p.1 

OAR Box 1784 

Prepped by Ollie Stewart 

Document Number: 

46) ll-B-5 

Docket Number: 

A-84-44 

Printed 10/31/2008 8:05:40 AM Sheet 46 of 143 
P.2 

1 ^ ^ \ UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

§ ^SK ^ S Office of Air Quality Planningi arid Standards 

\ ^mlwm^g Research Triangle Park, North Carolina 27711 

%PR0 ^ (peg 19-^ 

MEMORANDUM 

SUBJECT: Tri p Report - Murphy Oi l Refinery , Meraux, Louisiana 

FROM: Nancy D. McLaughlin, Environmental Engineer '?/iW} * M&& 

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

TO: Kenneth R. Durkee, Chief 

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

I . PURPOSE: 

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

amine treaters and to discuss Murphy Oil' s experiences with the refinery 

gas new source performance standard (NSPS). 

I I . TIME AND PLACE: 

2:45-5:00 p.m. 

Tuesday, November 27, 1984 

Murphy Oil USA, Incorporated 

Meraux, Louisiana 

III . ATTENDEES: 

U.S. Environmental Protection Agency 

Nancy D. McLaughlin Environmental Engineer 

Charles B. Sedman Environmental Engineer 

Debbie K. Wells Environmental Protection Specialist 

Murphy Oil 

Allden R. Frederickson Manager, Crude, Product, and Environmental 

David C. Petty Supervisor, Environmental Control 

Mark Lacour Process Engineer 

Mark Nolting Chief Process Engineer 

R. Lee Vail Process Engineer 

A-S4-44 

i-^-5-

ulh'^ 

of 

fuel 

Control 
P.3 

IV. DISCUSSION: 

Schedule of Activitie s 

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

2:45 p.m. The plant visi t had been scheduled for 11:00 a.m. but our plane 

flight s were delayed. We firs t met with Murphy personnel in their offices 

for about two hours to discuss the routine operation of their amine treater, 

the reliabilit y and performance of the amine treater, and Murphy's experiences 

with the refinery fuel gas NSPS. However, because of our late arrival , we 

did not have time to discuss these areas as thoroughly as we had planned 

(especially the operation of the amine treater). Following our discussion, 

we observed several areas of the refinery : the amine treating system (stripper 

and absorbers), Claus sulfur plant, tai l gas treater, and corresponding control 

room. 

We also surveyed the wastewater treatment area for Debbie Wells to 

become familiar with thi s part of a refinery . During thi s part of the refinery 

visit , the discussion emphasized control of air emissions from waste water 

treatment unit processes and the NSPS that i s currently being developed for 

thi s air emission source. 

We lef t the refinery shortly after 5:00 p.m. 

General Refinery Information 

Murphy Oil' s refinery in Meraux, Louisiana, is an older, medium-sized, 

fully-integrated refinery . It s nominal capacity i s 95,000 barrels of crude 

per day (80,000 barrels/day in #1 crude unit and 15,000 barrels/day in #2 

crude unit) . Currently, Murphy is using 65,000 barrels/day. About 15,000 

barrels/day are high sulfur content crude from the Alaskan North Slope. 

This high sulfur crude increases the sulfur content in al l the downstream 

products. The sulfur recovery unit routinely handles 12 long tons of sulfur 

per day but i s designed to handle up to 38 long tons per day. 

The refinery was initiall y constructed in and has had a series of 

expansions since then. In late 1970's, the refinery buil t their second 

fluidized catalyti c cracking unit (#2 FCCU). Associated with thi s unit was 

an isostripper reboiler, which was subject to the NSPS for refinery fuel gas. 

Thus, an amine treater unit and associated sulfur recovery plant were also 

added to clean the H2S from the fuel gas. One of the reasons for thi s refinery 

expansion was to make i t capable of handling the high sulfur content Alaskan 

crude. 

Amine Treating Unit 

The amine treater system was buil t in 1975 but didn't start operation 

unti l 1978. The engineering contractor was Erhart. The amine treating system 

includes one stripper and four absorbers (low pressure absorber, high pressure 

abosorber, #2 FCCU absorber, and liqui d propane gas absorber). The nominal 
P.4 

design size.of the amine treating system is 25,273 MM scf/day. Generally, 

Murphy personnel felt the system was operating as predicted by the vendor. 

Murphy provided us with a schematic of the amine treating system, along 

with amine flow rates, fuel gas flow rates, inlet and outlet H2S levels, and a 

sulfur material balance for a recent, typical operating day (November 20, 1984) 

They also provided a detailed breakdown by absorber of amine and gas flow 

rates for both design levels and actual operating levels on the sample day. 

(Copies are attached.) Treated fuel gas from the amine treater is routed to 

a Claus plant and SCOT tail gas unit rated at 38 LT/D capacity. It currently 

operates at 12 LT/D output. 

The acid gases in the fuel gas at the inlet to the amine absorbers are 

primarily H£S and C0£. Murphy does not routinely test for the level of H2S 

in the inlet gas but provided us with sample values for their sample day. 

The values for the low pressure, high pressure, and FCCU absorbers were 2100, 

16800, and 2760 grains per 100 scf, respectively. The wide range of values 

is because the fuel gas comes from different process units. There are traces 

of COS in the inlet gas but no mercaptans. 

The inlet gas to the high pressure amine absorber is at 100 psig. The 

gas to the low pressure absorber is at 70 psig. The different pressures 

are due to the pressures of the fuel gases from the various process units. 

The low pressure gas is compressed slightly from about 60 psig to 70 psig. 

The higher the pressure of the inlet gas, the more easily the amine absorbs 

the acid gases. However, it was more economical to install two different 

absorbers, one at each pressure level, than to boost the pressure of the low 

pressure gas to such a high level. Murphy does not feel that the difference 

in pressure between the two absorbers (30 psig) has a significant effect on 

the way the amine reacts. 

