p.1 

OAR Box 1784 

Prepped by Ollie Stewart 

Document Number: 

45) ll-B-4 

Docket Number: 

A-84-44 

Printed 10/31/2008 8:05:40 AM Sheet 45 of 143 
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"vm--.--.- ^ ^_UK^T|avSTATES ENVIRONMENTAL f ROTEOTJON^EM^ 

4-84-4 + 

0 1 FEB 1985 

MEMORANDUM 

SUBJECT: Trip Report - Shell Oil Company, Norco, Louisiana (ESED #83/03) 

FROM: Nancy D. McLaughlin, Environmental Engineer 

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

TO: 

I . PURPOSE 

Kenneth R. Durkee, Chief 

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

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

amine treater s and to discuss Shell Oil' s experience with the refinery 

fuel gas npw source performance standard (NSPS). 

I I . TIME AND PLACE: 

1:00 to 4:30 

November 27, 1984 

Shell Oil Company 

Norco, Louisiana 

III. ATTENDEES: 

U.S. Environmental Protection Agency 

Nancy D. McLaughlin 

Charles B. Sedman 

Debbie K. Wells 

Shell Oil Company 

William L. Caughman 

Dennis V. Knudson 

Jim Pfaff 

James Fox 

Freddy Babineaux 

Bill Green 

Larry Scherinski 

Environmental Engineer 

Environmental Engineer 

Environmental Protection Specialist 

Manager, Environmental Conservation 

Sr. Engineer, Environmental Conservation 

Process control and instrumentation 

Technical support 

Facilities operations 

Sulfur plant 

Continuous monitoring instruments 

CONCURRENCES 

SYMBOL \ 

SURNAME \ 

DATE \ 

£?><>/1 $6 

'Tf! ^4*M*L 

2v?Bf 

EPA Form 1320-1 (l'2-70) OFFICIAL FILE COPY 

GPO : 1983 O - 403-201 
P.3 

IV. DISCUSSION: 

Schedule of Activities 

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

1:30 p.m. We first met-with a group of refinery personnel for about 2 

hours to discuss the operation, reliability, and performance of their 

newer amine treater and their experiences with the refinery fuel gas 

NSPS. We then observed the amine treating and sulfur recovery areas of 

the refinery, including the operator control room for those areas. We 

left the refinery around 4:30 p.m. 

General Refinery Information and Background 

Shell's refinery in Norco, Louisiana, is an older, large, fully-integrated 

refinery. The refinery.was started in 1920 and over the years has undergone 

a n'.tmber of. expansions and modifications. The nominal size of the refinery 

is 220,000 barrels of crude per day. The refinery generally uses lower 

sulfur "sweet" crude with an average sulfur content of about 0.2 percent. 

Around 1980, Shell expanded by constructing a new ethylene plant. 

Because many new conthustion devices were part of this expansion, Shell also 

had to construct a new amine treating unit and sulfur plant in order to 

comply with the NSPS for refinery fuel gas. Shell designed the new amine 

treating unit specifically to treat the amount of flow of sour fuel gas 

that would he directed to all new combustion sources. The amine treater was 

also designed to control the hydrogen sulfide (H2S) safely below the NSPS 

level of 16U ppmv. 

Amine Treating Unit 

Sh<=>ll provided us with schematic diagrams of the fuel gas/amine treating 

system end of tho fuel gas treater with process instrumentation, (see 

attached figures 1 end 2) . 

The new amine treating system was installed in 1980 because of the 

new process heaters that were in the new ethylene plant. Shell would not 

have added a new amine treating unit in the absence of the NSPS. They do 

.not feel that the corrosion problems caused by N2S in fuel gas are significant 

enough to warrant control. Also, the value of the sulfur recovered does not 

pay for the cost of running the sulfur recovery system (amine treater, Claus 

plant, and tail gas treater). In contrast, in 1965 Shell had installed an 

amine treating/sulfur recovery unit because of the value of the sulfur. 

