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OAR Box 1784 

Prepped by Ollie Stewart 

Document Number: 

44) ll-B-3 

Docket Number: 

A-84-44 

Printed 10/31/2008 8:05:40 AM Sheet 44 of 143 
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^ " v—v A-84-4* 

' , ? g% \ UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

I *&?7 * Ofi\ce of Air Quality Planning and Standards j£ ~ "£> - ^ 

V**^ / Research Triangle Park, North Carolina 27711 

• " 1 1 DEC 1984 

MEMORANDUM 

SUBJECT: Meeting Report: Refinery Fuel Gas NSPS Review Kickoff Meeting (83/03) 

FROM: Nancy D. McLaughlin, Environmental Engineer sftM&'yWf^ 

Standards Documentation Section, ISB (MD-13)

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TO: Kenneth R. Durkee, Chief 

Standards Documentation Section, ISB (MD-13) 

I. PURPOSE: 

The purpose of this meeting was to review the draft work plan for 

the refinery fuel gas NSPS review and to discuss any additional issues 

that may affect this review. 

II. TIME AND PLACE: 

2:00-3:30, October 17, 1984 

7th Floor Conference Room 

N.C. Mutual Building, Durham, N.C. 

III. ATTENDEES: 

Industrial Studies Branch 

Stan Cuffe 

Ken Durkee 

Nancy McLaughlin 

Charlie Sedman 

Emission Measurement Branch 

George Walsh / 

Standards Development Branch 

Gail Lacy 

Economic Analysis Branch 

Do.n Gillette 

Al Wehe 
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IV. DISCUSSION AND DECISIONS: 

A. Background 

Prior to the meeting, a draft work plan was distributed-to all attendees. 

The draft work plan presented: 

1 . Summary of current NSPS. 

2. Summary of issues raised by previous review. 

3. Additional issues raised during preliminary information gathering. 

4. Outline of areas of work. 

5. Schedule for project. 

B. Claus Sulfur Plant Standard 

The interrelationshi p of the refiner y fuel gas and Claus sulfur plant 

NSPS's was discussed. The fuel gas NSPS is based on the use of amine treater s 

to clean the H2S from the fuel gas. An amine treater produces a secondary 

gas waste stream with very high concentrations of H2S, which i s usually 

sent to a Claus sulfur plant or sulfuri c acid plant to recover the sulfur. 

These sulfur plants also produce waste "tai l gas" streams that are regulated 

by the sulfur plant NSPS. The entire sulfur treatment system i s often 

purchased and installe d as one unit , (amine treater, sulfur plant, tai l 

gas unit) , so i t i s difficul t to segregate costs for each part . Charlie 

Sedman fel t the review of the refinery fuel gas and sulfur plant NSPS's 

should be combined into one overal l review process. He fel t that thi s 

would be a more realisti c approach, especially toward the cost/effectiveness 

of the emission reduction. 

Deci si on: This i s somewhat a moot issue since the Claus sulfur plant 

review has already been completed; thus the refinery fuel gas review must 

be done separately. However, one result of thi s review may be to recommend 

that the two reviews be combined next time. 

C. Other Related Standards and Possible Conflicts 

This discussion was about the general interrelationshi p of the refiner y 

fuel gas NSPS and other NSPS's. The combustion sources at a refinery may 

also be regulated under Subpart D, Subpart Db, or the new process heater 

•NSPS which i s under development. Although thi s may be undesirable, there 

does not appear to be any conflict . Charlie Sedman noted a philosphical 

conflic t in that currently some combustion sources at refineries are 

regulated only for SO2 due from burning fuel gas; SO2 emissions from fuel 

o i l and soli d fuels are not always regulated by other NSPS's although 

their emission contribution may be more significant . 
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Decision: These two issues are interesting, but outside the scope 

of thi s NSPS review. As outlined in the work plan, this review wil l 

focus on the narrower issue of SO2 emissions due only to burning fuel 

gas. Project engineers on the other NSPS's wil l be consulted to ensure 

there is no direct conflict between standards. 

D. Other Pollutants 

The current standard for refinery fuel gas combustion devices regulates 

only SO2 emissions; other pollutants (particulates, N0X , CO, and VOC) are 

not addressed. Some of these other pollutants are or may be regulated 

under other NSPS's. The previous review did not address these other 

pollutants, and no one in the meeting had a feel for the significance of 

these other pollutants. 

Decision: This is beyond the scope of the current review, and the 

focus will remain on SO2 emissions. However, any data and emission 

estimates that are available on other pollutants will be requested. One 

goal for this review project will be to decide whether or not to recommend 

further study in th'is area, not to prepare an emission standard for these' 

other pollutants. 

E. Economic Analysis 

Usually, in NSPS review projects, only costs of control and emission 

reductions are determined in order to calculate cost/effectiveness of the 

regulation. Al Wehe suggested that an economic analysis step be added to 

the review process. Stan Cuffe indicated that this was a major change in 

our policy toward review studies, and would set a precedent for future 

NSPS reviews. Ken Durkee was concerned about the additional data gathering, 

cost, and time needed for this. He also indicated that NSPS review is 

supposed to be more like a "screening study" with recommendations for 

follow-up detailed work as needed. However, EAB still felt some form of 

economic analysis was appropriate for NSPS review projects, but perhaps 

in a less complex and less rigorous manner than done for newly developed 

standards. 

