p.1 

OAR Box 1124 

Prepped by Ollie Stewart 

Document Number: 

61) II-D-2 

Docket Number: 

A-84-44 

Printed 4/16/2008 8:13:21 AM Sheet 61 of 70 
P.2 
P.4 

ATTACHMENT 1 

Report on EPA Questionnaire on New Source 

Performance Standard for H2S in Fuel Gas to 

Fuel Gas Combustion Devices 

Citgo Petroleum Corporation 

P. 0. Box 1562 

Lake Charles, LA 70602 

March 15, 1985 

Attachment 1 

Attachment 2 

Attachment 3 

Attachment 4 

Attachment 5 

Attachment 6 

Attachment 7 

Attachment 8 

CONTENTS 

- Item by Item responses to Questionnaire 

- Copy of all NSPS emission testing reports on Method 11 

H2S in Fuel Gas 

- Brief Summary of Stack Emission Tests bf NSPS Sources 

- H2S hourly data from 4th Quarter, 1984 

- H2S Quarterly Report from 4th Quarter, 1984 

- Central Amine Unit Sample and Test Schedule 

- Performance test for AI-507 H2S in Fuel Gas Analyzer 

- Forms used for record keeping 
P.5 

II-l 

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), H2S concentrations, and sulfur 

mass balances. Note on the diagram where gas blending i6 done and where 

process monitoring and emission monitoring samples are taken. 

Sketch 1 contains a simplified flow schematic of our fuel gas system. An 

approximate sulfur mass balance is included. The actual fuel gas system is 

considerably more complex and flexible than this sketch shows. Only the 

"normal" routing for the various make gas and treated gas streams has been 

shown. Alternate routing of various gas streams can be and is sometimes done 

to accommodate different processing scenarios. This flexibility is absolutely 

essential to allow unit turnarounds, more economical processing or recovery 

of hydrocarbon streams, or maintenance of the NSPS sulfur specification. In 

nearly all cases, once the blended fuel gas leaves the main fuel loop (the 

bold line) and enters a processing unit for combustion, no additional blending 

of process make gas or natural gas can be done. In a few cases, low pressure, 

small volume, relatively sweet make gases are burned in the unit rather than 

sent to an amine unit. The only NSPS unit where this is normally done is 

'C Reformer. This was included in the sketch. 

The sulfur and fuel gas balance as given in Sketch 1 was taken from actual 

process data from May,. 1984. At this time, all but one of the refinery 

process units were operating at reasonable rates. The refinery crude rate 

for that month was 287,000 barrels per day, which was 87% of refinery total 

capacity. This balance represents a "snapshot" of the refinery at that time, 

based on the best data available. The sulfur loadings to the amine units 

and the H2S production from those units do not balance completely. The 

explanation for this is that the sulfur data is based on mass spectrometer 

analyses of the various make gas streams, which is a routine process analysis . 

The mass spectrometer typically under-estimates H2S content of gas streams 

of less than 10% H2S. A real sulfur balance would require a massive sampling 

program with more careful analyses of the sulfur content. The total sulfur 

production is real data for the month of May, 1984. 
P.6 

III-l 

III. Costs (Primarv Emission Control Systems) 

2. Provide the following cost information. Index costs to year and month. 

(1984 Annual Costs) 

Item 

Capital3 

Labor4 

Materials & 

Supplies 

Chemicals6 

Enerev6 

Sulfur Credits' 

Date of Startup 

LERU1 

$7,063,000 

301,400 

324,000 

500 

382,000 

N/A 

September, 1968 

TABLE I -

FGPU 

$1,804,000 

264,100 

201,800 

2,200 

1,412,000 

N/A 

August, 1974s 

Benzene 

Amine 

$2,729,000 

232,100 

99,800 

21,800 

1,412,000 

N/A 

July, 1971 

Central2 

Amine 

$8,173,000 

298,700 

62,700 

73,900 

943,200 

N/A 

August, 1983 

N/A - Not Available 

Footnotes: 

1This unit recovers light hydrocarbons in addition to amine treating, 

a 50% environmental factor has been applied to all costs.-#-•.__ ^.jyy.;:.,—• 

2Does not include cost of amine contactors which are in other units. 

3Includes purchase, installation, and chemical inventory costs. These 

could not be broken out. 

4Labor costs include labor overhead. Total hours are not available-. 

Administrative and management cost are included. 

sIncludes amine makeup and replacement. 

6Includes steam and electricity 

?Not used in our accounting system 

8Date of conversion of existing unit to fuel gas treating service. 
P.7 

III-2 

Key accounting factors 

1. Lifetime of equipment. 

24 years 

2. Equipment amortization and depreciation rate 

24 years straight line method 

5% salvage factor 

4.2% per year 

3. Labor and management charges 

See Table I above. Administration costs are estimated at 7.1% 

times the total operating and maintenance (less depreciation and 

energy) cost for each unit. 

4. Overhead rate 

Labor burden is estimated at 30 percent. 
P.8 

IV-1 

IV. Refinery Combustion Devices 

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

your refinery...? 

11 Flares (includes 1 at our Lube Oil and Wax Plant) 

16 Boilers (includes 4 at our Lube Oil and Wax Plant) 

64* Process heaters (includes 17 at our Lube Oil and Wax Plant) 

0 Incinerators 

•Multiple compartment and common stack heaters are treated as single 

sources. 

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

please provide the following information: 

Device 

Flares 

Boilers 

Boilers 

Process 

Heaters 

Heat 

Release 

MMBTU/HR 

Variable 

535(Ave) 

139-330 

6-450 

Costs 

N/A 

N/A 

N/A 

N/A 

Table 

Service 

Intermittent 

Continuous 

9 Continuous 

3 Intermittent 

Most are 

Continuous 

II 

Fuels 

Used 

Fuel Gas 

Fuel Gas, 

#6 Fuel Oil 

Fuel Gas 

#6 Fuel Oil 

H2, Fuel Ga 

#2-6 Fuel 0 

Comments 

Used for emergencies or 

periodic gas releases only. 

High Pressure Boiler (4) 

Low Pressure Boilers (12) 

N/A -Not Available 

Note: Sufficient oil burning capacity has been provided in the Refinery and Lube 

Plants to burn up to 30,000 BBLs per day of #6 Fuel Oil. Present oil burning 

rates average less than 500 BBLS per day. Present permitted limit is 

21,651 BPD. 

3. (a) Please list and describe any new, modified, or reconstructed combustion 

devices you have that are subject to the NSPS, and the dates of installation. 

See Table III, following. 
P.9 

IV-2 

Table III 

NSPS Combustion Sources 

o. 

1 

2 

3 

4 

5 

6 

7 

8 

Source Name 

Furnace B-101 

Furnace B-4 

Furnace B-104 

Furnaces B-501, 502, 

Furnaces B-503, 504, 

Furnace B-201 

Furnace B-202 

Furnaces B-l, 2, 3, 

506 

505 

4, 5, 

Unit Name or Description 

'B' Light Cycle Oil Hydrotreater 

'A' Topping Unit 

'B* Topping Unit 

'C Reformer Unit 

'C Reformer Unit 

Coker II Unit 

Coker II Unit 

Unicracker Unit 

Date of 

Initial 

Startup 

09/04/80 

07/19/81 

12/13/81 

06/09/82 

06/09/82 

09/02/83 

09/02/83 

02/05/84 

3. (b) For these affected combustion devices, describe how you complied with the NSPS 

and the resulting decrease in H2S concentration. Estimate, if possible, 

the cremental cost of compliance and the resulting S02 emission reduction. 

The first NSPS source in the refinery was the B-101 furnace at 'B' Light 

Cycle Oil Hydrotreater ('B' LCOH). Prior to this time, amine capacity 

had been installed and placed into operation in order to reduce the contribution of fuel gas combustion to the ambient S02 levels downwind 

particularly during fuel oil combustion periods. The amine capacity * 

existent in 1980 was sufficient to treat all of our sour make gas streams; 

to NSPS levels. Therefore, there were no expenditures required to reach 

the NSPS level at the time of the startup of the first NSPS unit. 'A' and 

'B' Topping Units use the same source of gas as 'B' LCOH, so therefore, 

no expenditure was required to meet NSPS for these units either. 

'C' Reformer unit burned its own sweet off gas, and did not require any 

treating to reach the NSPS. When the Unicracker Unit came on line, the t 

'C Reformer offgas (mostly H2) was supplied to them as feed stock and the! 

'C Reformer furnaces went on Refinery fuel gas. The amine capacity 

on this part of the fuel system was also sufficient and no expenditures 

were required to reach the NSPS. 

Both the Coker II and Unicracker Units have sour off gas streams that had 

to be amine treated in order to achieve NSPS for these sources. In order ) 

to accommodate the new amine contacting capacity, a new amine regeneration 

unit (Central Amine) had to be built to handle the load. The capital and '-

operating costs for the central amine unit are given above. The H2S 

concentration in the feed gas to the Coker II off gas amine contractor 

is about 7.0% H2S (design). The sweetened gas averaged 46 PPM H2S 

(10-200 range) in a set of tests conducted over a 45 day period. The 

amount of S02 emissions that have been reduced due to this unit is 

approximately 230 tons per day (design). 
IV-3 

4. Without the NSPS, what level of H2S and other sulfur compounds in fuel gas 

would be acceptable before there would be significant adverse corrosion of 

combustion equipment? 

Most of the existing process heaters in the refinery have relatively hot 

stacks (600-1000°F) which would not suffer corrosion damage from sulfuric 

acid mist formation at almost any reasonable level of concentration of H2S in 

the fuel gas. Most of the new sources, and in particular the NSPS sources, 

do have one form or another of heat recovery and have much lower stack exit 

temperatures (250-400cF). For these sources, the percent of bypass on the 

air preheater or final stack temperature is controlled by the sulfur content. 

We do not control the sulfur content of the fuel gas to achieve any particular ! 

dew point of sulfuric acid mist in the flue gas of the process heaters. 

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? 

There are only two Federal and State environmental regulations that 

affect the design of Refinery combustion devices. The first is the NAAQS 

for S02 which caused fuel gas and fuel oil sulfur concentrations to be 

controlled, at least within certain ranges. The second is the imposition 

of the Best Available Control Technology (BACT) upon new sources that are 

subject to the Prevention of Significant Deterioration (PSD) rules. For 

process heaters firing fuel gas or fuel oil, this generally resulted in low excess 

air-low oxides of nitrogen burners. 
P.11 

V-l 

V. PRIMARY CONTROL 

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)? 

See Tables IV, V and VI 

2. Amine heater description... 

UNIT-Light Ends Recovery Unit (LERU) 

Note: This unit is designed to recover light ends from the feed gas and 

amine treat the residual tail gas. Only the portion of the unit dealing 

with the amine contactor and strippers is detailed below. 

(a 

(b 

(c 

(d 

(e 

(f 

(g 

(h 

(i) 

General Schematic 

See Sketch No. 2 

Manufacturer or Vendor 

Fluor Corporation 

Startup Date 

September, 1968 

Design capacity and range 

Design 35.4 MMSCF/D; Range 6.3-21.9 MMSCF/D 

Hours of operation, hours/year 

24 hrs/day, 365 days/year, except for occasional turnarounds 

Number of vessels in system (strippers and absorbers) 

1 absorber, 1 stripper 

Total amine inventory in system 

N/A 

For each absorber, design and actual operating levels 

1. Gas flow rate 

Design 35.4 MMSCFD; Actual 6.3-21.9 MMSCFD 

2. Gas Pressure (inlet) 

Design 550 psi; Actual 190-200 psi 

Gas Temperature (outlet) 

Design 120°F; Actual 40-120°F 

3. Amine circulation rate 

Design 250 gpm; Actual N/A gpm 

Amine circulation temperature (inlet) 

design 120°F; Actual 100-125°F 

For each stripper, design and actual operating levels 

1. Amine circulation rate 

Design 250 gpm; Actual N/A gpm 

Amine circulation temperature (inlet) 

Design N/A°F; Actual N/A °F 

2. Steam usage (35 psi) 

Design 35,000 lb/hr; Actual 25,000-35,000 lb/hr 

N/A - Not Available 
UNIT 

LERU 

FGPU E-3 

FGPU E-3A 

Benzene Amine 

Coker 2 E-204 

LERU 

FGPU E-3 

FGPU E-3A 

Benzene Amine 

Coker 2 E-204 

LERU 

FGPU 

Benzene Amine 

Central Amine 

INLET GAS TO i 

FLOW RATE 

6.3 

5.3 

14.5 

6.5 

12.0 

MMSCF/D 

-21.9(17.1) 

- 8.6(6.4) 

- 22.3(19.2) 

- 12.1(9.2) 

- 23.4(21.0) 

OUTLET GAS FROM 

2.8 

6.8 

11.1 

0.1 

1.6 

0.3 

1.9 

N/A - Not Available 

- 16.1(10.8) 

N/A 

N/A 

- 13.6(9.1) 

- 23.3(20.0) 

ACID GAS 

- 1.0(0.4) 

- 2.5(2.1) 

- 1.6(1.0) 

- 4.0(3.3) 

V-2 

TABLE IV 

>\MINE TREATERS (1984 Data) 

HEATING VALUE 

BTU/SCF 

1100 - 1350(1225) 

1100 - 1190(1128) 

1050 - 1600(1330) 

930 - 1570(1090) 

1370 - 2500(1840) 

TABLE V 

TEMP. °F 

N/A 

40 - 120(98) 

40 - 120(98) 

73 - 128(97) 

70 - 110(97) 

AMINE TREATERS (1984 DATA) 

1040 - 1220(1132) 

1460 - 1740(1590) 

910 - 1260(1090) 

720 - 1070(860) 

1032 - 1649(1226) 

TABLE VI 

FROM AMINE STRIPPERS 

570 - 640(600) 

N/A 

490 - 690(644) 

510 - 810(670) 

N/A 

N/A 

N/A 

N/A 

88 - 122(114) 

N/A 

30 - 210(95) 

N/A 

90 - 120(100) 

PRESS. PSI 

190 

165 

55 

62 

162 

60 

160 

10 

- 200(198) 

- 190(183) 

- 70(62) 

- 68(65) 

- 202(180) 

N/A 

N/A 

N/A 

- 65(62) 

- 200(178) 

N/A 

N/A 

N/A 

- 17(13) 

1.8 • 

8.5 -

4.5 • 

.005 

.002 

.005 

.01 

.001 

66 -

59 -

83 • 

82 -

-

H2S % 

- 2.7(2.4) 

N/A 

N/A 

- 9.3(8.7) 

- 9.8(7.0) 

- l.O(.Ol) 

- 0.1(.005) 

- 0.5(.01) 

- 0.5(.02) 

- .02(.005) 

- 80(72) 

- 87(77) 

- 95(91) 

- 97(92) 

--

C02 % 

1.3 - 1.4(1.3) 

0.6 - 1.7(0.9) 

0 - 1.5(0.8) 

0 - 0.1(0.1) 

0 - 0.4(0.2) 

0 - 0.1(0.1) 

0 - 0.2(0.1) 

0 - 0.2(0) 

0 - 0.1(0) 

N/A 

17 - 30(23) 

9 - 27(17) 

0 - 1.0(0.2) 

0.5 - 2.2(1.1) 
P.13 

V-3 

(j) Types of amine used 

Monoethanolamine (MEA) 19% 

(k) Other important design or operational criteria 

LERU was designed for operation as a cryogenic light ends removal unit 

at high pressure. When the "cold box" is down, the unit operates at 

lower pressure, which greatly restricts the flowrate. 

UNIT - Fuel Gas Processing Unit (FGPU) 

(a) General Schematic... 

See sketch No. 2 

(b) Manufacturer or Vendor 

Hudson Engineering Corporation 

(c) Startup Date 

August", 1974 (Revised Unit) 

(d) Design Capacitv and Range 

Design; 31.8 MMSCF/D Range: 19-31 MMSCF/D 

(e) Hours of operation, hour/year 

24 hours/day, 365 days/year, except for occasional turnarounds 

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

2 absorbers, 1 stripper 

(g) Total Amine inventory in system. 

N/A 

(h) For each absorber, design and actual operating levels 

1. Gas flow rate 

E-3 Design 12.0 MMSCF/D: Actual 5.3-8.6 MMSCF/D 

E-3A Design 19.8 MMSCF/D: Actual 14.5-22.3 MMSCF/D 

2. Gas Pressure (Inlet) 

E-3 Design 210 psi; Actual 165-190 psi 

E-3A Design 75 psi; Actual 55-70 psi 

3. Amine Circulation Rate 

E-3 Design 265 gpm; Actual 283-355 gpm 

E-3A Design 370 gpm; Actual 244-355 "gpm 

4. Amine circulation temperature (inlet) 

E-3 Design 100°F; Actual 110-125°F 

E-3A Design 100°F; Actual 110-120°F 

(i) For each stripper, design and actual operating levels 

1. Amine circulation rate 

Design 635 gpm; actual 535-710 gpm 

Amine circulation temperature 

Design 100°F; Actual 110-125°F 

2. Steam usage (30 psig steam) 

Design 41,030 lb/hr; Actual 34,000-49,000 lb/hr 
P.M 

V-4 

(j) Type of amine used 

MEA 15% 

Note: This unit was originally designed for Diethanolamine 

(k) Other important design or operational criteria. 

