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OAR Box 1784 

Prepped by Ollie Stewart 

Document Number: 

47) ll-B-6 

Docket Number: 

A-84-44 

Printed 10/31/2008 8:05:40 AM Sheet 47 of 143 
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UNITED STATES ENVIRONMENTAL PROTECTION AGENCY ; ~£x. 

~<S 

H m 1885 

A-84-44 

MEMORANDUM 

SUBJECT: Trip Report "- Marathon Petroleum Refinery, Garyville, Louisiana 

FROM: Nancy D. McLaughlin, Environmental Engineer 

Standards Documentation Section, ISB,"ESED (MD-13) 

TO: Kenneth R. Durkee, Chief 

Standards Documentation -Section, ISB, ESED (MD-13) 

I . PURPOSE: 

The purpose of the visi t was to become familiar with the operation 

of ?.min° treatin g units and t c discuss Marathon's experiences, with the 

refinery fuel 35s NSPS. 

I I . TIHE AND PLACE: 

•v.:30-1 2:0.'. ?.rn. 

Mover.iber i.'S, 1984 

2;dr&tho.-i Petroleum Company 

Geryvi lie , Louisiana 

III . ATTENuEF.S: 

U.S. Environveni:?)! Protection Auencv 

^ancy D. i3cl.ai.qhlin 

Charles fi. Seaman 

Pebble K. Wells 

Envi ronHsntal Engineer 

Envi ronm°ntal Engi nc-er 

Environmental Protection Specialist 

Marathon Petroleum Company 

Blake Harmon 

Sue Shaughnessy 

Ken L. Wilkey 

Environmental Coordinator 

Refining Engineer 

Associate Refinina Engineer 

EPA Form 1320-1 (12-70) 

CONCURRENCES 

SYMBOL k 

SURNAME k 

DATE k 

SPS/j?3S 

-W-JUu^/M-

-ZJKL/ZL 

OFFICIAL FILE COPY 

GPO : 1983 O - 403-201 
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IV. DISCUSSION: 

Summary of Activitie s 

Charlie Sedman, Debbie Wells, and I arrived at the refinery at 

8:30 a.m. We firs t .met with Marathon nersonnel for about two-and-one-half 

hours to discuss the routine operation of their amine treaters , the 

reliabilit y and performance of the amine treaters , and Marathon's experiences 

with the refinery fuel gas NSPS. Following the discussion, we observed 

the amine treatin g area and the refinery' s central control room. 

We then visite d the wastewater treatment area for Debbie Wells to 

become familia r with thi s part of the refinery . The discussion here 

emphasized control of air emissions from wastewater treatment unit 

processes and the NSPS that i s currently being developed for thi s air 

emission source. 

Vie lef t the refinery around 12:00. 

The information in thi s report reflect s the discussions during our 

•visit and a subsequent follow-up phone conversation on December 14. 

General Refinery Information 

Marathon's refinery in Garyville, Louisiana, i s the newest grass-roots 

refinery in the country. I t was designed in 1974 and started operation in 

1976. The original refinery was designed by UOP and. constructed by Parsons 

Engineering. There was a major expansion in 1D79 when a flui d catalyti c 

crscMng unit , alkylation unit , amine treater, staurate gas plant, snd 

butann iscmerization unit "-vre added. The contractor for thi s expansion 

was Fluor. 

The re^in^ry has a nominal capacity o^ 255,000 barrels of crude psr 

day. Tho refinery was designed for ani usually runs high sulfur crude 

(greater then ? percent sulfur). 

Amine Treating Systems 

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This refinery has two separate amine treating systems. The first 

system, which was installed with the original refinery, uses monoethanolamine 

(MEA) and was built by Parsons around 1976. The second system which was part 

of tho 197.-? refinery expansion uses diethanolamine (DEA), and was designed by 

Exxon and constructed by Fluor Engineering. 

The HEA system includes one stripper and five absorbers: two for 

hydrotreater recycle gas, one for liquid propane gas, one for the vacuum 

tower off-gas, and one for fuel gas. About 8 million scf/day of gas srq 

treated in the MEA unit. This represents 25 to 50 percent of the total 

fuel r?.s produced in the refinery. About 20 percent of the amine in the 

MEA system is used for the fuel gas treatment. 
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The pressure of the fuel gas in the MEA unit is maintained at 65 psig. 

The H2S level in the inlet stream ranges from 3 to 12 percent; there is little 

or no CO? in the inlet stream. The wide range of inlet H2S concentrations is 

due to variations in the type of crude oil being charged. The outlet concentration of HgS from the MEA routinely averages about 100 ppmv, but again this 

concentrate fluctuates due to changes in the crude type. 