Because of the lack of time, we were not able to discuss in detail the 

routine operation of the amine treating unit and the operating parameters 

that are monitored to ensure proper performance. We discussed this subject 

area briefly, but for details, Murphy provided us with a copy of their 

operating manual (attached). Briefly, Murphy monitors the outlet H2S 

concentration daily to ensure proper performance of the treater and to 

demonstrate on-going compliance. The rich and lean amines are sampled daily 

and analyzed for strength (percent amine), percent H2S, and salts. The flow 

rate and temperature of the amine are crucial operating parameters. Inlet 

pressure is important but since that is at a preset level, it does not 

affect the daily operation. The amine treating process parameters that are 

monitored in the sulfur plant area control room are listed in Table 1. 

The biggest operating problem that Murphy has experienced is foaming, 

due to salt build-up in the amine. A charcoal filter.is used when a foaming 

problem arises. The foaming causes the system to lose amine. Murphy has to 

replace two to four drums of amine per month out of a baseline operating 

inventory of 15,000 gallons. 
P.5 

The off gases from the amine treater to the sulfur recovery plant are 

routinely maintained around 90 percent H2S and 10 percent CO2. 

The amine that is used is diethanolamine (DEA). This amine has been 

used since the amine unit started operation. Murphy is considering switching 

to methyl-diethanolamine (MDEA), or to Union Carbide's brandname MDEA called 

Ucarsol, especially if Murphy switches to using more sour crude. MDEA is a 

tertiary amine and would have the advantages that it reacts more quickly to 

H2S than to CO2 and therefore would pick up more H2S at the same circulation 

rate. Thus, less steam would be needed to strip the amine for the same amount 

of control. MDEA has the disadvantage that it is more expensive than DEA. 

Union Carbide claims that their Ucarsol with its special additions 

has less foaming and corrosion problems than generic MDEA. However, Ucarsol 

is more expensive. 

Before 1979, Murphy did not do any amine treating to reduce the H2S 

content of the fuel gas. The amine treating unit was installed only because 

of the NSPS regulation. However, Murphy has now decreased the H2S level to all 

of its combustion sources, not just the one new reboiler. Murphy could not 

estimate the cost savings due to the decrease of corrosion because of the lower 

H2S content. They did comment that they had previously had significant 

build-up of sulfur inside the combustion devices. With a lower H2S content, 

the heater outlet temperatures can be lowered from about 450° to 300° F without 

significant amounts of sulfuric acid condensing and attacking heater surfaces. 

Thus, there is an indirect maintenance and energy savings due to the NSPS. 

Combustion Sources 

The Murphy refinery in Meraux has 19 combustion sources: 12 process 

heaters, 4 boilers, 2 flares, and 1 incinerator. The isostripper reboiler is 

the only combustion source that is subject to the NSPS. 

Fuel Gas System 

All the fuel gas produced in the refinery except the off-gas from the 

platformer is now treated prior to combustion. The treated fuel gas streams 

from the three amine treating absorbers are combined in a common header before 

being routed to the combustion devices. In addition, the platformer (reformer) 

off-gases which are free of sulfur compounds are then blended in with the 

treated fuel gas. The fuel gas flow rates for a recent typical day are provided in the memorandum Murphy prepared for us on the fuel gas analysis and 

sulfur material balance. 

Natural Gas Blending 

Natural gas is blended with the treated fuel gas in about a 1 to 2 ratio 

by volume. The natural gas is used strictly as a fuel supplement; the blending 

is not done to meet the standard. The amount of natural gas that is used 
P.6 

varies depending on the amount of additional makeup heat that is needed, the 

amount of other fuels being used (e.g., fuel oil), the season of the year, and 

the mode of plant operation. 

Emission Performance Tests 

An initial performance test to determine compliance with the NSPS was 

conducted for Murphy by Air Resources, Inc. The average H2S concentration for 

seven Method 11 runs was 27.70 mg/dscm (0.012 gr/dscf). This value is well 

within the allowable concentration of 230 mg/dscf (0.010 gr/dscf). Samples 

for the performance test were taken immediately after the amine treater before 

the fuel gas stream had been blended with natural gas. 

Emission Monitoring and Excess Emissions 

For NSPS recordkeeping and compliance purposes, Murphy tests the 

hydrogen sulfide (H2S) level in the treated fuel gas daily, using the 

Tutweiler test procedure. A gas sample is extracted in a glass bomb and 

analyzed using wet chemistry procedures. The samples are taken by the unit 

operator and analyzed in the field at a semi-enclosed table. Murphy prefers 

the Tutweiler procedure over the Draeger tube method because the Tutweiler 

procedure can handle higher concentrations, and because the Draeger tubes 

have had problems with interferences due to N0X , especially off the fluid 

cracking unit. 

Murphy has not had any serious difficulties in routinely meeting the 

NSPS. They have had minor exceedances above the standard but did not have 

a record of their sampling results or excess emission reports readily 

available. 

The samples are taken before blending with natural gas. Murphy conducts 

the monitoring solely for NSPS compliance purposes. They would probably not take 

these samples to ensure that the amine treater was performing properly. 

Instead, they feel the other operating parameters that are monitored and the 

amirfe sample results are sufficient to operate the unit properly. 

Murphy officials could not assign a separate cost for the monitoring, 

recordkeeping, and reporting that they do for this NSPS. The Tutweiler sampling 

and analysis takes the area foreman or operator at most one hour per sample. 

Other Regulations Affecting Combustion Sources 

The State of Louisiana has adopted the federal NSPS levels for H2S 

content in refinery fuel gas for new sources; there is no state regulation for 

existing sources. However, the State does have additional regulations affecting the sulfur dioxide (SO2) emissions from refinery combustion sources: fuel 

oil must be less than 0.7 percent by weight sulfur; and effluent from heater 

stacks must be less than 2000 ppm SO2. These additional State regulations do 

not conflict with complying with the NSPS for fuel gas. 
P.7 

Comments or Problems with the NSPS 

Murphy personnel had no specific comments or problems concerning the 

refinery fuel gas NSPS. 

