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OAR Box 1784 

Prepped by Ollie Stewart 

Document Number: 

19) ll-A-1 

Docket Number: 

A--84-44 

Printed 10/31/2008 8:05:38 AM Sheet 19 of 143 
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APTD-1352 a ff-A-i 

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 

Sewage Treatment Plants 

Volume 1, MAIN TEXT 

U. S. ENVIRONMENTAL PROTECTION AGENCY 

Office of Air and Water Programs 

Office of Air Quality Planning and Standards 

Research Triangle Park, North Carolina 27711 

June 1973 
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TECHNICAL REPORT NO. 8 -

PETROLEUM REFINERIES, BURNING OF GASEOUS FUELS 

SUMMARY OF PROPOSED STANDARD 

The proposed standard of performance for petroelum refineries will limit emissions of sulfur 

dioxide from process heaters, boilers, and waste gas disposal systems that burn process gas 

generated in the refinery. The proposed standard does not apply to extraordinary situations, such 

as emergency gas releases, or to the burning of liquid or solid fuels in the same heaters and boilers. 

The proposed standard will limit sulfur dioxide emissions to the atmosphere from heaters, 

boilers, and flares by specifying that the fuel gas burned shall contain no more than 230 mg/Nm3 of 

hydrogen sulfide, or 0.10 gr/dscf, unless resultant combustion gases are treated in a manner 

equally effective in preventing the release of sulfur dioxide to the atmosphere. 

Compliance with the standard is based upon measurement of the hydrogen sulfide concentration in the fuel gas or the sulfur dioxide concentration in the exit gases. The proposed standard 

is equivalent to a sulfur dioxide content of approximately 20 gr/100 scf of fuel gas burned. Burning 

such fuel will result in a concentration of 15 to 20 ppm of sulfur dioxide in the combustion 

products. 

The regulation would have the effect of requiring hydrogen sulfide removal from all refinerygenerated fuel gases used to fire new boilers and heaters. The extracted sulfur compounds cannot 

be burned in flares, heaters, or any other sources unless the control devices used (for example, 

flue gas scrubbers) are equally effective as fuel desulfurization. 

EMISSIONS FROM PETROLEUM REFINERIES 

Refinery processes, such as distillation and fluid catalytic cracking, produce substantial 

quantities of "process gas" (Figure 8) that may contain more than 5 percent hydrogen sulfide by 

volume. If this untreated gas is burned in heaters, boilers, or flares, substantial quantities of sulfur 

dioxide will be emitted to the atmosphere. Monoethanolamine (MEA) and diethanolamine (DEA) 

scrubbing units (Figure 9) are widely used to remove the hydrogen sulfide from both refinery 

process gases and natural gas.1 In addition, new processes that employ other scrubbing media are 

being applied to refinery process gases. The proposed standard will require owners and operators 

of new facilities to reduce the hydrogen sulfide content of refinery-derived fuel gases to levels that 

are consistent with these technologies. For most such gases, the proposed limit represents a 

reduction of more than 99 percent in sulfide levels. For a fuel gas equivalent to methane, the 

resultant emission of 16 ppm sulfur dioxide is roughly equivalent ;to 4he burning of fuel oil 

containing 0.04 percent sulfur by weight. 

Approximately 1 million tons of sulfur charged to U.S. refineries could not be accounted for in 

1970. The majority of this sulfur was probably burned and emitted to the atmosphere as sulfur 

dioxide. If all sources were controlled to the level of the standard, these emissions would be 

reduced by 95 percent. (Most of the difference between the 99+ percent mentioned in the 

preceding paragraph and 95 percent is the result of losses in conversion of the recovered gases into 

sulfur or sulfuric acid.) 

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At the present time, only one local regulation restricts sulfur dioxide emissions from the burning 

of refinery process gas. Some State and local agencies have proposed regulations with limits 

ranging from 10 to 50 grains of hydrogen sulfide per 100 scf of fuel gas burned (19 to 94 grains of 

sulfur dioxide per 100 scf). 