The MEA unit is generally operating at design expectations and there have 

been no significant operating problems. There are no foaming problems at this 

time. MEA losses are minor, about 600 lbs/day out of a baseline operating 

inventory of about 29,000 gallons. The MEA unit uses a precoat filter, 

reclaimer, and flash drum to remove any ccntaminents. (Hydrocarbons in amine 

had been a problem but that has been minimized with the flash drum.) 

The DEA system includes one stripper and two absorbers: one for fuel gas, 

and one for a propane/butane/propylene/butylene mixture. About 15 million 

scf/day of fuel gas are treated in the DEA unit, representing 50 to 75 percent 

of the total fuel gas produced in the refinery. About 90 percent of the amine 

in the OFA system is used for the fuel gas treatment. 

The pressure of the fuel gas into the DEA unit is maintained at ICO psig. 

The composition of the inlet fuel gas stream stays fairly constant since it is 

coming from a ^ore constant source (the FCCU). The H^S level in the inlet 

stream is about 3 percent with some CO2. Marathon has never, tested for other 

sulfur compounds and does not think they are present in significant quantities. 

The outlet concentration of HpS from the DEA is routinely less than 10 ppmv, 

ranging up to 20 ppmv. 

The Jl"A is operating at only 20 to 30 percent of its design level. The 

current circulation rate is P,000 barrels/day vs. a design rate of 27,000 

L.arr°lf./,:!ay. If it were at full load, Marathon estimated the H^S outlet 

concentration could rise to 100 np-.y. Operating at such a low level ha? 

caused som*: operating problems. DEA losses ar?. significant, about 1,500 lbs/ 

6dy out oY ?! baseline inventory of about 27,000 gallons. These high losses 

are rop^rt^'Hy duo to amine entrainment in the liquid treater. There are 

no fcaiv.irig or contamination problems. The DEA uses precoat and carbon filters 

and a flash 6mr:< to remove the impurities which might cause foaming problems. 

Hoth amino treating systems have an excellent reliability record. Seldom 

•has either unit been off-line except for scheduled shutdowns. However, problems 

have been experienced with corrosion inside the amine treaters, piping, and 

exchangers. 

To ensure the amine treaters are operating properly, Marathon samples 

t^e outlets with Oraeger tubes e^'ery four hours, &nd samples the rich an^ lean 

amine one? a day for percent amine, HoS concentration, and hydrocarbon 

contamination. The important variable operating parameters which can be set 

by the operator are the amount of stripping steam and the temperature and 

circulation rate of the amine. The temperature of the amine in the low 
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pressure MEA unit is particularly critical. A 20°F swing in temperature can 

cause the outlet H2S concentration to exceed specifications (150 ppmv). The 

pressure stream in the MEA unit 1s an important parameter, but it is set by 

the pressure of the refinery fuel gas system. The amount of fuel gas flowing 

to the amine treater varies with the crude charge. Based on the fuel gas 

rate, the outlet concentrations, and the amine sample results, the amine 

circulation rates are adjusted any"time the gas rate or outlet concentration 

changes significantly. ' 

Typical operating ranges are listed below: 

Parameter 

Absorber pressure (psig) 

Lean Amine Temperature (°F) 

Amine in Absorbent (weight percent) 

MEA 

H?S in amine (moles/mole) lean 

rich 

DEA 

65 

100 

5 to 18 

0.1 

0.4 

180 

130 

14 to 17 

0.05 

0.4 

In general, if operated at design levels, the DEA unit would be 

cheaper to operate than the MEA unit. This'is because DEA is easier to strip 

•and can be operated at a higher concentration than MEA. Marathon operates 

two separate amine systems because neither system has sufficient capacity 

to handle all treating within the refinery and because it is convenient to 

Operate both low and high pressure fuel gas treaters. 

At thi? time Marathon is not considering switching amines based on the 

current performance of the amine treaters. However, Marathon is not 

satisfied with the performance of their Beavon Stretford tail gas treater 

and is considering changing fro^- DEA to a tertiary amine (MDEA) to be able 

to treat the Claus tail gss in the current amine treater. Currently, the 

snin« treat.r.r off-gas is routed to two 22S LT/D Claus units followed by a 

12 LT/L1 Ssavon Stretford tail gas unit. 

Combustion Sources. 

Because the entire refinery was constructed after the refinery fuel gas 

NSPS took effect, all the combustion sources ir. the refinery are subject to 

the standard. There are 22 affected combustion sources in the refinery: 

2 flares, 2 boilers, 2 incinerators, and 16 process heaters. 