Costs of Complying with the NSPS 

Murphy personnel did not have a breakdown of the costs they incur to 

comply with this NSPS. The major component is the capital and operating costs 

of the amine treater system and the associated sulfur recovery unit. The 

estimated cost of monitoring was at most 1 hour/sample each day of a unit 

operator's time. The cost of recordkeeping and reporting for just the refinery 

fuel gas NSPS was considered minimal (about one hour per week), although it 

is difficult to separate out the administrative cost of one NSPS from all the 

other environmental reporting that is required. The main administrative costs 

are incurred upfront during the initial planning of the refinery expansion. 

Murphy was able to provide, however, an estimate of the labor cost to 

routinely operate the entire amine treating and sulfur system (including the 

sour water separator): 

1 engineer 

1 operator 

1 operator assistant 

1 area foreman 

1 shift foreman 

(full-time) 

(full-time) 

(full-time) 

(one-half time) 

(one-half time x 3 shifts/day) 

V. Summary 

The Murphy oil refinery is representative of a medium-sized, fullyintegrated refinery which has recently upgraded its crude processing and 

has had to add a new amine treater to an existing refinery. The plant visit 

was \/ery informative for us, and Murphy personnel were quite helpful. Murphy 

provided us with two handouts: the operating manual for the amine treating 

unit; and a sulfur and fuel gas material balance for a typical day. Murphy 

personnel indicated that this information and the topics discussed were not 

considered proprietary. 

4 Attachments 

cc Charlie Sedman 

Debbie Wells 
P.8 

TABLE 1 

AMINE TREATING PROCESS PARAMETERS THAT ARE MONITORED 

AUTOMATICALLY IN THE CONTROL ROOM 

MURPHY OIL USA, INC. 

MERAUX, LOUISIANA 

High pressure absorber 

Low pressure absorber 

Stripper reboiler recovery 

Amine stripper reboiler 

Stripper overhead 

Sour gas to sulphur plant 

Amine flash drum 

Sour water stripper 

Treated gas product 

Lean amine surge drum 

Pressure (psig) 

Amine circulation rate (gpm) 

Pressure (psig) 

Amine circulation rate (gpm) 

Steam usage (lbs/hr) 

Level {%) 

Pressure (psig) 

Level {%) 

Sulphur (%) 

Flare status 

Flow rate (Mscf/hr) 

Pressure (psig) 

Level {%) 

Off gas flow (?) 

Stripper pressure (psig) 

Flow rate (Mscf/hr) 

Level {%) 
P.9 

LIST OF ATTACHMENTS 

Trip Report for Murphy Oil, Meraux, La. 

1. Business Cards 

2. Operating Manual for Amine Gas Treating Unit (2/10/76) 

3. Amine Unit 

Schematic 

Amine and gas flow rates - design vs. actual 

H2S levels 

Sulfur material balance 

4. Emission Test Report by Air Resources, Inc. (8/31/81) 
P.10 

MURPHY 

0*1 COVCOBATIOB 

ALLDE N R. FREDERICKSON 

MANAGER 

CRUDE. PRODUCT & 

ENVIRONMENT CONTROL 

MERAUX REFINERY 

P. o. BOX too 

MERAUX. LOUISIANA 70073 

(304) 271.4141 

MURPHY 

OH COKPOBATIOft 

MAR K LACOU R 

PROCESS ENOINEER 

TECHNICAL SERVICES 

MERAUX REFINERY 

P. O. BOX 100 

MERAUX. LOUISIANA 70078 

(304) 271-4141 

MURPHY 

OH. CO«ftO*ATION 

DAVID C. PETTY 

SUPERVISOR 

ENVIRONMENTAL CONTROL 

MERAUX REFINERY 

P. O. BOX 100 

MERAUX. LOUISIANA 70073 

13041 271-4141 

MURPHY 

on uoaroa-MiOM 

R. LEE VAI L 

PROCESS ENOINEER 

P. O. BOX 100 

MERAUX. LOUISIANA 7007S 

(S04) 271.4141 
P.11 

) 'MURPHY 

OIL CORPORATION 

FROM: Mark LaCour 

TO: Mark Nclting 

INTER-OFFICE CORRESPONDENCE 

LOC.: Meraux . ,.• DATE: 11/21/8 4 

LOC.: Meraux CARBONS TO: DST , JTC , 

Area Foremen 

Allden 

SUBJECT: Fuel Gas Analysis to Heaters 

Below is a list of tutweilder results from 11/20/84 of fuel gas 

to various heaters. This data was taken with an average Sulphur 

production of 23 tons/day at a crude charge rate of 65,000 B/D; 

of which an estimated 1:3,000 B/D of Alaskan North Slope is being 

injected. 

Area II Combined Gas to Fuel Drum 

DHT Heater Fuel Gas 

Rose Heater Fuel Gas 

Vacuum Heater Fuel Gas 

Nebraska Fuel Gas (Boiler) 

Alky Reboiler Fuel Gas 

Area II Platformer Fuel Drum 

Grains/IOOSCF 

- 8 

8 

6 

? 

2 . 4 

10 

9 

f 

nn& JLjLCe^ 

Mark LaCour 

MLC:rj 

•m-
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Y~ 

MURPHY OIL COMPANY 

MERAUX REFINERY 

EMISSION TEST PROGRAM 

ON AUGUST 5, 1981 

PROJECT NO. 28 6-02 

AUGUST 31, 1981 

Prepared By: 

Air Resources, Inc. 

600 North First Bank Drive 

Palatine, IL 60067 

(312) 359-7810 
P.18 

I RltOUICIt 

) 

MURPHY OIL COMPANY 

MERAUX REFINERY 

1.0 INTRODUCTION AND "EXECUTIVE SUMMARY 

Air Resources, Inc. (ARI) was retained by Murphy Oil Company to 

conduct an emission test program at their Meraux Refinery located 

in Meraux, Louisiana. Testing was performed on August 5, 1981 for 

particulates on the exhaust stack from the No. 2 FCC Unit Electrostatic Precipitator (ESP) and for Hydrogen Sulfide on the fuel gas 

line from the Amine Unit leading to the Isostripper Reboiler on the 

Alkylation Unit. The purpose of the sampling was to determine compliance with 40 CFR Part 60, Subpart J, Standard of Performance for 

Petroleum Refineries. f 

Personnel conducting the testing on the ESP stack included Mr. L. 

