 and 7. Capital recovery 

was calculated from the capital cost with a 10 percent rate of return and a 

15-year equipment life (Reference 2) . There is no waste disposal cost, 

because spent catalysts are regenerated. The annualized cost includes an 

estimate of the credit for recovered sulfur at prices applicable in January 

1985, a period of relative stability for recovered sulfur prices. Note 

also that credit for different pressures of steam varies in that, in 

general, the larger the Claus plant, the greater the heat recovery practiced 

and the higher the pressure of steam that is recovered. 

The annualized costs for both sections were added together for each 

model plant and are presented in Tables 6-3 through 6-9. Again, costs for 

expanding the existing 10.16 Mg/D plant to 10.668 Mg/D were calculated as 

incremental costs. All annualized costs are based on 350 operating days 

per year. See Appendix B for an example of annualized cost estimation for 

the individual processes that make up the control system (amine treating 

and Claus sulfur recovery). 

6.3 LO-CAT® PROCESS 

6.3.1 Capital Costs 

Capital costs for LO-CAT® model plants are also estimated. Although the 

model plants envision incoming hydrogen sulfide concentrations of 1, 5, and 10 

percent, according to Reference 5 the differences in capital cost among the three 

would not be significant. Therefore, the costs are developed independent of 

hydrogen sulfide concentration. The purchased equipment cost was taken directly 

from Reference 3 and includes all primary and auxiliary equipment and 

instrumentation. Taxes and freight costs were obtained from Reference 6. 
P.79 

6-7 

Table 6-3 

ANNUALIZED COST SUMMARY3 

AMINE TREATMENT WITH CLAUS SULFUR RECOVERY 

5.08 Mq/D (5 LT/D) PLATiT ' 

(January 1985 Dollars) 

Cost in Thousands of Dollars 

1% H2S 5% H2S 10%H2S 

Direct Operating Cost 

Operating labor 

Supervision 

Maintenance, repairs 

Supplies, laboratory 

Utilities 

4300 Kp steam 

Boiler feedwater 

Electricit y 

Fuel Gas 

Chemicals, catalyst 

Indirect Operating Cost 

Overhead (50 percent of al l labor costs) 

Capital Recovery (10 percent rate of return, 

15 years equipment life ) 

Taxes (one percent of capital cost) 

Insurance (one percent of capital cost) 

Administration (two percent of capital cost) 

Total Annualized Cost Without Credit 

Credits 

4300 Kp steam 

1760 Kp steam 

352 Kp steam 

106 Kp steam 

Steam Condensate 

Sulfur 

Total Credits 

Net Annualized Cost ' 

210 

61 

70 

17 

. 4 

12 

57 

10 

3 

210 

61 

70 

17 

4 

12 

57 

10 

3 

210 

61 

70 

17 

4 

12 

57 

10 

3 

153 

1,007 

244 

762 

153 

1,003 

244 

759 

153 

15 

24 

24 

48 

312 

24 

24 

47 

312 

24 

24 

47 

1,002 

0 

48 

0 

3 

5 

189 

0 

48 

0 

3 

5 

189 

0 

48 

0 

3 

5 

189 

244 

758 

Totals may not add due to rounding 
P.80 

6-8 

Table 6-4 

ANNUALIZED COST SUMMARY3 

AMINE TREATMENT WITH CLAUS SULFUR RECOVERY 

10.16 Mg/D (10 LT/D) PLANT 

(January 1985 Dollars) 

Cost in Thousands of Dollars 

1% H2S 5% H2S 10%H2S 

210 

61 

82 

17 

7 

24 

114 

19 

7 

210 

61 

82 

17 

7 

24 

114 

19 

7 

210 

61 

82 

17 

7 

24 

114 

19 

7 

Direct Operating Cost 

Operating labor 

Supervision 

Maintenance, repairs 

Supplies, laboratory 

Utilities 

4300 Kp steam 

Boiler feedwater 

Electricit y 

Fuel Gas 

Chemicals, catalyst 

Indirect Operating Cost 

Overhead (50 percent of al l labor costs) 155 155 155 

Capital Recovery (10 percent rate of return, 

15 years equipment life ) 

Taxes (one percent of capital cost) 

Insurance (one percent of capital cost) 

Administration (two percent of capital cost) 

Total Annualized Cost Without Credit 1,184 1,177 1,175 

Credits 

4300 Kp steam 

1760 Kp steam 

352 Kp steam 

106 Kp steam 

Steam Condensate 

Sulfur 

Total Credits 489 489 489 

Net Annualized Cost 695 688 686 

374 

28 

28 

57 

369 

28 

28 

56 

367 

28 

28 

56 

0 

95 

0 

6 

9 

378 

0 

. 95 

0 

6 

9 

378 

0 

95 

0 

6 

9 

378 

Totals may not add due to rounding 
P.81 

6-9 

Table 6-5 

ANNUALIZED COST SUMMARY3 

AMINE TREATMENT WITH CLAUS SULFUR RECOVERY 

50.8 Mg/D (50 LT/D) PLANT 

(January 1985 Dollars) 