None 

UNIT-Benzene Amine Unit 

(a) General Schematic 

See Sketch No. 2 

(b) Manufacturer or Vendor... 

Ford, Bacon, and Davis Texas Incorporated 

(c) Startup date 

July, 1971 

(d) Design capacity and range 

Design 20.8 MMSCF/D; Range 6.5-12.1 MMSCF/D 

24 hrs/day, 365 days/year, except for occasional turnarounds 

(f) Number of vessels in system (stripper and absorbers) 

1 absorber, 1 stripper 

(g) Total amine inventory in system 

N/A 

(h) For each absorber, design and actual operating levels 

1. Gas flow rate 

Design 20.8 MMSCF/D; Actual 6.5-12.1 MMSCF/D 

2. Gas pressure 

Design 85 psi; Actual 62-68 psi 

Gas Temperature 

Design 100°F; Actual 73-128°F 

3. Amine circulation rate 

Design 425 gpm; Actual 192-314 gpm 

Amine circulation temperature (inlet) 

Design 120°F; Actual 87-103°F 

(i) For each stripper, design and actual operating levels 

1. Amine circulation rate 

Design 425 gpm; Actual 205-314 gpm 

Amine circulation temperature (inlet) 

Design 200°F; Actual 179-200°F 

2. Steam usage (25 lb steam) 

Design 24,098 lb/hr; Actual 15,600-18,600 lb/hr 

(j) Type of amine used 

MEA 15% 

(k) Other important design or operational criteria. 

None 
P.15 

V-5 

UNIT-Central Amine Unit 

Note:. This unit serves as the common regeneration unit for 3 amine absorbers, 

all in different units. Only one of the absorbers is used in treating process 

make gases that go into the fuel gas system. That one absorber (E-204 in 

Coker 2) is included in this section. 

(a) General Schematic 

See Sketch No. 2 

(b) Manufacturer or Vendor... 

S.I.P. Engineering, Inc. 

(c) Startup date 

August, 1983 

(d) Design capacity and range 

See question h. and i. below 

(e) Hours of operation, hours/year 

24hrs/day, 365 days/year, except for occasional turnaround 

(f) Number of vessels in system (stripper and absorbers) 

3 absorber, 1 stripper (See note Above) 

(g) Total amine inventory in system 

222,000 gallons 

(h) For each absorber, design and actual operating levels 

1. Gas flow rate 

Design 24.2 MMSCF/D; Actual 12-23 MMSCF/D 

2. Gas pressure (inlet) 

Design 180 psi; Actual 160-200 psi 

Gas Temperature (inlet) 

Design 130°F; Actual 70-110°F 

3. Amine circulation rate 

Design 770 gpm; Actual 720-1030 gpm 

Amine circulation temperature (inlet) 

Design 165°F; Actual 105-140°F 

(i) For each stripper, design and actual operating levels 

1. Amine circulation rate 

Design 2078 gpm; Actual 1400-1800 gpm 

Amine circulation temperature (inlet) 

Design 220°F; Actual 210-225°F 

2. Steam usage (25 lb steam) 

Design 162,300 lb/hr; Actual 61,000-152,000 lb/hr 

(j) Type of amine used 

MEA 15% 
P.16 

V-6 

(k) Other important design or operational criteria. 

The Central Amine Unit was designed to accommodate a second stripper 

tower with associated exchangers and vessels. The design of the amine 

circulation system was based on the addition of the second stripper, 

which would boost the amine flow to 3,000 gpm. The second stripper 

would replace the amine strippers of Benzene Amine, LERU, and FGPU. There 

are no plans at present to add the second stripper tower. 

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

effect? List the differences from the present system. 

As was explained briefly earlier most of our amine capacity had been installed 

prior to the NSPS regulations. In 1973-74, a nationwide gas shortage forced 

the Refinery and Lube plants to convert most of their process heaters to 

residual fuel oil firing as a backup energy source. In order to achieve 

the N.A.A.Q.S. by May 31, 1975, which was the date mandated by the EPA, the 

refinery implemented a number of S02 reduction projects. This included 

conversion of a large, idle amine system into make gas sweetening service and 

addition of tie-ins of the remaining sour gas process make gas streams into the 

various" amine units. By 1975, sufficient amine capacity had been installed 

to treat our sour make gas streams down to an average level of 100 PPMV 

(142mg/dscm)(design). The actual levels varied over a wide range due primarily 

to inadequate understanding of operating parameters and periodic by passing 

of sour gas streams. 

Ambient monitoring of S02 levels during this period indicated that fuel gas 

sulfur levels contributed very little to the overall ambient levels, especially 

compared to fuel oil and other source contributions. In 1980, when the first 

NSPS source started up, additional emphasis was put up on the operation of 

the amine units, which eventually resulted in the NSPS standard being maintained 

a majority of the time. As time went on, the percentage of 3 hour periods 

in compliance has gradually risen to present levels (99.6%+). 

In 1983 and 1984, two new process units were built which produce sour make 

gas that would exceed present amine treating capacity. Additionally, the 

percentage of sour crude processed in the refinery had risen considerably 

and was expected to increase again, after the new units were on line. In 

order to meet the NSPS for these units and also to protect the S02 ambient 

levels, a new amine unit was built (Central Amine). Had the NSPS not been 

in effect, one or more smaller separate amine units would have been built 

anyway. Some sour gas would have gone directly to fuel with the S02 levels 

at the stacks or at the S02 ambient analyzer dictating the level of treatment. 

Of the three contactors in the central amine system, only 1 ( in product 

sweetening service) would likely have been built if NSPS had not been in 

effect. / 
V-7 

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. 

In accordance with a discussion between D. K. Monfore and Nancy McLaughlin, 

only the maintenance history of the newest amine system (Central Amine) will 

be provided for questions 5-9. The other amine units do have occasional outages 

caused by hydrocarbon contamination of the amine, excess corrosion in the 

steam/amine reboilers, and other less frequent problems. A major problem 

has been failure of the H2S compressors which causes a shutdown of the amine 

unit or flaring of some or all of the recovered H2S. Degradation of amine 

due to the presence of heat stable salts is also sometimes a problem requiring 

amine replacement. 

5. Are the maintenance requirements and amine replacement rates more excessive 

than that indicated by the vendor? 

The maintenance requirements of the unit have been very minimal since startup. 

Amine replacement has been 30,000 gallons of 85% MEA. No vendor information 

on amine losses was available. 

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)? 

Central Amine unithas not had one day of downtime since startup in August, 1983. 

The only major problem that the Central Amine unit has had since startup 

was an overpressuring of the lean MEA surge tank in February of 1984. The 

roof of the tank was lifted when a shot of liquid propane was received in the 

rich MEA line from one of the units. The pressure relief system was redesigned 

to present this from happening again. The unit did not have to shut down 

during the episode or during the corrective modifications. 

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

system, and what types of personnel perform these inspections? 

Central Amine Unit operator make unit inspections a minimum of 3 times 

per 8 hour shift. During these inspections, all rotating equipment, all 

liquid levels, and outside temperatures and pressures are checked. An inside 

(board) operator reads the unit recorders and inside instruments a minimum 

of twice per shift. Various readings are recorded in the unit operational 

log sheets. Amine, reflux, and H2S samples are taken on a regular schedule 

and analyzed by the laboratory. The results of these analyses are checked 

against operational standards, and adjustments are made accordingly. A sample 

and test schedule for Central Amine is attached (Attachment 6) . 

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)? 

All of the unit operating parameters are used to determine if the unit is 

performing properly. However, certain of these parameters could be considered 

"key" parameters. These include the MEA concentration, the H2S/MEA ratio in 

the lean MEA, the stripper overhead temperature, the MEA flow to the 

contactors, the contactor operating pressure, and the lean MEA temperature. 
P.18 

V-8 

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

for varying conditions and inlet loadings so that a low H2S concentration 

can be maintained at the outlet? 

See V 8. above 
P.19 

VI-1 

VI. SECONDARY CONTROL 

1. How is the more concentrated H2S stream exiting the amine treater handled 

(sulfuric acid plant, Claus sulfur plant with tail gas treaters, 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? 

In 1971, Ford, Bacon, and David Texas built a 4 stage sulfur recovery unit 

as part of a package that included the construction of the Benzene Amine unit. 

This unit (designated 'A' and 'B' SRU's) consisted of two identical 50 tons 

per day units. Each unit had 3 catalytic converter beds and 4 passes of sulfur 

condensers. The tail gas from the unit was incinerated in a tall stack by 

combustion of fuel gas and tail gas. Both units were shutdown in 1975 and 

subsequently demolished after startup of a new Sulfur Recovery Unit. 

In 1975, two new SRU's and a Beavon-Stretford tail gas cleanup unit were built 

by R. M. Parsons Co. Each SRU was rated at 120 tons per day and were also 

4 stage units. The primary difference with these SRU's was their use of direct 

fired reheaters instead of steam reheat for the converter beds. These units 

were designated 'C and 'D' SRU. The Beavon-Stretford Unit was designed to 

handle tail gas from 3-120 tons per day SRU's and recover 20 tons per day of 

elemental sulfur. Both units are still operable. 

By 1982, the need for processing additional H2S resulted in the "reconstruction" 

of 'A' and 'B' SRU into a new 120 ton per day SRU designated as 'E' SRU. 

The tail gas from 'E' SRU is treated in the Beavon-Stretford Unit. Total system 

sulfur recovery capacity including the 20 TPD from the Beavon Stretford 

Unit is 380 tons/day. See Sketch 3 for a block flow diagram. 

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

combining the tail gas and fuel gas amine stripping? What are the advantages 

and disadvantages of this approach? 

We do not now utilize amine scrubbing of SRU tail gas. This approach may 

be considered if additional Sulfur Recovery capacity is needed at a future 

date. 
P.20 

VII-1 

VII. Emission Testing 

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

your amine treaters. Include the date of the test and a description of 

the process conditions at time of test and test methods used. 

See Attachment 2 

a. What was the cost of the emission performance tests? 

All of the H2S in fuel gas testing (Method 11) was conducted "in-house". 

A typical performance test of 3 runs and 2 samples each costs approximately 

$680 for labor. Materials cost is about $1000 for the first time and is 

$100 per test or less thereafter. 

b. Was the testing performed by your company or by,a consultant? 

By our company. 

c. Besides H2S, what other compounds were tested for...? 

None 

d. Where was the test sampling site? Was it before or after blending 

with natural gas or other refinery gas? If after blending, what 

volume of other gases were blended with the treated fuel gas? 

All of the tests were conducted after all blending had been done and 

were as close to the combustion device as practical. See Attachment 2 

for details of site location for each test. 

2. Please provide a brief summary of any emission test that has been performed 

at the outlet of combustion devices which burn fuel gas. Describe the 

combustion devices tested. In addition to the types of information listed 

above, we are interested in a summary of the emission data for any other 

pollutants/compounds (S02, total sulfur, NO , CO hydrocarbons, etc.). 

See Attachment 3. All of the sources tested were fuel gas fired process 

heaters 

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? 

None 
P.21 

VIII-1 

VIII. Monitoring of Emissions and Process Operation 

2. Please describe any State or local regulations that require you to monitor. 

The State of Louisiana has been requiring that some form of monitoring for ' 

H2S in fuel gas be done. The choice of method has been up to the source. 

3. Emission monitoring of H2S concentration in the fuel gas: 

a. How do you monitor the H2S 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? 

We are currently monitoring two separate fuel gas systems by two different 

methods. The NSPS heaters at the 'B' Light Cycle Oil Hydrotreater and 

'A' and 'B' Topping Units are monitored by an on-line continuous H2S 

analyzer. The sample point is located just downstream of the F-2 fuel 

drum which feeds all of the above heaters (See sketch 1). In addition 

to the continuous monitor, a Draeger tube reading is caught off of the line 

feeding the analyzer once per shift. Whenever the analyzer's level 

approached or exceeds the limit, additional Draeger's are caught at the 

individual sources feeding the F-2 drum in order to identify and correct 

the causative streams. The NSPS heaters at 'C' Reformer, Unicracker, and 

Coker II are monitored once/shift with Draeger tubes at the Coker II unit. 

The Coker II operator samples fuel gas to the unit which is representative 

of the F-104 fuel drum that supplies the above heaters. Additional 

tubes are taken at sources which feed the F-104 drum whenever high 

levels are observed. The location of the NSPS H2S in fuel gas sample 

locations is noted in Sketch 1. 

The primary purpose of the monitoring is to comply with the NSPS regulations. 

If these were not in effect, some monitoring of the treated gas would 

still be done to assure adequate operation of the amine treaters and 

to maintain compliance with permitted S02 levels. 

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. 

Draeger tube reading are taken from the F-104 fuel drum system once per 

shift every day with the concentration and time sampled recorded in a logbook maintained by the console operator and also recorded on shift reports. 

If the H2S reading is above 162 ppm, a second reading during the shift 

is taken until the situation is under control. 

The operator prepares the tube and pump according to the manufacturer's 

instruction and draws in a sample off of the fuel gas sample line. One 

pump stroke is sufficient for concentrations greater than 20 ppm; however, 

ten pump strokes are required when concentrations are less than 20 ppm. 
VIII-2 

A Draeger tube costs about $2.60 each. The operator time to sample and 

log the results is about 12 minutes which amounts to about $3.72 per tube. 

The total cost per tube is therefore $6.32 per tube. One tube per shift 

would cost approximately $6,900 per year. In 1984, 8,000 tubes were 

purchased for use by operations. The annual cost of all Draeger tubes 

samples for H2S in fuel gas as a result of NSPS amounts to at least 

$30,000-$50,000. 

The Draeger tube can be read at about ±5% at best. The actual accuracy 

of the tube versus the actual concentration is not known, but comparisons 

to our continuous analyzer shows that the tubes are usually within ±10% of 

the analyzer. The analyzer and Draeger tube readings are given side by side 

for a 3 month period in Attachment 4. Occasional samples show a variation 

of 100% or more. This illustrates the main problem with Draeger tubes, 

which is the repeatibility of the test. As in any strictly manual test, 

the skill and patience of the operator will affect the results. If the 

sample line is not properly flushed or tube is withdrawn prematurely, a 

negative bias will result. If the tube is held into a flowing gas stream 

at excess velocity, a positive bias can result. The data seems to indicate 

a slight positive bias, for whatever reason. 

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

1. Describe the monitors, including vendor, model number, date installed 

and costs to purchase and install. 

Vendor - Bendix Corporation 

Model No. - 7170 (Programmer Model No. 7000 and Analyzer 

Model No. 007) 

Date Installed - October, 1980 

Purchase Cost - $12,200 (instrument) + $5,000 (shelter) 

Installation Cost - $4000 (estimate) 

2. What is the maintenance history of the instrument monitors including predominant 

problems (such as drift, bias, breakdowns), length of outages, reliability 

history, and cost of maintenance (capital, operating, and labor)? What is 

your normal preventative maintenance program for the monitors, and how many 

labor hours/week are expended? Please break down these hours by type of 

personnel. 

The Bendix analyzer has a long history of valve wear, drift and sample 

problems, and electronic circuit board breakdowns. The analyzer drift is 

probably due to instrument design, not the service. Circuit board failure 

is frequent, but doesn't cause excessive downtime due to adequate spare 

inventory. Because of high drift rates and analyzer unreliability, the 

analyzer is checked and calibrated by an instrument man a minimum of 5 times 

per week. As a result of the intensive preventative maintenance program, 

the analyzer has a high data capture rate, exceeding 95% per month. 

The instrument has an annual operating and maintenance cost of about $8,900/yr. 

this is composed of the following: replacement parts $600, helium $300, .. 

span gas (certified) $200, and labor $7,800. No supervision or administrative./, 

time is included in the labor cost. 
P.23 

VIII-3 

The Preventative maintenance program for this analyzer requires a minimum 

of 5-7 manhours per week by the instrument man. That schedule is given 

below: 

TABLE VII 

Preventative Maintenance Program 

Instrument - AI-507 

Service - H2S in Fuel Gas from F-2 Drum 

A. Daily 

1. Check carrier gas bottles and change as required. 

2. Calibrate analyzer using standard calibration mixture. 

3. Run chromatogram on analyzer to check baseline and gate position 

against master chromatogram. 

4. Check recorder for accuracy. 

B. Monthly 

1. Check carrier gas and sample flows against specification sheet. 

2. Clean and inspect building and enclosures. 

3. Please include any data comparing the instrument emission monitoring system 

to manual sampling emission tests, including a description of methods used, 

quality assurance, and relative accuracy evaluations. 