Goldfine, General Manager, and Messrs. T. Wallace and D. Klarup, 

Environmental Scientists, for ARI's Environmental Sciences Division 

(EVS). Testing on the fuel gas line to the Isostripper Reboiler was 

conducted by Mr. J. Tuinenga, Supervisor-Laboratory Services for 

ARI's EVS. All field samples from both locations were placed in Mr. 

Tuinenga's custody for subsequent laboratory analysis by him. 

Sampling on the No. 2 FCC Unit Precipitator stack was conducted for 

particulates using a standard method 5 sampling system. Sampling 

was performed in the 10 foot ID stack at the sampling platform in 

four ports located 86 feet above grade. A schematic of the precipitator stack and the location of the sample ports is given in Figure 

1-1. The average particulate emission rate during the compliance 

tests was 11.15 lb/hr or 0.54 lb/1000 lb of coke burnoff based on an 

average coke burnoff rate of 20448 lb/hr (See Section 3.0 - Results 

for calculation of coke bur%off rates). This value is well within 

the allowable particulate emission rate of 20.45 lb/hr or 1.0 

lb/1000 lb of coke burnoff. A summary of the No. 2 FCC Unit test 

results is given in Table 1-1. 

Hydrogen Sulfide sampling was performed on the fuel gas line from 

the Amine Unit to the Isostripper Reboiler at the Alkylation Unit. 

A schematic of the fuel gas line and sampling location is given in 

Figure 1-2. The average H2S concentration for the seven runs was 

27.70 mg/dscm (0.012 gr/dscf). This value is well within the allowable concentration of 230 mg/dscm (0.10 gr/dscf). A summary of 

these results in given in Table 1-2. 

1-1 
- &*&im&<i»-> i jaiwatfafrtfaafittg^^ 

nt" 

/L-f/W 

AMINE 

FUEL GAS 

A35 0KBEK 

4 \ 

T 

<r' Ttf FLASH PXUM 

• 

6" FUBL GAS FROM 

GAS coA/c£//rxAr/0/v a/v/r 

FCC "z 

• *: 

7 

I 

0-frp/?c 

X SAM PL £ 

LOC A TION 

d 

FIGURE 1-2 

SCHEMATIC OF FUEL GAS LINE 

AND SAMPLE LOCATION 

FUEL QAS DRUM 

FUBL GAS 

FUEL GAS 

TO 

REF/A/EAiY 

TOHF TO FCC 
f ATABLE 1-2 

FUEL GAS LINE TO ISOSTRIPPER REBOILER 

HYDROGEN SULFIDE RESULTS 

Run 

1 

2 

3 

4 

5 

6 

7 

Sample 

Volume 

dscm 

0.037 

0.037 

0.033 

0.033 

0.032 

0.036 

0.036^ 

mg/dscm 

19.36 

33.08 

31.21 

26.54 

28.31 

28.15 

27.23 

Concentration 

gr/dscf 

0.008 

0.014 

0.014 

0.012 

0.012 

0.012 

0.012 

ppm 

15.88 

27*13 

25.59 

21.76 

23.21 

23.08 

22.33 

Average 27.70 0.012 22.71 
P.21 

I RllOUl 1 

Based on the size of the aliquot of the' digested sample, the 

total sulfate in the sample was calculated. This value along 

with the value allowed in Step 1, were then subtracted from the 

total weight gain previously determined in the standard 

particulate matter analysis. This. "Sulfate Free" value was then 

used to calculate a "sulfate free" emission rate for each test. 

2.3 Fuel Gas Line To Isostripper Reboiler Sampling and 

Analytical Procedures 

2.3.1 Hydrogen Sulfide Sampling Train 

The hydrogen sulfide sampling train used during the testing is 

shown schematically in Figure 2-2. The sampling and analytical 

methods follow Method 11 of the 40 CFR Part 60, Appendix A. The 

components are described below: 

1. Sampling Valve - Needle valve, stainless steel. 

2. Sample Line - 1/4 inch Teflon tubing. 

3. Impinger Train - Five glass mini impingers connected in 

series with ball joint fittings and glass connectors. 

All five impingers have standard tapered tips with . 

internal diameter of 1mm which is positioned 4 to 6mm 

from the bottom of the impinger bottle. xex. , -ri-r ^|*x? 

• ~ *' 7 •.;.*; -L 

4. Drying Tube - Polyethylene packed with 6 to 16 mesh 

silica gell.

 :' 

5. Rotameter - To monitor the gas flow rate during the^ 

sampling procedure. . -,7'7§.fs:T; '•'-£-.?'*' 

6. Dry Gas Meter - Leajc free, equipped with aothermom«t«r to 

measure actual temperature of gas within 3 C. A Hoffman 

Pinch clamp is used to seal off sampling train during tha 

required leak checks. 

7. Pump - Diaphragm pump, used during the air purge at the 

conclusion of each test run. 

2.3.2 Sampling Procedures 

Method 11 is used to determine the concentration of hydrogen 

sulfide in a fuel gas stream. No attempt is made to measure 

volume flow rates of the fuel gas and thus no flow rate in pounds 

per hour is calculated for H,S. Since it measures the concentration of a gas in a gas stream, it is not necessary to sample 

the gas stream isokinetically. 