However, Mr. Caughman noted that the cost of the older system has now more 

than doubled due to the requirement for a tail-gas treater. The current 

sulfur recovery scheme includes two Claus sulfur plants and tail gas 

treaters rated at 40 LT/D (1965) and 125 LT/D (1982). 
P.4 

The new amine treating system uses diethanolamine (DEA). The fuel gas 

treater was designed by Shell and constructed by Standard Tool. (The second 

sulfur recovery plant and tall gas treater had to be added 1n conjunction 

with the new DEA unit.) There have been no modifications to the fuel gas 

treater since it was installed, and it is performing as expected. The 

fuel gas treater was designed for an inlet fuel gas stream of 28 MM scf/day 

and an amine circulation rate of 300 gallons/minute. It 1s currently 

operated at lower levels, 20 MM scf/day and 200 gallons/minute. 

The DEA system is composed of one stripper and 10 absorbers. The main, 

large absorber is the new fuel gas treater which was constructed to treat 

the fuel gas to NSPS combustion sources. The 9 older, smaller absorbers 

are located in various process units; they also treat fuel gas but were not 

necessarily designed to meet the NSPS levels. 

The inlet fuel gas to the new fuel gas treater is at 75 psig and less 

than 100°F. The composition of the inlet fuel gas varies from day-to-day. 

Shell does" not routinely monitor or test the composition of the inlet stream. 

For samples taken last month, the inlet stream had 4% HpS by weight and 

0.05 percent mercaptans by weight. The outlet stream was 0.01 percent H^S by 

weight and 0.03 percent mercaptans by weight. 

There have been no major operating problems with the fuel gas treater. 

Entrained liquids in the incoming gas are removed to a larg° extent by 

a small knock-out pot; however, entrained liquids still cause occasional 

problems. To keep down particle contamination in the DEA system, cotton 

fiber filters s.re used. 

To monitor the performance of the amine treater, Shell monitors the 

outlet H2S concentration and the ratio of le3n DEA circulation rate to the 

flow of fuel gas. They try to maintain this ratio at 10 gallons of DEA per 

minute to 1,000,000 scf/day of fuel gas. Shell analyzes the amine as 

necessary. The fuel gas treater is run so that the outlet H2S concentration 

is about 100 to 150 ppmv, slightly below the NSPS level. 

If the outlet H?S concentration goes up, this indicates to the systems/ 

Claus plant operator that the treater is not operating properly, or that 

there has been a change in some upstream process unit. The operator checks 

with the other process units to determine if there has been a production 

change, and adjusts the circulation rate and stripper steam accordingly. 

Shell is not currently considering changing to another amine. 

Combustion Sources 

Shell's Norco refinery has 19 new combustion sources subject to the NSPS 

for refinery fuel gas. Fourteen of these sources were part of the new 

ethylene plant. Shell is also now constructing another combustion source 

which will be subject to NSPS; (the unit ID is F-164). 
P.5 

Shell currently has about 78 operating combustion devices in the Norco 

refinery: 23 ethylene cracking furnaces, 10 boilers, 9 flares, 2 SCOT 

incinerators, 1 CO heater, and about 33 process heaters. 

Fuel Gas System and Natural Gas Blending 

Shell provided us with a general schematic of their fuel gas system, with 

amine treaters, NSPS combustion sources, and other gas streams noted (see 

Figure 1). To provide accepted levels of HgS in fuel gas to the NSPS 

combustion sources, Shell selected its fuel gas streams of highest H2S 

concentration to treat. These streams are treated in the new fuel gas treater. 

The treated fuel gas is then blended with natural gas and untreated and partially 

treated waste gas (relatively H2S free) in a fuel gas blend drum. This 

mixed stream is then routed to the NSPS combustion sources. Some additional 

sweet waste gas is also added later for the ethylene plant process heaters. 

Shell provided us with the approximate volumes of each gas that is routinely 

used in the system. However, these are only general values because the 

amounts that are used vary so much from day to day. 

. Fuels in Fuel Gas System Volume 

Ireated fuel gas 8 to 20 MM scf/day 

Untreated and'partially 40 to 50 MM scf/day 

treated waste gas 

Natural gas 0 to 50 m scf/day 

Emission Testing 

Shell proviripH us with copies of reports of two performance tests that 

had r>een conducts on their fuel gas to new combustion sources. The tests 

were both conducted by Southwest Laboratories and were done on November 4, 1981, 

and January 26, 19r>4. The cost, of the recent 1984 test was S3200, and Southwest 

had informed Sb?ll that a similar test today would cost $3500. Shell noted that 

there is an additional .expense to She'll for the time of Shell's staff that is 

involved in the testing. 