See Attachment 4 for a comparison of Bendix 7170 to the Draeger tube. Attachment 

7 provides the comparison data between Method 11 and the analyzer, that was 

used as the performance demonstration. Additional comparison can be found in 

Attachment 2-2 (Page 12). 

4. How is the data recorded (manually or by instrument; periodically or continuously)? 

How is the raw data reduced and analyzed? How long are data records retained? 

The on-line analyzer takes gas samples at a rate of about once every 5 minutes 

and analyzes for H2S. The analyzer drives a chart recorder. The charts are 

maintained in the Environmental Office as part of our records. In addition, 

the analyzer sends a signal every minute to the Refinery Honeywell computer 

system. A computer program has been established which will process the one 

minute readings into the following: 5-minute average, 15-minute average, 

one-hour average and 24-hour average values. This data is retained for 60 hours 

before it becomes overlayed with new data. This information can be retrieved 

at any time from several terminals located within the plant and is used by 

the console operator to monitor the H2S levels leaving the F-2 fuel drum. 

Prior to August, 1984, one hour average report had to be generated every 

day in order to obtain the necessary data for our quarterly NSPS report. 

During August an additional program system was commissioned which sends 

the one minute readings to the IBM computer system allowing storage of up 

to 4 months of one hour average values. 
P.24 

VIII-4 

At this time, one hour average readings are accessible from the IBM system 

which are scanned for high values; 3-hour average exceedences are hand 

calculated and logged on the quarterly report. Software is .being developed 

to generate the required reports from the IBM stored data. 

This program also generates an immediate TDC readout on the console operator's 

screen when a 3-hour average exceedence has just occurred. This warning signal 

prompts him to notify the shift superintendent of the exceedence which is 

then reported to the Louisiana Department of Environmental Quality. Just 

prior to the end of each shift a computer printout report is generated which 

compiles any/all exceedences of the shift and provides room for explanations 

and action taken which is to be provided by the console operator. The 

Environmental Control Department is responsible for writing an explanation 

letter to the state to report the length of the episode, the cause, and 

action taken to prevent it's recurrence. Our records are maintained for 3 years. 

If for some reason the H2S analyzer is down, then Draeger tube readings are 

taken once/shift. If the computer transmitting system is down, the 

analyzer charts are reviewed for any exceedences. The console operator 

also keeps a log of the 162 ppm standard exceedences. This record provides 

information which can be used to fill in missing data or help explain 

occurrences. 

5. Please provide a summary of monitoring data for the H2S content of fuel gas 

with corresponding process conditions for the last 3 months, (daily averages 

and ranges, noting any 3-hour periods of excess emissions). For periods 

of excess emissions, explain the causes and corrective action taken. 

A summary of H2S in fuel gas hourly data is enclosed as Attachment 4. A 

quarterly report for the same period (4th quarter, 1984) is enclosed as 

Attachment 5. A report on the process conditions was not supplied because 

of the voluminous amount of data that would have to be submitted. 

6. 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? 

A wide variety of process parameters are monitored continuously (temperature, 

pressures, flow rates, stream composition, etc.) for a number of different 

streams for each amine treater. A listing of all of the parameters 

monitored by operations is really beyond the scope of this questionnaire. 

See Section V item 8 for additional information. A list of the laboratory 

sample schedule or the Central Amine Unit is enclosed as Attachment 6. 

b. Which process parameters are good indicators of the proper performance 

of the amine treater and of low H2S concentrations at the outlet? 

How well do the process parameters correlate with H2S concentrations? 

See Section V item 8. 
vni-g' 

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

what type? 

We have no plans for replacement of any process monitor or H2S analyzer at 

this time, but the AI-507 analyzer will have to be replaced probably within 

the next 2-3 years. The instrument department is presently having some 

difficulties in obtaining replacement parts for this instrument. 

8. Are any of the instrument monitors integrated into the process as a control 

system? 

As mentioned previously, some of the process monitors are placed with the 

TDC/Honeywell control system and are used to control the process. The H2S 

analyzer is used for informational purposes, but is not part of a control 

loop. Ore example of this is that the amine circulation rate at the Coker II 

E-204 amine contactor is ratioed to the inlet gas rate. 
P.26 

IX-1 

IX. GENERAL REFINERY INFORMATION 

1. What is the nominal size bf 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 Citgo Refinery is 330 MBPD. Current operating level 

is 140 MBPD. Operation is now alternately scheduled for 4 days on a prototype 

(sweet) crude followed by 5 days on sour crude. The higher sulfur crudes will 

increase the loading on the amine units. H2S production is a function of 

the following variables : crude rate, crude sulfur level, sulfur compound 

composition of crude (varies with geographical location of crude source), 

and processing scheme. 

2. What is the sulfur content of crude oil (typical and range)? How does 

the crude oil sulfur content affect the operation of amine treaters and the 

level of H2S and other sulfur compounds in the fuel gas? 

Sulfur content in the crude oil averages about 1%. The range of sulfur in 

crudes processed at the Refinery has been 0.03% to 3.2% by weight. During 

runs of high sulfur crudes, amine treating system loading will increase to 

keep fuel gas on spec. 

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

%affect the sizing, operation, and cost of your amine treating system? 

As any product is desulfurized, the off gas will add to the loading on the 

amine units. The cost of treating is directly proportional to the quantity 

of sour gas to be treated. Approximately 10% of the total sour make gas is 

generated in the desulfurization of products. 

4. How much natural gas (if any) is blended with the refinery fuel gas prior to 

combustion (typical and range)? Is this blending done primarily to keep 

constant flow of gas to process units or to dilute the H2S concentration 

to an acceptable level? 

The Refinery purchased an average of 39,800 MMBTU/D of natural gas in 1984. 

This amounted to 32% of Refinery usage. Purchased Natural gas can range 

from 26 to 46% of Refinery fuel gas usage. Natural gas is purchased to 

supplement Refinery fuel as is needed to supply energy to the Refinery, not 

to dilute H2S concentration. 
P.27 

X-l 

[. 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? 

We have had no problems in interpreting the NSPS. We have had, however, some 

problem is achieving and maintaining the NSPS. The problem lies in the complexity 

of our make gas and amine treating system. We have over 35 different make 

gas streams that are normally amine treated in various combinations in 

5 amine contactors. Practically all of these can go more than one route to more 

than one amine unit and have bypass routes directly to the fuel system 

(normally closed). It was a lengthy and difficult process to identify each 

of these streams, determine their potential to affect the resultant H2S 

in fuel gas concentrations, and develop control strategies for the various 

processing modes encountered in normal operation. The amine units themselves had 

to be overhauled to some extent and then operated over a long period to learn 

how to achieve the lowest outlet H2S concentration. The control of an 

amine treater is sometimes more of an art than a science. 

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? 

The primary problem withthe NSPS has been the magnitude of effort required 

to bring the program to its current level of proficiency. The operating department 

has become able to keep fuel gas H2S concentrations down during routine 

operations and have limited the length of excursions during periods of 

unit upsets. The instrument department calibrates and checks the continuous analyzer every weekday to insure proper operations. Automation 

of unit controls and computer communications have enabled direct acquisition of analyzer generated data. Laboratory personnel perform 

monthly checks on the analyzer, and the environmental control department 

draws all the information together to produce a quarterly report meeting 

federal standards and also prepares the state required notification letters. 

The participation of virtually every department in the plant spreads the 

workload over various persons without unduly burdening anyone. A facility 

which does not have the personnel and particularly the computer capabilities 

that we have would be more burdened by the requirements more than we are. 

With regard to the manual sampling program, fewer people are involved. The 

operators catch the samples and coordinate unit operations to stay within the 

standards. Environmental control personnel prepare the quarterly reports 

and exceedence notification letters when necessary. The only major problem 

encountered in establishing the manual sampling system for the F-104 fuel gas 

streams was getting the Draeger tube readings every shift. Often when the unit 

was in an upset or down or the operator was just busy, they would occasionally 

miss a reading. However, when the operator realized the importance of these 

analysis both for reporting purposes and as a key operational indicator, the 

response improved. 

In view of our considerable experience in operating under this program, we 

have several suggestions for changes of the Subpart J NSPS for H2S in fuel 

gas: 

• •• -
P.28 

X-2 

(1) The use of Draeger tubes for occasional monitoring of process data 

should be encouraged, but should not be a permanent substitute for a 

compliance determination method. Draeger tubes are not repeatible and 

accurate enough to be used for compliance determination. Additionally, 

they are expensive and labor consuming. 

(2) The standard should be raised to at least 500 to 1000 ppmv (708-1417 mg/dscm). 

The purpose of the NSPS is to achieve and maintain the NAAQS for S02. • 

It is our experience that the NSPS could be raised to those levels while 

still maintaining the air quality standards. We would encourage the use 

of air quality dispersion modeling or actual air monitoring of existing 

facilities to support this premise. We would also encourage use of the 

ppm by volume unit because of the greater ease of calculation. A ppm is a 

ppm in either the english or metric system. 

(3) The period of the standard should be increased from a 3 hour average to a 

8 hour standard. This would allow occasional upsets to occur and be 

corrected within the 8 hour period without causing a violation. The 

existing standard does not allow enough time to find the source of the 

problem and correct it before an exceedence is produced. 

(4) We recommend that the reporting of exceedences only be maintained. If all 

H2S reading have to be reported, the extra work required on reporting 

requirements would be considerable. As it is at present, if no exceedences 

are reported, then our reporting work is essentially over. We have 

enough routine reports to do without requiring more. 

How much does it cost you to comply with the NSPS regulations for recordkeeping 

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

and a sample of a report. 

See Table VIII below for the cost of recordkeeping and reporting. 

TABLE VIII 

Cost of NSPS Recording & Reporting 1984 

Console Operator 

-Fill out report 5 minute (last year 45 times) $70 

Environmental 

-Write Exceedence letter 8 hours (10 letters) $1649 

-Prepare quarterly 24 hours (4 reports) 1949 

Data Processing 

-Program development 2473 --

Total Annual Cost $6171 

A copy of the shift report for H2S in fuel gas is enclosed as Attachment 8. 

The recordkeeping for Draeger tubes is included in Attachment 4. A copy 

of the Quarterly report is included as Attachment 5. 
P.29 

XI-1 

XI. CONTACT FOR FURTHER INFORMATION 

Please include the names and phone numbers of appropriate contacts should 

clarification of the above information be needed. 

For information about material submitted, please contact 

David K. Monfore 

Staff Engineer 

318-491-7371 

For general refinery information, please contact 

James E. Miller 

Manager, Technical Services 

318-491-7356 
P.30 

SULFUR RECOVERY UNITS WITH TAIL GAS CLEANUP 

AND 

SULFURIC ACID DOUBLE CONTACT/DOUBLE ABSORPTION UNIT 

Parsons SRU 

Train € 120 T/D 

Be a von 

Hydrogenation 

Unit 

Parsons SRU 

Train D 120 T/D 

Beavon 

Hydrogenation 

Unit 

Parsons SRU 

Train E 120T/D 

i 

150 Ft 

et 

i -eBeavon 

Hydrogenation Unit: 

Stretford 

Absorber 

Tail 

Gas 

Stretford 

Liquor 20 

Oxidizer T/D 

Z 

Stretford 

Absorber 

Stretford 

Absorber 

Tail 

Gas 

Tail 

Gas 

Central Amine H„S 

Sulfuric 

Acid Unit B 350T/D -e-

\ 

0- DC/DA Unit 

36.4T/D 

Emergency Bypass 

rO Stack 

250 Ft. 

.<> 

- 4— FGPU H2S 

LERU, Benzene Amine H„S Sketch 3 

Revised 3/11/S5 

D. K. Monfore 
P.32 

- , ,.-

• 

Attachment 

Attachment 

Attachment 

Attachment 

2-

2-

2-

2-

ATTACHMENT 2 

Complete copy of all emission 

on fuel gas to NSPS combus 

-1 

-2 

-3 

-4 

• 

testing performed 

tion devices. 

Citgo Petroleum Corporation 

P. 0. Box 1562 

Lake Charles, LA 70602 

CONTENTS 

- 'B' LCOH Unit 

February 24-25, 1981 

- 'A' and 'B' Topping Unit 

April 1, 1982 

- 'C Reformer Unit 

October 12, 1982 

- Coker II Unit 

December 15-16, 1983 

Attachment 2-5 - Coker II Unit Retesting 

March 2, 1984 

Attachment 2-6 - Unicracker Unit 

July 24, 1984 

Note: Some of the pages in these reports were not needed for H2S 

in fuel gas testing data and were therefore deleted. 
P.33 

. 

ATTACHMENT ?-l 

COMPLIANCE PERFORMANCE TEST REPORT 

I. Introduction 

a. Company Name and Address: 

Cities Service Company 

P. 0. Box 1562 

Lake Charles, LA 70602 

b. Signature of Responsible Company Official for Submitting Report: 

\cJr />Jich*&?*r-~ 

vk"T. ThompsonU 

iW-figer Operations Engineering 

c. Testing Organization and Address: 

Performed "in house". 

d. Signature of Responsible Test Organization Offical for Submitting 

Report: 

Not applicable. 

e. Test Dates: 

February 24, 1981 

February 25, 1981 

f. Names and Titles of Test Personnel: 

G. L. Grout - Chemist 

F. R. Smith - Staff Chemist 

g. Schematic Drawing of Process: 

See Figure 1. 

h. Description of Process being Sampled: 

The process unit that heater B-l01 is a part of is a 

light cycle oil hydrotreater. A light oil stream is 

mixed with hydrogen gas and heated in a set of 

exchangers and then in a small process heater (existing). 

The hot oil/hydrogen mix is then reacted in a set of 

tv/o reactors in series containing a cobalt/molybdenum 

catalyst. The reaction mixture is cooled and flash 

separated. The recycle gases go to the fuel gas system 

and the oil goes to a fractionation tower. The bottoms 

of the tower is heated with the new heater B-l01 for heat 

input to the tower. The overhead of the tower goes to 

the fuel gas system and the bottoms, after cooling, go 

to product storage.. 
II Summary 

a. Summary of Test Results and Performance Standard: 

Test # Date 

1 

Time 

:e Standard: 

H2S in Fuel Gas 

mg/dscm 

96 

157 

50 

101 

Performance Std. 

mg/dscm 

230 

230 

230 

230 

P.34 

• •• 

2/24/81 10:54 a.m.-12:30 p.m 

2 2/24/81 1:41 p.m.- 3:30 p.m 

3 2/25/81 8:45 a.m.-10:27 a.m. 

Average for 3 runs 

b. Isokinetic Rates: 

Not applicable. 

c. Design, Normal Maximum, and Actual Operating Level of Process 

during Tests: 

Design - 10,000 BPD Light Cycle Oil 

Normal - 10,000 BPD Light Cycle Oil 

Actual - 10,300 BPD Light Cycle Oil 

Operating levels are measured with orfice flowmeters. 

d. Air Pollution Control Equipment: 

Amine gas treating units are used to control the level 

of H2S in the fuel gas. For actual levels of operation 

of amine units and flow of fuel gas, see Figures 2 and 3. 

e. Opacity Readings: 

No official opacity readings were taken during the test, 

but there were no visible emissions from the stack. 

III. Procedure 

Method 11 - H2S in fuel gas - was used. The sample was taken from 

the center of the fuel gas line by use of a stainless steel probe. 

There were no variations from the official method. 

IV. Analytical Techniques 

The three impingers containing the CdS04 were rinsed into a 500 ml 

iodine flask with deionized water. Due to the residual cadmium 

sulfide remaining in the impingers, a portion of the 50 milliliters 

of acidified iodine was used to rinse the impingers into the flask. 

The flask was quickly stoppered after each addition. The flask 

was then shaken and placed in the dark for 30 minutes. A blank 

was also set up for this method. 
P.35 

After 30 minutes the samples were titrated using O.OIN^ sodium 

thiosulfate solution until the solution fades to a light yellow. 

Starch indicator is added to the flasks and the titration continued until a blue color just disappears. 

A special stainless steel probe was designed in order to assure 

that the samples were drawn "from a point near the centroid of the 

fuel gas line". 

V. Chain of Custody 

G. L. Grout and F. R. Smith, Chemists, were responsible for 

collecting the samples. 

G. L. Grout determined the hydrogen sulfide concentrations as 

described in Method 11. 

VI. Test Data and Calculations 

a. Field Data Collected: 

See Table 1. 

b. Log of Process Operations 

See Figures 2 and 3. 

c. Laboratory Data and Standarization 

See Table 2. 

d. Emission Calculation 

See Table 3. 
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P.41 

1. Cal' 

com 

VII. Appendix 

a. Calibration of Dry Gas Meter 

librated wet test meter using bomb calibrated to 

itain 0.100 ft3 (NBS) 

2. Passed exactly 0.1 ft3 of gas through dry gas meter 

Vuncorr. = 0.1063 

Temp * 296°C 

Pressure = 764 mm Hg 

vcorrected = (0.1063)(764)(273) 

(760)(296) 

vc = 0.0986 ft3 

(0.0986)(x) = 0.1 ft3 

x = 1.014 

Factor = 1.014 @ STP 

Resume of Lab Personnel Conducting Tests: 

1. F. Ray Smith, Staff Chemist 

B.S. in Chemistry with minor in Math from Northwestern 

State. M.S. in Organic Chemistry from Northwestern State. 