Cost in Thousands of Dollars 

1% H2S 5% H2S 10%H2S 

Direct Operating Cost 

Operating labor 

Supervision 

Maintenance, repairs 

Supplies, laboratory 

Utilities 

4300 Kp steam 

Boiler feedwater 

Electricity 

Fuel Gas 

Chemicals, catalyst 

Indirect Operating Cost 

Overhead (50 percent of all labor costs) 

Capital Recovery (10 percent rate of return, 

15 years equipment life) 

Taxes (one percent of capital cost) 

Insurance (one percent of capital cost) 

Administration (two percent of capital cost) 

Total Annualized Cost Without Credit 

Credits 

4300 Kp steam 

1760 Kp steam 

352 Kp steam 

106 Kp steam 

Steam Condensate 

Sulfur 

Total Credits 

Net Annualized Cost 

210 

61 

151 

17 

58 

170 

512 

97 

35 

210 

61 

151 

17 

58 

170 

512 

97 

35 

210 

61 

151 

17 

58 

170 

512 

97 

35 

169 

2,436 

169 

2,400 

169 

733 

56 

56 

111 

705 

54 

54 

107 

700 

53 

53 

106 

2,393 

0 

464 

18 

26 

50 

1,889 

2,448 

(11) 

0 

464 

18 

26 

50 

1,889 

2,448 

(47) 

0 

464 

18 

26 

50 

1,889 

2,448 

(55) 

Totals may not add due to rounding 
P.82 

6-10 

Table 6-6 

ANNUALIZED COST SUMMARY3>b 

AMINE TREATMENT WITH CLAUS SULFUR RECOVERY 

101.6 Mg/D (100 LT/D) PLANT 

(January 1985 Dollars) 

Cost in Thousands of Dollars 

1% H2S 5% H2S 10%H2S 

Direct Operating Cost 

Operating labor 

Supervision 

Maintenance, repairs 

Supplies, laboratory 

Utilities 

4300 Kp steam 

Boiler feedwater 

Electricity 

Fuel Gas 

Chemicals, catalyst 

Indirect Operating Cost 

• Overhead (50 percent of all labor costs) 

Capital Recovery (10 percent rate of return, 

15 years equipment life) 

Taxes (one percent of capital cost) 

Insurance (one percent of capital cost) 

Administration (two percent of capital cost) 

Total Annualized Cost Without Credit 

Credits 

4300 Kp steam 

1760 Kp steam 

352 Kp steam 

106 Kp steam 

Steam Condensate 

Sulfur 

Total Credits 

Net Annualized Cost 

210 

61 

227 

17 

0 

441 

1,007 

194 

71 

210 

61 

227 

17 

0 

441 

1,007 

194 

71 

210 

61 

227 

17 

0 

441 

1,007 

194 

71 

184 

3,897 

184. 

3,825 

184 

1,140 

87 

87 

173 

1,084 

82 

82 

165 

1,073 

82 

82 

163 

3,810 

307 

101 

322 

52 

39 

3,779 

4,600 

(702) 

307 

101 

322 

52 

39 

3,779 

4,600 

(775) 

307 

101 

322 

52 

39 

3,779 

4,600 

(789) 

3

 Totals may not add due to rounding. 

0

 Note: For estimating the cost of plants with capacities in excess of 100 LT/D, 

the costs in thi s table would be used as costs of individual trains . For 

example, a 200 LT/D plant would consist of two 100 LT/D trains , and the costs 

for the plant would be twice the costs in thi s table. 
6-11 

Table 6-7 

ANNUALIZED COST SUMMARY 

AMINE TREATMENT WITH CLAUS SULFUR RECOVERY 

EXPANSION OF 10.16 Mg/D (10 LT/D) PLANT TO 10.668 Mg/D" (10.5 LT/D) 

(January 1985 Dollars) 

1% H2S 

10.66 Mg/D 10.16 Mg/D Incremental 

Direct Operating Cost 

Operating labor 

Supervision 

Maintenance, repairs 

Supplies, laboratory 

Utilitie s 

210,000 

60,900 

83,000 

16,800 

172,300 

210,000 

60,900 

82,070 

16,800 

164,100 

• 0 

0 

930 

0 

8,200 

Chemicals, catalyst 

Indirect Operating Cost 

Overhead (50 percent of al l labor costs) 

Capital Recovery (10 percent rate of return, 

15 years equipment life)-

Taxes (one percent of capital cost) 

Insurance (one percent of capital cost) 

Administration (two percent of capital cost) 

