p.1 

OAR Box 1124 

Prepped by Ollie Stewart 

Document Number: 

64) ll-D-5 

Docket Number: 

A-84-44 

Printed 4/16/2008 8:13:22 AM Sheet 64 of 70 
(conoco) 

P.2 

North American Refining Conoco Inc. 

P.O. Box 37 

Westlake. LA 70669 

(318) 491-5211 

April 1, 1985 

CERTIFIED MAIL - RETURN RECEIPT REQUESTED (P 243 177 372) 

Dtt-kf 

A-84-44 

Mr. John R. Farmer 

Director 

Enission Standards and Engineering Division 

U. S. Environmental Protection Agency 

Office of Air Quality Planning and Standards 

Research Triangle Park, North Carolina 27711 

Dear Mr. Farmer: 

Attached is Conoco's response to the Fuel Gas KSPS Questionnaire. We were 

glad to be of assistance in this natter. If you have any questions or 

conments, please contact Mr. Rick McCalip at the refinery at (318) 491-5599. 

Sincerely, 

Manager 

Lake Charles Refinery 

MES/sww 

Att. 
P.3 

INFORMATION NEEDS FOR REVIEWING ' 

THE REFINERY FUEL GAS KSPS 

Listed below is the information we are seeking for the facilities subject to 

the new source performance standard (NSPS) for refinery fuel gas. 

I. INTRODUCTION 

The affected facility for the NSPS is any new, modified, or reconstructed refinery combustion device that burns fuel gas, such as flares, 

boilers, and process heaters. The primary control device is a preprocessing 

unit (usually an amine treater) that removes the H^S from the fuel gas 

before it is combusted. Secondary controls are then needed to process the 

more concentrated H_S stream that exits from the amine treater; these 

secondary controls may be sulfuric acid plants, thiosulfate plants, Claus 

sulfur plants, etc. These secondary controls, in turn, have emissions that 

require treatment, such as tail-gas units. Less conventional one-step 

systems (such as LO-CAT, Stretford, Stauffer, etc.) may also be used, and 

may be preferred by smaller refineries. As an alternative, refineries are 

allowed to blend the refinery fuel gas with natural gas to dilute the H„S 

concentration or use add-on controls such as flue gas desulfurization (FGD) 

units. 

In order to conduct a comprehensive review of the NSPS and to understand the effects of the current regulation, we need to investigate the 

entire system that deals with fuel gas (combustion devices, primary controls, and secondary controls), and the costs, credits, and emission reductions of each part. Although the affected facility is a combustion 

device,.our main focus will be on the primary control device (amine treaters 

or others), particularly current designs, chemicals, technical capabilities, 

and costs. We are also focusing on alternative monitoring approaches for 

emission compliance determinations. 

II. FACILITY DESCRIPTION 

Please provide a general description and schematic of the refinery fuel 

gas system, combustion devices, and sulfur treatment processes, (such as 

amine treaters, sulfur plants, tail gas units). Include gas flow rates 

(untreated fuel gas, treated fuel gas, and natural gas), K_S concentrations, 

and sulfur mass balances. Note on the diagram where gas blending is done 

and where process monitoring and emission monitoring samples.are taken. 

Drawing No. LC-55-00-8A-42.2T-B is a schematic of the refinery's fuel gas 

system. Fuel gas produced in various refinery processes is collected in-one 

of two fuel gas knock-out drums. The fuel gas sent to these drums.is either 

free of hydrogen sulfide (H-S) by nature of the process it is coming from, 

or has had the H-S removed in one of the refinery's fuel gas/amine absorbers. 

The low pressure system receives off-gas fron the refinery's hydrogen 

purification plant. It supplies fuel gas only to the Kc.2 Coker heaters, 

H-3001 and. H-3002, the pilot for the north flare, and the six heaters in the 

No.3 Reformer/Hydrodesulfurizer Units. If more fuel gas is required by 

these heaters than can be supplied by the purification plant, gas from the 

high pressure system makes up the difference. 
P.4 

The high pressure system receives fuel gases from all other producers in the 

refinery. It supplies fuel gas to all heaters in the plant not served by 

the low pressure system including the Nos. 6 and 7 Hydrodesulfurizer heaters, H-3101 and H-3201, and the Thermal Cracker heater, H-14. When demand 

exceeds supply, the difference is made up with purchased natural gas. 

The refinery has both modified and new combustion devices in operation which 

must meet the NSPS. Table I lists these devices and process flow diagrams 

are included detailing each. The refinery's sulfur treatment includes 

primary amine treating, two sulfur recovery unit trains with tail gas units, 

and a sulfuric acid plant. Process flow diagrams are included for each. 

Compositions for some streams in the Sulfur Recovery Unit are given in Table 

X, following the drawings. 

III. COSTS 

1. We would like separate capital and operating costs of your primary 

emission control systems (amine treater, FGD, or other processing unit). 

The costs requested are for the entire control systen, but we are also 

interested in the costs associated with the additional absorption capacity 

required for treating the fuel gas that is routed to new combustion sources. 

Please provide a breakdown (or factor) for just the fuel gas treatment, if 

possible. 

The total capital investment for the primary amine treatment system through 

December 31, 1984, was $14238798.12. 

2. Please provide the following cost information. Index costs to 

year and month. 

a. Purchase cost (explain what is included). 

1. Breakdown by major equipment item (i.e., vessel) 

2. Cost of initial chemical inventory. 

The capital investment for major equipment items is shown in Table I. 

The cost of the initial chemical inventory was not available. 

b. Installation cost (explain what is included) 

1. Breakdown by direct and indirect costs. 

2. Note specific costs attributable to retrofitting a new or 

expanded amine treater into an existing system. 

The installation costs were not available. 

c. Annual operating costs. 

1. Labor costs (Does this include overhead?) Note labor hours, 

and $/hour rate". 

2. Materials 

a. Replacement parts 

b. Chemicals (# of gallons; $/gallon) 

3. Steam (cost, amount, pressure, and temperature) 

4. Electricity ' 

5. Water 

6. Other utilities and fuel costs 

7.. Credits for value of sulfur in the off-gas to the sulfur 

plant. 
P.5 

SEE TABLES II AND III, 

IV. REFINERY COMBUSTION DEVICES 

1. How many combustion sources that burn refinery fuel gas are there 

at your refinery (flares, boilers, process heaters, incinerators, others) 

Flares - 2 

Boilers - 5 

Process Heaters - 25 

2. For each general type of combustion device that burns refinery 

fuel gas, please provide the following information (for a typical example 

and ranges): 

a. Size - capacity, BTU rating, fuel consumption 

b. Costs - capital and operating 

c. Hours of operation, days per year, (continuous or periodic 

operation) 

d. Other fuels used, and in what proportion 

A. 

B. 

C. 

See Tables IV & V 

See Table VI for Capital Costs. 

See Table VII for Operating Costs of Units including the 

specified combustion devices. Operating costs for each 

combustion device alone are not available. 

The refinery operates 24 hours/day, 7 days/week, 52 

weeks/year. Normal operation for combustion devices is on 

this same continuous schedule unless otherwise specified. 

D. Other fuels in addition to refinery fuel gas are used by B-5, 

B-6, and B-7. In 1984, B-5 and B-6 used 27% purchased 

natural gas. B-7 used 158.4 MTon of green coke. 

3. Please list and describe any new, modified, reconstructed combustion devices you have that are subject to the NSPS, and the dates of 

installation. For these affected combustion devices, describe how you 

complied with the NSPS and the resulting decrease in H„S concentration. 

Estimate, if possible, the incremental cost of compliance and the resulting 

S02 emission reduction. 

SEE TABLE VI 

a. Existing H_S level was acceptable (e.g., used existing amine 

treater or sweet crude). 

NO 

Added new amine treater or other preprocessing unit, 

YES, added new amine treater. 

c. Upgraded an existing amine treater. Describe how (increased 

capacity, increased flow rate, added trays, changed chemicals) . 