5 years experience at Olin Corporation in Lake Charles 

as Analytical Organic Chemist. Has experience in Instrumentation, 

Wet Chemistry. 1 year experience at Cities Service as Staff 

Chemist. 

Member of American Chemical Society. 

2. Gretchel L. Grout, Chemist 

B.S. in Chemistry from McNeese State University. Candidate 

for M.S. in Chemistry at McNeese. 

2 years experience at Conoco Chemicals in Lake Charles 

as Chemist. 3 years experience at Cities Service. Experienced 

mainly in Wet Chemistry with Instrumental endpoints, environmental projects and water effluent analysis and quality 

assurance. 

Member of American Chemical Society. 

Description of Continuous Monitoring System: 

Manufacturer: Bendix Corp. 

Model Number: 7170 

Serial Number: Controller 58259-603, Analyzer 58248-1087 

Monitoring Scheme: Extractive with gas chromatographic 

analyses of H2S peak using thermal 

conductivity detection. 
P.42 

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8.5 MMSCFD 

Refinery 

Make Gas 

7.9 MMSCFI 

8.6 MMSCFD 

Refinery 

Make Gas 

7.7 MMSCFD 

Refinery 

Make Gas 

JAS-DKM/tb 

04/06/81 

SIMPLIFIED FLOW DIAGRAM 

F-2 DRUM FUEL GAS SYSTEM 

FOR FEBRUARY 24, 1981 

CITIES SERVICE COMPANY 

<.l MMSCFD 

—. H2S Gas to SRU 

3.3 MMSCFD 

Light Ends Recovery Unit 

E-204 Amine Treater 

Amine Circ. = 180 gpm 

Lean Amine Cone. = 21.1% MEA 

0.5 MMgQF/p 

1.9 MMSCFD 

Fuel Gas Process Unit 

E-3A Amine Treater 

Amine Circ. = 315 gpm 

Lean Amine Cone. - 17.8% DEA 

14.6 MMSCFD 

I 

lU MMSCFD 

Fuel Gas Process Unit 

E-3 Amine Treater 

Amine Cir. = 265 gpm 

Lean Amine Cone. = 17.8% DEA 

I 

I 6.3 MMSCFD 

I 

17.1 MMSCFD 

Excess Ho Gas 

74.5 MMSCFD 

00 

.«. and Acid Plant 

Fuel Gas to 

Other Refinery 

Process Units 

F^2 Drum -

Fuel Gas System 

"B" Light Cycle 

Oil Hydrotreater 

A 

B-101 

Furn. 

Feed Rate = 

10.4 MBPD 

0.37 MMSCFD 

Sample Point 

45.7 MMSCFD 

4.7 MMSCFD 

Purchased 

Natural Gas 0 MMSCFD 

Fuel Gas to other 

Plants and F-104 Drums 

Natural Gas to 

Petrochemical Plant 

Feed Gas to 

Petrochemical Plant 

FIGURE NO. 2 
8.1 MMSCFD 

Make Gas 

o 

tn 

9.0 MMSCFD 

Make Gas 

8.5 MMSCFD 

Make Gas 

JAS-DKM/tb 

04/06/81 

SIMPLIFIED FLOW DIAGRAM 

F-2 DRUM FUEL GAS SYSTEM 

FOR FEBRUARY 25, 1981 

CITIES SERVICE COMPANY 

<.l MMSCFD 

3.4 MMSCFD 

_^ H2S Gas to SRU 

and Acid Plant 

Light Ends Recovery Unit 

E-204 Amine Treater 

Amine Circ. » 174 gpm 

Lean Amine Cone. = 23.0% MEA 

2.0 MMSCFD 

Fuel Gas Process Unit 

E-3A Amine Treater 

Amine Circ. = 338 gpm 

Lean Amine Cone. = 16.9% DEA 

Fuel Gas Process Unit 

E-3 Amine Treater 

Amine Circ. =274 gpm 

Lean Amine Cone. = 16.9% DEA 

14.5 MMSCFD 

4 MMSCFD 

CS| 

7.1 MMSCFD 

19.2 MMSCFD 

Excess H2 Gas 

74/5 MMSCFD 

Fuel Gas to 

Other Refinery 

Process Units 

F-2 Drum 

Fuel Gas System 

"B" Light Cycle 

Oil Hydrotreater 

A 

3-101 

Furn. 

Feed Rate = 

10.2 MBPD 

0.38 MMSCFD 

Sample Point 

Purchased 

Natural Gas 

50. 3 MMSCFD 

3.2 MMSCFD 

4.9 MMSCFD 

FIGURE NO. 3 

Fuel Gas to other 

Plants and F-104 Drums 

Natural Gas to 

Petrochemical Plant 

Feed Gas to 

Petrochemical Plant 
P.45 

ATTACHMENT 2-2 

Page 1 

COMPLIANCE PERFORMANCE TEST REPORT 

'A' & 'B' TOPPER HEATERS 

Introduction 

A. Company Name and address: 

Cities Service Company 

P. 0. Box 1562 

Lake Charles, LA 70602 

B. Signature of Responsible Company Official 

E. W. lurnbulT** 

Ua 

Manager, Refinery 

Testing Organization and Address: 

Entropy Environmentalists 

P. 0. Box 12291 

Research Triangle Park, NC 27709 

Signature of Responsible Test Organization Official: 

See attached report (Attachment 4) 

Test Dates: 

March 30, March 31 and April 1, 1982 

Names and Titles of Test Personnel: 

Name Ti tle 

Organization 

J. T. Nash 

J. A. Winstead 

G. L. Grout 

F. R. Smith 

Team Leader 

Engineering Technician 

Chemist 

Staff Chemist 

Entropy Environmentalists 

Entropy Environmentalists 

Cities Service Company 

Cities Service Company 

Schematic Drawing of Process: 

See figures 1, 2, and 3. 
P.46 

ATTACHMENT 2-2 

(continued) Page 2 

II. 

H. Description of Process being Sampled: 

Heaters B-4 and B-104 are part of two crude atmospheric 

distillation units. Desalted crude oil is preheated to 400°F by 

exchange with various distillation products and is then heated 

to fractionation temperature of approximately 700°F in the unit 

process heater. Various fractions of the crude are taken off the 

fractionation tower and are separated into the different products, 

Product and intermediate streams include topper tail gas, topper 

overhead, kerosene, light gas oil, heavy gas oil, and residuum. 

The new process heaters (B-4 and B-104) are designed as 

an eight pass unit with horizontal convection section and 

vertical radiant section. Each heater is equipped with a forced 

draft (FD)/induced draft (ID) fan system and a regenerative type 

Ljungstrom air preheater. Ten floor mounted John Zink high 

intensity low N0X burners (HIV-70) are used for combustion of 

either fuel oil, fuel gas, or both fuel. At the time of testing, 

both heaters were fired with fuel gas. The fuel gas burned is 

a mixture of process make gases that have been amine treated 

for H2S removal. 

Summary 

A. Summary of Test Results and Performance Standard: 

See Table I and Table II. 

B. Isokinetic Rates: 

See Attached Report (Attachment 4) . 

C. Design, Normal Maximum and Actual Operating Level of Process 

during Tests: 

Unit 

'A' Topper 

'B' Topper 

'A' Topper 

'B' Topper 

Item 

Crude Rate 

Crude Rate 

Heat Release 

Heat Release 

TABLE III 

Design Rate 

117 MBPD 

130 MBPD 

456.6 MMBtu/hr 

456.6 MMBtu/hr 

Normal Rate 

100 MBPD 

110 MBPD 

320.0 MMBtu/hr 

360.0 MMBtu/hr 

Actual Rate 

106 MBPD 

108 MBPD 

390.5 MMBtu/hr 

366.6 MMBtu/hr 

The actual rate of crude processing was limited at the 

time of testing by the amount of sales of products and the crude 

oil inventory. The proper criteria to use in specifying limits 

of pollutant emissions is the million Btu per hour of heat 

release, since pollutant emissions are only released in the 

combustion of fuel. In order to fire the heaters as high as 
P.47 

ATTACHMENT 2-2 

(continued) 

possible while maintaining a more limited crude rate, certain 

crude preheat exchangers were bypassed to create a need for 

more fired duty. The unit crude rate can vary extensively 

while operating at or below the permitted heat release. 

D. Air Pollution Control Equipment: 

Page 3 

Sulfur dioxide emissions are controlled by limiting 

the level of hydrogen sulfide in the fuel gas. Amine units 

are used to remove H£S from the fuel gas to acceptable levels. 

The processing scheme of our fuel gas amine treating units 

can be varied extensively for maximum efficiency and economy, 

while still providing acceptable HoS levels. The actual level 

of operation of the amine units and fuel gas processing scheme 

on the days of testing is provided as Figures 4, 5, and 6. 

Oxides of Nitrogen are controlled by use of low N0X 

burners and by limiting the amount of excess air used in 

combustion. Particulates (mostly soot) from fuel gas combustion, carbon monoxide, and opacity are controlled by 

providing sufficient excess air to insure good combustion. 

Part B of our testing program involved the testing of the 

furnaces for N0X and CO at varying levels of excess air in 

the firebox. Testing was performed at three levels of 

oxygen (high, normal, and low) and at two operating rates 

(high and normal). Oxygen levels from the firebox were 

plotted against the pounds per hour of NO and CO emitted 

to determine the upper and lower limits of oxygen that the 

unit would have to stay between to avoid exceeding the 

standards. These graphs are enclosed as Figures 7 and 8. 

The results of Part B testing indicate that while burning 

fuel gas, neither N0X or CO is limiting the oxygen range 

of the furnace. 

E. Opacity Readings: 

Opacity observations were performed by Mr. William 

Coltrin of the Air Quality Division of the Department of 

Natural Resources on April 1, 1982. These readings are 

attached as Attachments 2 and 3. 

III. Procedure 

EPA Reference Methods (40 CFR Part 60 - Appendix 'A') 

were used for all testing and were applied in a rigorous 

manner. A copy of the applicable methods is included as 

Appendix 'D' in the attached report (Attachment 4). There 

were only two deviations from the official methods: 

The sampling trains for particulates and SO2 (Methods 

5 and 8) were combined so that both could be collected 

simultaneously. The Method 8 impinger train (one impinger of 
ATTACHMENT 2-2 

(continued) Page 4 

isopropanol, two impingers of Hydrogen Peroxide, and one impinger 

with silica gel) was substituted for the Method 5 impinger train 

(two water impingers, one empty impinger, and a silica gel 

impinger). This modification makes no difference to the Method 5 

analyses, in that the only purpose of the impingers is to collect 

moisture and dry the gas stream. This was accomplished with the 

Method 8 train with no loss of efficiency or accuracy. Since 

we are analyzing for SO2 rather than SO2 and acid mist, the main 

filter is in the heated compartment ahead of the first impinger 

as in Method 5. A secondary filter of glass wool has been 

inserted between impingers one and two to prevent carryover of 

any isopropanol or acid mist into the peroxide impinger. 

In 3 of the 6 runs for TSP and SOp, one of the standard 

Smith-Greenburg impingers was replaced with a modified SmithGreenburg impinger in order to reduce pressure drop through the 

impinger train. Without this substitution, it might have been 

impossible to draw enough vacuum to insure isokinetic flow. 

The standard Smith-Greenburg impinger is a little more efficient 

than the modified one. Method 8 calls for one standard and one 

modified impinger for collection of the SO2 and conversion to 

sulfuric acid. In series, the total collection efficiency of 

the two impingers still exceeds 96% even with two modified 

impingers. Since the measured SOp is so far below the limit 

(30#/hr vs. 479#/hr), this substitution makes an insignificant 

effect upon the results of the testing. 

IV. Analytical Technique 

Standard EPA reference methods were used as explained 

in Section III. Additional details including calibration data 

are provided in the attached report (Attachment 4) . 

V. Chain of Custody 

A. Methods 1-8, 10: 

All of the samples were collected by John Nash and 

Andy Winstead. Some of the analyses such as orsat were 

conducted at the time of sampling. The remainder of the 

samples were carried back to Research Triangle Park for 

analyses in the home office of Entropy Environmentalists. 

Analyses of the carbon monoxide in the integrated gas sampling 

bags was conducted by W. E. Reynolds of Entropy Environmentalists. 

B. Method 11 

H2S in fuel gas was determined by Method 11 by G. L. 

Grout and F. R. Smith of Cities Service. 
P.49 

ATTACHMENT 2-2 

(continued) Page 5 

VI. Test Data, Calibrations, and Calculations 

A. Methods 1-8, 10: 

See attached report (Attachment 4) . 

B. Method 11, H2S in fuel gas: 

1. Calibration of Dry Gas Meter 

a. Procedure 

Exactly 0.100 cubic feet (CF) of ambient air from an 

NBS calibrated container is displaced with water into the 

dry gas meter to be calibrated. The meter readings before 

(0.000) and after are taken and the test repeated 5 times. 

The temperatures and pressures of the apparatus are allowed 

to equilibrate to room conditions, so that no corrections 

for temperature and pressure are needed. The calibration 

factor will be obtained by dividing the actual volume 

(0.1 CF) by the meter reading and is a unitless factor. 

b. Calculations 

True Value (VT) = 0.100 CF 

Measured Volume (V ) = 0.094 CF (average of 5 runs) 

Factor = VT/Vm = 0.100/0.094 = 1.064 

2. Resume of Lab Personnel Conducting Tests 

a. F. Ray Smith, Staff Chemist 

B. S. Chemistry with minor in Math from Northwestern 

State. M.S. in Organic Chemistry from Northwestern State. 

5 years experience at Olin Corporation in Lake Charles 

as Analytical Organic Chemist. Has experience in 

Instrumentation, Wet Chemistry. 2 years experience at 

Cities Service as Staff Chemist. 

Member of American Chemical Society. 

b. Gretchel L. Grout, Chemist 

B.S. in Chemistry from McNeese State University. 

Candidate for M.S. in Chemistry at McNeese. 

2 years experience at Conoco Chemicals in Lake Charles 

as Chemist. 4 years experience at Cities Service. Experienced 

mainly in Wet Chemistry with Instrumental endpoints, environmental 

projects and water effluent analysis and quality assurance. 

Member of American Chemical Society. 
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TABLE II 

Summary of Results 

(Method 11 - H2S in Fuel Gas) 

Page 12 

Run 

No. 

1 

2 

3 

Average 

Date 

4/1/82 

4/1/82 

4/1/82 

4/1/82 

Time 

7:57 - 9:04 

10:48 - 12:02 

2:02 - 3:08 

7:57 - 3:08 

Performance Standard Method 11 Results 

mg/dscm ppmv mg/dscm ppmv 

230 

230 

230 

230 

162 

162 

162 

162 

48 

25 

23 

32 

34 

18 

16 

22 

Analyzer 

ppmv 

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21 

22 

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mg/dscm = milligrams HpS per dry standard* cubic meter 

ppmv = parts per million by volume (assuming ideal gas law) 

•Standard conditions are 20°C and 760 mm Hg 
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Page 1 

ATTACHMENT 2-3 

COMPLIANCE PERFORMANCE TEST REPORT 

'C REFORMER 

Introduction 

A. Company Name and address: 

•Cities Service Company 

P. 0. Box 1562 

Lake Charles, LA 70602 

B. Signature of Responsible Company Official: 

J. R. Bowler 

General Manager, Operations 

C. Testing Organization and Address: 

Entropy Environmentalists 

P. 0. Box 12291 

Research Triangle Park, NC 27709 

D. Signature of Responsible Test Organization Official: 

See attached report (Attachment 2) 

E. Test Dates: 

October 12 through October 17, 1982 

F. NameNams ane d Titles of Test Personnel: 

W. S. Nesbit 

J. A. Winstead 

S. S. Helms 

G. L. Grout 

F. R. Smith 

Title Organization 

Entropy Environmentalists 

Engineering Technician Entropy Environmentalists 

Engineering Technician Entropy Environmentalists 

Team Leader 

Chemist 

Staff Chemist 

Cities Service Company 

Cities Service Company 

G. Schematic Drawing of Process: 

See figures 1 and 2. 
P.63 

Page 2 

ATTACHMENT 2-3 

(continued) 

H. Description of Process being Sampled: 

1. Introduction 

Cities Service Company has constructed in its Lake Charles 

Refinery a 45,000 BPD Continuous Platformer. The Unit is 

capable of converting low octane virgin and coker gasoline 

to a 102 Research octane product substantially by the conversion of paraffinic and naphthenic hydrocarbons to 

aromatics. Permits to operate and construct the unit were 

obtained from the State of Louisiana (Permit No. 1168-R) 

and the Federal Government (Permit No. PSD-LA-222). 