2-6 

3fc. 
P.22 

f\!"""C1' 

Stl/CA tf£L ruae 

WALV& 

PUMP 

(FOR A/~ PUP<$£} 

FIGURE 2-2 

H2S SAMPLING TRAIN 
P.23 

f Af 

V f\J'ou*cis 

In the sample clean-up/analysis area, the impinger train was 

assembled as follows:

 /: 

15 milliliters (ml) of 3% H-O^, were placed in the first 

impinger. The second impinger was assembled dry. 15 ml of 

Cadmium Sulfate absorbing solution were placed in the third, 

fourth and fifth impingers. All of the connecting glassware 

was then assembled. The charcoal filter was attached to the 

inlet of the first impinger to protect the contents during 

transport to the sample site. A fresh portion (less than 

30g.) of silica gel was placed in the drying tube and the 

outlet tube sealed with a pinch clamp. 

The impinger train was then transported to the sample site where 

the exit end of the drying tube was connected to the inlet of the 

rotameter and the charcoal tube was replaced with the leak check 

apparatus. The sampling train was then leak checked as follows: 

1. 

2. 

The exit of the dry gas meter was closed, 

clamp after the drying tube was removed. 

The pinch 

Using the rubber squeeze bulb, the sampling train was 

pressurized to 25 cm (10 inches) of water, and then the 

pinch clamp on the leak check apparatus was closed. 

3. The pressure of the system was monitored, a drop in 

pressure of more than 1 cm (1/4") of water is 

unacceptable and would be semi-dried. 

4. Upon passing the leak check, the outlet of the dry gas 

meter was opened to relieve the pressure. 

Prior to sampling, the sample line was purged by opening the 

sampling valve and allowing fuel gas to flow thru the line. The 

valve is then closed and the sample line is connected to the 

inlet of the first impinger^ 

Sampling was accomplished as follows: 

The initial dry gas meter volume and temperature 

were recorded. 

The sampling valve was opened and a flow rate of 

1 liter per minute (1 1pm) was established and 

maintained to + 10%. 

Every two minutes, the dry gas meter volume and 

temperature were recorded. 

At the end of 10 minutes, or when at least 0.35 

dscf of fuel gas was sampled, the sampling valve 

was closed. The final dry gas meter volume and 

temperature were then recorded. 

sr 

2-7 
P.24 

f4? 

) 

Immediately following the sampling, the, sample line was removed 

from the first impinger and replaced with the leak check 

apparatus. A leak check as previously described was performed. 

Upon passing the leak check, the leak check apparatus was 

replaced by the charcoal tube, and the diaphragm pump was 

connected to the dry gas meter outlet. The sample train was then 

purged with charcoal filtered ambient air for at least 15 minutes 

at 1 1pm. The air purge was conducted on the sample 

cleanup/analysis area where the air pump could be used without 

creating an explosion hazard. 

A pinch clamp was then placed on the outlet of the drying tube, 

and the inlet to the rotometer was disconnected. The sampling 

train was then transported to the sample cleanup/analysis area. 

2.3.3 Sample Recovery and Analysis 

The recovery and analysis of the contents of the sample train 

were done immediately following the sampling. 

At the sample recovery/analysis area., the sample was handled as 

follows: 

1. The contents of the first and second impinger were 

discarded^ 

2. The contents of the third, fourth and fifth impingers 

were carefully rinsed into a 500 ml iodine flask using 

distilled water. Dow-Corning Anti-Foam B was used in the 

Cadmium Sulfate Absorbing Solution so the alternate acid 

extraction of the impinger was not necessary. 

3. 50.0 ml of 0.01 N Iodine was added to 10 ml of 3M HC1 in 

an Erlenmeyer Flask. This solution was then quantitatively rinsed into the iodine flask containing the sample. 

The iodine flask was stopped immediately, shaken for 10 

seconds, then placed in the dark for 30 minutes. 

4. The solution was quickly titrated using a 0.01 N solution 

of sodium thiosulfate with starch as an indicator of the 

endpoint. 

5. Blanks of the absorbing solution were also analyzed by 

placing 45 ml of the absorbing solution in an iodine 

flask, which was then carried thru the entire analysis 

procedure (steps 3 and 4). 

2-8 
P.25 

V4r 

MURPHY OIL COMPANY 

MERAUX REFINERY;. 

QRA »' QR E (dOO - (C02+02))/79) 

This value was then used to calculate the coke burnoff rate per 

40 CFR Part 60, Subpart J, Section 60.106(a)(4). A summary of the 

coke burnoff rates for the three tests is given in Table 3-6 and 

a copy of the process data is given in Appendix 4. 

3.2 Fuel Gas Line to the Isostripper Reboiler Results 

The results of the seven Hydrogen Sulfide (H2S) runs conducted on 

8/5/81 are given in Tables 3-7 to 3-13. The results indicate that 

the average hydrogen sulfide concentration measured during the test 

ing was 27.70 mg/dscm (0.012 gr/dscf). This compares to an allowable concentration of 230 mg/dscm (0.10 gr/dscf). All field data 

sheets are given in Appendix 3. All calibration data is given in 

Appendix 2. 

\ . 

3-2 
TABLE 3-7 

METHOD 11 - FIELD SAMPLING ANp.LABORATORY DATA 

DETERMINATION OF HYDROGEN SULFIDE IN FUEL GAS 

MURPHY OIL COMPANY 

RUN 1 

Volume at Dry Gas Meter Actual Conditions 

Dry Gas Meter Temperature 

1.35 Ft " 

554 

Standardizatio n of Thiosulfat e or Phenylarsin e Solution s 

Weight of K2C r 2 0 ? (W) 2.0070 g 2.0070 m i jnl 

Volume of Solutio n (V ) 42.35 ml 42.35 ml ml 

s 

Standardizatio n of Iodine Solution 

Volume of Iodin e (V.) 

l 

25.0 m l 25.0 ml 

Volume of Thio/Pheny (V ) 25.80 mi 25.80 ml 

ml 

ml 

Blank Titration 

Volume of Thio/Pheny 50.75 m i 50.75 ml ml 

Sample Titration 

Volume of Thio/Pheny 

46.35 46.35 

ml ml ml 
TABLE 3-7 (continued ) 