YES, upgraded an existing amine treater. 
P.6 

Changes to increase amine treater capacity were not just due to NSPS. But 

rather, they were necessary when the refinery changed to a sour crude feed 

stream. With this process change made it would be difficult, if possible, 

to estimate the incremental cost of compliance and the resulting S0_ emission reduction due to NSPS. 

d. Added a flue gas desulfurization (FGD) unit at outlet of the 

combustion source. 

NO 

e*. Replumbed and rerouted various fuel gas lines so cleaner gas 

was routed to NSPS combustion sources. 

NO 

f. Blended with natural gas. 

NO, this was not a change made. The refinery alone 

purchases natural gas for the purpose of meeting refinery 

fuel demand when it is not met by refinery fuel gas. 

4. Without the NSPS, what level of H„S and other sulfur compounds in 

fuel gas would be acceptable before there would be significant adverse 

corrosion pf combustion equipment? 

The level of sulfur compounds acceptable depends on the metallurgy and flue 

gas temperature. Acceptable loading of the refinery system would be between 

0.5% and 1.0%. 

5. What other Federal, State, and local environmental regulations 

apply to these combustion devices, and how did that affect your design 

considerations and decisions to replace or upgrade existing devices? 

H-3001, H0-3002, H-3101, H-3201, and H-3804 are PSD for NO , 

requiring low NO burners and 0. control. Other design parameters were 2$% 

opacity, 2000 ppm SO in stack gas, and 0.6 lb PM/10 BTU heat input. When 

designs are specified to meet NSPS, there is no problem meeting any other 

requirements. There are problems meeting NO limits on coker furnaces due to 

their cyclical duty. ~ 

V. PRIMARY CONTROL (AMINE TREATERS) 

1. What are the characteristics and composition of the fuel gas that 

is expected at the inlet to the amine treater and that is desired at the 

outlet prior to combustion (typical and range)? 

a. Flow rate 

b. 

SEE TABLE VIII 

Heating value 

Current Typical Value 990 3TU/ft , 

After cyrogen'ic unit on stream 880 BTU/ft 
P.7 

c. Temperature and pressure 

SEE TABLE IX 

d. Acid gas composition (H-S, CO., other sulfur compounds) 

Acid Gas to Sulfur Recovery Unit 

Component Percent by Vol. 

H,S 92.81 

CO- 1.65 

HC^ .95 

H20 4.58 
P.8 

2. Amine treater description (If the refinery has more than one amine 

treater system, describe only the systems that provide fuel gas to combustion sources subject to the NSPS.) 

a. General schematic, including flow rates and sulfur material 

balance. 

SEE DRAWING SD-2720-42-98-L 

Manufacturer or vendor (include licensor and engineering 

firm) 

SEE TABLE IX 

Start-up date 

SEE TABLE IX 

Design capacity and range 

SEE TABLE VIII 

Hours of operation, hours/year 

24 hours/day, 7 days/week, 52 weeks/year 

f. Number of vessels in system (strippers and absorbers) 

Note the relative gas flow rates and amine circulation rates 

for fuel gas treatment vs. other gas treatment. 

8 absorbers (5 fuel gas, 3 propane-butane) 

2 strippers 

SEE TABLE VIII for gas flow rates and amine circulation 

rates. 

g. Total amine inventory in system 

20000 gal. 

Estimated from volume of D-3502, Amine Surge .-

For each absorber, design and actual operating levels 

1. Gas flow rate 

2. Gas pressure and temperature 

3. Amine circulation rate and temperature 

SEE TABLE VIII Design rate is given as maximum and actual 

operating rate is given as normal. 

SEE TABLE IX for temperatures and pressures. Also see 

Drawing No. SD-2720-42-98-L. 

i. For each stripper, design and actual operating levels. 

1. Amine circulation rate and temperature 

2. Steam usage 
P.9 

W-3501, W-3551 

Design 

Amine Circulation Rate 500 gpm 

Temperature (Top) 110°F 

Duty 36.88 MMBTU/hr. 

50 psig Steam 

Also see Drawing Nos. SD-2720-42-98-L and LC-91-00-82-42.1A-D. 

j. Type of amine used. 

UCARSOL MDEA 

k. Other important design or operational criteria. 

Not available. 

3. What type of system would have been installed if the NSPS had not 

been in effect? List the differences from the present system. 

The system would have been very similar. The Tail Gas Unit may 

not have been economically justifiable. 

4. A complete maintenance history of the amine treating system is 

requested, or at a minimum, a narrative of the major outages and most 

frequent maintenance items that have occurred since start-up. In discussing 

these problems or outages, please indicate the excess emissions that occurred and the corrective action taken. 

a. Degradation or loss of amine, (provide loss rate vs. baseline 

inventory) . v 

b. Foaming 

c. Contamination of amine 

d. Corrosion of vessels and piping 

e. Other 

The loss rate of amine is 200,000 lb/month. 

Foaming at the contactors is a problem. Some of the causes of foaming are 

known, heavy hydrocarbon from GRP, solids (Fe SO,). However, the total 

cause is yet to be identified. 

Contamination of amine is not a big problem because a significant amount of 

amine is lost and replaced by fresh amine each month. 

Corrosion occurs in an amine system when the maximun allowable concentrations of MDEA and sulfides are exceeded. In general, Conoco's system has 

high loadings. However, these are not high enough to account for the 

corrosion rates seen. A testing program is being run to analyze for impurities in the system which may be a source of the corrosion. When the 

corrosion problen is solved, foaning should decrease in all contactors and 

the use of antifoam will be minimal. 

The most frequent maintenance item is changing filters. The carbon filters 

are changed every six months due to iron sulfide plugging from corrosion. 

Cartridge filters are changed out about 3 times a month. 
P.10 

Several refiners have experienced increased filter problems (solids in amine 

system), extreme carryover or both when Ucarsol was introduced into their 

amine systems. We have not determined whether or not Ucarsol is a major 

source of our problems. 

Installation of larger knock-out drums is planned because of amine carryover 

from the contactors. 

5. Are the maintenance requirements and amine replacement rates more 

excessive than that indicated by the vendor? 

YES, the biggest maintenance item is changing filters. 

6. What was the reliability of the amine treater system on an annual 

basis for each year since start-up, (amount of scheduled and unscheduled 

downtime)? 

There have been no unscheduled downtimes since modification of the 

system in 1983. 

W-13 was chemically cleaned during a scheduled downtime. 

7. What are the inspection practices and schedules for the amine 

treater system, and what types of personnel perform these inspections? 

Inspections are conducted by refinery personnel or by Conoco 

Engineering Department personnel. The amine treaters are inspected with their respective units every 2-3 years. The amine regenerators are inspected annually. Corrosion probes are read monthly. 

8. What are the process operating parameters that are monitored or 

tested to determine if the amine treater is performing properly, (for 

example: amine samples, outlet concentration)? 

Samples are taken. Sulfide concentration in lean and rich is 

measured daily. Foaming is monitored. 

9. What amine treater operating parameters are set by operators to 

adjust for varying conditions and inlet loadings so that a "low H_S concentration can be maintained at the outlet? 

The circulation rate is kept at a maximum, as is the rich amine 

strength, to keep loadings at an acceptable level. By running all 

the lean amine through, the sulfide's in lean amine are"^kept at 500 

ppm. 

VI. SECONDARY CONTROL (SULFUR PLANT, ETC.) 

1. How is the more concentrated H-S stream exiting the amine treater 

handled (sulfuric acid plant, Claus Sulfur plant with tail gas treater, 

thiosulfate plant, sold to another firm)? Briefly describe this secondary 

control system, including design size, vendor, year installed, and sulfur 

mass balances. Was this secondary control system installed separately or as 

part of a package with the amine treater? 
P.11 

The refinery's secondary control includes two,Claus sulfur plant 

trains with tail gas treatment and a sulfuric acid plant. 