This Unit is necessary due to TEL (tetra ethyl lead) phasedown schedules set forth by the Environmental Protection 

Agency restricting the use of lead alkyls in motor gasoline 

blending. These restrictions will generate an excess of 

low octane gasoline blending components which cannot be 

blended into motor gasoline. Thus, additional reforming 

capacity is necessary to upgrade the octane of these components in order to comply with EPA regulations. 

2. Process Description 

The Unit is called 'C' Reformer and is comprised of three 

basic.sections: 

a. Naphtha Hydrotreater 

b. Moving Bed Platformer 

c. Continuous Catalyst Regeneration Section 

Each section is described in general below: 

3. Naphtha Hydrotreater Section 

The Naphtha Hydrotreater is capable of processing a total of 

40,500 BPD virgin gasoline and 4,500 BPD of coker gasoline 

to reduce the sulfur and nitrogen content of the feed to the 

Platformer since the catalyst utilized in the Platformer is 

rendered inactive by these catalyst "poisons". The Naphtha 

Hydrotreater Reactor contains a Nickel-molybdenum catalyst 

in a fixed down-flow bed. Hydrogen produced on the Platformer is used in the treating process. 

An absorber is included as an integral part of the Naphtha 

Hydrotreater using total fresh feed as a lean oil to recover 

light ends (primarily propane and heavier) from two Platformer 

gas streams plus a combined gas stream from the existing 

Reformers. Hydrogen gas from this absorber is then routed 

to the Refinery Fuel system and is also used as the primary 

fuel for the 'C' Reformer unit heaters. Sour gas from the 

Naphtha Hydrotreater flash drum is routed to an existing 

Refinery Amine treater for removal of H2S before being routed 

to fuel. 
Page 3 

ATTACHMENT 2-3 

(continued) 

The liquid product from the Hydrotreater is stripped of ^ S 

and water before being routed to the Platformer section of 

the Unit. A small overhead liquid stream from the stripper 

tower is produced which is sent to an existing Refinery 

Amine Treater for H2S removal. (See figure 1 for more 

details.) 

Platformer Section 

This Platformer incorporates UOP's latest design features 

including a stacked 3 reactor system. The stacked arrangement facilitates gravity flow of catalyst through the 3 

reactor vessels. The principal reforming reactions are 

endothermic, thus intermediate heaters between reactors are 

necessary to replace the endothermic heat lost in the 

preceding reactor. A large cabin type furnace containing 

3 individual cells is utilized for preheating and reheating 

feed. A common convection section utilizing coils for waste 

heat steam generation is employed to obtain maximum thermal 

efficiency. 

Effluent from the Platformer reactors is cooled and separated 

into gas and liquid products. Hydrogen produced is the 

source of hydrogen for the Naphtha Hydrotreater section with 

excess amounts going to the absorber described in the Naphtha 

Hydrotreater section. Liquid product from the separator is 

stabilized in a Debutanizer tower before being routed to 

tankage for use as a high octane blending component. A small 

overhead liquid stream is also produced on the Debutanizer 

which is sent to an existing Refinery fractionation plant. 

(See Figure 1 for more details.) 

Catalyst Regeneration Section 

Partially spent catalyst flows from the bottom of the third 

Platformer reactor to a catalyst collector, a lock hopper, 

and then batchwise transferred to a Regenerator vessel by 

way of a gas lift utilizing nitrogen as an inert gas. In 

the Regeneration tower, carbon is burned from the catalyst, 

metal activators are dispersed, and chloride content reestablished, restoring the catalyst to essentially fresh 

catalyst activity. A similar sequence of lock hopper then 

lift engager is utilized and the regenerated catalyst is 

gas lifted to the top of the first Platformer reactor. The 

carrying gas in this case is hydrogen which also serves to 

reduce the oxidized catalyst completing the final step in 

the regeneration process. 

The Regeneration section is capable of circulating 2,000 

lbs/hr. of spent catalyst while maintaining 5 wt. % carbon 

on catalyst in the third reactor. A small Regenerator vent 

stream to the atmosphere purges the system of combustion 

products (primarily CO- and excess O2). (See figure 2 for 

more details.) 
P.65 

Page 4 

ATTACHMENT 2-3 

(continued) 

II. Summary 

A. Summary of Test Results and Performance Standard: 

See Table I and Table II. 

B. Isokinetic Rates: 

See Attached Report (Attachment 2). 

C. Design, Normal Maximum and Actual Operating Level of Process 

during Tests. 

See Table III. 

D. Air Pollution Control Equipment: 

Sulfur dioxide emissions are controlled by limiting the level 

of hydrogen sulfide in the fuel gas. In the present configuration, the 'C' Reformer heaters burn as fuel the platformer 

absorber offgas which is mainly hydrogen. Since the sulfur in 

the feed naphtha is removed in the unit hydrotreater prior to 

the platforming section, the hydrogen offgas is extremely sweet, 

normally having less than 10 ppmv of H2S. Amine treating of 

this gas stream prior to combustion is therefore unnecessary. 

Oxides of Nitrogen are controlled by use of low NO burners and 

by limiting the amount of excess air used in combustion. 

Particulates (mostly soot) from fuel gas combustion, carbon 

monoxide, and opacity are controlled by providing sufficient 

excess air to insure good combustion. Part B of our testing 

program involved the testing of the furnaces for N0X and CO at 

varying levels of excess air in the firebox. Testing was 

performed at three levels of oxygen (high, normal, and low) and 

at two operating rates (high and normal). Oxygen levels from the 

firebox were plotted against the pounds per million BTU of N0X 

and pounds per hour of CO emitted to determine the upper and 

lower limits of oxygen that the unit would have to stay between 

to avoid exceeding the standards. These graphs are enclosed as 

Figures 3, 4, and 5. 

The results of the Part B testing indicate that Heater B-503, 504, 

and 505 must stay between certain limits of oxygen in the flue 

gas as measured by the unit oxygen analyzers in order to not 

exceed the N0X and CO permitted limits. These limits were 

determined by plotting N0X in lb per million BTU and CO in lb 

per hour versus Oxygen in percent and are reported in Table IV. 

(See Figures 3 and 4.) The N0X plot was determined by use of 

least squares curve fit. The CO plot seemed to fit a curved 

path better and was drawn in that fashion. Since the firing of 

this heater is directly proportional to the operating level of 

the unit, two curves were drawn, one for maximum rates and one 

for normal rates. Correlation coefficients for these curves 

were good (>.98). 
P.66 

Page 5 

ATTACHMENT 2-3 

(continued) 

The firing rates for Heater B-501,502,506 are dependant upon 

the hydraulic rate of feed to the unit which is relatively 

constant. Accordingly, there was no significant difference 

between the Maximum and Normal unit operational rates. Only 

one curve (Figure 5) was drawn for the N0X testing by use of 

least squares curve fitting equations. The correlation 

coefficient for this curve was slightly lower (.88). 

The results for the CO testing indicate that at least one or 

more of this heater's burners (out of 9 total) was not properly 

balanced and emitted excessive amounts of carbon monoxide for 

the entire period of testing, except at very high oxygen levels. 

A plot of this data did not provide a very meaningful correlation coefficient (.7) and therefore was omitted. 

NO for both heaters and CO for heaters B-503, 504, 505 will be 

controlled by limiting the oxygen range of the heaters to the 

levels given in Table IV. CO for heaters B-501, 502, 506 will 

be controlled by rebalancing the burners in the heaters and by 

providing a reasonable excess oxygen. A request for a variance 

on the CO limit on heaters B-501, 502, 506 is enclosed in the 

cover letter to this report. 

Opacity Readings: 

Opacity observations were performed by Mr. Joe Withers of the 

Air Quality Division of the Department of Natural Resources on 

October 12, 13, and 14, 1982. These readings are summarized 

in Table I. 

III. Procedure 

EPA Referenced Methods (40 CFR Part 60 - Appendix 'A') were used for 

all testing and were applied in a rigorous manner. A copy of the 

applicable methods is included as Appendix 'D' in the attached report 

(Attachment 2). There were three deviations from the official methods: 

The sampling trains for particulates and SO2 (Methods 5 and 8) were 

combined so that both could be collected simultaneously. The Method 

8 impinger train (one impinger of isopropanol, two impingers of 

Hydrogen Peroxide, and one impinger with silica gel) was substituted 

for the Method 5 impinger train (two water impingers, one empty impinger, 

and a silica gel impinger). This modification makes no difference 

to the Method 5 analyses, in that the only purpose of the impingers is 

to collect moisture and dry the gas stream. This was accomplished 

with the Method 8 train with no loss of efficiency or accuracy. Since 

we are analyzing for SO2 only rather than SO2 and acid mist, the main 
P.67 

Page 6 

ATTACHMENT 2-3 

(continued) 

filter is in the heated compartment ahead of the first impinger 

as in Method 5. A secondary filter of glass wool has been 

inserted between impingers one and two to prevent carryover of any 

isopropanol or acid mist into the peroxide impinger. 

A Byron Instruments Model 233-A gas Chromatograph was used in place 

of the NDIR for the carbon monoxide measurements. Both instruments 

have similar sensitivities and accuracies, but the gas chromatograph 

does not have to subtract out a much larger CO2 background as does 

the NDIR. Calibration data and a linearity graph are enclosed in 

Appendix E of Attachment 2. 

In the Method 11 testing, one sample (2(a)) had to be discarded due 

to an apparent laboratory error. The measured absorbence from that 

sample was less than the blank which indicated that an incorrect 

absorbing solution had been used. The data from the rest of the 

samples was in the expected range. Since these samples are taken 

in duplicate for each run, the duplicate sample was used for the 

second run average and was used in the average for the day's testing. 

IV. Analytical Technique 

Standard EPA reference methods were used as explained in Section III. 

Additional details including calibration data are provided in the 

attached report (Attachment 2). 

V. Chain of Custody 

A. Methods 1-8, 10: 

All of the samples were collected by Willis Nesbit, Steve Helms, 

and Andy Winstead. Some of the analyses such as orsat were 

conducted at the time of sampling. The remainder of the 

samples were transported to Research Triangle Park, N.C. for 

analyses in the home office of Entropy Environmentalists. 

B. Method 11 

H2S in fuel gas was determined by Method II by G. L. Grout and 

F. R. Smith bf Cities Service. 

VI. Test Data, Calibrations, and Calculations 

A. Methods 1-8, 10: 

The lb per million BTU calculations as given in Attachment 2 by 
P.68 

Page 7 

ATTACHMENT 2-3 

(continued) 

Entropy Environmentalists were based on an assumed Hydrogen/ 

methane ratio. Actual heat content measurements of the fuel 

gas were used in the calculations for Table I of Attachment 1 

and should be used preferentially over those in Entropy's 

report. See Attached Report (Attachment 2) for additional 

information. 

B. Method 11, H2S in fuel gas: 

1. Calibration of Dry Gas Meter 

a. Procedure 

Exactly 0.100 cubic feet (CF) of ambient air from an 

NBS calibrated container is displaced with water into 

the dry gas meter to be calibrated. The meter readings 

before (0.000) and after are taken and the test repeated 

5 times. The temperatures and pressures of the apparatus 

are allowed to equilibrate to room conditions, so that 

no corrections for temperature and pressure are needed. 

The calibration factor will be obtained by dividing the 

actual volume (0.1 CF) by the meter reading and is a 

unitless factor. 

b. Calculations 

True Value (VT) = 0.100 CF 

Measured Volume (Vm) = 0.096 CF (average of 5 runs) 

Factor = VT/Vm = 0.100/0.096 = 1.047 

2. Resume of Lab Personnel Conducting. Tests 

a. F. R. Smith, Staff Chemist 

B.S. Chemistry with minor in Math from Northwestern 

State. M.S. in Organic Chemistry from Northwestern State. 

5 years experience at Olin Corporation in Lake Charles 

as an Analytical Organic Chemist. Has experience in 

Instrumentation, Wet Chemistry. 2 years experience at 

Cities Service as Staff Chemist. 

Member of American Chemical Society. 

b. Gretchel L. Grout, Chemist 

B.S. in Chemistry from McNeese State University. 

M.S. in Chemistry from McNeese State University. 
P.69 

Page 8 

ATTACHMENT 2-3 

(continued) 

2 years experience at Conoco Chemicals in Lake Charles 

as Chemist. 4 years experience at Cities Service. 

Experienced mainly in Wet Chemistry with Instrumental 

endpoints, environmental projects and water effluent 

analysis and quality assurance. 

Member of American Chemical Society. 

3. Raw Data - See following pages. 

4. Calculations - See following pages. 
TABLE II 

Run 

1 

2 

3 

Average 

Date 

10/12/82 

10/12/82 

10/12/82 

Summary of Results 

(Method 11 - H2S in Fuel Gas) 

Time 

8:45 - 9:55 AM 

12:21 - 12:32 PM 

2:18 - 3:32 PM 

Performance 

mg/dscm 

230 

230 

230 

230 

Standard 

ppmv 

162 

162 

162 

162 

Method 

mg/dscir 

8 

19 

9 

12 

11 

i 

Results 

ppmv 

5 

14 

6 

8 

mg/dscm = milligrams H2S per dry standard* cubic meter 

ppmv = parts per million by volume (assuming ideal gas law) 

* Standard conditions are 20°C and 760 mm Hg 

fB 

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P.71 

TABLE III 

Design, Normal Maximum, and Actual Operating 

Level of Process During Tests 

Page 11 

DATE 

10/12/82 

13 

14 

15 

16 

17 

Average 

Design 

Normal 

Maximum 

Unit Feed Rate 

BPD 

45,529 

45,366 

47,294 

51,148 

49,768 

46,141 

47,541 

45,000 

50,000 

Product Octane 

RONC* 

101.2 

101.3 

97.3 

96.7 

96.0 

96.0 

98.1 

102.4 

98.0 

B-501, 502, 506 

Heat Release 

MMBTU/HR 

121.1 

120.4 

N/A 

N/A 

N/A 

127.0 

122.8 

198.54 

125.0 

B-503, 504, 505 

Heat Release 

MMBTU/HR 

N/A 

N/A 

477.6 

511.5 

431.1 

N/A 

473.4 

536.95 

500.0 

* Research Octane Number Clear 
P.72 

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ATTACHMENT 2-4 

COMPLIANCE PERFORMANCE TEST REPORT 

COKER II FURNACES B-201 AND B-202 

Company Name and Address: 

CITGO Petroleum Corporation 

P. 0. Box 1562 

Lake Charles, LA 70602 

Signature of Responsible Company Official: 

Jl R. Bowler 

General Manager, Operations 

Testing Organization and Address: 

York Research Consultants 

938 Quail Street 

Denver, Colorado 

Signature of Responsible Test Organization Official: 

See attached report (Attachment 2) 

Test Dates: 

December 15 through 17, 1983 

Names and Titles of Test Personnel: 

Name Title Organization 

Carolyn Grahm Project Manager York Research Consultant 

Joey Landreneau Project Engineer York Research Consultant 

John Floyd Project Engineer York Research Consultant 

F. R. Smith Staff Chemist CITGO Petroleum Corp. 

G. L. Grout Staff Chemist CITGO Petroleum Corp. 

Schematic Drawing of Process: 

See Figures 1 and 2. 

Description of Process Being Sampled: 

1. CITGO Petroleum Corporation has constructed in its Lake Charles 

• Refinery a 35,000 BPD Delayed Coking Unit. The process utilizes 

thermal cracking to upgrade residual oils to more valuable 

P.79 

a l 
P.80 

products, such as gasoline and number two fuel oil blend stocks. 

Permit to construct and operate the unit was obtained from the 

State of Louisiana under Permit No. 1594. 

2. Process Description 

In the thermal cracking process, petroleum coke is produced in 

large drums as a co-product of the reaction. The coke accumulates 

in the drum until the drums are full, at which time the drum is 

taken out of service and the coke removed from the drum. A more 

detailed description of the process follows. 

Fresh feed is processed through a fractionator to remove light 

ends and to provide preheat. The feed then leaves the fractionator along with the recycle where it is split as charge for the 

two identical furnaces (Sources 3 (XXVI) 1 and 3 (XXVI) 2 in the 

EIQ). The charge is heated to 920°F and then given a 'delayed1 

soaking period in the coke drums where the thermal cracking process 

is completed. 

Cracked products are taken from the overhead of the coke drums 

and separated in a fractionator. The fractionator products include: 

tail gas, naphtha, blend oil, heavy gas oil, and recycle. Coke isremoved from two drums per day by hydraulic decoking. The wet coke 

is cut into a pit beneath the coke drums. The coke is removed by 

cranes with buckets and put into rail cars or trucks for movement 

to the Port of Lake Charles for storage and shipment. 