Total Annualized Cost Without Credit 

Credits 

4300 Kp steam 

1760 Kp steam 

352 Kp steam 

106 Kp steam 

Steam Condensate 

Sulfur 

Total Credits 

Net Annualized Cost 

7,268 

155,300 

6,922 

155,300 

346 

379,600 

28,870 

28,870 

57,740 

200,600 

0 

100,100 

0 

6,601 

9,767 

396,800 

513,268 

687,330 

374,800 

28,500 

28,500 

57,000 

1,184,900 

0 

95,360 

0 

6,287 

9,302 

377,900 

488,849 

696,050 

4,775 

370 

370 

740 

15,700 

0 

4,740 

0 

314 

465 

18,900 

24,419 

(8,720) 
6-12 

Table 6-8 

• 

ANNUALIZED COST SUMMARY 

AMINE TREATMENT WITH CLAUS SULFUR RECOVERY 

EXPANSION OF 10.16 Mg/D (10 LT/D) PLANT TO 10.668 Mq/D (10.5 LT/D) 

(January 1985 Doll 

5% H2S 

Direct Operating Cost 

Operating labor 

Supervision 

Maintenance, repairs 

Supplies, laboratory 

Utilitie s 

Chemicals, catalyst 

Indirect Operating Cost 

Overhead (50 percent of al l labor costs) 

Capital Recovery (10 percent rate of return, 

15 years equipment life ) 

Taxes (one percent of capital cost) 

Insurance (one percent of capital cost) 

Administration (two percent of capital cost) 

Total Annualized Cost Without Credit 

Credits 

ars ) 

10.66 Mg/D 

210,000 

60,900 

83,000 

16,800 

172,300 

7,268 

155,300 

373,850 

28,430 

28,430 

56,860 

1,193,140 

10.16 Mg/D 

210,000 

60,900 

82,070 

16,800 

164,100 

6,922 

155,300 

369,250 

28,080 

28,080 

56,160 

1,177,660 

Incremental 

0 

0 

930 

0 

8,200 

346 

0 

4,600 

350 

350 

700 

15,480 

P.84 

4300 Kp steam 

1760 Kp steam 

352 Kp steam 

106 Kp steam 

Steam Condensate 

Sulfur 

Total Credits 

Net Annualized Cost 

0 

100,100 

0 

6,601 

9,767 

396,800 

513,268 

679,870 

0 

95,360 

0 

6,287 

9,302 

377,900 

488,849 

688,810 

0 

4,740 

0 

314 

465 

18,900 

24,419 

(8,940) 
P.85 

6-13 

Table 6-9 

ANNUALIZED COST SUMMARY 

AMINE TREATMENT WITH CLAUS SULFUR RECOVERY 

EXPANSION OF 10.16 Mq/D (10 LT/D) PLANT TO 10.668 Mg/D (10.5 LT/D) 

(January 1985 Dollars) 

10% H2S 

10.66 Mg/D 10.16 Mg/D Incremental 

Direct Operating Cost 

Operating labor 

Supervision 

Maintenance, repairs 

Supplies, laboratory 

Utilitie s 

Chemicals, catalyst 

Indirect Operating Cost 

Overhead (50 percent of al l labor costs) 

Capital Recovery (10 percent rate of return, 

15 years equipment life ) 

Taxes (one percent of capital cost) 

insurance (one percent of capital cost) 

Administration (two percent of capital cost) 

Total Annualized Cost Without Credit 

Credits 

4300 Kp steam 

1760 Kp steam 

352 Kp steam 

106 Kp steam 

Steam Condensate 

Sulfur. 

Total Credits 

Net Annualized Cost 

210,000 

60,900 • 

83,000 

16,800 

172,300 

210,000 

60,900 

82,070 

16,800 

164,100 

0 

0 

930 

0 

8,200 

7,268 

155,300 

6,922 

155,300 

346 

372,580 

28,330 

28,330 

56,660 

1,191,470 

0 

100,100 

0 

6,601 

9,767 

396,800 

513,268 

678,200 

368,070 

27,990 

27,990 

55,980 

1,176,120 

0 

95,360 

0 

6,287 

9,302 

377,900 

488,849 

687,270 

. 4,510 

340 

340 

680 

15,350 

0 

4,740 

0 

314 

465 

18,900 

24,419 

(9,070) 
P.86 

6-14 

Direct and indirect installation factors from Reference 7 were then applied 

to each model plant purchased equipment cost to obtain total installed cost. 

The capital costs for the four model plants are presented in Table 6-10. 

6.3.2 Annualized Costs 

The annualized costs for the LO-CAT® model plants have also been estimated. 

Most of the direct operating costs were taken directl y from Reference 3, 

interpolating values from tabular data therein. Operating labor was calculated 

based on one-third of a man per shif t for al l model plants (Reference 5), 350 

days per year, and a labor rate of $15 per hour (see Table 6-2). Supervision 

was figured at 15 percent of labor and maintenance labor was assumed to equal 

operating labor (Reference 6). Catalyst costs, obtained from Reference 7, 

were found to vary according to the method used to separate the recovered 

sulfur from the catalyst solution. 