METHOD 11 CALCULATIONS 

DETERMINATION OF HYDROGEN SULFIDE IN FUEL GAS 

I hlitouicii 

MURPHY OIL COMPANY 

RUN 1 

Gas Sample Volume a t Standar d Condition s 

P. 

mstd = 17.64°R/inHg V Y TB~ 

m m m 

(30.13) 

= 17.64 ( 1.35M 1.00 ) ( 554 ) 1.295 ft" 

Normality of Standard Thiosulfate Solution (=0.1 N) 

N = 2.039 W/V 

s s 

(2.O39)(2.0q70) 

( 42.35 ) 0.0966 N 

Normality of Standard Thiosulfate Solution (=0.01 N) N =0.1xN =.00966 

Normality of Standard Phenylarsine Solution 

N = 0.2039 W/V 

a ' s 

(0.2039H ) 

= I 5 = Na 

Normality of Standard Iodine Solution 

N

i =

 N t Vv

i 

• ( 0.00966 )( 25. 8 ) " 

( 25. 0 ) ' 0.00997 N; 

Concentratio n o f H S 

Cu = 17.0 4 x 10 3[(V . N. - V N ) sampl e - (V. N.-V N )Blank] 

H S it- i tt— t ^ it~ l tt^t 

(V ^ ) (2.83 2 x 10 1 I /Ft" 3) 

mst d 

= 6.0169xl0 2 [( ( 50. 0 )( .00997)-( 46.3 5 ) (0.00966)) " . ( (50.0) f0.00997j; 

U n 70)10.00966)3 

( 1.29 5 > 

19.36 mg/dscm 
Mi. 

TABLE 3-8 

P.28 

n 1 

I J-^llOUICII I 

METHOD 11 - FIELD SAMPLING ANP LABORATORY DATA 

DETERMINATION OF HYDROGEN SULFIDE IN FUEL GAS 

MURPHY OIL COMPANY 

RUN 2 

Volume at Dry Gas Meter Actual Conditions 1.318 Ft" 

Dry Gas Meter Temperature 535 R 

Standardization of Thiosulfate or Phenylarsine Solutions 

Weight of K2Cr20_ (W) 2.0070 g 2.0070 mi 

Volume of Solution (V ) 42.35 m l 42.35 m l 

Standardization of Iodine Solution 

jnl 

ml 

Volume of Iodin e (V. ) 25.0 0 ml 25.00 m i m l 

l 

Volume of Thio/Pheny (V ) 25.80 ml 2 5.80 ml ml 

Blank Titration 

Volume of Thio/Pheny 50.75 m l 50.75 m l ml 

Sample Titration 

Volume of Thio/Pheny 43.30 m l 43.30 m l ml 
P.29 

TABLE 3-8 (continued) 

METHOD 11 CALCULATIONS 

DETERMINATION OF HYDROGEN SULFIDE IN FUEL GAS 

MURPHY OIL COMPANY 

RUN 2 

Gas Sample Volume at Standard Conditions 

O -^B -

V fc , = 17.64 R/inHg V Y T mstd ' ^ m m m 

( 30.13) 

= 17.6 4 (1.318) ( 1.00 ) ( 535 ) = 1-309 

f4r~ 

f t " 

Normality of Standard Thiosulfate Solution (=0.1 N) 

N = 2.039 W/V t 

. s s -

(2.O39)(2.0070 ) 

( 42.35 ) 0.0966 N 

Normality of Standard Thiosulfate Solution (=0.01 N) N =0.1xN =.00966 

Normality of Standard Phenylarsine Solution 

N = 0.2039 W/V 

a ' s 

(0.2039)( T T Na 

Normality of Standard Iodine Solution 

N

i =

 N t V V

i 

(0.00966 ) (25.80) 1 

( 25.0 0 ) 0.00997 N 

Concentration of H?S 

C„ ._ = 17.0 4 x 10 3[(V . N. H2S it-i -V N )sampl e - (V N -V. N )Blank ] —11—t

 c ! i t ~i—1 1 - t 

(V ^.,)(2.83 2 x 10 U /Ft 3) 

mst d 

= 6.0169xl0 2 [( ( 50.0 )(0.00997)-( 43.30 ) (0.00966)) -

( 1.309 ) 

.(( 50.0) (0.00997)-

( 50.75) (0.00966)] 

33.08 mg/dscm 

V * 
P.30 

TABLE 3-9 

METHOD 11 - FIELD SAMPLING AND LABORATORY DATA 

DETERMINATION OF HYDROGEN SULFIDE IN FUEL GAS 

MURPHY OIL COMPANY 

RUN 3 

Volume at Dry Gas Meter Actual Conditions 

1.183 

Ft" 

Dry Gas Meter Temperature 

540 

Standardization of Thiosulfate or Phenylarsine Solutions 

2.0070 g 2.0070 m_ jnl Weight of K2Cr20? (W) 

Volume of Solution (V ) 42.35 m l 42.35 m l m l 

s 

Standardization of. Iodine Solution 

Volume of Iodine (V.) 

l 

25.00 ml 25.00 ml 

Volume of Thio/Pheny (V ) 25.80 ml 2 5.80 ml 

ml 

ml 

Blank Titration 

Volume of Thio/Pheny 50.75 m l 50.75 . m l ml 

Sample Titration 

Volume of Thio/Pheny 

44.50 44.50 

ml ml ml 
P.31 

TABLE 3-9 (continued ) 

METHOD 11 CALCULATIONS 

DETERMINATION OF HYDROGEN SULFIDE IN FUEL GAS 

MURPHY OIL COMPANY 

RUN 3 

i 

Gas Sample Volume a t Standar d Condition s 

1

 P. 

i~4T 1 

I /-riiooicii 1 

mstd = 17.64°R/inHg V Y T 6 -

' ^ m m m 

( 30.15) 

= 17.64 (1.183M 1.00 ) ( 540 ) = 1.164 

Normality of Standard Thiosulfate Solution (=0.1 N) 

ft' 

N = 2.039 W/V

 :$ 

s s ••-• 

(2.O39)(2.0070 ) 

= ( 42.35 ) = 0.0966 N 

Normality of Standard Thiosulfate Solution (=0.01 N) N =0.1xN =.00966 

Normality of Standard Phenylarsine Solution 

N = 0.2039 W/V 

a s 

(0.2039H ) 

= I 5 = Na 

Normality of Standard Iodine Solution 

Nw . = N V /v. i

 1Nt t/ v i 

(0.00966 )( 25.80)1 

( 2 5.00 ) = 0.00997 N. 