Tail gas from the fractionator together with noncondensed hydrocarbon 

vapors from the blowdown drum (produced during the quenching/cooling 

cycle) is processed in a new amine contactor unit to recover HjS 

and produce make gas suitable for combustion in the.Refinery fuel 

gas system. A small portion of uncondensed vapors produced at the 

end of the blowdown period is flared, at the point at which the blowdown gas compressor would lose suction (approximately 5 psi). 

Simplified flow diagrams to illustrate the process and various pieces 

of equipment are provided in Figure 1 and 2. 

II. Summary 

A. Summary of Test Results and Performance Standard 

See Table I and Table II. 

B. Isokinetic Rates 

See attached report (Attachment 2). 
P.81 

I 

C. Operating Level of Process During Test 

The actual operating conditions of the Coker II Unit and the furnaces 

are given in Tables III and IV. For each performance testing, the 

• furnace firing rate was increased to a maximum firing rate while 

the firing rate for other furnaces was reduced accordingly. This 

'swinging' of the furnaces explains the discrepancy between the 

average heat release during the test and the expected normal maximum 

heat release shown in the Tables. 

D. Air Pollution Control Equipment 

Sulfur dioxide emissions are controlled by limiting the level of 

hydrogen sulfide in the fuel gas. Amine treating units are used 

to remove H2S from process make gas to acceptable levels. The 

processing scheme of' our fuel gas system can vary extensively for 

maximum efficiency and economy. 

Oxides of nitrogen are controlled by use of low NO burners. Particulates (mostly soot) from fuel gas combustion, carbon monoxide, and 

opacity are controlled by providing sufficient excess air to insure 

good combustion. 

E. Opacity Readings 

Opacity observations were performed by Mr. Kenneth Johnson of the 

Air Quality Division of the Department of Natural Resources on 

December 14 and 16, 1983. These results are given in Table I. 

III.Procedures 

EPA Referenced methods (40 CFR Part 60 - Appendix *A') were" used for all 

testing and were applied in a rigorous manner. There were three deviations 

from the official methods. 

The sampling trains for particulates and S0„ (Methods 5 and 6) were combined 

so that both could be collected simultaneously. A modified Method 6 impinger 

train (one standard size tipped impinger of isopropanol, two standard size 

untipped and tipped impingers of hydrogen peroxide, and one standard size 

untipped impinger of silica gel) was substituted for the Method 5 impinger 

train (two water impingers, one empty impinger, and one silica gel impinger). 

This modification makes no difference to the Method 5 analyses, in that the 

purpose of the method-5 impingers is to collect moisture and dry the gas stream. 

This was accomplished with the modified Method 6 train with no loss of 

accuracy to the method 5 test. The glass wool filter between the first and 

second impinger(normally used in Method 6) was also removed. Therefore, any acid 

mist from the first impinger would carryover into the peroxide impinger. This 

carryover gives a high bias to the result and therefore acceptable from 

the regulatory position. 

In the. molecular weight determination of the stack gas, an orsat analyzer 

was used to determine C02 of the gas stream. However, the oxygen content 

of the stack gas was determined by a Sybron-Taylor paramagnetic 02 analyzer. 
P.82 

In the Method 10 testing, one sample (N-1 or B-202) was discarded due 

to adverse weather conditions (rain and low temperatures). The instrument 

is sensitive to changes in ambient temperature and humidity and, before the 

first runs could be completed, these conditions varied dramatically, causing 

erratic readings for this first run. 

IV. Analytical Technique 

Standard EPA reference methods were used as stated in Section III. Additional details including calibration data are provided in the attached 

report (Attachment 2). 

V. Chain of Custody 

A. Methods 4-6, 10: 

All of the stack gas samples were collected by Carolyn Grahm and John 

Floyd. The orsat analysis, oxygen readings, and CO readings were 

conducted at the time of sampling. The S02 samples were analyzed on 

site by Carolyn Grahm while the remainder of the samples were transported to Denver, Colorado for analyses in the home office of York 

Research Consultants. 

B. Method 11 

H2S samples were ^gathered by F. R. Smith and returned to the refinery 

laboratory forcanaylsis) by Mr. Smith and Ms. G. L. Grout. 

VT . Test Data, Calibrations, and Calculations 

A. Methods 1-6, 10: 

All test data, calculations, and calibrations are given in Attachment 2 -

Report on Emission Testing prepared by York Research Consultants. 

B. Method 11, H2S in fuel gas: -.. 

1. Resume of Lab Personnel Conducting Tests 

a. F. R. Smith, Staff Chemist 

B.S. Chemistry with minor in Math from Northwestern 

State. M.S. in Organic Chemistry from Northwestern State. 

5 years experience at Olin Corporation in Lake Charles 

as an Analytical Organic Chemist. Has experience in 

instrumentation and wet chemistry. 3 years experience at 

CITGO Petroleum as Staff Chemist. 

Member of American Chemical Society. 

b. Gretchel L. Grout, Chemist 
P.83 

B.S. in Chemistry from McNeese State University. 

M.S. in Chemistry from McNeese State University. 

2 years experience at Conoco Chemicals in Lake Charles 

as Chemist. 4 years experience at CITGO Petroleum. 

Experienced mainly in wet Chemistry with instrumental 

endpoints, environmental projects, water effluent 

analysis. 

2. Calibration of Dry Gas Meter 

a. Procedure 

Exactly 0.100 cubic feet (CF) of ambient air from an NBS 

calibrated container is displaced with water into the dry 

gas meter to be calibrated. The meter readings before 

(0.000) and after are taken and the test repeated 5 times 

The temperatures and pressures of the apparatus are allowed 

to equilibrate to room conditions, so that no corrections 

for temperature and pressure are needed. The calibration 

factor will be obtained by dividing the actual volume (0.1 

CF) by the meter reading and is a unitless factor. 

b. Calculations 

True Value (V^.) = 0.100 CF 

Measured Volume (V ) = 0.095 CF (average of 5 runs) 

Factor = VT/Vm = 0.100/0.095 = 1.0526 

3. Method 11 Equations - See following pages. 

4. Normality Calculation Summary - See following pages: 

5. Field Test Data - See following pages. 

6. Laboratory Data and Calculation Summary - See following pages. 
DATE 

12-15-83 

12-15-83 

Average 

12/16/83 

12/16/83 

Average 

RUN 

la* 

lb 

1 * 

la 

lb 

1* 

TIME 

9:50 - 10:06 AM 

11:35 - 11:49 AM 

-

10:07 - 10:18 AM 

12:00 - 12:11 PM 

-

TABLE II 

Summary of Results - Coker II Testing 

(Method 11 - H2S in Fuel Gas) 

Performance Standard 

mg/dscm ppmV 

230 162 

230 162 

Method 11 

mg/dscm 

526 

411 

469 

322 

222 

272 

Results 

ppmV 

373 

291 

332 

227 

157 

192 

* Performance Tests Cancelled after first run. See discussion transmittal letter. 
P.85 

TABLE III 

Design, Normal Maximum, and Actual Operating 

Level of Furnace B-201 During Testing 

RUN 

S-1 

S-2 

S-3 

Average 

S-1 

S-2 

S-3 

Average 

Design 

POLLUTANT(s) 

TSP,S02,CO 

TSP,S02,C0 

TSP,S02,C0 

-

NOx 

NOx 

NOx 

-

Normal Maximum 

DATE 

12-15-83 

12-15-83 

12-15-83 

-

12-15-83 

12-15-83 

12-15-83 

-

UNIT FEED 

RATE (BPD) 

34,100 

34,101 

34,416 

34,206 

34,244 

33,954 

33,397 

33,865 

35,000 

38,000 

HEAT RELEASE 

MMBTU/HR 

173.3 

168.8 

178.2 

173.4 

168.4 

169.3 

178.8 

172.2 

158.8 

125.0 
P.86 

TABLE IV 

Design, Normal Maximum, and Actual Operating 

Level of Furnace B-202 During Testing 

Run 

N-1 

N-2 

N-3 

Average 

N-1 

N-2 

N-3 

Average 

Design 

Pollutant(s) 

TSP,S02,C0 

TSP,S02,C0 

TSP,S02,C0 

-

NOx 

NOx 

NOx 

-

Normal Maximum 

Date 

12-16-83 

12-17-83 

12-17-83 

-

12-17-83 

12-17-83 

12-17-83 

-

Unit Feed 

Rate (BPD) 

36,302 

37,807 

36,089 

36,733 

37,593 

38,021 

37,636 

37,750 

35,000 

38,000 

Heat Release 

MMBTU/HR 

155.5 

157.2 

153.4 

155.4 

154.9 

159.4 

154.8 

156.4 

158.8 

125.0 
Normality Calculation Summary 

For Method 11 Test 

P.87 

Date /Z. //$- /6l 

Chemist (3r. f^s*^ fTest Identification £o/'sa- 27 

/^wr / (j-c^ 7ss/Jj /Cr /•/, S 

A. Sodium Thiosulfate 

• Sample #1 

Sample #2 

Average (Nth) 

Weight of K2Cr207 

(grams) 

£. c o 

— 

Volume of Na2S203 

(ml) 

<-/0. Z. 

— 

Calculated 

Normality 

&. /o /r 

— . 

&. / o'sr 

B. Iodine 

Sample #1 

Sample #2 

Average (Ni) 

Kth 

JOIZ 

" a — 

Volume of Na2S20o 

To Titrate I?(ml) 

2V./ 

— 

Volume of Io 

(ml) ' 

Zf. o 

— 

Calculated 

Normality 

. oo<?9 

— 

. b c? f? 
P.88 

Field Data For Method 11 Test 

Date /?-/ ' * /& ^ 

Chemistr^vff <J^~J^£ 

Test Identification /^^/^,- /T~ 

f^r-, J" /a* /^Zu^f t£* _f 

Run# 

/ 

Sample 

ID 

f # 

/ e 

Time 

4.TO -/o : OC /f/^ 

//•'/* ' -//'^ ^ 

Temp. 

(C°) 

2/°CZc. (,'C 

(mmHg) 

76 £ 

7C6 

* 

Vm 

(ft 3) 

,5"^ 

. S>/ 

Notes: 1. Two samples constitute 1 run. 

2. Temperature must be converted to K° for calculation. 
P.89 

Field Data For Method 11 Test 

Date /Z//6/0? 

Chemist /T/^ STM, '/* 

Test Identification ^ g yfUs- jr 

Run# 

/ 

Sample 

ID 

S<9 

/£ 

Time 

/or07 -/&.:/S/f»t 

/Z:oO -/ £ -v/ /^/ ^ 

Temp. 

(C°) 

J?. z. 

7.7 

t ^ s (mmHg) 

7C 6> 

76C 

Vm 

(ft 3) 

, 7SS 

,SoS 

Notes: 1. Two samples constitute 1 run. 

2. Temperature must be converted to K° for calculation. 
Laboratory Data and Calculation Summary 

For Method 11 Test 

Date /Z/sr /ff* 

Chemist(s) <£„ 6 r p^ t r./rt J?*t YA 

Test Identification- Co/^r' ZT 

/AS /M &,+/ 6>s 

Run 

// 

/ 

Sample 

ID 

/'? 

/4 

NVh1 

'O/o / 

,0/o 1 

Ni 

.ooqf 

.00f1 

Vthb 

(ml) 

V7.s-

</7>r 

• \ 

\m 

ZS. i 

/*/.9 

' • 

Vib 

(ml) 

£-0 

£~o 

Vis 

(ml) 

ro 

s~o 

• 

Vstd ) 

(1) 

/ • , 0 9 ' 

/3.7o 

H2S Concentratio n 

mg/dscm 

£-2 e 

</// 

ppmV 

?7J 

2. <?/ 

Notes: 1. Prepared by 10 to 1 dilution of sodium thiosulfate solution - see Normality Calculation Summary. 

2. A conversion factor of .707 was calculated to convert mg/dscm to ppmV. 

TJ 

CO 
Laboratory Data and Calculation Summary 

For Method 11 Test 

Da te /Z//6/S 7 

Chemist(s) ". -fXy. /A 

Test Identification- £o /**,- IT 

/£JJ /-» / ^ / / dir_r 

Run 

(1 

/ 

Sample 

ID 

/ # 

/5 

Nf* 1 

, 0/0/ 

/ e/o / 

Ni 

.oof? 

.009$ 

Vthb 

(ml) 

C7.6" 

978 

I® 

2 <S. 7 / 

Z8.f> 

Vib 

(ml) 

7T 

S~° 

Vis 

(ml) 

7r 

.To 

Vstd ) 

•'• ( D 

1/.Z7 

/</.$Z 

H2S Concentration 

mg/dscm 

^ z 

2 2 Z. 

ppmV 

Z-Z--7 

/S~ 7 

Notes: 1. Prepared by 10 to 1 dilution of sodium thiosulfate solution - see Normality Calculation Summary. 

2. A conversion factor of .707 was calculated to convert mg/dscm to ppmV. 

CO 
P.92 

ATTACHMENT 2-5 

NSPS PERFORMANCE TEST REPORT 

COKER II FURNACES B-201 and B-202 

H2S IN FUEL GAS 

I. Background Information 

A. Company Name and Address: 

CITGO Petroleum Corporation 

P. 0. Box 1562 

Lake Charles, LA 70602 

B. Signature of Responsible Company Official: 

I. *R. Bowler 

General Manager, Operations 

C. Testing Organization and Address: 

CITGO Petroleum Corporation 

P. 0. Box 1562 

Lake Charles, LA 70602 

D. Signature of Responsible Test Organization Official: 

See above signature 

E. Test Date: 

March 2, 1984 

F. Name and Titles of Test Personnel: 

Name Title Organization 

F. R. Smith Staff Chemist CITGO Petroleum Corporation 

G. L. Grout Chemist CITGO Petroleum Corporation 

G. Schematic Drawing of Process: 

Figure 1 - Simplified Process Flow Diagram of Coker II 

Figure 2 - Simplified Process Flow Diagram of F-104 Fuel Gas System 
P.93 

H. Description of Process Being Sampled: 

1. Affected Facilities-' 

CITGO Petroleum Corporation has constructed in its Lake Charles 

Refinery a 35,000 BPD Delayed Coking Unit identified as Coker II. 

The permit to construct and operate this unit was obtained from 

the State of Louisiana under Permit No. 1594. Compliance testing 

was previously conducted on December 15-17, 1983 for the two identical process heaters in the Coker II Unit. However, the NSPS 

testing for H2S in the fuel gas was terminated after it was determined that high H2S existed on the days of the testing. The H2S 

in fuel gas problem was investigated and the NSPS testing was 

rescheduled for March 2, 1984. 

A detailed description of the Coker II process was provided in the 

compliance testing report submitted January 30, 1984. The affected 

facilities are the two process heaters at the Coker II Unit. Both 

heaters are permitted to burn either fuel gas or fuel oil. Currently, the heaters are only capable of burning fuel gas which is 

supplied through the F-104 fuel gas drum. A description of the 

fuel gas system is supplied below. 

2. Description of the Fuel Gas System--

The fuel gas system in the refinery is very flexible and complex. 

The fuel gas supplied to the F-104 drum is a blend of process make 

gas and purchased natural gas. The amount of natural gas received 

varies continuously according to the Refinery's fuel requirements, 

the amount of process make gas going to fuel gas, and the 

amount of natural gas available from our supplier. The fuel gas 

requirements and process make gas production varies according 

to the operating plan of the refinery, the operating levels of 

individual units, and the quality of feed to the units. 

Fuel gas to the F-104 comes from several sources. Amine units 

at the Coker II Unit and the Benzene Unit supply treated process 

make gas to the fuel gas system as shown in Figure 2. The 

Benzene Amine gas is sent directly to the F-104 drum while the 

Coker II Amine gas is sent to the high pressure residue gas 

system. The residue gas system supplies fuel gas to the F-104 

drum as needed to maintain the proper pressure in the fuel gas 

system. If the residue gas demand to the F-104 drum exceeds 

the amount of gas supplied from Coker II Amine, additional 

residue gas is available and is monitored with a flow recorder. 

This make-up residue gas consists of mostly purchased natural 

gas and some treated process make gas. Normally, the residue 

gas has a low H2S concentration because the large amount of 

natural gas in the residue gas system. 
P.94 

Another source of fuel gas is hydrogen off gas from the ' C 

Reforming Unit. This gas is normally sent to the Unicracker 

for process consumption. Any excess off gas from the ' C 

Reformer Unit is preferentially burned in the 'C Reformer heaters with 

any additional excess gas going to the F-104 drum. This hydrogen 

rich gas also has a very low H2S concentration. 

II. Summary 

A. Summary of Test Results: 

See Table I 

B. Isokinetic Rates: 

The determination of isokinetic rates is not required for Method 11 

testing. 