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GAS 

CRUDE 

ATMOSPHERIC 

TOWER 

GAS COMPRESSION 

PROCESS GAS 

NAPTHA 

HYDR0TREATER 

PROCESS CAS m 

GAS OILS 

CATALYTIC CRACKING 

UM VACUUM TOWER 

CRUDE DISTILLATION 

RESIDUUM 

DELAYEDCOKER 

CAS 

f 

GAS COMPRESSION 

SOUR PROCESS GAS 

TO AMINE TREATING 

ABSORPTION & 

FRACTION UNIT 

I 

SOUR PROCESS GAS 

TO AMINE TREATING 

Figure 8. Petroleum refinery process gas system. 

RATIONALE FOR PROPOSED STANDARD 

The proposed sulfur dioxide standard is consistent with the capability of a well designed and 

properly operated amine treating unit that is used to scrub typical refinery process gases at the 

moderate pressures available in the refinery.2'

4

 Amine treating technology is well demonstrated 

and has been widely used to reduce hydrogen sulfide concentrations, uugas streams ta levels less 

than that required to meet the proposed standard. ' ' I 

Three refineries were visited by EPA representatives, and information was obtained on the 

operation of amine systems. All systems were stated to be operating with exit gas concentrations of 

less than 13 grains of hydrogen sulfide per 100 scf. Diethanolamine (DEA) and monoethanolamine 

(MEA) scrubbers are found in almost every U.S. refinery, and hundreds are operated in natural gas 

fields throughout the country. Amine treating is used to reduce the hydrogen sulfide content of 

natural gas to the pipeline specification level of 0.25 gr/100 scf. It would be difficult, however, to 

consistently achieve this level in a refinery where treating pressures are lower than in natural gas 

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SOUR PROCESS GAS J 

ABSORBER WATER 

AMINE 

Figure 9. Petroleum refinery process gas treating unit. 

fields, since higher treating pressures favor hydrogen sulfide removal. The refinery gases also 

contain unsaturated hydrocarbons not usually found in natural gas. These unsaturates tend to 

accelerate fouling of the amine solutions and to reduce scrubbing efficiency. There is no 

discernible difference in plant hardware or design operating parameters for an amine treating unit 

designed to treat refinery process gas to 10, 50, or 100 grains of hydrogen sulfide per 100 scf.2"

4 

Exit gas levels are apparently associated with operating practices; a standard equivalent to 13 

grains of hydrogen sulfide per 100 scf requires good operating practice and has, therefore, been 

chosen as the basis for the standard. 

The proposed standard is expressed in terms of hydrogen sulfide, but can be measured as either 

hydrogen sulfide in the fuel gas or total sulfur compounds in stack gases. Process gas streams also 

contain small amounts of other sulfur compounds, which are not removed by the amine scrubbing 

system. These materials would be included in the total sulfur compounds measured. 

ENVIRONMENTAL IMPACT OF PROPOSED STANDARD 

Due to thermal and chemical degradation, amine solutions require periodic replacement or 

treatment. In MEA treating systems, it is common practice to send a continuous slipstream of 

amine solution to a heated reclaimer. There, caustic soda is a,dded and MEA is disassociated from 

complex salts, distilled, and returned to the regenerator tower. As the'salt content in the reclaimer 

increases, it is necessary to purge the salts and recharge the reclaimer. For a typical 200,000-

bbl/day refinery producing 30 x 106 dscf of process gas, about 2000 lb/month of waste salts may be 

formed. Water is added to reduce the viscosity of salt slurry before disposal by incineration or 

landfill. 

Diethanolamine has a higher boiling point than MEA and cannot be similarly treated. Usual 

practice is to continue operating until the solution is spent and the hydrogen sulfide content of 

treated gas reaches undesirable levels. The entire solution is then replaced with fresh solution. In 

the typical refinery cited above, approximately 50,000 gallons of solution containing 20 percent 

DEA and 10 percent complex salts would have to be removed annually. 