Refinery Fuel Qas System and Natural Qas Blending 

All of the refinery fuel gas and natural gas that is used in the refinery 

is first combined in a common mix drum before being distributed to the various 

combustion sources. Thus Marathon can demonstrate compliance for the entire 

fuel gas system (i.e., all the affected combustion sources) by monitoring at 

this one location. The combined stream is composed of fuel gas from two 

separate amine treating systems, natural gas, and excess platformer gas. 

About 60 percent of the refinery's energy needs is supplied by refinery fuel 

gas; the remainder is from fuel oil or natural gas. 
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The relative amount of each auxiliary fuel that is used depends upon the 

relative cost. Currently, natural gas is preferred and used when possible 

because of its availability and low cost. (Note that Marathon did. not start 

using natural gas at the refinery until a few months ago.) 

Emission Monitoring and Excess Emissions Reports 

To demonstrate compliance with the refinery fuel gas NSPS, the combined 

stream is sampled three times a day using Draeger tubes. Marathon has had 

no significant problems at this refinery with meeting the NSPS, (0.10 gr/dscf 

or 160 ppmv). In general, there have been only 2 or 3 minor excursions above 

the standard for 2 or 3 hours each quarter. In the past, the concentration 

of H?S in the combined fuel stream routinely ranged from 20 to 25 ppmv. Thus, 

Marathon can easily meet the NSPS without adding natural gas. Since Marathon 

has begun to blend significant amounts of natural gas, the concentration in 

the sampled stream has decreased proportionally to the volume of natural gas 

added. 

Emission"Tests 

Emission performance tests were conducted on the treated fuel gas when 

the refinery began its initial operation and after the expansion. Marathon 

personnel did not have the test reports readily available, but agreed to 

provide these reports later. Blake Harmon did note, however, that the tests 

were done on streams directly after the amine treaters, not after blending 

with any natural gas. The refinery did not begin using auxiliary natural gas 

until a few months ago. 

Cost of Complying with NSPS 

r.srathon personnel ^i^ not. have a breakdown of the costs they incur to 

comrjly witY1 this NSPS. The major component, of course, is the capital and 

operating costs of the amine treater system and its associated sulfur 

recovery unit. The cost of monitoring was estimated as one hour per day for 

field testinn, plus Sb for testinn suonlies each day (S2/Draeqer tube; 3 tubes/ 

o&y). 

The administrative cost of recordkeeping and reporting for just the 

refinery fuel gas HSPS was considered relatively low, although it is difficult 

to separate out the administrative cost of one NSPS from all the other 

environmental reporting that is required. 

State Regulations 

In addition to the federal HSPS limitations on the level of H2S in the 

fuel gas, S0^ emissions from combustion sources are also regulated by a 

Louisiana State standard which limits the sulfur content of fuel oil to 

0.7 percent by weight. The State has adopted the federal NSPS for fuel gas 

by reference. 
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««cjjr 

Comments or Problems with NSPS 

Marathon personnel voiced a few complaints about the refinery fuel gas 

NSPS. In general, they felt the NSPS level (160 ppm H2S) was technologically 

feasible. However, they felt it was unrealistic and disproportionally costly 

to control the level of H^S in fuel gas to such a low level when compared to 

the other sources of SO2 emissions. They would prefer a "bubble" approach. 

Marathon would like a -bubble for SO2 emissions for the entire refinery. It 

would be operationally and economically beneficial if the NSPS for refinery 

fuel gas could he waived under a "bubble" approach. 

V. SUMMARY: 

The plant visi t was very informative for us, and Marathon personnel 

were helpful. Because the Marathon refinery is a new, grass-roots refinery, 

the two amine treating systems are representative of new, state-of-the-art 

technology and operations. Marathon personnel indicated that none of the 

information that was discussed during our visit was considered proprietary. 

Attachment 

cc: D. Wells, SDB 

ESFD/ISB/SDS/NDHcLaughlin/cbaker/bjoverman x5595 Rm. 752 MU 12/21/84 

Project 83/03 File AIP 8.1.15.2 Disk: NMcLaughlin 1 Retyped 2/25/85 chb 
Attachment 1 

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Sue Shaughnessy 

Refining Engineer 

Louisiana Refining Division 

Marathon 

Petroleum Company 

P.O. Box AC 

Garyville, Louisiana 70051 

Telephone 504/535-2241 

Ken L Wilkey 

Associate Refining Engineer 

Louisiana Refining Division 

Marathon 

Petroleum Company 

P.O. Box AC 

Garyville, Louisiana 70051 

Telephone 504/535-2241