C. Operating Conditions During Test: 

The operating level of the Coker II unit does not generally affect 

the H2S in the fuel gas, and therefore, was not addressed in this 

report. However, the operating conditions of the F-104 fuel gas 

system, the Benzene Amine Unit, and the Coker II Amine Unit were 

monitored and recorded. The amine treating facilities at the Light 

Ends Recovery Unit (LERU) and the Fuel Gas Processing Unit (FGPU) 

were considered insignificant H2S sources and were not monitored 

during the test. 

The overall fuel balance showing flows and H2S concentrations is 

shown in Figure 2. The H2S concentrations from the different 

fuel gas sources were analyzed using draeger tubes. The operating 

conditions for Benzene Amine and Coker II Amine are shown in Table II 

and Table III, respectively. 

D. Air Pollution Control Equipment 

Sulfur dioxide emissions are controlled by reducing H2S concentrations 

in the various process make gas streams. These gas streams are sent 

to amine treating facilities. Here, sour process make gas flows 

through a contactor where H2S is absorbed by a monoethanolamine 

(MEA) solution. The treated sweet gas flows to the fuel gas system 

while the MEA solution is sent to a stripping tower for regeneration. 

Stripped acid gas (H2S) is sent to the sulfur recovery facilities 

while the lean MEA solution is recirculated back to the contactor. 

E. Opacity Readings 

Opacity readings were performed during the compliance testing on 

December 15-17, 1983 and are not included in this report. 

III. Procedures 

EPA reference Method 11 (40 CFR Part 60 Appendix 'A') was used for the 

testing and was applied in a rigorous manner. The sample was taken 

from the center of the fuel gas line by use of a stainless steel probe. 
P.95 

IV. Analytical Technique: 

The standard EPA Method 11 was used as stated above. No deviations 

were made from the analytical techniques outlined in the official 

procedures. 

V. Chain of Custody: 

H2S samples were gathered by F. R. Smith and returned to the refinery 

laboratory for analysis by Mr. Smith and Ms. G. L. Grout. 

VI. Test Data, Calibrations, and Calculations: 

A. Resume of Lab Personnel Conducting Tests: 

1. F. R. Smith, Staff Chemist 

B. S. Chemistry with minor in Math from Northwestern State. 

M. S. in Organic Chemistry from Northwestern State. 

5 years experience at Olin Corporation in Lake Charles as an 

Analytical Organic Chemist. Has experience in instrumentation 

and wet chemistry. 3 years experience at CITGO Petroleum as 

Staff Chemist. 

Member of American Chemical Society. 

2. Gretchel L. Grout, Chemist 

B. S. in Chemistry from McNeese State University. 

M. S. in Chemistry from McNeese State University. 

2 years experience at Conoco Chemicals in Lake Charles as 

Chemist. 4 years experience at CITGO Petroleum. Experienced 

mainly in wet Chemistry with instrumental endpoints, 

environmental projects, water effluent analysis. 

B. Calibration of Dry Gas Meter: 

1. Procedure 

Exactly 0.100 cubic feet (CF) of ambient air from a NBS 

calibrated container is displaced with water into the dry 

gas meter to be calibrated. The meter readings before 

(0.000) and after are taken and the test repeated 5 times. 

The temperatures and pressures of the apparatus are allowed 

to equilibrate to room conditions, so that no corrections 

for temperature and pressure are needed. The calibration 

factor will be obtained by dividing the actual volume (0.1 

CF) by the meter reading and is a unitless factor. 
P.96 

i 

2. Calculations 

True Value (VT) =0.100 CF 

Measured Volume (V ) = 0.100 CF (average of 5 runs) 

Factor = VT/Vffl = 0.100/0.100 = 1.000 

C. Method 11 Equations - See following pages. 

D. Normality Calculation Summary - See following pages. 

E. Field Test Data - See following pages. 

F. Laboratory Data and Calculation Summary - See following pages. 
Run 

1 

2 

3 

Average 

NSPS 

Standard 

Date 

3-2-84 

3-2-84 

3-2-84 

-

-

•» 

TABLE I 

Summary of Results 

(Method 11 - H2S in fuel Gas) 

Time of 

Periods 

8:00 - 11:00 AM 

11:00 AM - 2:00 PM 

2:00 PM - 5:00 PM 

-

-

H2S in Fuel Gas 

mg/dscm 

55.8 

57.0 

58.5 

57 

230 

••;!•• • '" f l " V. 

PP"» 

39.7 

40.4 

41.4 

40 

162 

P.97 

i 
TABLE II 

Actual, Design, and Normal Maximum Operations 

Conditions of Coker II Amine Unit and Central Amine Unit 

Run 

1 

2 

3 

Average 

Design 

Maximum 

Normal 

Sweet Gas 

Production 

(MMSCFD) 

20.84 

19.89 

22.32 

21.04 

30.0 

30.0 

Amine 

Circulation 

(GPM) 

850.3 

850.1 

850.8 

850.4 

870.0 

870.0 

Regenerator 

Overhead Temp 

(°F) 

261 

261 

260 

261 

262 

265 

Sweet Gas 

HpS Cone, 

(ppm) 

20 

18 

10 

16 

1601 

2 

160 

Lean Amine 

MEA 

(%) 

-

-

16.8 

15.01 

20.0 

Solution 

H2S 

(%) 

-

-

-

.016 

.021 

2 

.04 

Notes: 

1. These figures represent desired levels. 

2. These figures represent best estimates, 
TABLE III 

Actual, Design, and Normal Maximum Operating 

Conditions of Benzene Amine Unit 

Run 

1 

2 

3 

Average 

Design 

Normal 

Maximum 

Sweet Gas 

Production 

(MMSCFD) 

8.81 

8.12 

9.71 

8.88 

20.8 1 

15.0 

Amine 

Circulation 

(GPM) 

305.4 

309.8 

270.1 

295.1 

430 

340 

Regenerator 

Overhead Temp 

(

8F) 

220 

220 

220 

220 

245 

240 

Sweet Gas 

H2S Cone. 

(ppm) 

220 

62 

82 

121 

2 

160 

200 

Lean Amine Solution 

HET 

(%) 

19.6 

18. o' 

20.0 

(%) 

.064 

2 

.04 

.08 

Notes: 

1. The operating limit depends on the H2S generation, not hydraulic flows 

2. These figures represent desired levels. 

3. These figures represent best estimates 
Coker No. 2 Simplified Process Flow Diagram 

F-201A F-201B F-202A F-202B 

V V V/ V 

•Q" 

I 

•o 

f COKE / \ 

. j ..»• 

Tai l Gas 

B-202 

Fre9hTeed 

Coke Drums Heaters Fractionator 

FIGURE 1 
SIMPLIFIED FLOW DIAGRAM 

F-104 FUEL CAS SYSTEM 

UNICRACKER 

(F-105 *\ 

DRUM J FURNACES 

HYDROGEN MAKE 

GAS FOR PROCESS s 

w 

rH S 

o o: 

U~) C/l 

' C' REFORMER 

FURNACES 

"TV MMSCFD 

COKER I I 

-FURNACES 

/£Sj w 

^C7 

BENZENE 

AMINE 

EXPORT GAS 

,' 'A* LCOH, • J { _._ , 

i'B' REFORMER i > 'A' REFORMER! i _ J '_ _-_.«. —.' 

BOH, 

T G 

21.0 MMSCFD 

@ 16 PPM 

8.9 MMSCFD 

@ 121 PPM 

-104 DRUM 

FUEL GAS >©-

A. 

RESIDUE GAS 

H 

10.3 MM?^FD 

@ 10 PPM 

FIGURE 2 

Tl 

ho 
P.3 

SECTION, VI - c. 

METHOD OF CALCULATION 

EPA Reference Method 11 

Determination of Hydrogen Sulfide in Fuel Gas 

Equations: 

1. Normality of Sodium Thiosulfate Solution 

N 1K 

- a.Q3q* WK, 

2. Normality of Standard Iodine Solution 

Nj Vi 

3. Dry Gas Volume Correction to Standard Conditions (STP) 

V.M-V.XY^W^^M4. Concentration of Hydrogen Sulfide (H?S) 

. 
P.4 

METHOD OF CALCULATION 

EPA Reference Method 11 

Determination of Hydrogen Sulfide in Fuel Gas 

Nomenclature: 

Variable 

Nth 

Wkc 

Vth 

K 

n 

V. 

1 

V. 

1 

Vo(std) 

V 

m 

T std 

T 

JD 

Pstd 

Pb 

Y 

S. 

*c 

V. 

IS 

Vib 

Vths 

V^.,. 

Units 

eq/liter 

grams 

ml 

2.039 

eq./liter 

ml 

liters(1) 

cubic feet 

293°K 

°K 

760mm Hg 

om Hg 

dimensionless 

mg/dscm 

17.04 x IO3 

ml 

ml * 

ml 

ml thb 

Definition 

Normality of sodium thiosulfate 

Weight of potassium chromate 

Volume of sodium thiosulfate 

Conversion factor 

Normality of iodine 

Volume of iodine 

Gas volume at STP 

Gas volume through meter 

Standard temperature 

Temperature of meter 

Standard pressure 

Barometric pressure 

Dry gas calibration factor 

Concentration of hydrogen sulfide 

Conversion factor 

Iodine solution volume for sample 

Iodine solution volume for blank 

Thiosulfate solution volume for sample 

Thiosulfate solution volume for blank 
P.5 

£cc+it>N vr-o. 

Normality Calculation Summary 

For Method 11 Test 

Date 

Chemist 

A. Sodium Thiosulfate 

Test Identification M-, S N) S fi S> 

T^-V\v^ » + C\ior IT 

Weight of K2Cr207 

(grams) 

Volume of Na2S203 

(ml) 

Calculated 

Normality 

Sample fli 2.0CO M.O «at n./asto 

Sample #2 

Average (Nth) 

Z.AM W.ft «^_ A.lbM 

A.lO^O 

B. Iodine 

Sample #1 

Sample #2 

Average (Ni) 

H

t h 

. 0 ^ 

JH^ 

Volume of Na2S20o 

To Titrat e I?(ml) 

£5.(oC)*& 

55.SS' 

]^>~<Cl 

Volume of I2 

(ml) 

<P5" 

ZS 

^XC 

Calculated 

Normality 

.OlM>V 

.6)64-0; 

.0104-3' 
P.6 

Secfion Vl" E". 

Field Data For Method 11 Test 

Date 3 ML <h 

Chemist 

Test Identification }-Jl S M S 95" 

Run/' 

Z 

2Z" 

^ T 

Sample 

ID 

_ £ 

s 

A 

G 

rt 

B 

Time 

j>:ft ft ^o/tlnt 

/o: i6 i'o /0'.{t> 

/ /.To ic /1: a 2 

/:«s ** /•rfr>r~> 

2 •' ff fo Z -fi P* 

3'<hf /o J.'jfP* 

Temp. 

(c°) 

Z-S'c 

zz

v

c 

Z i ° c 

•2-l' c 

Zf' c 

•z-f*c 

t

 ? b

 N 

(mmHg) 

. Z*_7 

7 £7 

7 67 

7 6 6 

7 £>C 

~? 6 * 

Vm 

(ft 3) 

/. oo / 

0- f9f 

/•CO / 

o. 8'? 7 

/. 0 a 0 

. ?6 / 

Notes: 1. Two samples constitute 1 run. 

2. Temperature must be converted to K° for calculation. 
Stf t + IOrs VI - F. 

Date s ,/x/V 

Laboratory Data and Calculation Summary 

For Method 11 Test 

Chemist(s) F- ft. 

Test Identification VKS OYA CoW>' iL 

Run 

// 

1 

2Z" 

TH 

Sample 

ID 

A 

a 

a 

A 

' a 

Nt-V, 1 

.01 oio 

.OIOJO 

.01 fato 

>0l026 

.0102-6 

Nl 

,01043 

.oio*5 

,o\<& 

.0^ 

,o\&z 

,01043 

V

thb 

(ml) 

51.3 

51.3 

57,3 

57 > 3 

si. y 

513> 

(SU 

_42._8 

4/. 3 

42.5 " 

42,3 

.42.6. 

4/. 8 

Vib 

(ml) 

_5I)L O 

50,0 

_ 50<& 

mo 

so£> 

V i s 

(ml) 

50.0 

50.0 

50.0 

50.6 

-5Q,0_ 

SO, 6 

Vstd ) 

(1) 

J. ool 

o.ms 

JJPM 

6.?M 

0.961 

H2S Concentration ] 

mg/dscm 

_ "SkiT 

fan :o 

__53,J?_ 

foLO 

_ m^SSi.^-

ppmV 

39.7-

<*g,0 

4S.b 

Notes: 1. Prepared by 10 to 1 dilution of sodium thiosulfate solution - see Normality Calculation Summary. 

2. A conversion factor of .707 was calculated to convert mg/dscm Jto ppmV. 
P.8 

ATTACHMENT 2-6 

NSPS PERFORMANCE TEST REPORT 

FOR PERMIT NO. 1594 

UNICRACKER FURNACES B-l, 2, 3, 4, 5 

H2S IN FUEL GAS 

I. Background Information 

A. Company Name and Address: 

CITGO Petroleum Corporation 

P. 0. Box 1562 

Lake Charles, LA 70602 

B. Signature of Responsible Company Official: 

J. c-a^a/Thompson 

General Manager, Operations 

C. Testing Organization and Address: 

CITGO Petroleum Corporation 

P. 0. Box 1562 

Lake Charles, LA 70602 

D. Signature of Responsible Test Organization Official: 

See above signature 

E. Test,Date: 

July 24, 1984 

F. Name and Titles of Test Personnel: 

F. RNam. Smit e Titl h e 

G. L. Grout 

Staff Chemist 

Chemist 

Organization 

CITGO Petroleum Corporation 

CITGO Petroleum Corporation 

Schematic Drawing of Process: 

Figure 2.1 - Simplified Process Flow Diagram of Fuel Gas System 
P.9 

H. Description o.f the Fuel Gas System Being Sampled: 

The fuel gas system in the refinery is very flexible and complex. 

The fuel gas supplied to the Unicracker is a blend of process make 

gas and purchased natural gas. The amount of natural gas received 

varies continuously according to the Refinery's fuel requirements, 

the amount of process make gas going to fuel gas, and the amount 

of natural gas available from our supplier. The fuel gas 

requirements and process make gas production varies according 

to the operating plan of the refinery, the operating levels of 

individual units, and the type of feed to the units. 

Fuel gas to the Unicracker comes from the F-104 drum, which 

receives gases from several sources. Amine units at the Coker II 

Unit and the Benzene Unit supply treated process make gas to the 

fuel gas system as shown in Figure 2.1. The Benzene Amine gas is 

sent directly to the F-104 drum while the Coker II Amine gas is 

sent to the high pressure residue gas system. The residue gas 

system supplies fuel gas to the F-104 drum as needed to maintain 

the proper pressure in the fuel gas system. If the residue gas 

demand to the F-104 drum exceeds the amount of gas supplied from 

Coker II Amine, additional residue gas is available and is monitored 

with a flow recorder. This make-up residue gas consists of mostly 

purchased natural gas along with some treated process make gas. 

Normally, the residue gas has a low H2S concentration because of the 

large amount of natural gas in the residue gas system. 

Another source of fuel gas is hydrogen off gas from the ' C1 

Reforming Unit. Under normal operation, this gas is sent to 

the Unicracker for process consumption. Any excess off gas from 

the 'C' Reformer Unit is preferentially burned in the 'C Reformer 

heaters with any additional excess gas going to the F-104 drum. This 

hydrogen rich gas also has a very low H2S concentration. 

II. Summary 

A. Summary of Test Results: 

The results of the testing are given in Table 2.1. The HaS levels 

averaged 77 mg/dscm (54 ppm) for three runs. These levels are below 

the NSPS standard of 230 mg/dscm (162 ppm). 

B. Isokinetic Rates: 

The determination of isokinetic rates is not required for Method 11 

testing. 

C. Operating Conditions During Test: 

The operating rate of the Unicracker unit does not significantly 

affect the H2S in the fuel gas, and therefore, was not addressed in 

this report. However, the operating conditions of the F-104 fuel 

gas system, the Benzene Amine Unit, the Coker II Amine Unit, and 

the Central Amine Regeneration unit were monitored and recorded. 

The amine treating facilities at the Light Ends Recovery Unit 

(LERU) and the Fuel Gas Processing Unit (FGPU) are not considered 

1 
P.10 

significant H2S sources and were not monitored during the test. 

The overall fuel balance showing flows and H2S concentrations is 

shown in Figure 2.1. The H2S concentrations from the different 

fuel gas sources were analyzed using draeger tubes. The operating 

conditions for Coker II Amine (including Central Amine) and Benzene 

Amine are shown in Tables 2.2 and 2.3,respectively. 

D. Air Pollution Control Equipment 

Sulfur dioxide emissions are controlled by reducing H2S concentrations in the various process make gas streams. These gas streams 

are sent to amine treating facilities. Here, sour process make gas 

flows through contactors where H2S is absorbed by a monoethanolamine 

(MEA) solution. The treated sweet gas flows to the fuel gas system 

while the MEA solution is sent to a stripping tower for regeneration. 