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ECONOMIC IMPACT OF PROPOSED STANDARD 

Treatment of the various refinery gas and liquid streams to control product quality is a 

commonly accepted and necessary practice. Consultation with several engineering companies that 

design amine absorption systems, which are the most commonly used control devices, indicates 

that there could be a 2 to 5 percent increase in investment cost, but no discernable difference in 

operating costs, between a new plant designed to meet the equivalent of 13 grains of hydrogen 

sulfide per 100 scf and a new one designed to meet 100 grains of hydrogen sulfide per 100 scf 

(typical current practice). Therefore, there is a small increase in amine treating cost to refiners as a 

result of the proposed standard. In addition, increased operator effort and attention may be 

required to maintain the design efficiency of the process during actual operation. Because this cost 

factor is quite variable depending on the individual company's present operating practice and 

should be of minor consequence, it has not been quantified. If the refiner chooses to run an 

increased volume of gas through an existing amine absorption system, he may incur costs in 

upgrading the existing system to meet the proposed standard. Because each system must be 

examined individually to determine the cost of upgrading, no attempt has been made to give costs 

for this type of modification. 

It is the intent of the proposed standard that hydrogen-sulfide-rich gases exiting the amine 

regenerator be directed to an appropriate recovery facility, such as a Claus sulfur plant. A mediumsize refinery that processes crude oil containing 0.92 weight percent sulfur, the national average in 

1968, would have an emission potential of over 100 tons/day of sulfur dioxide (50 tons/day of 

sulfur) from the amine regenerator. The annualized cost was calculated for a range of Claus plant 

sizes. A discontinuity occurs in the cost-capacity curve at about 10 long tons/day. The reason for 

the discontinuity is that for plants up to about 10 long tons/day, less costly prefabricated package 

units can be used. Units producing more than 10 long tons/day are generally field-erected and 

considerably more expensive. 

For each size unit, the required sulfur sales price to break even was calculated. At a sales price of 

$20/long ton, the break-even size for package Claus units is about 5 long tons/day. The plant 

investment for a 5-long-ton/day package Claus unit is about $90,000 exclusive of possible future 

investment for control of the sulfur dioxide in the tail gas. The break-even size (at a sulfur price of 

$20/long ton) for field-erected Claus units is about 15 long tons/day, which represents an 

investment of about $350,000. 

No data are presented to show the cost that refineries would incur if their hydrogen sulfide 

removal systems were required to meet the 0.25 gr/100 scf achieved by plants processing natural 

gas. There are several reasons why one should not compare natural gas processing plants with 

refinery fuel gas systems. The natural gas plant processes gas at a high pressure, with a stable gas 

composition, and with low levels of impurities. These conditions allow better hydrogen sulfide 

absorption. Refinery gas is at lower pressure, has a variable composition, and has a variety of 

impurities that reduce the ability of an absorption system to reach the low levels of hydrogen 

sulfide achieved in a natural gas plant. The refinery gas.pressure could be increased at a high cost, 

but other limitations would still prevent the absorption system from achieving the low levels found 

in natural gas plants. 

Cost data have not been developed for higher pressure absorption systems, but the small 

incremental reduction in hydrogen sulfide would make such a system highly questionable from a 

cost-effective point of view.. . •.,-,». „ r 

REFERENCES FOR TECHNICAL REPORT NO. 8 

1. Kohl, A.L. and F.C. Riesenfeld. Ethanolamines for Hydrogen Sulfide and Carbon Dioxide 

Removal. In: Gas Purification. New York, McGraw Hill Company, Inc., 1960. 

2. Thompson, H.L. Private communication to R.K. Burr, U.S. Environmental Protection Agency, 

Research Triangle Park, N.C. UOP, Process Division, Des Plaines, 111. November 15,1971. 

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3. Parnell, D.C. Private communication to R.K. Burr, U.S. Environmental Protection Agency, 

Research Triangle Park, N.C. Ford, Bacon and Davis Texas, Garland, Texas. January 4, 1972. 

4. Mayes, J.R. Private communication to R.K. Burr, U.S. Environmental Protection Agency, 

Research Triangle Park, N.C. Graff Engineering Corporation, Dallas, Texas. January 6,1972. 

u <•,» • 

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