Claus Sulfur Plant 

Train 1 - 108 LTPD (expansion to 190 planned) 

Train 2 - 108 LTPD (expansion to 190 near completion) 

Vendor - Ralph M. Parsons 

Installed In 1983 

Part of Amine Treater package 

See Drawings LC-91-00-82-42.1A-D and LC-91-00-82-42.2A-D. 

2. If the tail gas unit uses amine scrubbing, does it now (or are you 

considering) combining the tail gas and fuel gas amine stripping? What are 

the advantages and disadvantages of this approach? 

The refinery is not considering combining the tail gas and fuel 

gas amine stripping. The fuel gas is presently scrubbed at 180 

psi, whereas the tail gas is scrubbed at 2 psi. It would not be 

practical to combine operations presently at such different 

pressures. 

Each unit has advantages and disadvantages. Tail gas treating has 

the potential of heat stable salts which are less probable in fuel 

gas treating. On the other hand, chlorides and ammonia cause 

problems with fuel gas treating. 

VII. EMISSION TESTING 

1. . Please provide a full copy of all emission tests performed on fuel 

gas from your amine treaters. 

No emission tests have been performed at the amine treaters. 

2. Please provide a brief summary of any emission tests that have 

been performed at the outlet of combustion devices which burn fuel gas. 

Describe the combustion devices tested. In addition tp the types of information listed above, we are interested in a summary of the emission data for 

any other pollutants/compounds (SO-, total sulfur, NO CO, hydrocarbons, 

etc.) 

On May 14, 1981, Conoco Inc. performed the required EPA testing of 

the fuel gas used in furnaces H-1101, H-1102, H-l20'l, and H-1301. 

The sampling point is shown in the attached Drawing No. 

LC-55-00-81-42.1F-A. 

The result of this investigation was that the level of H-S in the 

fuel gas, 55.2 mg/m , was well within the maximum allowable level 

of 230 mg/m . This result was based on a test series of 3 sets 

with 2 runs per set. 

Isokinetic sampling rates were not applicable because the fuel gas 

contained no liquid or solid particles. 

The designed firing duty of furnaces H-1101 and H-1102 were 265.4 

MMBTU/HR. During the testing, 71% of the designed duty was used. 

Furnaces H-1201 and H-1301 were designed for a firing duty of 28.5 

and 29.4 MMBTU/HR respectively. The operating rates the day of 
P.12 

ii. 

the tests were 3% and 4% of the designed duty, 

no way affected the H-S level In the fuel gas. 

These low rates in 

On May 11, 1983, Conoco Inc. conducted a H-S Fuel Gas Test to 

determine compliance of the fuel gas to the new heaters H-26, 

H-46, and H-1201. The sampling point is shown in the attached 

Drawing No. LC-55-00-83-42.1B-A. 

The average concentration of H^S found in the test, a series of 

three sets of two runs each, was 40 mg H-S/m of fuel gas. This 

is well within the maximum allowable concentration of 230 mg/m . 

The design duties of H-26, H-46, and H-1201 were 60.0, 117.0, and 

33.0 MMBTU/HR respectively. THe corresponding operating rates the 

day of the test were 74.5, 97.6, and 16.6 % of capacity. 

conducted a H-S in Fuel Gas Test 

to determine compliance of the low pressure fuel gas system. The 

iii. On November 2, 1983, Conoco Inc 

to determine compliance of 

average concentration of H found in the test series of 3 sets of 

2 runs each was 27 mg H-S/m of fuel gas. 

On November 3, 1983, Conoco Inc. conducted a H-S in Fuel gas Test 

to determine compliance of the high pressure fuel gas system. The 

average concentration of H„S found in the test series of 3 sets of 

2 runs each was 29 mg H-S/m of fuel gas. 

Drawing No. LC-55-00-84-42.2T-B is a schematic of the refinery's 

fuel gas system. The sampling points for November 2 and 3 are 

indicated. 

3. Are there any State or local regulations that require testing of 

fuel gas for existing sources, or that require additional testing for new 

sources beyond that required by the NSPS? 

VIII. 

Yes, but the State must request the testing and has not. 

MONITORING OF EMISSIONS AND PROCESS OPERATION 

1, Discussion: 

The present regulation requires a continuous H_S monitor on the fuel 

gas line at the inlet to a combustion device affected by the NSPS. Combustion devices having a common source of fuel gas may be monitored at one 

location instead of each combustion device having a separate monitor. 

Excess emission reports are required whenever the average H-S concentration 

for 3 hours exceeds the standard. However,, continuous H-S monitors are not 

yet required because EPA has not promulgated performance specifications. 

As part of this review project, EPA is investigating alternative monitoring 

approaches which may be reliable indicators of performance but not as costly 

as continuous H-S monitors. We are seeking information about the type of 

monitoring you conduct (if any) and the usefulness of the monitoring results, costs, and problems. Monitoring can be divided into two categories: 

direct emission monitoring of H-S concentration; and indirect emission 

monitoring by monitoring of process parameters. 

Please describe any State or local regulations that require you to 

monitor. 

None 10 
P.13 

3. Emission monitoring of H-S concentration in the fuel gas: 

a. How do you monitor the H-S concentration of the fuel gas, 

(continuous instruments, periodic grab samples)? Do you monitor more than 

one location, (immediately after treating, after blending, or before combustion)? Do you monitor primarily to demonstrate compliance with the NSPS, 

or for your own purposes to ensure that the amine treater is operating 

properly? 

H-S concentration is monitored by periodic grab samples. Samples 

are taken after treating at W-13 and W-67 and after blending in 

the fuel gas system. There are plans to install a continuous 

monitor for the fuel as system sample. 

The monitoring is done primarily to ensure safe operation. **-

b. If manual sampling is done, describe the procedure and costs. 

What is the scheduled frequency of sampling? Describe problems that you 

have had with this procedure and the accuracy of the measurements. 

Drager tubes are used to sample W-13 and W-67 once per day and the 

fuel gas system once per shift. Drager tubes are accurate to ±20%. 

Sampling is done by refinery personnel as a part of the unit 

operating cost. This sampling can be a safety problem when H-S in 

fuel gas is high. 

c. If instrument emission monitors are used, provide the following: 

Instrument monitors are not presently used. 

4. Monitoring of process parameters: 

a. What process parameters are monitored? How is the monitoring 

done(instruments or manual sampling)? What is the scheduled sampling 

frequency? How much does it cost to conduct this monitoring? 

Level, Flow, Temperature, and Pressure are monitored continuously 

by instruments. Amine strength is monitored daily by grab sample. 

Monitoring is done by refinery personnel as a part of the unit 

operating cost. 

b. Which process parameters are good indicators of the proper 

performance of the amine treater and of low H-S concentrations at "the 

outlet? How well. do the process parameters correlate with --H-S concentrations? 

The amine-hydrogen sulfide ratio is monitored and controlled. 

5. Are there plans to replace or purchase new monitors, and if so, 

vhy and with what type? 

No 

11 
6. Are any of the instrument monitors integrated into the process as 

a control system? 

Yes 

IX. GENERAL REFINERY INFORMATION (RELATED TO AMINE TREATERS AND FUEL GAS) 

1. What is the nominal size of your refinery and current operating 

level (barrels of crude/day)? What is the operating schedule? What refinery operating parameters affect the sizing and operation of your amine 

treaters? 

The nominal size of the refinery is 164 MBPSD or 156 MBPCD. 

In 1984, the refinery operated at 117400 BBLS/day. The refinery 

operates 24 hr/day, 7 days/week, 52 weeks/year. Crude feed rate 

and sulfur content affect the sizing and operation of the amine 

treaters. 

2. What Is the sulfur content of the crude oil (typical and range)? 

How does the crude oil sulfur content affect the operation of amine treaters 

and the level of H-S and other sulfur compounds in the fuel gas? 

No.2 Crude Unit - Sweet Crude 

No.3 Crude Unit - Sour Crude 

Sulfur 

Typical 

.35% 

2.5% 

Content 

Range 

.15-

2-

.7% 

3% 

Thirty percent of all sulfur recovered comes from the fuel gas 

contactors. As the crude sulfur increases, loading in the fuel 

gas increases. 