Decision: This decision needs to be made at the Division Director 

level. Adding an economic analysis would increase the amount of data 

gathering and analysis and may lengthen the review schedule; however, it 

could provide useful information (such as size cutoffs - see below). 

This would be a significant addition to this draft work plan. 

F. Size Cutoff 

The regulation does not include a lower size cutoff. The original 

standard was based on amine treating, but amine treating units with 

associated sulfur plants may not be practical for very small sources. 
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Charlie Sedman added that a lower size cutoff was included for Claus 

sulfur plants (20 tons/day). Possible approaches to a lower size cutoff 

would be based on total refinery size, total refinery SO2 emission due to 

burning of H2S in fuel gas, size of individual affected combustion sources, 

or combined sizes of all affected combustion sources in one refinery. 

Rather than basing the cutoff solely on cost/effectiveness, Al Wehe and Don 

Gillette (EAB) felt this was an area where an economic analysis could be 

useful. 

Decision: It was agreed that this issue needs to be investigated further. 

We will decide if size -cutoff is a problem. However, determining a lower size 

cut off would be difficult and may be beyond the scope of the review project. 

We will gather information on the costs and technical capabilities of amine 

treaters and alternative control processes for smaller sources. 

G. Flue Gas Desulfurization (FGD) 

The standard allows a refinery owner to put an FGD on the outlet of 

a combustion source to control SO2 emissions rather than controlling the 

H2S at the inlet. To date, we know of no refinery that has selected this 

compliance option. Charlie Sedman indicated that this'would be an expensive, 

compliance-option for individual combustion sources, but that it would be 

relatively inexpensive to route the outlet emissions to an existing FGD 

on a FCCU. 

Decision: Investigate to see if any refineries have chosen the FGD 

option and why, as outlined in the draft work plan. 

H. Natural Gas Blending 

The regulation allows a refinery owner to blend natural gas with 

refinery fuel gas prior to the combustion source, and thus diluting the 

H2S concentration to an acceptable level. Stan Cuffe commented that this 

provision was not originally included to allow dilution and circumvention 

of the standard. Instead, it was included because refineries need to use 

natural gas as an auxiliary backup gas to provide constant flow to certain 

combustion sources (such as process heaters). It is not known how much 

refineries blend natural gas with refinery fuel gas to achieve the standard, 

and the previous review provides no information on this area. Gail Lacy 

suggested adjusting the standard so a refinery would not get any advantage 

or credit from dilution with natural gas. 

Deci si on: Investigate how much natural gas blending is done by 

"refineries, why is it done, how it affects emissions, and if the standard 

should be adjusted. This is an issue that will be studied as part of the 

NSPS review. 
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I. Continuous Monitoring 

The regulation requires a continuous H2S monitor at the inlet of a 

combustion source, but because performance specifications have not been 

promulgated by EPA, monitoring is not yet required. IERL completed a 

study in 1982 of five commercially available monitors and concluded that 

none could meet the necessary performance criteria. George Walsh did not 

feel it would be fruitful to continue to require continuous monitors or 

to ask IERL to restudy the issue, and suggested that alternative monitoring 

approaches be investigated (such as periodic performance tests, grab 

samples, etc.). However, continuous H2S monitors are used for operation 

and maintenance by many refineries, they are required in some parts of 

California, and they are relied on as warning devices for low concentrations 

of H2S in ambient air. Nancy McLaughlin suggested that perhaps H2S 

continuous monitors could be used as indicators or to monitor gross violations, 

and thus less stringent performance criteria could be applied. 

Decision: A definite decision was made to investigate alternatives 

to the present continuous monitoring requirement rather than just repeating 

the present requirement and hoping that new monitoring technology will 

eventually provide an acceptable monitor. The experiences of refineries using 

continuous monitors and other monitoring approaches will be investigated. The 

amount of EMB involvement was not decided. 

J. Other Sulfur Compounds 

The standard regulates H2S levels in the inlet gas; Method 11 

measures H2S; and the continuous monitors sense H2S. However, other compounds 

containing sulfur may be present (CS2, COS, sulfides, mercaptans) and will 

.produce SO2 emissions when combusted. Charlie Sedman agreed with the 

current approach to regulate only H2S as a surrogate for all sulfur compounds, 

because H2S is by far the primary contaminant, and he believes the relative 

proportion of the different sulfur compounds is constant. However, recent 

literature suggests that the proportion is not constant, but varies with 

the crude feedstock and up-stream refining processes. Also, amine treaters 

can preferentially treat certain acid gases and sulfur compounds by using 

different amine chemicals. 

The previous review did not address emissions due to other sulfur 

compounds, and there seems to be little information readily available that 

can be used to determine the emission impact of these other sulfur compounds. 

Decision: Gather the information that is available and estimate if 

there is a significant impact on emissions. The goal for this review 

project will be to decide whether or not to recommend further study. 

Changing the regulation to total sulfur would probably require source 

testing, maybe a new test method, and a detailed cost and economic analysis. 

The focus will remain on H2S.