Shell was easily in compliance for both tests, with H2S concentrations 

at 27.5 percent and 38.8 percent of the allowable limit. The sampling 

sites for the two performance tests are noted on the schematic in Figure 1. 

Both sampling sites were after natural gas had been blended, but the 

amount of natural gas being used at the time of the test is not known. 

Emission Monitoring and Excess Emissions 

To monitor the performance of the operation of the new fuel gas treater 

system, Shell has two Tracor-Atlas monitors which continuously monitor 

the H£S concentration. (Shell has a DuPont UV SO2 monitor on the Claus 

tail-gas treater effluent stream). One monitor is located immediately 

after the fuel gas treater. This monitor reflects how well the treater 
P.6 

i s working. The second monitor i s located after the fuel gas blend drum 

after the blending of the treated fuel gas, untreated fuel gas, and 

natural gas. This instrument monitors the fuel gas going to al l the new 

combustion sources and i s used to monitor compliance. The location of 

these continuous emission monitors (CEMS) i s noted on the amine treater/fue l 

gas schematic in Figure 1 . The output from these monitors i s sent directl y 

to Shell's central computer, sc the data can be easily reduced. The 

monitors also have an alarm that i s set at 150 ppmv so that the operators 

wil l be alerted when they are nearing an excess emission. 

Shell has a very intense and sophisticated system for CEMS operation and 

maintenance, including Shell' s internal qualit y assurance specifications . 

Shell considers the monitors a very costly , high-maintenance item, and 

estimates that i t requires 10* of one person's time to keep the monitors 

running properly. This i s much more time than the vendor estimates. Shell 

has an internal requirement on al l it s CEM's of 97% uptime. 

Shell's maintenance and quality assurance schedule for the HgS CEM's 

consists of daily visibl e checks, and weekly-span checks at 80% of scale 

(.300 ppmv). They also occasionally check the monitors with a lower concentratio n gas. They have not had any serious drif t problems. Shell' s policy 

i s to select a monitor that could run for 30 days unattended and then tend to 

i t every day. I f an operator suspects a problem with the CE.M's values, Draeger 

tube samples are. taken. This occurs about 3 or 4 times a month. The CEM's 

values generally compare well with Draeger tube results . 

Shell provided us with their estimated excess emission record for the past 

year. 

Time Period % time in compliance with NSPS 

30 ly23 9773 

4Q 19S3 90.2 

IQ 1984 94.8 

20 1984 93.8 

I t i s important to note that i f the analyzer is not working, Shell treats i t 

lik e a violation . Thus, there are some "violations " that sre reall y due to 

monitor downtime. 

Shell complained about EPA Region 6's interpretation of an excess 

emission period. Shell, on previous occasion, has been instructed by 

Region 6 to report every 3-hour rollin g average period when reporting NSPS 

violations . Shell feels they should only have to report discreet 3-hour 

periods or tota l periods of non-compliance and they feel i t i s an extra 

burden to reduce the data into the other format. Shell estimated that i t 

takes 8 hours per month to prepare the excess emission report i f there 

have been excursions above the standard. 
P.7 

Shell did not have their monitoring results readily available in NSPS 

report format because they are required only to report excess emissions 

as defined by State regulations. Routine operating monitoring values are 

available. Generally, the concentration of H2S in the stream after the 

blending drum ranges from 125 to 160 ppmv. 

The prime purpose of the monitors was for NSPS compliance purposes. 

However, they are being relied on heavily as an indicator of the amine 

treater's performance. Shell has no plans to integrate the monitors 

into an automatic process control system. 

Cost of Complying with the NSPS 

Shell personnel did not have a complete breakdown of the costs that they 

incur to comply with this NSPS. The major component, of course, is the 

capital, operating, and labor costs of the amine treater system and its 

associated sulfur recovery unit. The direct costs of emission testing, 

were noted previously, as were the maintenance and reporting costs for 

monitoring. (Capital costs for the monitors could be obtained from the vendor.) 

Comments or Problems with the NSPS 

Shell was generally satisfied with the level of the NSPS (160 ppmv) 

and felt that it was technologically feasible to meet that .level consistently. 