Indirect costs were factored from capital costs or direct operating costs 

using factors from References 6 and 8. As with the amine-Claus control system, 

capital recovery i s based on a 10 percent rate of return and a 15-year equipment life . There are no waste disposal costs for spent catalyst, in accordance 

with Reference 3. Product recovery credits for sulfur have also been calculated. 

Note that because the LO-CAT® process directl y produces the desulfurized refinery 

fuel gas, these model plants are designed to meet (or better) the limi t of 162 

parts per million (ppm) H2S in the gas. The design sulfur removal efficiencies 

vary with H2S inle t concentration, with a consequent variation in sulfur 

recovery. Note also that there i s some question about the quality of sulfur 

recovered from the LO-CAT® process. To be conservative, therefore, each 

annualized cost table includes a cost for sulfur disposal, calculated at a 

unit cost of $24.60 per long ton ($24.22 per Mg). The total annualized 
P.87 

6-15 

Table 6-10 

CAPITAL COST SUMMARY 

Purchased equipmentD(A) 

Taxes and freight(0.08cXA) 

Base Cost (B) 

Direct/indirect installation 

(0.50dxB) 

Total Installed Cost 

(J 

LO-CAT® PROCESS 

anuary 1985 Dollars) 

I 

Cost in Tho 

Plant Capacity 

1.016(1) 

520 

fl 

562 

281 

843 

2. 

usands of Dollars3 

, Mg/D (LT/D) Sulfur. 

032(2) 

810 

65_ 

875 

438 

1313 

5.08(5) 

1460 

117 

1577 

789 

2366 

10.16(10) 

2380 

190 

2570 

1285 

i 

3855 

3 Cost for each capacity applies for inlet hydrogen sulfide concentrations 

of 1, 5, or 10 percent. 

D Costs were developed from information in Reference 3 and include instrumentation. 

c Reference 6 was the source of this factor. 

d Overall installation factor suggested by Reference 7 for refinery installations. 
P.88 

6-16 

cost for the process is therefore bracketed between a low figure that 

includes full credit and a high figure that includes the full cost of 

disposal. In reality, the annualized cost would probably fall in between, 

depending on the quality of the sulfur produced and the available markets 

for sulfur of that quality. 

The annualized costs for the model plants are presented in Tables 6-11 

through 6-14. 

6.4 COST-EFFECTIVENESS 

The cost-effectiveness values are determined from the costs developed 

in Sections 6.2 and 6.3 and the emission reductions presented in Chapter 5. 

The cost-effectiveness values represent the estimated cost (in January 1985 

dollars) that would be incurred by a refinery for each ton of SO2 emissions 

that is controlled. 

Cost-effectiveness values for both control systems and all model plants 

are shown in Tables 6-15 and 6-16, for the amine-Claus and LO-CAT® processes, 

respectively. All cost-effectiveness values are based on a baseline of 

zero control. For both processes, the C/E ratio increases as the model 

plant size decreases. 

The amine-Claus system's cost-effectiveness improves to a credit of 

$10 to $12/Mg at the 101.6 Mg/D model plant size. The model plant size at 

where the transition from cost to credit occurs is approximately 30 Mg/D. 

(Note that because costs for the 203.2 and 508 Mg/D plants are multiples of 

the cost for the 101.6 Mg/D plant, the cost-effectiveness for all plants 

101.6 Mg/D and larger is exactly equal in this analysis.) Cost-effectiveness 

is not a strong function of inlet H2S concentration in the range of concentrations examined in this analysis. 
P.89 

6-17 

Table 6-11 

ANNUALIZED COST SUMMARY3»b 

LO-CAT® PROCESS 

1.016 Mg/D (1 LT/D) PLANT 

(January 1985 Dollars) 

Cost in 

Thousands 

of Dollars 

Direct Operating Cost 

Operating labor 42 

Supervision 6 

Maintenance labor 42 

Utilities (electricity) 2 

Catalysts and chemicals 64 

Indirect Operating Cost 

Overhead (50 percent of all labor costs) 45 

Capital Recovery (10 percent rate of return, 15 years 

equipment life) 111 

Taxes (one percent of capital cost) 8 

Insurance (one percent of capital cost) 8 

Administration (two percent of capital cost) 17 

Total Annualized Cost Without Credit 346 

Sulfur Credit0 38 

Net Annualized Cost (With Credit) 308^ 

Sulfur Disposal0 8 

Total Annualized Cost with Disposal 355 

aWith the exception of the sulfur credit and sulfur disposal cost, the costs 

shown apply for inlet H2S concentration of 1,5, and 10 percent. See Note c. 

bTot als may not add due to rounding. 