- l 

Concentration of H2 S 

C„ ._ = 17.04 x 103[(V. ,N. - V N ) sample - (V N -V N )Blank] 

H2-S lt-l tt 1~ * it~i tt-t^

 i 

(V t J(2.83 2 x 10 U /Ft 3) ' mstd 

= 6.0169xl0 2 [( ( 50.0 )(0.00997)-( 44.50 ) (0.00966)) - ((50.0) (0.00997)-

. ( 50.75) (0.00966)] 

(1.164 ) 

31.2 1 _mg/dscm 

IU 
TABLE 3-10 

METHOD 11 - FIELD SAMPLING AND. LABORATORY DATA 

DETERMINATION OF HYDROGEN SULFIDE IN FUEL GAS 

MURPHY OIL COMPANY 

RUN 4 

Volume at Dry Gas Meter Actual Conditions i.168 Ft" 

Dry Gas Meter Temperature 540 

Standardization of Thiosulfate or Phenylarsine Solutions 

Weight of K Cr O (W) 2.0070 g 2.0070 m_ 

Volume of Solution (V ) 42.35 ml 42.35 ml 

Standardization of Iodine Solution 

-ml 

ml 

Volume of Iodine (V. ) 

l 

25.0 ml 25.0 ml 

Volume of Thio/Pheny (V ) 25.80 ml 25.80 ml 

ml 

ml 

Blank Titration 

Volume of Thio/Pheny 50.70 ml 50.70 m_ ml 

Sample Titration 

Volume, of Thio/Pheny 

45.45 45.45 

ml ml ml 
TABLE 3-10 (continued) 

METHOD 11 CALCULATIONS 

DETERMINATION OF HYDROGEN SULFIDE IN FUEL GAS 

-TA. 

I /VllOUtCM ] 

MURPHY OIL COMPANY 

RUN 4 

Gas Sample Volume a t Standar d Condition s 

P. 

mst d = 17.64°R/inH g V Y T&

3 ~ 

 m m m 

( 30.13) 

= 17.6 4 ( 1.168)( LOO ) ( 540 ) 1.150 f t " 

Normalit y of Standar d Thiosulfat e Solutio n (=0. 1 N) 

N = 2.03 9 W/V 7? 

s s 

(2.O39)(2.0070 ) 

( 42.3 5 ) 0.0966 N 

Normalit y o f Standar d Thiosulfat e Solutio n (=0.0 1 N) N =0.1xN =.0096 6 

J

 t s 

Normality of Standard Phenylarsine Solution 

N = 0.2039 W/V 

a s 

(0.2039M ) 

T T Na 

Normality of Standard Iodine Solution 

N

i =

 N t V v

i 

(0.00966 )( 25.80 ) ^ 

( 25.00 ) 0.0099 7 N 

Concentration of H_S 

:„ ,c = 17.04 x 103[(V. N. - V N ) sample - (V N -V. N )Blank] 

H S it-i tt—t

 c it~i tt~t ' 

(V _)( 2.832 x 10 1 I /Ft3) mstd 

= 6.0169xl02 [(( 50.0 )(0.00997)-( 45.45 ) (0.00966)) -.((50.0) (0.00997)-

( 50.70) (0.00966)] 

( 1.150 ) 

26.54 mg/dscm 
TABLE 3-11 

METHOD 11 - FIELD SAMPLING AND LABORATORY DATA 

DETERMINATION OF HYDROGEN SULFIDE IN FUEL GAS 

MURPHY OIL COMPANY 

RUN 5 

Volume at Dry Gas Meter Actual Conditions 1.137 Ft" 

Dry Gas Meter Temperature 

540 

Standardizatio n of Thiosulfat e or Phenylarsin e Solution s 

Weight of K2Cr20_ (W) 2.0070 g 2.0070 m l 

Volume of Solutio n (V ) 42.35 ml 42.35 m l 

Standardization of Iodine Solution 

-ml 

ml 

I 

1 

Volume of Iodine (V.) 

l 

25.00 m_ 25.00 m l 

Blank Titratio n 

Volume of Thio/Pheny 

Sample Titratio n 

Volume of Thio/Pheny 

50.70 

45.25 

ml 

ml 45.25 

Volume of Thio/Pheny (V ) 25.80 ml 25.80 ml 

50.70 m l 

ml 

_ml 

m l 

ml 

ml 
TABLE 3-11 (continued ) 

METHOD 11 CALCULATIONS 

P.35 

I hliioutcii I 

DETERMINATION OF HYDROGEN SULFIDE IN FUEL GAS 

MURPHY OIL COMPANY 

RUN 5 

i 

Gas Sample Volume a t Standar d Condition s 

o

 ! -^B -

V t . = 17.6 4 R/inHg V Y T mst d

 3 m m m 

( 30.13) 

= 17.6 4 (1-137) (1.00 ) ( 540 > 1.119 f t " 

Normality of Standard Thiosulfate Solution (=0.1 N) 

N = 2.039 W/V > 

s s Y 

(2.039)(?.nn7n ) 

= I 42.35 ) 0.0966 N 

Normality of Standard Thiosulfate Solution (=0.01 N) N =0.1xN =.00966 

Normality of Standard Phenylarsine Solution 

N = 0.2039 W/V 

a ' s 

(0.2039H ) 

= ( ) Na 

Normalit y of Standar d Iodin e Solutio n 

Nw . = N V /V. i

 w t t / v i 

(0.00966 )( 25.80% 

( 25.00 ) 