3. How do other refinery operating factors (such as desulfurization 

of products) affect the sizing, operation, and cost of your amine treating 

system? 

Increased desulfurization demands increased circulation from the 

amine treaters, thus increasing pumping costs. More steam is 

needed for regeneration. There are more problems In general 

because of the stress on the system. 

4. How much natural gas (if any) is blended with th'e, refinery fuel 

gas prior to combustion (typical and range)? Is this blending done primarily to keep a constant flow of gas to process units or to dilute the H2S 

concentration to an acceptable level? 

X. 

Natural gas is blended with refinery fuel gas when necessary, to 

keep a constant flow of gas to process units. Natural gas is sent 

to the steam plant first and then any additional needed is blended 

with the refinery fuel gas. 

GENERAL REGULATORY INFORMATION 

1. What problems have you experienced in interpreting the NSPS, 

achieving the NSPS, and operating the control systems to comply with the 

NSPS? 

No problems have been identified in interpreting and achieving the 

NSPS. 

12 
P.15 

2. What problems or difficulties, if any, have'you experienced in 

performing testing, monitoring, and recordkeeping for the NSPS? Do you have 

any suggestions (please provide rationale) for alleviating these problems, 

including alternative approaches of achieving the same objective? 

Due to the complexity of the refinery's fuel gas system, opening 

fuel gas lines for grab samples can present a safety problem. 

There are plans to install a continuous monitor for the fuel gas 

system sample. 

3. How much does it cost you to comply with the NSPS regulation for 

recordkeeping and reporting? Please provide a copy of the forms you routinely have to fill out and a sample of a report. 

This cost is a part of the operating overhead and is not recorded 

separately. 

Forms and a sample of a report are attached. 

XI. CONTACTS FOR FURTHER INFORMATION 

Rick McCalip - Senior Technologist 

Mark Sternberg - Process Engineer 

Melody Yozzo - Environmental Technologist 

(318)491-5599 

(318) 491-5208 

(405) 767-5234 

13 
•w 

• 

a * 

ITEM 

D-68 

D-69 

D-1602 

D-1601 

D-1603 

D-1604 

D-1605 

D-3501 

D-3502 

D-3503 

D-3551 

D-3553 

T-3525 

T-3528 

T-1602 

W-13 

W-14 

W-63 

w 

COST 

11019.89 

11019.89 

1183.94 

12203.83 

' 52347.48 

204.89 

151.00 

52703.37 

204.88 

1034.36 

63392.10 

65163.73 

151.00 

763.00 

130709.07 

65180.99 

65180.99 

42262.25 

43443.37 

85705.62 

223976.49 

230549.68 

40188.84 

223976.49 

2332.00 

226306.49 

40188.84 

4358.88 

26153.26 

3129.64 

3217.11 

17435.51 

23782.26 

36543.51 

75915.61 

847322.45 

959781.57 

173282.25 

12686.35 

10728.58 

5700.00 

29114.93 

TABLE I 

P 16 

I 

AMINE UNIT CAPITAL INVESTMENT 

MAJOR EQUIPMENT 

PURCHASE DATE 

7/53 

7/53 

7/84 

12/80 

8/81 

8/81 

8/81 

8/81 

12/80 

8/81 

8/81 

8/81 

12/80 

12/80 

12/80 

8/81 

5/83 

5/83 

5/83 

5/83 

2/84 

5/83 

5/83 

5/83 

12/80 

8/81 

5/83 

6/41 

12/80 

9/83 

12/80 

9/56 

3/80 

12/73 

DESCRIPTION 

Feed Surge Drum 

Knockout Drum 

Alarm 

Drum 

New Line 

New Line 

New Line 

Permanent Connections 

Drum 

Drum 

New Line 

Permanent Connections 

Drum ! 

Drum > 

Drum 

Drum 

Low Pressure Flash Drum | 

Lean Amine Surge Drum 

Oil Separator 

Low Pressure Flash Drum 

Spare Relief Valve 

Oil Separator 

Anti-foam Makeup Tank 

Oil Supply Tank 

Caustic Tank 

i 

*~. 

Partial Stabilizer Tower 

Modifications 

Furnace Feed Stripper Tower 

Tower ; 

Modification 

Trays 
P.17 

W-1601 

W-1602 

W-1602 

223179.64 

308993.94 

269505.18 

218354.93 

2470.02 

8111.00 

277037.11 

224457.35 

102967.21 

1635076.38 

257548.86 

356577.57 

614126.43 

257548.86 

356577.57 

614126.43 

12/80 

12/80 

12/80 

12/80 

12/80 

12/80 

8/81 

8/81 

9/83 

12/80 

12/80 

12/80 

12/80 

Low Pressure Absorber 

2 New Trays 

Low Pressure Absorber 

Low Pressure Absorber 

W-3501 

W-3551 

813601.83 

813601.83 

5/83 

5/83 

Amine Regenerator 

Amine Regenerator 

X-1607 92891.50 

128608.83 

221500.33 

12/80 

12/80 

Exchanger 

Exchanger 

X-1601 49275.65 

50652.77 

99928.42 

12/80 

8/81 

Exchanger 

Exchanger 

X-1602 49275.65 

50652.77 

X-1605 

X-3501 

X-3502 

X-3503 

X-3504 

X-3505 

X-3507 

X-3508 

X-3510 

X-3511 

X-3551 

X-3552 

X-3553 

X-3554 

X-3555 

X-3557 

X-3558 

99928.42 

77267.18 

95367.23 

98032.48 

79426.59 

350093.48 

159020.52 

159020.52 

159020.52 

217246.39 

217246.39 

122235.97 

122235.57 

125230.51 

125230.51 

159020.52 

159020.52 

159020.52 

217246.39 

217246.39 

122235.97 

122235.97 

12/80 

8/81 

12/80 

12/80 

8/81 

8/81 

5/83 

5/83 

5/83 

5/83 

5/83 

5/83 

5/83 

5/83 

5/83 

5/83 

5/83 

5/83 

5/83 

5/83 

5/83 

5/83 

Exchanger 

Exchanger 

Exchanger 

Lean Rich Amine Exchanger 

Lean Ricb Amine Exchanger 

Lean Rich Amine Exchanger 

Regenerator Reboiler 

Regenerator Reboiler 

Regenerator Pumparound 

Regenerator-Pumparound. 

Lean Amine Trim Cooler 

Lean Amine Trim Cooler 

Lean Rich Amine Exchanger 

Lean Rich Amine Exchanger 

Lean Rich Amine Exchanger 

Regenerator Reboiler 

Regenerator Reboiler 

Regenerator Pumparound 

Regenerator Pumparound 
P.18 

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P.19 

TABLE III 

AMINE UNIT OPERATING COSTS 1984 

No. Amine 

Labor Costs 

Contract Costs 

Op. Materials 

Maint. Materials 

Process Supplies 

Total 

53897 

27984 

140 

3687 

13430 

$99137 

Process Supplies 

Nitrogen $13430/13096 cu. ft. 

No.2 Amine 

Labor Costs 

Contract Costs 

Op. Material 

Maint. Materials 

Process Supplies 

Tota 

88015 

25285 

10737 

8345 

13430 

$245812 

Process Supplies 

Diethanolamine 0 this year 

Nitrogen $13430/13096 cu. ft. 

No.3 Amine 

Labor Costs 

Contract Costs 

Op. Materials 

Maint. Materials 

Process Supplies 

Electricity-Clearance 

Steam 

Water 

Total 

136970 

27008 

102184 

21311 

2249173 

19484/564000 KWH 

1387883/307361 MMBTU 

55108/27710 GAL. 

$3999120 

Process Supplies 

NITROGEN $13430/13096 cu. ft. 

CHEMLINK IPC 5120 $1275/920 cu.ft. 

Activated Carbon $2162/1800 lb. 

Ceramic Balls $1411/2070 lb. 

UCARSOL MDEA $2211154/1472300 lb.) 