cThe sulfur credit and disposal cost shown are for 1 percent H2 S. For other 

inlet H2S concentrations, the sulfur credit would be as follows: 5 percent 

H2S -- 39; 10 percent H2S -- 39. The disposal cost would be: 5 percent 

H2S -- 9; 10 percent H2S -- 9. 
P.90 

6-18 

Table 6-12 

ANNUALIZED COST SUMMARY3»b 

LO-CAT® /PROCESS 

2.032 Mg/D (2 LT/D) PLANT 

(January 1985 Dollars) 

Cost in 

Thousands 

of Dollars 

Direct Operating Cost 

Operating labor 42 

Supervision 6 

Maintenance labor 42 

Utilities (electricity) 3 

Catalysts and chemicals 129 

Indirect Operating Cost 

Overhead (50 percent of all labor costs) 45 

Capital Recovery (10 percent rate of return, 15 years 

equipment life) 173 

Taxes (one percent of capital cost) 13 

Insurance (one percent of capital cost) 13 

Administration (two percent of capital cost) 26 

Total Annualized Cost Without Credit 493 

Sulfur Credit0 77 

Net Annualized Cost (With Credit) 416_ 

Sulfur Disposal0 17 

Total Annualized Cost with Disposal 509 

aWith the exception of the sulfur credit and sulfur disposal cost, the costs 

shown apply for inlet H2S concentration of 1,5, and 10 percent. See Note c. 

bTotals may not add due to rounding. 

cThe sulfur credit and disposal cost shown are for 1 percent H2 S. For other 

inlet H2S concentrations, the sulfur credit would be as follows: 5 percent 

H2S -- 78; 10 percent H2S -- 78. The disposal cost would be: 5 percent 

H2S -- 17; 10 percent H2S -- 17. 
P.91 

6-19 

Table 6-13 

ANNUALIZED COST SUMMARY3>b 

LO-CAT® PROCESS 

5.08 Mg/D (5 LT/D) PLANT 

(January 1985 Dollars) 

Cost in 

Thousands 

of Dollars 

Direct Operating Cost 

Operating labor 42 

Supervision 6 

Maintenance labor 42 

Utilities (electricity) 5 

Catalysts and chemicals 142 

Indirect Operating Cost 

Overhead (50 percent of all labor costs) 45 

Capital Recovery (10 percent rate of return, 15 years 

equipment life) 311 

Taxes (one percent of capital cost) 24 

Insurance (one percent of capital cost) 24 

Administration (two percent of capital cost) 47 

Total Annualized Cost Without Credit 688 

Sulfur Credit0 192 

Net Annualized Cost (With Credit) 496_ 

Sulfur Disposal0 42 

Total Annualized Cost with Disposal 731 

3With the exception of the sulfur credit and sulfur disposal cost, the costs 

shown apply for inlet H2S concentration of 1,5, and 10 percent. . See Note c, 

DTotals may not add due to rounding. 

cThe sulfur credit and disposal cost shown are for 1 percent H2S. For other 

inlet H2S concentrations, the sulfur credit would be as follows: 5 percent 

H2S -- 195; 10 percent H2S -- 195. The disposal cost would be: 5 percent 

H2S — 43; 10 percent H2S — 43. 
P.92 

6-20 

Table 6-14 

ANNUALIZED COST SUMMARY3.b 

LO-CAT® PROCESS 

10.16 Mg/D (10 LTTD T PLANT 

(January 1985 Dollars) 

Cost in 

Thousands 

of Dollars 

Direct Operating Cost 

Operating labor 42 

Supervision 6 

Maintenance labor 42 

Utilities (electricity) 7 

Catalysts and chemicals 284 

Indirect Operating Cost 

Overhead (50 percent of all labor costs) 45 

Capital Recovery (10 percent rate of return, 15 years 

equipment life) 507 

Taxes (one percent of capital cost) 39 

Insurance (one percent of capital cost) 39 

Administration (two percent of capital cost) 77 

Total Annualized Cost Without Credit 1088 

Sulfur Credit0 385 

Net Annualized Cost (With Credit) 7Ctt 

Sulfur Disposal0 • 85 

Total Annualized Cost with Disposal 1172 

3With the exception of the sulfur credit and sulfur disposal cost, the costs 

shown apply for inlet H2 S concentration of 1,5, and 10 percent. See Note c. 

DTotals may not add due to rounding. 

c T he sulfur credit and disposal cost shown are for 1 percent H2 S. For other 

inlet H2 S concentrations, the sulfur credit would be as follows: 5 percent 

H2 S -- 390; 10 percent H2S — 391. The disposal cost would be: 5 percent 

H2 S — 86; 10 percent H2 S — 86. 
6-21 

Table 6-15 

COST EFFECTIVENESS 

SULFUR DIOXIDE CONTROL 

AMINE TREATMENT WITH CLAUS SULFUR RECOVERY3 

(January 1985 Dollars) 

Annualized 

Plant Size Cost (Credit) S02 Removed C/E; 