0.00997 Na 

Concentratio n of H2S 

C„ ._ =17.0 4 x 10 3[(V . N. - V N ) sample' - (V N -V. N )Blank ] 

H 2 S it- i tt— t

 c it-i—tt~ t 

(V «.)(2.83 2 x 10 1 I /Ft 3) mstd 

1 

I 

= 6.0169xl0 Z C(( 50.0 )(o.0099^" ( 45.25 )0.00966)) -.((50.0 ) (0.00997-

( 50.70) (0.00966)] 

( 1.119 ) 

28.3 1 mg/dscm 

&L. 
TABLE 3-12 

METHOD 11 - FIELD SAMPLING ANp .'LABORATORY DATA 

DETERMINATION OF HYDROGEN SULFIDE IN FUEL GAS 

MURPHY OIL COMPANY 

RUN 6 

Volume at Dry Gas Meter Actual Conditions 1-290 FtDry Gas Meter Temperature 540 

Standardization of Thiosulfate or Phenylarsine Solutions 

2.0070 g 2.0070 m l -ml Weight of K2Cr20? (W) 

Volume of Solution (V ) 42.35 m l 42.35 m l m l 

s 

Standardization of Iodine Solution 

Volume of Iodine (V.) 

l 

25.00 ml 25.00 ml 

Volume of Thio/Pheny (v ) 25.80 m l 25.80 ml 

ml 

ml 

Blank Titration 

Volume of Thio/Pheny 50.70 m l 50.70 

ml ml 

Sample Titration 

Volume of Thio/Pheny 44.55 m l

 44.55 ml ml 

IV 
TABLE 3-12 (continued) 

METHOD 11 CALCULATIONS 

f A- ] 

DETERMINATION OF HYDROGEN SULFIDE IN FUEL GAS 

MURPHY OIL COMPANY 

RUN 6 

Gas Sample Volume at Standard Conditions 

P. 

mstd = 17.64°R/inHg V Y T 

m m 

Bm 

( 30.13) 

= 17.64 (1.290) ( 1.00 ) ( 540 ) 1.270 ft" 

Normality of Standard Thiosulfate Solution (=0.1 N) 

N = 2.039 W/V * 

s s Y 

(2.O39)(2.0Q70 ) 

= ( 42.35 ) 0.0966 N 

Normality of Standard Thiosulfate Solution (=0.01 N) N =0.1xN =.00966 

J

 t s 

Normality of Standard Phenylarsine Solution 

N = 0.2039 W/V 

a s 

(0.2039H ) 

= ( 5 = Na 

Normality of Standard Iodine Solution 

N

i -

 N t V v

i 

-(0.00966) ( 25.80k 

( 25.00 ) -

0.00997 

N. 

Concentratio n of H-S 

'H. 

= 17.0 4 x 10 3[(V.,N . - V. . N, )sampl e - (V N -V N )Blank ] 

S lt - i tt— t * it~i—tt~t j ! 

(V .,)(2.83 2 x 10 1 I /Ft 3) mstd 

= 6.0169xl0 2 [( ( 50.0 ) (p. 00997) -( 44.55 ) (0.00966)) - ((50.0) (0.00997) 

( 1.270 ) 

( 50.70) (0.00966) S; ] 

28.1 5 mg/dscm 
TABLE 3-1 3 

I f\J>ovtcu I 

METHOD 11 - FIELD SAMPLING AND LABORATORY DATA 

DETERMINATION OF HYDROGEN SULFIDE IN FUEL GAS 

MURPHY OIL COMPANY 

RUN .7 

Volume at Dry Gas Meter Actual Conditions 1.290 Ft" 

Dry Gas Meter Temperature 540 R 

Standardization of Thiosulfate or Phenylarsine Solutions 

2.0070 2.0070 jnl Weight of K Cr 0? (W) 

Volume of Solution (V ) 42.35 m l 42.35 m l 

s 

-ml 

ml 

Standardization of Iodine Solution 

Volume of Iodine (V.) 

l 

Volume of Thio/Pheny (V ) 

25.00 m l 25.00 m l 

25.80 m l 25.80 m l 

_ml 

ml 

Blank Titration 

Volume of Thio/Pheny 150.7 0 m l

 50.7 0 m l ml 

Sample Titration 

Volume of Thio/Pheny 

44.75 . 44.75 , 

ml ml ml 
TABLE 3-13 (continued) 

METHOD 11 CALCULATIONS 

DETERMINATION OF HYDROGEN SULFIDE IN FUEL GAS 

-TA. 

MURPHY OIL COMPANY 

RUN 7 

Gas Sample Volume a t Standar d Condition s 

V ^„ = 17.6 4 R/inHg V Y T mstd

 3 m m m 

(30.13 ) 

= 17.6 4 (1.290)(1.00 ) ( 5 4 0 ) 1.270 

Normality of Standard Thiosulfate Solution (=0.1 N) 

ft" 

J 

N = 2.039 W/V 

• s s 

(2.O39M2.0070 ) 

= ( 42.35 ) 

0.0966 

N 

Normality of Standard Thiosulfate Solution (=0.01 N) N =0.1xN =.00966 

Normality of Standard Phenylarsine Solution 

N = 0.2039. W/V 

a x* s 

(0.2039M 

T T Na 

Normality of Standard Iodine Solution 

N

i =

 N t V v

i 

(0.00966) ( 25.80) 

( 25.00 ) 

0.00997 

-

Ni 

Concentration of H_S 

:„ c =17.04 x 10J[(V. N. - V N )sample - (V N -V. N )Blank] 

H S it-i tt—t ^ ^ it~i—tt-t' 

(V .. ) (2.832 x 10 U /Ft 3) mstd 

ji 

= 6.0169xlOZ [((50. 0 )(0.00997)-( 44.75 ) (0.00966)) -.((50.0 ) (0,00997)-

( 50.70) (0.00966)] 

(1.270 ) 

27.23 mg/dscm