TRETT0-LITE K437 $19741/2559 GAL 
TABLE IV 

P.20 

COMBUSTION DEVICE 

H-6, FCC 

H-9, Heating Oil Belt(H-10 Spare) 

H-ll, No.l Reformer 

H-l2, No.l Reformer 

H-13, No.l Reformer 

H-18, Premium Coker 

H-21, No.2 Reformer 

H-22, No.2 Reformer 

H-23, No.2 Reformer 

H-24, Naphtha Desulfurizer 

B-5, High Pressure Boiler 

B-6, High Pressure Boiler 

B-7, Calciner Waste Heat Boiler 

ST-4, Flare and Blowdown 

H-1101, Crude Unit Heater 

H-1102, Vacuum Unit Heater 

H-1301, Gas Oil Desulfurizer Heater 

H-26, Coker Heater 

H-2801, Sulfuric Acid Air Heater 

H-3101, CD HDS Heater 

H-3201, HVGO HDS Heater 

H-3001, Coker Heater 

H-3002, Coker Heater 

H-3801,2,3,4ABC, No.3 Reformer 

H-14, Thermal Cracker 

H-46, (H-4&H-5), No.2 Crude Topping Unit 

H-1201, Distillate Desulfurizer Heater 

St-3, Flare 

H-3951, No.8 HDS 

BTU RATING 

MMBTU/HR. 

67.0 

55.0 

29.0 

29.0 

17.0 

96.0 

' 69.0 

50.0 

23.0 

38.0 

178.0 

178.0 

50.0 

250.0 

37.0 

33.0 

60.0 " 

5.0 

16.0 

15.0 

9.7 

99.0 

99.0 

247.0 

107.0 

117.0 

•- 33.0 

CAPACITY #/HR. 

(OPERATING) 

128000 

37500 

BPSD 

148596 Op. A 

165655 Op. B 

208997 

208997 

208997 

108000 Steam Out 

108000 Steam Out 

946730 

529940 

246210 Gas Oil 

& Recycle H 

221985 

227470 

371868 

320320 

320320 

136227 

345756 

219166 

515683 

205668 

514083 

342490 Distillate 

& Recycle H12.5 
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age 2 

r 

Li-3101, 

tl-3201, 

'1-3001, 

-1-3002, 

1-3801, 

CD HDS Heater 15068 

HVGO HDS Heater10035 

Coker Heater 

Coker Heater 

2,3,4ABC, No.3 

Reformer 

[-14, Thermal Cracker 

[-46, (H-4&H-5), No.2 

Crude 

1-1201, 

Topping Unit 

Distillate 

Desulfurizer Heater 

IT-3, Flare 

s 1-3951, No.8 HDS 

87214 

78696 

143183 

0 

104857 

17693 

18000 

14839 

94335 

89624 

163127 

0 

120160 

23731 

32842 

17352 

84472 

75865 

137122 

0 

106505 

22230 

35840 

15143 

67634 

62180 

86859 

0 

68642 

18147 

42265 

17327 

96437 

91460 

128545 

0 

117131 

24582 

40853 

24004 

81875 

76972 

129189 

0 

99553. 

22783 

27597 

12879 

45850 

42069 

50578 

472068 

73610 

13083 

17104 

9848 

27596 

26423 

53494 

681188 

47516 

10552 

16794 

12128 

50372 

51150 

'•:•'. 

'80331 

347789 

93437 

12626 

Surge Drum 

2136 

5750 

33445 

27154 

58908 

482027 

60651 

11454 

/ 

522 

3434 

22910 

24200 

53184 

20632 

579278 

7117 

85 

1196 

13248 

12665 

71606 

0 

342438 

11359 

PILOT 

249106 

143935 

705388 

658458 

1156126 

2003704 

1813778 

195357 

100SCFH 
P.23 

Combustion Device 

H-6, FCC 

H-10, Heating Oil Belt (Spare) 

H-ll, No.l Reformer 

H-l2, No.l Reformer 

H-13, No.l Rformer 

H-18, Premium Coker 

H-21, No.2 Reformer 

H-22, No.2 Reformer 

H-23, No.2 Reformer 

H-24, Naphtha Desulfurizer 

ST-4, Flare and Blowdown 

H-1101, Crude Unit Heater 

H-1102, Vacuum Unit Heater 

Hr1301, Gas Oil Desulfurizer Heater 

H-26, Coker Heater 

H-2801, ST-2801, Sulfuric Acid 

Air Heater and Stack 

H-3101, CD HDS Heater 

H-3201, HVGO.HDS Heater 

H-3001, Coker Heater 

H-3002, Coker Heater 

H-3801,2,3,4ABC, No.3 Reformer 

H-14, Thermal Cracker 

H-46, No.2 Crude Topping Unit 

H-1201, Distillate Desulfurizer Heater 

ST-3, Flare 

H-3951, No.8 HDS 

TABLE VI 

Installation 

Date 

1953 

1953 

1953 

1953 

1953 

1957 

1959 

1959 

1959 

1971 

1981 

1980 

1980 

1980 

1982 

1980 

1983 

1983 

1983 

1983 

1983 

1982 

1983 

: 1983 

1981 

1985 

Total Capital Invested 

(through December 31, 1984) 

189750.14 

185798.38 

69913.00 

89876.23 

104608.92 

505329.81 

139459.86 

105011.00 

58240.00 

159579.59 

845178.24 

6990096.07 

1476970.28 

1341280.49 

3058971.47 

830841.01 

750519.93 

480621.54 

5072213.48 

5072213.48 

5658043.14 

1884135.74 

674689.34 

696497.48 
P.24 

TABLE VII 

Unit 

No.2 Crude Topping 

thermal Cracking 

No.l Fluid Catalytic Cracking 

No.l Coker 

Gas Oil Heating Belt 

No.l Calciner & Coke Loading 

No.l HDS Naphtha 

No.2 HDS Naphtha 

No.2 Reformer 

No.3 Crude Topping 

No.4 HDS Distillate 

No.5 HDS-Gas Oil 

No.3 Vaccum Unit 

Steam Plant 

No.3 HDS Naphtha 

No.3 Cat Reformer 

No.6 HDS Cracked Distillate 

No.2 Coker 

No.7 HDS-Hvy Vacuum Gas Oil 

1984 Operating Cost Combustion Devices 

X 10 $ in Unit 

9.87 

9.6 

5.7 

9.2 

1.4 

2.2-

1.41 

.90 

3.55 

9.95 

2.03 

1.56 

2.77 

44.82 

2.16 , 

1.84

 J 

2.85 

9.26 

1.7 

HHH -46 (H-4 & H-S) 

H-14 

H-6 

H-18, H-26 

H-9, H-10 

B-7 

H-24 

-21, H-22, H-23 

H-1101 

H-1201 

H-1301 

H-1102 

B-5, B-6 

-3801, 2,3,4 AB 

H-3101 

H-3001, H-3002 

H-3201 
Type 

Internals* 

Cas 

Contactors 

W-13 

W-67 

W-1202 

W-3701 

W-3702 

P-B 

Contactors(lO) 

W-14 

W-63 

W-3304 

VT 

VT 

VT 

VT 

VT 

P 

ST 

P 

Maximum 

Amine Rate 

GPM(l) 

390 

150 

260 

0 

120 

GPM 

70 

' 300 

Minimum 

Amine Rate 

GPM(2) 

20 

30 

20 

20 

20 

GPM 

TABLE VIII 

Amine Contactors 

Lake Charles Re 

Maximum 

Process Fluid 

Lb/Hr(4) 

163,000 

38,000 

56,000 

75,000 

27,000 

GPM 

250(11) 

300(12) 

250 

finery 

Minimum 

Process Fluid 

Lb/Hr(5) 

20,000 

9,000 

13,000 

19,000 

3,500 

GPM 

30(13) 

50 

30 

Normal(7) 

Amine Rate 

Required 

GPM 

265 

30 

180 

150 

20 

GPM 

10 

10 

45 

Normal(8) 

Process 

Rate 

Lb/Hr 

92,986 

31,490 

40,372 

35,779 

10,258 

GPM 

35 

223 

200 

Rich Amine (9) 

Loading 

Mol H.S/Mol MDEA 

ii 

0.56 

0.16 

0.60 

0.44 

0.24 

0.45 

0.45 

0.45 

* VT = Valve Trays, ST = SieveTrays, P = Packing (No. 2 HY-PAK) 
P.26 

wWwwwwwwww-

•63 

-67 

•13 

-14 

-3304 

-1202 

-3701 

-3702 

-3501 

-3551 

Inlet 

Temp.°F 

110 

115 

115 

• 110 

110 

110 

110 

110 

Column 

Press. 