Inlet Concentration Mg/day (LT/D) $103/yr Mg/yr tons/yr $/Mq $/ton 

1% H2S 

5% H2S 

10% H2S 

5.08 

10.16 

50.8 

101.6 

•0.51 

5.08 

10.16 

50.8 

101.6 

0.51 

5.08 

10.16 

50.8 

101.6 

0.51 

(5) 

(10) 

(50) 

(100) 

(0.50)b 

(5) 

(10) 

(50) 

(100) 

(0.50)b 

(5) 

(10) 

(50) 

(100) 

(0.50)b 

762 

695 

(ID 

(702) 

(8.7) 

759 

688 

(47) 

(775) 

(8.9) 

758 

686 

(55) 

(789) 

(9.1) 

3,435 

6,870 

34,350 

68,700 

344 

3,435 

6,870 

34,350 

68,700 

344 

3,435 

6,870 

34,350 

68,700 

344 

3,787 

7,573 

37,867 

75,734 

379 

3,787 

7,573 

37,867 

75,734 

379 

3,787 

7,573 

37,867 

75,734 

379 

222 

101 

(0.32) 

(10.2), 

(25.3) 

221 

100 

(1.37) 

(11.3) 

(26.0) 

221 

100 

(1.60) 

(11.5) 

(26.4) 

201 

92 

(0.29) 

(9.3) 

(23.0) 

200 

91 

(1.24) 

(10.2.) 

(23.6) 

200 

91 

(1.45) 

(10.4) 

(23.9) 

3 The cost-effectiveness ratios for 200 LT/D and 500 LT/D plants would be the same as 

shown for 100 LT/D, in that the annualized costs for these plants are multiples of the 

100 LT/D costs in this analysis. However, if large plants were to be custom-jdesigned, 

their C/E ratios would be expected to be lower, reflecting economies of scale in the 

capital costs. 

b Expansion case (10.16 to 10.668 Mg/D). All values shown on these lines are incremental 

between the base and expansion capacities. 
P.94 

6-22 

Table 6-16 

COST EFFECTIVENESS 

SULFUR DIOXIDE CONTROL 

LO-CAT® PROCESS 

(January 1985 Dollars) 

Inlet Concentrat 

1% H2S 

5% H2S 

10% H2S 

*For the special 

Plant Size 

ion Mg/D (LT/D) 

1.016 (1) 

2.032 (2) 

5.08 (5) 

10.16 (10) 

1.016 (1) 

2.032 (2) 

5.08 (5) 

10.16 (10) 

1.016 (1) 

2.032 (2) 

5.08 (5) 

10.16 (10) 

Sulfur 

Status 

recovered 

disposed 

recovered 

disposed 

recovered 

disposed 

recovered 

disposed 

recovered 

disposed 

recovered 

disposed 

recovered 

disposed 

recovered 

disposed 

recovered 

disposed 

recovered 

disposed 

recovered 

disposed 

recovered 

disposed 

case where neither a sulfur 

Annualized 

Cost (Credit 

$103/yr* 

308 

355 

416 

509 

496 

731 

703 

1,172 

308 

355 

415 

509 

493 

732 

698 

1,173 

308 

355 

415 

509 

493 

732 

697 

1,173 

) S02 

Mg/yr 

700 

700 

1,399 

1,399 

3,499 

3,499 

6,997 

6,997 

709 

709 

1,418 

1,418 

3,545 

3,545 

7,090 

7,090 

710 

710 

1,420 

1,420 

3,551 

3,551 

7,101 

7,101 

recovery credit nor a < 

Removed 

tons/yr 

771 

771 

1,543 

1,543 

3,856 

3,856 

7,713 

7,713 

781 

781 

1,563 

1,563 

3,907 

3,907 

7,815 

7,815 

783 

783 

1,565 

1,565 

3,914 

3,914 

7,827 

7,827 

iisposal cost 

( 

$/Mq 

440 

507 

297 

364 

142 

209 

100 

168 

434 

501 

293 

359 

139 

206 

98 

165 

434 

500 

292 

358 

139 

206 

98 

165 

were 

:/E 

$/ton 

399 

460 

270 

330 

129 

189 

91 

152 

394 

455 

266 

326 

126 

187 

89 

150 

393 

453 

265 

325 

126 

187 

89 

150 

taken, 

the annualized cost would be found in Table 6-11, -12, -13, or -14. The cost-effectiveness would then be the quotient of this cost (the "Total Annualized Cost Without Credit") 

and the "SO2 Removed" value in column 5. 
P.95 

6-23 

The most interesting aspect of Tables 6-15 and 6-16 is the comparison of 

cost-effectiveness between the two control systems at the common model plant 

sizes--5.08 and 10.16 Mg/D. At the 10.16 Mg/D size, the cost-effectiveness • 

ratios of the amine-Claus and LO-CAT® systems (sulfur recovery case) are 

essentially equal. But as the model plant size decreases to 5.08 Mg/D, 

the amine-Claus system becomes less cost-effective than the LO-CAT® system 

(sulfur recovery case). This indicates that for these lower sulfur loadings, 

the LO-CAT® would be the preferred control system to use. 