As mentioned previously, Shell did not like the EPA Region 6's interpretation 

of the requirements for monitoring excess emission reports. Shell's main 

complaint concerned the definition of the affected facility in the NSPS. 

Since any new combustion source is considered an affected facility, a large, 

existing refinery, such as Shell, must install an amine treater for control 

for a small reconstruction compared with the size of the refinery. Shell 

suggested that the size of the modification or reconstruction be compared 

to^the size of the refinery (50%) to determine if it would be affected by 

the NSPS. 

V. SUWARY: 

Shell's Norco refinery is representative of a large, older refinery 

that has been gradually upgraded and become subject to the NSPS. The 

plant visit was very informative for us, and Shell personnel were very 

helpful. Shell provided us with copies of two emission test reports and 

two schematic diagrams. They indicated that the information provided and 

the topics discussed were not considered to be proprietary. 

6 Attachments 

cc: C. Sedman, ISB 

D. Wells, SDB 

ESED/ISB/SDS NDMcLaughlin/cbaker/bjoverman x5595 Rm. 752 MU (MD-13) 

File: AIP 8.1.15.2 Project: 83/03 Disk: McLaughlin 1 Retyped 1/31/85 chbaker 
P.8 

LIST OF ATTACHMENTS 

Trip Report for Shell Oil Company, Norco, LA 

1. Business cards 

2. Figure 1 - Schematic of fuel gas/amine treating system 

3. Figure 2 - Schematic of fuel gas treater with process Instrumentation 

4. Emission test report - 11/4/81 

5. Emission test report - 1/26/84 

6. Brochure about Shell's Norco manufacturing complex. 
P.9 

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P.11 

SHELL OIL COMPANY 

Norco, Louisiana 

SWL Project No: 54-907 

INTRODUCTION 

Field sampling fur hydrogen sulfide at the OL-5 Pyrolysis Furnace Fuel 

Gas Line of SHELL OIL COMPANY'S Norco, Louisiana facility, was conducted 

November 4, 1981 by personnel of Southwestern Laboratories' Environmental 

Engineering Services Division. Present during the sampling period were 

Mr. Dan O'Connor and staff of SHELL OIL COMPANY, Mr. Robert A. Ressl of 

Pedco Environmental, Inc. (the E.P.A. representative) and Messrs. John R. 

Smith (Senior Field Supervisor) and C. Mark Tipton (Environmental Technician) of Southwestern Laboratories, Inc. 

• Sampling was conducted to determine the hydrogen sulfide content 

within the .source, in order to provide data required by the U.S. Environmental Protection Agency's (E.P.A.) "Standards of Performance for New 

Stationary Sources", Subpart J, as contained in 40 CFR 60 and Permit No. 

.PSD-LA-8. 

RESULTS 

Results of each sample, calculated in accordance with E.P.A. procedures, are- shown in "Summary of Sampling Results" (Figure No. 2) and are 

summarized below:• 

Run 

No. 

1 

2 

3 

Average H2S 

Concentration 

41.1 mg/uson 

190.1 mg/dson 

36.4 mg/dscm 

Allowable H2S 

Concentration 

230 mg/dscm 

230 mg/dscm 

230 mg/dscm 

% c 

Allov 

17 

£2 

15 

>f 

.•able 

9% 

1% 

8% 

•CUTM»XI1E« N LUBOIiTOBlt l 
P.12 

SHELL OIL COMPANY S M Project No: 54-907 

The average H2S concentration for all three runs was 89.2 mg/dscm, or 

38.8% of the stated allowable concentration of 230 mg/dscm. 

PROCEDURE 

Sampling equipment and procedures were in conformity, e.xcept where 

noted, with Reference Method 11 of the Environmental Protection Agency 

(as contained in Appendix A, Reference Methods of the New Source Performance Standards of the E.P.A.). 

Determination of Hydrogen Sulfide Content - Fuel Gas Streams - Method 11: 

A sampling train similar to the one described in E.P.A. Method 11 (as 

contained in 40 CFR 60, Appendix A) , was used to collect the samples. 

Impinger.1 contained 15 ml of 3% H-XL, Impinger 2 was dry, Impingers 3, 4 

and 5 each contained 15 ml of pH3 cadmium sulfate solution, and Impinger 

6 contained silica gel. 