PSIG 

290 

195 

195 

125 

300 

500 

750 

295 

TABLE IX 

C. 

C. 

C. 

C. 

Parsons 

Parsons 

Vendor 

Wyatt 

Wyatt 

F. Braun 

F. Braun 

F. Braun 

F. Braun 

, Delta Southern 

, Delta Southern 

-

Installation 

Date 

1956 

1941 

Modified 

1980 

1983 

1983 

1983 

1983 

1983 

1983 

1983 
P.27 

TABLE X 

Stream No. 1 2^ 2 

Component 

lb mo/hr (Max. Normal for Design) 

H 17.59 2.91 2.91 5.67 

N, 

H,S 13.89 0.13 21.80 21.68 

C0_ 24.23 0.11 26.84 38.54 0.03 11.70 

CO 2.51 

COS 0.01 

H O 64.86 61.40 2.17 

S0_ 6.95 

N / 653.97 0.045 0.31 

S, 0.04 

SZ 0.09 

C, 10.925 12.23 

ci 0.89 

C 0.355 4.49 

C, 0.02 1.25 

IC. 0.25 

IC* 0.25 

2.91 

32.58 

0.13 

26.84 

0.02 

0.01 

64.86 

2.91 

732.58 

21.80 

38.54 

0.02 

0.01 

61.40 
PROCESS FLOW DIAGRAMS 

Drawing No. 

LC-55-00-84-42.2T-B 

SD-2720-42-98-L 

LC-91-00-82.42.1A-D 

LC-91-00-82-42.2A-D 

LC-23-00-84-42.1A-D 

LC-91-00-84-42.1E-D 

LC-92-06-84-42.1C-B 

LC-83-00-84.42.1A-D 

SRE-029-8205-PI-04-L 

LC-53-00-84-42.1B-D 

LC-57-00-84-42.1A-D 

LC-39-00-84-42.1A-D 

LC-52-00-84-42.1A-D 

LC-58-00-84-42.1A-D 

LC-37-00-81-42.1B-D 

LC-56-00-84-42.1A-D 

LC-03-00-83-42.1C-D 

LC-25-00-84.42.1A-D 

LC-14-00-84-42.1A-D 

SD-2720-42-45-L 

SD-2720-42-188-L 

LC-79-00-84-42.1A-D 

LC-81-00-84-42.1A-D 

LC-82-00-84-42.1A-D 

Process Flow Diagrams 

Description 

Schematic Flow Diagram 

Fuel Gas System 

Amine System 

Sulfur Recovery Unit (Sht. lof2) 

Sulfur Recovery Unit (Sht. 2of2) 

Sulfuric Acid Plant 

MDEA Tail Gas Unit 

Sulfur Pits, Sulfur Degassing 

Fuel Gas Cryogenic Plant 

(Pending) 

FCC 

Heating Oil Belt 

t. 

No.l HDS 

Premium Coker 

No.2 Reformer 

Naphtha HDS 

600 PSIG Steam System 

Calciner 

No.3 CTU 

No.3 Vacuum Unit 

No.5 Gas Oil HDS 

No.6 HDS Unit 

No.7 HDS Unit 

Regular Coker 

No.3 NHDS Unit 

No.3 Reformer 

Equipment Included 

Train No. 1 

H-6 

H-9, H-10 

H-ll, H-12, H-13 

H-18, H-26 

H-21, H-22, H-23 

H-24 

--' B-5, B-6 

B-7 

H-1101 

H-1102 

H-1301 

H-3101 

H-3201 

H-3001, H-3002 

H-3801, H-3802 

H-3803, H-3804, A,B,C 
C-15-00-84-42.1A-D Thermal Cracking Unit H-14 

LC-02-00-79-42.1B-C No.2 Crude Topping Unit H-4&5 (H-46) 

LC-10-00-84-42.1A-D Distillate HDS Unit H-1201 

LC-84-00-84-42.1A-D No.8 Gas Oil HDS H-3951 

LC-55-00-81-42.1F-A Fuel System NSPS'fest " H^l101, B=fib2, H-1201, H-1301 

LC-55-00-83-42.1B-A Fuel System NSPS Test H-46, H-26, H-1201 
PURCHASED 

GAS 0-

IN-PLANT 

SUPPLIERS 

0-

OTMEn 

USERS A-i 

IN-PLANT 

SUPPLIERS 

/ 8< " / 

/ gioo / 

/ < 3,

782 / 

/ 55751/ 

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HIGH PRESSURE 

FUEL GAS 

KNOCK-OUT ORUM 

LEGEM) 

/ / FUEL FLOW RATE (MSCFO)., 

' NOV. 2. 1903 

/6001 / 

MAKE-UP 

No.O DOS 

H-3101 

/ 7FUE L FL0H n*

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' 1 ' NOV. 3. 19B3 

A SAMPLE LOCATION NOV. 2. 

A SAMPLE LOCATION NOV. 3. 

THERMAL 

CRACKER 

H-14 

1903 

1983 

LOt* PRESSURE 

FUEL GAS 

KNOCK-OUT ORUM 

121 7 

dtJ 

/ sw / 

1 

H-3002 H-3001 

No.2 COKER 

/

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H-3B01 H-3802 H-3B03 H-3804A 

No.3 HOS/REFORHER 

No.7 HOS 

H-3201 

Q-20 

04 CSA 

ORIGINAL 

PL 

Cconoco) CONOCO INC. 

REF1NEBY ENGINEERING CEHTEfl 

LAKE CH«RI.ES. LOUISIANA 

SCHEMATIC FLOW DIAGRAM 

FUEL GAS SYSTEM . 

LAKE CHARLES REFINERY 

f i c > LC-55-00-84-42.2T-B 

to 
P.31 

Conoco, Inc. 

Lake Charles, Louisiana refinery 

Response to Section 114 request 

$tUr 

Original contains 23 pages of diagrams (each 11" x 17") of.refinery processes 


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FEED SULFIDES CONC. IfC/LI ________ _ 

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N°- > *"" __—______ — 

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EXCESS FEED IFEES RATES DUR INQ FLARINO) 

NO. I SRU „_______________ _ 

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P39.. 

HI FT FOREMAN'S MORNING REPORT 

0.-2* CRUDE UNIT 

Cha rge 

LSR 

Naphtha 

HOD 

Hvy HOD 

Diesel 

Gas Oil 

Reduced Crd 

AT POLY 

Total Feed 

Recycle 

Poly BB 

Gasoline 

EMARKS: 

LKY 

B-B Charge 

Iso Charge 

Al kylate 

HSINGHEAD 

Deeth Gas 

Propane „ 

Iso 

Normal 

EMARKS: 

JLFURIC ACID PLAN 

oent Acid Feed 

line Gas Feed 

•JS Gas Feed 

:id Product 

IMARKS: 

JMPHOUSE 

Salt Filter Rate 

Cit-Con Return L 

Water Wells on 

)CKS 

Barges Loading 

Ships Loading 

Barges Unloading 

•Shjps Unloading 

IMARKS: 

DWER PLANT 

600 PSIG 

B-5 

B-6 

B-9 

B-2801 

Total 

EMARKS: 

. BPD 

BPD 

BPD 

BPD 

BPD 

BPD 

BPD 

BPD 

BPD 

BPD 

BPD PP 

BPD 

BPD P-P 

BPD 

BPD 

MMSCFD 

BPD 

BPD. 