6.5 COST COMPARISON 

To determine their representativeness, the capital costs plus the operating 

and the maintenance (O&M) costs in Sections 6.2 and 6.3 were compared to cost 

data obtained from refineries that responded to Section 114 letter requests. 

Of the 13 plants covered in these 114 responses, seven contained enough cost/ 

process data to allow meaningful comparisons. Because some of the respondents 

requested their cost data to be held confidential, no specific results 

are shown herein. However, some general information about the cost comparisons 

can be provided: 

o After escalating all costs to January 1985 dollars, costs were 

compared for seven amine treating units (ATU's), one LO-CAT® 

system, and one combination ATU-CLAUS system. (Note: some 

refineries provided data on more than one system.) 

o All but one of the capital cost sets differed by less than +_ 50%, 

the nominal accuracy of the total installed costs in the chapter, 

o Larger discrepancies were seen in the O&M costs, due to differences 

in unit prices, cost allocations, accounting methods, and other 

factors. In all but one case, the O&M costs in the chapter were 

higher than the respondents'. 

L.l 
P.96 

6-24 

o Details of the cost comparison have been placed in the confidential 

portion of the project docket. 

6.6 REFERENCES FOR CHAPTER 6 

1. Shumaker, Jeffrey L., Memorandum to Docket A-80-20A, dated September 11, 

1984, concerning sweetening plant cost factors. 

2. Review of New Source Performance Standards for Petroleum Refinery Claus 

Sulfur Recovery Plants, U.S. Environmental Protection Agency, EPA-450/ 

3-83-014, August 1983. 

3. Hardison, L.C , "Minimizing Gas Treating Costs with LO-CAT® for H2S. 

Removal", for presentation at the Panhandle Plains Regional Meeting of 

the Gas Processors Association, Amarillo, TX, October 11, 1984. 

4. -Hardison, L.C , "Go from H2S to S in One Unit", Hydrocarbon Processing, 

April 1985, pp. 70-71. 

5. Telecons--Thomas Beggs (JACA Corporation, Fort Washington, PA) with 

Mr. L.C. Hardison (President, ARI Technologies, Inc., Palatine, IL): 

Apri l 1 , 1985; May 21 , 1985; and June 10, 1985. 

6. Vatavuk, William M. and Neveril, Robert B., "Estimating Air-Pollution Control 

Costs—Part II : Estimating Capital and Operating Costs," Chemical Engineering, 

November 3, 1980, pp. 157-162. 

7. Letter from L. C Hardison (ARI Technologies, Inc. , Palatine, IL) to W. 

L. Elmore (U.S. Environmental Protection Agency, ResearchTriangle Park, NC), 

February 26, 1986. 

8. Peters, M.S. and Timmerhaus, K.D., Plant Design and Economics for Chemical 

Engineers, Third Edition. McGraw-Hill, New York, NY, 1980, pp. 203-209. 
• f • r fy 

I ' 

P.97 

APPENDIX A 

Listed below are the cost factors that were obtained or derived from 

Reference 1 and used in estimating capital and annualized costs for the 

amine treating process. 

Component Cost Factor 

Capital cost (10% H2S) $0.51 per standard cubic feet 

per day (SCFD) of acid gas* 

Capital cost (1% H2S or 5% H2S) 0.9 (cap. cost at 10%) 

+0.1 (cap. cost of 10%)|~ 10 ~1 0-

6 

ij^S cohc_J 

Operating labor (including some 

maintenance 

$126,000 per year 

Maintenance $0.01 per year per SCFD acid gas 

Utilitie s (heat and electricity ) $0,274 per year per SCFD acid gas 

Chemicals $0.0187 per year per SCFD acid gas 

The acid gas flowrate is related to the sulfur loading, as follows: 

Flowrate (SCFD) = 33,160 x S 

where: S = sulfur fed to amine treater (LT/D) 

Via thi s equation, the above factors may be rewritten in terms of the,sulfur 

loading. 
P.98 

APPENDIX B 

This section presents three examples of line item annualized costs for 

the control systems analyzed. The model plant used for illustration is the 

5.08 Mg/D (5 LT/D) plant with an inlet concentration of one percent H2 S. 

The examples are shown in Tables B-l, B-2, and B-3. 
P.99 

B-2 

Table B-l 

LINE ITEM ANNUALIZED COST EXAMPLE3 

AMINE TREATMENT, 5 LT/D, 1% H?S 

(January 1985 Dollars) 

Di rect 

Operating labor 0 

Supervision 

Maintenance 

Utilitie s 

Chemicals 

Indirect 

Overhead 

Capital recovery 

Taxes 

Insurance 

Administration 

(direct from Reference 1) $126,000 

15% of above: $126,000 x 0.15 18,900 

$0.01 per SCFD: 165,800 x 0.01 1,658 

$0.274.per SCFD: 165,800x0.274 45,429 

$0.0187 per SCFD: 165,800 x 0.0187 3,100 

50% of labor: (126,000 +.18,900) x 0.50' 72,450 

CRF (10 percent, 15 years) = 0.1315: 

$109,925 x 0.1315 

percent of capital cost: 

$109,925 x 0.01 

percent of capital cost: 

$109,925 x 0.01 

percent of capital cost: 

$109,925 x 0.02 

14,455 

1,099 

1,099 

2,199 

$286,389 

3

 Direct factors from Reference 1 . (See Appendix A). 