Six samples were obtained, with the arithmetic average of two samples 

of equal sampling time constituting one run. The fuel gas line pressure 

was sufficient to operate the train, therefor a vacuum pump was not necessary to obtain samples from the line. (See Figure No. 3 for schematic of 

sampling train.) Each sample was 11 minutes in duration, averaging approximately 18. 5. liters of duct gas. Each sample was conducted at an 

approximate sampling rate of 1.68 liters/min. At the conclusion of each 

sample, the train was purged with ambient air for 15 minutes to ensure 

that all the H-S was removed from the peroxide impinger. 

lOUTHXCITCD N LABOB.VTORIE * 
P.13 _ 

SHELL OIL COMPANY SWL Project No: 54-907 

Prior to and following each sample run, leak checks of the sampling 

system were performed. Upon completion of each sample run, the samples 

were carried immediately to the analytical site . 

D. SAMPLE RECOVERY 

In accordance with prescribed techniques, hydrogen sulfide determinations were made on site using sodium thiosulfate solution as a titrant. 

.Analytical data sheets and calculations are included with this report, 

and are summarized in "Summary of Sampling Results", Figure No. 2. 

E. CUSTODY OF SAMPLES 

After completion of tests, each sample was placed in the custody of 

the technician responsible for analysis. It was his assigned responsibilit y to insure that each sample was recorded and correctly analyzed. 

Analysis of samples was performed in lab facilitie s at the jobsite by 

Environmental Engineering Services personnel. It was the duty of the 

Senior Field Supervisor to answer any procedural queries from the Environmental Technician. 

F . QUALITY ASSUPANCE 

Southwestern Laboratories, Inc. maintains a strict Quality Assurance 

program. Included in the program where applicable are: equipment calibration checks such as the Meter Box Gamma check, performed after each 

field used; barometer and thermometer calibration checks; balance calibration checks; analytical calibration checks; and calculation checks. 

SOUTMWESTCH N LABORATORIE S 

-3- I •• 
P.14 

SHELL OIL COMPANY SWL Project No: 54-907 

Also included in SWL's Quality .\ssurancc program is its participation in 

the E.P.A. Inter-Laboratory Source Survey for Methods 5, 6 and 7. 

G. DISCUSSION 

Sampling was delayed due to a plant upset the morning of November 4, 

1981. Due to the inaccessability of the mid-point probe in the fuel gas 

line (approximately forty feet in elevation), i t was agreed to obtain 

samples from a 1/4-inch stainless stee l tubing lin e used to connect the 

fuel gas lin e to a specifi c gravity analyzer. Samples were drawn downstream of the swirl filte r of the specific gravity analyzer. Prior to 

conducting tests, the E.P.A. Region 6 office was notified and approved 

of the sample location. 

H. SIB-MARY 

Sampling was conducted only during stable plant operations. 

The average H2S concentration for the three sample runs was 89.2 

mg/dscm. This represents 38.8% of the stated allowable concentration of 

230 mg/dscm. 

W^tP/ 

.?&' 

SOU 1MKESTER N LABORATORIE S 

-4-
P.15 

SHELL OIL COMPANY 

Norco, Louisiana 

SWL Project No. 54-1189B 

A. INTRODUCTION 

Field sampling for hydrogen sulfide at the Blend Drum 

Fuel Gas Line of SHELL OIL COMP.ANY' s Norco, Louisiana 

facility, was conducted January 26, 1984 by personnel of 

Southwestern Laboratories' Environmental Engineering 

Services Division. Present during the sampling period were 

Mr. Ken McAuliffe and staff of SHELL OIL COMPANY, and 

Messrs. Russell J. DiRaimo (Project Engineer) and John R. 

Smith (Senior Environmental Technician) of Southwestern 

Laboratories, Inc. 

Sampling was conducted to determine the hydrogen 

sulfide content within the source, in order to provide data 

required by; the U.S. Environmental Protection Agency 

(E.P.A.) "Standards of Performance for New Stationary 

Sources", Subpart J, as contained in 40 CFR 60, and the 

applicable State of Louisiana • Environmental Control 

Commission regulations (Permit No. 1669T). 

lOUTHWE 5 T ER N LABORATORIE S 

- 1 -
T 

3 

] 

P.16 

SHELL OIL COMPANY SWL Project No. 54-1189B 

B. RESULTS 

Results of each sample, calculated in accordance with 

E.P.A. procedures, are shown in "Summary of Sampling 

Results" (Figure No. 2) and are summarized below: 

Run 

No. 