BPD 

T 

gpm 

MSCF 

MSCF 

GPM 

GPM 

GPM 

ine Status 

MLB/HR 

MLB/HR 

MLB/HR 

MLB/HR 

MLB/HR 

/ 

/ 

Chg 

H 

M 

98% 

96% 

93% 

Average for the Day Enci 

AREA "A" 

FCC 

°API "Total Feed 

DP Recycle 

EP Fresh Feed 

Color Fuel Gas 

10%/95% PP 

95% • BB 

90%/EP Gasoline 

Color LCCO 

vis Slurry 

Coke 

Cat Circu. 

Air Rate 

BPD Preheat/Riser/Regen 

gum Prefrac Btms Temp 

THERMAL 

BPD Slurry Chg 

LCGO Charge 

EP Therm. Tar 

Gas 

Gasoline 

Cycle Oil 

%Propylene W-10 

Lt. Gaso 

Hvy Gaso 

NO. 1 SUL 

Amine Ga: 

SWS Gas f 

Sulfur Pi 

Sulfur Ir 

Stack SO, 

NO. 1 SW! 

Feed 

Ammonia 

BPH 

LCCP To/From 

Bl 

B3 

B4 

B7 

H-18 

H-3804 

Total 

.FUR PLANT 

\ Fd. 

:eed 

-od 

wen 

Topped 

.. 

MSCFH 

MSCFH 

TPD * 

Tons 

ppm 

gpm 

ppm 

5:00 a.m. 

BPD 

BPD 

BPD 

MMSCFD 

BPD 

BPD 

BPD 

BPD 

BPD 

LB/HR 

TON/MIN 

MLB/HR 

/ 

°F 

BPD 

BPD 

BPD 

MMSCFD 

BPD 

BPD 

BPD 

BPD 

Anil 

Tota 

% Cor 

% Ef-

% Sit 

EP 

°API 

/ 

°API 

°API 

EP 

EP 

RVP 

NO. 2 SULFUR PLANT 

Amine Gas Fd. 

SWS Gas Feed 

Sulfur Prod 

Sulfur Inven 

Stack S0o 

NO. 2 SWS 

Feed 

Ammonia 

haze^ 

Crude Line Status 

350 PSIG 

MLB/HR 

MLB/HR 

MLB/HR 

MLB/HR 

MLB/HR 

MLB/HR 

MLB/HR 

MLB/HR 

-. 

G-5 

Purch Fuel 

Fuel-LCCP 

Fuel-Flare 

W67 H9S 

- W13 H^S 

j 

ine Pt ; 

1 LV% j 

TV j 

f 

jrry 

: 

; 

MSCFH 

MSCFH 

TPD 

Tons 

ppm 

gpm 

ppm 

KWH 

MMS 

MKS 

% C 

ppm 

ppm 
P.40. 

SHIFT FOREMAN'S MORI* 

EFS CRUDE - VACUUM U 

Raw Cruae 

Cutter to Crude 

Desalted Crude 

PB 

LSR 

Naphtha 

Cutter to Stg. 

. Kerosene 

Diesel 

AGO 

LVGO 

HVGO 

1 Kesid 

1 REMARKS: 

1 NO. 4 HDS 

| Total Charge 

1 Desulf Eff 

1 No. 3 Kero. 

| No. 3 Diese] 

| T-23/24 

1 T-36_Bf 

1 Rx Temp'In/Out 

| Recycle H0 

1 REMARKS: 

1 NO. 5 HDS 

| Total Charge 

| Desulf Eff 

| No. 3 AGO 

| No. 3 LVGO 

| No. 3 HVGO 

| No. 1 HCGO 

| T-84 

1 T-398 

1 Rx Temp In/Out 

1 Recycle H, 

1 Make up K; 

1 Sep Fress^ 

1 RtMAKKb: 

1 .'10. 1 CUKLK 

| Drum Ovhd Temp! 

| Furnace Chg 

1 Resid Charge 

1 Therm lar Cftg 

1 Slurry Charge 

1 Pyro lar Chg 

• Drum -i Tons 

1 Drum r Tons 

1 Pump PSIG 

I Fuel Gas 

| Pb to No.2 CRU 

1 PB to FCC 

| baseline 

| LLbU 

1 HCbO 

• Ldiciner Cnq 

IMS- REPORT 

NIT 

BPD 

BPD 

BPD 

BPD 

BPD 

BPD 

BPD 

BPD 

BPD 

BPD 

BPD 

BPD 

BPD 

Average for 

AREA 

°API 

°API 

DP 

EP 

Color 

EP 

TRANSFER TEMPS 

Crude ° 

Vacuum ° 

vis 

NO. 6 HDS 

BPD Total Charge 

BPD Desulf Eff 

BPD No. 2 LCGO 

BPD No. 3 Diesel 

BPD T-23/24 

BPD T-36__T 

/ "F Rx Temp In/Out 

MMSCFD Recycle H0 

BPD 

BPD 

BPD 

BPD 

BPD 

BPD 

BPD 

BPD 

/ 

MMSCFD 

MMSCFD 

PSIG 

°F 

BPD 

BPD 

BPD 

BPD 

BPD 

Drill Tim 

_ Drill Tim 

rpm 

MMSCFD 

BPD 

BPD 

BPD 

BPD 

BPD 

TPD 

NO. 7 HDS 

Total Charae 

Desulf Eff" 

No. 3 AGO 

No. 3 LVGO 

No. 3 HVGO 

No. 2 HCGO 

T-84 

T-398 

F Rx Temp In/Out 

Recycle H9 

Make Up H^ 

Sep Press 

Tank 

Tank 

Tank 

Tank 

e TBQ 

e TBQ 

qpm 

EP 

•EP 

°API 

- the Day Eno ing 5:00 a.m. 

"B" 

REFORMER DIVISION 

P.l. Btms 

P.T. Chg. 

P.T. Ovhd. 

No.l HDS Chg. 

No.2 REF Chg. 

No.l HDS A T/out 

No.2 HDSA T/out 

No.2 REF in T's 

No.2 REF__T 

Recycle H0 

NO. 3 REFORMER 

No.3 REF Chg 

F No.3 HDS Temp 

F No.3 CRU Temp 

Recycle H0 

c. 

H„ Comoression 

BPD "H? from Jupit 

BPD H; from LCCP 

BPD H, from No.2 

BPD Wz from No.3 

BPD PSA Charoe 

BPD PSA Hydrogen 

/ °F PSA Purge Gas 

MMSCFD H? to No. 4&5 

Vr2 to Citgo 

EFFLUEN 

BPD Prima 

BPD Final 

BPD v Y-1,2 

BPD . Y-4 B 

BPD Coker 

BPD Demin 

BPD Firep 

BPD Laqoo 

/ °F FCC FEE 

MMSCFD Ges 0 

MMSCFD Disti 

PSIG 

NO. 2 COKER 

Furnace Charge 

Resid Charge 

Drum # Tons 

Drum r Tons 

Pump PSIG 

Fuel Gas 

PP to Poly 

BB to Alky 

Stab. Gasoline 

LCGO 

HCGO 

Coke Gasoline 

#>*> 

BPD 

7 

T 

/ 

°F 

% rf, H 

BPD 

°F 

/ 

% H„ 

<i 

& Purifica 

er 

CRU 

CRU 

HDS 

T WATER 

ry DAF Fd 

DAF Feed 

,3,Blowdn 

lowdown 

Blowdown 

Make-up 

ond Overfl 

n Overflow 

D PREP 

il 

Hate 

BPD 

BPD 

Hrs On L 

Hrs On L 

rpm 

MMSCFD 

BPD 

BPD 

BPD 

BPD 

BPD 

BPD 

F 

F 

/ 

/ 

tion 

MMS 

MMS 

MMS 

MMS 

MMS 

MMS 

MMS 

MM 

MMS 

BPD 

ine 

ine 

I 

I 

[ 

E 

E 

ppr j 

i 

H

 c ! 