D

 Includes an unspecified amount of maintenance labor. 
P.1 

B-3 

Table B-2 

LINE ITEM ANNUALIZED COST EXAMPLE^ 

CLAUS SULFUR RECOVERY PLANT 5 LT/D, 1% H?S 

(January 1985 Dollars) 

Di rect 

Operating Labor 

Supervision 

Maintenance, repair0 

Supplies, lab 

4300 Kp steam 

Boiler feedwater 

Electricit y 

Fuel gas 

Catalyst 

Indirect 

Overhead 

Capital recovery 

Taxes 

Insurance 

5600 hours x $15 

year hour 

2100 hours x $2 0 

year hour 

3 percent of capital cost: 

$2,285,000 X 0.03 

20 percent of operating labor: 

$84,000 X 0.20 

200 Mg x $17.50 

Year " Mg 

3267 Mg x $3.60 

Year Mg 

764 Gj x $15.28 

Year Gj 

2423 Gj x $i 

Year Gj 

$655 x 5 LT/D x 1.1 

10 LT/D 

$84,000 

42,000 

68,550 

16,800 

3,500 

11,760 

11,670 

9,690 

361 

50 percent of labor: 80,138 

0.50 X (84,000 + 42,000 + 0.5 X 68,550) 

CRF (10 percent, 15 years) = 

0.1315: $2,285,000 X 0.1315 

1 percent of capital cost: 

$2,285,000 X 0.01 

1 percent of capital cost: 

$2,285,000 X 0.01 

300,478 

22,850 

22,850 
P.2 

B-4 

Table B-2 (cont'd) 

Indirect (cont'd) 

Administration 2 percent of capital cost: 45,700 

$2,285,000 X 0.02 

Total Annualized Cost w/o Credit 720,347 

Credits 

1760 Kp steam 

106 Kp steam 

Steam condensate 

Sulfur ' 5.08 

day 

Total Credits 

Mg 

2934 Mg x 

year 

286 Mg x 

year 

1550 Mg * 

year 

X 0.966 recove 

$16.25 

Mg 

$11.00 

Mg 

$3.00 

Mg 

ry x 350 days 

year 

x $no 

Mg 

47,680 

3,144 

4,651 

188,930 

244,405 

NET ANNUALIZED COST $475,942 

a

 Consumption figures derived from cost data in Reference 2. 

0

 Assumed to be equal parts labor and materials. 
P.3 

LINE 

LODirect 

Operating Labor 

Supervision 

Maintenance labor 

Utilities0 

Catalysts and 

Chemicals0 

Indirect 

Overhead 

Capital recovery 

Taxes 

Insurance 

Administration 

B-5 

Table B-3 

ITEM ANNUALIZED COST EXAMPLES 

-CAT® PROCESS, 5 LT/D, 1% H?S 

8 hours x 350 days x $15 

day year hour 

15% of above: $42,000 X 0.15 

Same as operating 

$2.70 x 5 LT x 350 days 

LT day year 

$81.20 x 5 LT x 350 days 

LT day year 

50 percent of labor: 

(42,000 + 6,300 + 42,000) X 0.50 

CRF (10 percent, 15 years) = 

0.1315: $2,366,000 X 0.1315 

1 percent of capital cost: 

$2,366,000 X 0.01 

1 percent of capital cost: 

$2,366,000 x 0.01 

2 percent of capital cost: 

$42,000 

6,300 

42,000 

i 

4,725 

142,100 

45,200 

311,100 

23,700 

23,700 

47 ,300 

$2,366,000 X 0.02 

Total Annualized Cost w/o Credit 688,100 

Sulfur Credit 5.08 Mg x 0.9838 recovery x 350 days x $110 192,400 

day year Mg 

NET ANNUALIZED COST (WITH CREDIT) $495,700 

Sulfur Disposal 5.08 Mg x 0.9838 recovery x 350 days x $24.22 42,400 

day year Mg 

TOTAL ANNUALIZED COST WITH DISPOSAL $730,500 

~* In most cases, unit consumption data were taken from References 3, 4, 

and 5. 

0 Unit costs for utilities and catalysts are not the same for all plant sizes, 

as the quantities required of steam, electricity, catalyst, etc., vary 

nonlinearly with capacity.