1 

2 

3 

Average H2S 

Concentration 

65.8 mg/dscm 

61.6 mg/dscm 

62.5 mg/dscm 

Allowable H2S 

Concentration 

230 mg/dscm 

230 mg/dscm 

230 mg/dscm 

% of 

Allowabl e 

28 

26. 

27 

6% 

8% 

2% 

The average H_S concentration for all three runs was 

63.3 mg/dscm, or 27.5% of the stated . allowable 

concentration of 230 mg/dscm. 

C. PROCEDURE 

Sampling equipment and procedures were in conformity, 

except where noted, with Reference Method 11 of the 

Environmental -Protection Agency (as contained in Appendix 

A, Reference Methods of the New Source Performance 

Standards of the E.P.A.). 

•SOUTHWESTER N U * BOR*TO B t £ S 

- 2 -
P.17 

SHELL OIL COMPANY SWL Project No. 54-1189B 

Determination of Hydrogen Sulfide Content - Fuel Gas 

Streams - Method 11: 

A sampling train similar to the one described in E.P.A. 

Method 11 (as contained in 40 CFR 60, Appendix A), was used 

to collect the samples. Impinger 1 contained 15 ml of 3% 

H_0_, Impinger 2 was dry, Impingers 3, 4 and 5 each 

contained 15 ml of pH3 cadmium sulfate solution, and 

Impinger 6 contained silica gel. 

Six samples were obtained, with the arithmetic average 

of two samples of equal sampling time constituting one run. 

The .fuel gas line pressure was sufficient to operate the 

train, therefore a vacuum pump was not necessary to obtain 

samples from the line. (See Figure No. 3 for schematic of 

sampling train). Each sample was 11 minutes in duration, 

averaging approximately 12.8 liters of duct gas. Each 

sample was conducted at an approximate sampling rate of 1.16 

liters/min. At the conclusion of each sample, the train was 

purged with ambient air for 15 minutes to ensure that all i 

the H»S was removed from the peroxide impinger. 

Prior to and following each sample run, leak checks of 

the sampling system were performed. Upon completion of each 

sample run, the sample were carried immediately to the 

analytical site. 

• SO U THV i EIT E R N LABORATORIE S 

- 3 -
P.18 

SHELL OIL COMPANY SWL Project No. 54-1189B 

S.AMPLE' RECOVERY 

In accordance with prescribed techniques, hydrogen 

sulfide determinations were made on site using sodium 

thiosulfate solution as a titrant. Analytical data sheets 

and calculations are included with this report, and are 

summarized in "Summary of Sampling Results", Figure No. 2. 

CUSTODY OF SAMPLES 

After completion of tests, each sample was placed in 

the custody of the field crew member responsible for 

analysis. It was his assigned responsibility to insure that 

each sample was recorded and correctly analyzed. Analysis 

of samples was performed in lab facilities at the jobsite by 

Environmental Engineering Services personnel. It was the 

duty of the Project Supervisor to answer any procedural 

queries from the Environmental Technician. 

QUALITY ASSURANCE 

Southwestern Laboratories, Inc. maintains a strict 

Quality Assurance program. Included in the program where 

applicable are: equipment calibration checks such as the 

Meter Box Gamma check, performed after each field use; 

barometer and thermometer calibration checks; balance 

calibration checks; analytical calibration checks; and 

calculation checks. Also included in SWL's Quality 

• SOUTHWESTERN : LABORATORIE S 

- 4 -
P.19 

SHELL OIL COMPANY SWL Project No. 54-1189B 

Assurance program is its participation in the E.P.A. InterLaboratory Source Survey for Methods 5, 8 and 7. 

DISCUSSION 

Sampling was conducted January 26, 1984 during normal 

plant operations. All sampling and analyses were conducted 

in accordance with E.P.A. regulations. 

H. SUMMARY 

Sampling was conducted only during stable plant 

operations. 

The average H_S concentration for the three sample 

runs was 63.3 mg/dscm. This represents 27.5% of the stated 

allowable concentration of 230 -mg/dscm. 

•SOUTHWESTER N LABORATORIE S 

- 5 -