-m— — | 

CFD 

CFD 1 

CFD I 

CFD ; 

CFD

 ! 

CFD 

CFD 

SCfD 

CFD 

gpm 

gpm j 

opm i 

gpm ! 

gpm 1 

±=i\ 

BPD i 

EP 

T 

CC-iii 

EP 

I? 

CAPI 

IP 
P 41 

Vfc^e- y T"l! 

/ ^ ^ 

North Amoricon Refining Conoco Inc. 

P.O. Box 37 

Westlake. LA 70S69 

(318) 431-5211 

October 15, 1984 

CEgnrn p MIL - RETURN RECEIPT REQUESTED (# P 243 177 324) 

Mr. Gus Van Bodungen 

Louisiana Department of Environmental Quality 

P. 0. Box 44066 

Baton Rouge, IA 70804 

Dear Mr. Van Bodungen: . ' 

Attached is the third quarterly report for -Conoco°s Lake Charles Refinery, as 

required by tte New Source Performance Standards (NSPS) [40 CFR 60.7(c)]. 

The period covered is for July through September, 1984. di s report includes 

the performance of the two Sulfur Recovery Units (SRUs) [required by 40 CFR 

60.104(a).2.i], and the performance of the fuel gas system [required by 40 

CFR 60.104(a).1]. 

A continuous nonitor records the sulfur -dioxide (SOJ concentration in the 

tail gas frcm each of the refinery's SRUs. The standard requires that the 

hourly average concentration not exceed 0.025% (250 ppn) SO_ on a dry basis 

corrected to zero oxygen for twelve consecutive hours. Hie monitors 

installed at the plant record the actual parts per million S02 concentration 

in the total stream, including moisture and oxygen. Die permitted level of 

250 ppm SO_ was adjusted to a comparable basis of 210 ppra, assuming 

concentrations of 10% moisture and 5% oxygen. ihe corrected 210 ppr. 

specification was then compared to actual readings. 

Tables I and II show the instances when the tail gas SO_ levels exceeded the 

corrected allowable 210 ppm reading for twelve consecutive hours in the No. 1 

and No. 2 SRUs, respectively. 

The following are major reasons for non compliance: 

(1) Tail gas unit problems due to corrosion cause most of the exceedances. 

Ihe corrosion causes exchanger leaks, plugging of the amine contactor 

tower and foaming. Ihese problems prevent adequate amine contact with 

the gas, and in some instances cause unit shutdown. The refinery is 

doing everything possible to pinpoint „the causes of corrosion and 

eliminate them. Corrosion inhibitor will also be injected in the 

future. 

(2) Amine solution in the tail gas units has degraded to heat stable salts 

due to S02 breakthrough from the Beavon Sulfur Recovery section of the 

sulfur train. As a preventative Treasure, the tailgas unit is bypassed 

during major upsets so that SO_ doesn't contact the amine solution for 

further degradation. 
P.42 

Mr. Gus Von Bodungen 

Page 2 

October 15, 1984 

(3) Feed fluctuations and upsets caused by upstream hydrocarbon processing 

units are problems which the sulfur plant must live with. This quarter 

was particularly difficult as the hydrogen compressor in the sour crude 

area had vibration problems and shutdowns. Consequently, swings in the 

primary amine hydrogen contactors were felt all the way through the 

Sulfur Plant. 

The refinery is installing a project to continuously add hydrogen to 

help hydrogenate the tail gas S02 to H_S. This prevents S0_ 

breakthrough to the amine unit and permits the H2S to be recovered ana 

recycled for optimum unit performance. 

(4) The combustion air to the B X is on ratio control fron an H2S/S02 

analyzer on the Claus tail gas. Conversion to sulfur is very sensitive 

to the proper H-S/SO- ratio. Feed composition changes or drifts in 

analyzer cal ibration sometimes result in ratio control problems. The 

analyzer is calibrated daily to minimize this problem. 

Table III shows periods of time when the concentration of hydrogen sulfide 

(H2S) in fuel gas to new heaters exceeded the standard 0.1 gr per dry 

standard cubic foot for three consecutive hours. While there is no 

continuous monitoring in the fuel gas system, operators test for H_S daily 

using sanpling tubes. 

If you have any questions, please call Mr. Rick McCalip at (318) 491-5599. 

Sincerely, 

P. W. Hashbroc^e 

Manager 

lake Charles Refinery 

VRD/sww 

att: 

cc/att: Mr. Joe Withers 

Department of Environmental Quality 

Air Quality Division 

P. O. Box 3047 

Lake Charles, IA 70602 

Mr. Bob Clark 

EPA Region VI 

1201 Elm Street 

Dallas, Texas 75270 

bcc: pWL/PFM JWL OM HGG RLM MES VRD 

File: 091.14 
SO- Exceedances 

TABLE I 

NO. 1 SULFUR RECOVERY UNIT 

THIRD QUARTER 1984 

P.43 

Start 

Date Time 

Bid Duration Average SO. 

Date 'Time Hours •» PPM Cause 

7-7 

7-8 

7-17 

7-29 

8-11 

8-18 

8-22 

8-30 

9-5 

9-6 

9-9 

9-12 

9-16 

9-17 

9-18 

9-22 

9-26 

7:00 

19:00 

5:00 

4:00 

5:00 

16:00 

13:00 

8:00 

1:00 

16:00 

22:00 

10:00 

18:00 

12:00 

9:00 

12:00 

10:00 

7-8 

7-11 

7-17 

7-29 

8-18 

8-21 

8-23 

9-4 

'9-6 

9-9 

9-11 

9-15 

9-17 

9-18 

9-19 

9-23 

9-27 

17:00 

16:00 

18:00 

23:00 

14:00 

4:00 

20:00 

22:00 

5:00 

3:00 

13:00 

. 9:00 

6:00 

24:00 

17:00 

8:00 

5:00 

34 

64 

13 

19 

177 

57 

31 

110 

28 

59 

39 

71 

12 

12 

31 

19 

19 

< 

a"- J 

447 

699 

1000+ 

1000+ 

405 

238 

230 

656 

284 

472 

450 

1000+ 

260 

230 

250 

615 

490 

Bypass to wash tailgas unit 

Bypass to repair leaking 

exchangers 

Washing unit/bypass 

Bypassed to tighten head on 

exchangers 

Washing unit 

Washing unit 

Ratio control problems 

Circulation problems due to 

plugging 

Foaming in tail gas contactor 

Air denend analyzer bad order 

Washing exchangers 

Bypassed for washing 

Foaming in contactor 

Foaming in contactor 

Foaming in contactor 

i 

Power f-feilure 

Tail gas upsets 
P.44 

. TABIE II 

NO. 2 SUIFUR RECOVERY UNIT 

THIRD QUARTER 1984 

SO? ExQepd-anoes 

1 

Start Bid Duration Average S02 

Date Time Date Time Hours PPM Cause 

6-30 1:00 7-2 16:00 63 924 Starting unit up 

7-2 18:00 7-3 10:00 16 580 Starting unit up 

7-3 18:00 7-10 19:00 169 1000+ Bypass MDEA to repair leaking 

exchanger 

7-19 20:00 7-20 8:00 12 526 Air demand analyzer calibration 

off 

8-15 5:00 8-16 22:00 41 396 Leaking discharge valve on air j 

blower j 

i 

8-30 3:00 9-6 2:00 191 848 Circulation problems in tail I 

gis due to plugging ! 

j 

9-10 24:00 9-12 12:00 36 509 Feed surges 

9-13 17:00 9-14 5:00 12 250 Foaming in tail gas contactor 

9-26 15:00 9-27 5:00 14 800 Tail gas upsets 
<*t 

TABLE III 

FUEL GAS SYSTEM 

P.45 

Start 

Date Time 

7-9 9:00 7-10 '13:00 

7-18 14:00 7-20 21:00 

Ehd Duration Average H_S 

Date Time Hours PPM 

28 

56 

220 

350 

Cause 

W-13 upset 

W-13 upset 

f