Stripped acid gas (H2S) is sent to the sulfur recovery facilities 

while the lean MEA solution is recirculated back to the contactor. 

The Benzene Amine unit has its own MEA regeneration section, while 

Coker II Amine utilized the Central Amine Unit for regeneration of 

its MEA. 

III. Procedures 

EPA reference Method 11 (40 CFR Part 60 Appendix 'A') was used for the 

testing and was applied in a rigorous manner. The sample was taken 

from the center of the fuel gas line by use of a stainless steel probe. 

IV. Analytical Technique 

The standard EPA Method 11 was used as stated above. No deviations 

were made from the analytical techniques outlined in the official 

procedures. 

V. Chain of Custody 

H2S samples were gathered by F. R. Smith and returned to the refinery 

laboratory for analysis by Mr. Smith and Ms. G. L. Grout. 

IV. Test Data, Calibrations, and Calculations 

A. Resume of Lab Personnel Conducting Tests: 

1. F. R. Smith, Staff Chemist 

B. S. Chemistry with minor in Math from Northwestern State. 

M. S. in Organic Chemistry from Northwestern State. 

5 years experience at Olin Corporation in Lake Charles as an 

Analytical Organic Chemist. Has experience in instrumentation 

and wet chemistry. 4 years experience at CITGO Petroleum as 

Staff Chemist. 

Member of American Chemical Society. 
P.11 

2. Gretchel L. Grout, Chemist 

B. S. in Chemistry from McNeese State University. 

M. S. in Chemistry from McNeese State University. 

2 years experience at Conoco Chemicals in Lake Charles as 

Chemist. 5 years experience at CITGO Petroleum. Experienced 

mainly in wet Chemistry with instrumental endpoints, 

environmental projects, water effluent analysis. 

Member of American Chemical Society. 

B. Calibration of Dry Gas Meter: 

1. Procedure 

Exactly 0.100 cubic feet (CF) of ambient air from a NBS 

calibrated container is displaced with water into the dry 

gas meter to be calibrated. The meter readings before 

(0.000) and after are taken and the test repeated 5 times. 

The temperatures and pressures of the apparatus are allowed 

to equilibrate to room conditions, so that no corrections 

for temperature and pressure are needed. The calibration 

factor will be obtained by dividing the actual volume (0.1 

CF) by the meter reading and is a unitless factor. 

2. Calculations 

True Value (VT) - 0.100 CF 

Measured Volume (V x «•,««-„/ c c -v 

m) = 0.100 CF (average of 5 runs) 

Factor = V_,Vv - 0.100/0.100 - 1.000 

i^ m 

C. Method 11 Equations - See Exhibit 2.1 

D. Normality Calculation Summary - See Exhibit 2.2 

E. Field Test Data - See Exhibit 2.3 

F. Laboratory Data and Calculation Summary - See Exhibit 2.4 
SIMPLIFIED FLOW DIAGRAM 

F-104 FUEL GAS SYSTEM 

UNICRACKER I 

FURNACES 

HYDROGEN MAKE 

GAS FOR PROCESS 

COKER II 

FURNACES 

' C' REFORMER s 

os 

w 

m —i os 

o c 

in co 

FURNACES 

I T 

£$ w 

z 

i- « 

•< H 

CJ — < O H 

ro Z 

I C 

BENZENE 

AMINE 

0 MMSCFD 

EXPORT GAS 

f'A' LCOH, j f _ BOH , 

«'B' REFORMER | J 'A' REFORMER; 

T 

C 

25.2 MMSCFD 

@ 41 PPM 

10.0 MMSCFD 

@ 39 PPM 

F-104 DRUM 

FUEL GAS |)-©hA. 

RESIDUE GAS 

£4.9 MMSCFD 

'<§ 66 PPM 

FIGURE 2.1 

TJ 

tV3 
P.13 

TABLE 2.1 

Summary of Results 

(Method 11 - H2S in Fuel Gas) 

un 

1 

2 

3 

Date 

7-24-84 

7-24-84 

7-24-84 

11 

2 

Time of 

Periods 

8:00 - 11:00 AM 

:00 AM - 2:00 PM 

:00 PM - 5:00 PM 

H2S in Fuel 

mg/dscm 

75.5 

86.5 

68.5 

Gas 

ppm 

53.5 

61.5 

48.0 

Average 77 54 

NSPS 

Standard 230 162 
TABLE 2.2 

fnft^.'iwwnv 

Actual, Design, and Normal -Mtn4flm» Operations 

Conditions of Coker II Amine Unit and Central Amine Unit 

Run 

1 

2 

3 

Sweet Gas 

Production 

(MMSCFD) 

27.0 

27.9 

20.6 

Amine 

Circulation 

(GPM) 

966.6 

1012.5 

799.6 

Regenerator 

Overhead 

(°F) 

247 

248 

249 

Temp 

Sweet Gas 

H2S Cone. 

(ppm) 

40 

33 

50 

Lean Amine 

MEA 

(Z) 

-. 

_ 

Solution 

H2S 

(%) 

-

-

j _ 

Average 25.2 926.2 248 41 13.8 .053 

Design 30.0 880.0 244 160 15.0 .04 

Normal 

Maximum 30.0 1060.0 260 160 15.0 .06 

Notes: 

1. These figures represent desired levels. 

2. These figures represent best estimates. 

T3 
TABLE 2.3 

Actual, Design, and Normal Maximum Operating 

Conditions of Benzene Amine Unit 

Run 

1 

2 

3 

Sweet Gas 

Production 

(MMSCFD) 

9.06 

11.12 

9.70 

Amine 

Circulation 

(GPM) 

254.5 

246.6 

202.1 

Regenerator 

Overhead Temp 

(°F) 

217 

215 

208 

Sweet Gas 

H2S Cone. 

(ppm) 

40 

37 

40 

Lean Amine Solution 

MEA H2S 

(%l (Z) 

-

_ _ 

Average 10.0 234.4 213 39 14.7 .049 

Design 20.8 440 220 160 15.0 .04 

Normal 

Maximum 15.0 340 240 200 20.0 .08 

Notes: 

1. The operating limit depends on the H2S generation, not hydraulic flows 

2. These figures represent desired levels 

3. These figures represent best estimates 

T3 
P.16 

EXHIBIT 2.1 

METHOD OF CALCULATION 

EPA Reference Method 11 

Determination of Hydrogen Sulfide in Fuel Gas 

Equations: 

1. Normality of Sodium Thiosulfate Solution 

2. Normality of Standard Iodine Solution 

3. Dry Gas Volume Correction to Standard Conditions (STP) 

4. Concentration of Hydrogen Sulfide (H?S) 

C, r fcRv?»4lr - V*. * M«) - <V;L *N:-V*M> * N*S1 

V^ltH) 
P.17 

EXHIBIT 2.1 (Cont'd) 

METHOD OF CALCULATION 

EPA Reference Method 11 

Determination of Hydrogen Sulfide in Fuel Gas 

Nomenclature: 

Variable 

N th 

W kc 

th 

K 

N. 

V. 

1 

m(std) 

m 

std 

m 

std 

y 

C 

K 

hs 

is 

ib 

ths 

thb 

Units 

eq/liter 

grams 

ml 

2.039 

eq./liter 

ml 

liters(l) 

cubic feet 

293°K 

°K 

760mm Hg 

mm Hg 

dimensionless 

mg/dscm 

17.04 x IO3 

ml 

ml 

ml 

ml 

Definition 

Normality of sodium thiosulfate 

Weight of potassium chromate 

Volume of sodium thiosulfate 

Conversion factor 

Normality of iodine 

Volume of iodine 

Gas volume at iSTP 

Gas volume through meter 

Standard temperature 

Temperature of meter 

Standard pressure 

Barometric pressure 

Dry gas calibration factor 

Concentration of hydrogen sulfide 

Conversion factor 

Iodine solution volume for sample 

Iodine solution volume for blank 

Thiosulfate solution volume for sample 

Thiosulfate solution volume for blank 
P.18 

Date 

Chemist 

T 

-EXHIBIT 2.2 

Normality Calculation Summary 

For Method 11 Test 

2A- J$J 

LL 

Test Identification VAn-vX>/V^OkgjK lAi £ 

A. Sodium Thiosulfat e 

fc5£ *a 

Sample 01 

Sample #2 

Average (Nt^) 

Weight of K2Cr207 

(grams) 

Sb. 00 

cO.OO 

Volume of Na2S203 

(ml) 

41.35 

4I.-Y) 

Calculated 

Normality 

0. 09R(n 

fi.CRffr 

O'OWfB. Iodine 

N th Volume of Na2S203 

To Titrate I?(ml) 

Volume of I9 

(ml) 

Calculated 

Normality 

Sample fli t^L aO.A>.(o0 ^•^.0 0.0091-1 

Sample #2 .og-fii* Stf>. (D£ rKfl A.0CflV3 

Average (Nj) 0.0C)9?<ZU 
P.19 

EXHIBIT 2.3 

Field Data For Method 11 Test 

Date 7/l +/? 

Chemist 

Test Identification/!//? /^jc^/ r 

Run* 

/ 

T, 

3 

Sample 

ID 

A 

a 

fi 

a 

A 

a 

Time 

*i:sf -/£>:of 

I/.'ff -Lt'Of 

/; z / - /.'3 / 

2:3 3 - 2.:+4 

3'.3/ - j:* / 

Temp. (c°) 

J& 

Iff 

/oz°f 

/ oz V 

?*V 

<?«-V" 

(mmHg) 

7^^ 

/ • 

// 

/ < 

? £ 3 

/ » 

Vm 

Cft3) 

• ft 

.C 17 

<gj>/ 

. 7o/ 

.S'^B 

.82.3 

Notes: 1. Two samples constitute 1 run. 

2. Temperature must be converted to K° for calculation. 

J 
EXHIBIT 2.4 

Date r L ?&.JPA> 

Chemist (s)\ \XQ^-2JU 

Laboratory Data and Calculation Summary 

For Method 11 Test 

Tes ^ i t Identification-V kvvSrCA^OVQ>" 

Run 

(7 

Sample 

ID Jitii Nj 

v

thb 

(ml) M Vi 8 

(ml) Vstd ) 

ID 

H2S Concentration 

mg/dscm PP°»V 

> 

_£ 1 " 49.4*T 

SOP. 

5T).Q 90 

.-£31 

&4-

& 

u .42-451 

40,75 

SQ._6 

/8J 

32. 

U A tf 43S0 50.0 

JJoJd. 

aCO.3 

m. 

3& 

Notes: 1. Prepared by 10 to 1 dilution of sodium thiosulfate solution - see Normality Calculation Summary. 

2. A conversion factor of .707 was calculated to convert mg/dscm to ppmV. 
P.22 

ATTACHMENT 3 

Summary of Stack Emission Tests 

from NSPS Sources 

Citgo Petroleum Corporation 

P. 0. Box 1562 

Lake Charles, LA 70602 

CONTENTS: 

Table 3-1 'A' and *B' Topping Unit 

March 30-April 1, 1982 

Table 3-2 'C Reformer Unit 

October 12-17, 1982 

Table 3-3 Coker II Unit 

December 15-17, 1983 

Table 3-4 Unicracker Unit 

July 24 and 26, 1984 

Table 3-5 'C Reformer Unit CO Retesting 

July 27, 1984 

Table 3-6 Coker II unit N02 Retesting 

July 28, 1984 

Table 3-7 Coker II Unit CO Retesting 

Jul7 28, 1984 
TABLE 3-1 

Summary of Results 

(All data in pounds per hour, except Opacity in Percent) 

Test Dates March 30, March 31, and April 1, 1982 

Run 

No. 

1 

2 

3 

Average 

1 

2 

3 

Average 

Part 

Limit 

39.5 

39.5 

39.5 

39.5 

39.5 

39.5 

.39.5 

39.5 

iculate 

Actual 

2.71 

1.42 

4.47 

2.87 

1.03 

0.61 

0.61 

0.62 

'/5 

Sulfur 

Limit 

479.0 

479.0 

479.0 

479.0 

'B' 

479.0 

479.0 

479.0 

479.0 

' TOPPING 

Dioxide 

Actual 

18.1 

30.3 

10.3 

19.6 

TOPPING 

11.2 

11.4 

10.9 

• 11.2 

UNIT - Heater B-4 

Nitrogen 

Limit 

320.0 

320.0 

320.0 

320.0 

Oxides* 

Actual 

82.8 

78.7 

78.6 

80.0 

UNIT - Heater B-104 

320.0 

320.0 

320.0 

320.0 

89.2 

78.7 

87.2 

84.9 

Garbon 

Limit 

15.3 

15.3 

15.3 

15.3 

15.3 

15.3 

15.3 

15.3 

Monoxide 

Actual 

<0.26 

<0.26 

0.79 

0.35 

0.81 

0.82 

1.24 

0.96 

Opacity 

Limit Actual 

20 

20 

20 

20 

20 

20 

20 

:o 

0 

0 

0 

0 

. 0 

0 

0 

0 

•Total Oxides of Nitrogen calculated as N0£ 
TABLE 3-2 

Summary of Results 

'C' Reformer 

Test Dates October 12-17, 1982 

(All data in pounds per hour, except where noted otherwise) 

HEATERS B-501, 502, 506 

Run 

No. 

1 

2 

3 

average 

Particulate 

Limit 

2.84 

2.84 

2.84 

2.84 

Ac tual 

1.52 

0.53 

0.41 

0.82 

Sulfur 

Limit 

3.58 

3.58 

3.58 

3.58. 

Dioxide 

Actual 

.95 

1.13 

.97 

1.02 

Nitrogen Oxide * 

Pounds/Hour 

Limit Actual 

37.6 17.3 

37.6 16.6 

37.6 22.6 

37.6 18.8 

Pounds/MMBTU 

Limit Actual 

0.19 0.14 

0.19 0.14 

0.19 0.18 

0.19 0.16 

Carbon Monoxide 

Limit 

3.21 

3.21 

3.21 

3.21 

Actual 

8.07 

5.18 

0.83 

4.69 

Opacity (%) 

Limit 

20 

20 

20 

20 

Actual 

0 

0 . 

0 

0 

1 7.67 0.81 

2 7.67 0.33 

3 7.67 1.62 

Average 7.67 0.92 

9.68 4.97 

9.68 4.2 

9.68 4.47 

9.68 4.55 

HEATERS B-503, 504, 505 

101.7 85.8 0.19 0.18 

101.7 70.3 0.19 0.15 

101.7 68.0 0.19 0.14 

101.7 74.7 0.19 0.16 

8.69 5.60 

8.69 4.01 

8.69 2.44 

8.69 4.02 

20 0 

20 0 

20 0 

20 0 

-Total Oxides of Nitrogen calculated as N02 
Run Particulates 

Np. Limit Actual 

S-1 3.69 

S-2 6.64 

S-3 2.78 

Average 14.21 4.37 

N-1 5.32 

N-2 1.83 

N-3 0.86 

Average 14.21 2.67 

* Run N-1 voided. See 

TABLE 3-3 

Summary of Results - Coker II Testing 

(All data in pounds per hour, except noted otherwise) 

Test Dates December 15 - 17, 1983 

FURNACE B-201 

Sulfur Dioxide Oxides of Nitrogen Carbon Monoxide 

Limit Actual Limit Actual Limit Actual 

14.4 25.6 3.45 

7.2 31.9 3.66 

7.9 40.9 4.08 

429.15 9.8 92.58 32.8 5.467 3.73 

FURNACE B-202 

7.7 27.9 * 

7.4 34.7 5.07 

5.7 36.9 9.88 

429.15 6.9 92.58 33.2 5.467 7.47 

t 

discussion in Section III. 

Opacity (%) 

Limit Actual 

0 

20 0 

0 

20 0 

] 
TABLE 3-4 

Summary of Results - Unicracker Testing 

Furnaces B-l, B-2, B-3, B-4, B-5 (Common Stack) 

Test Dates July 24 and 26, 1984 

Run 

No. 

1 

2 

3 

Particulates 

Lbs/Hr 

2.44 

0.745 

1.59 

Sulfur Dioxi 

Lbs/Hr 

1.69 

1.80 

2.76 

de Oxides of Ni 

i 

Lbs/Hr 

39.1 

41.6 

43.4 

trogen CJ irbon Monoxide 

Lbs/Hr 

1.13 

1.29 

2.13 

Opacity % 

-

-

-

Average 1.59 2.08 41.4 1.52 

Permit Limit 18.24 429.15 109.81 7.016 20 
' TABLE 3-5 

Summary of Results and Operating Levels 

'C1 Reformer CO Compliance Testing - B-501, 502, 506 

Test Date July 27, 1984 

Run 

No. 

1 

2 

3 

Average 3.21 

Carbon Monoxide* Product 

Limit Actual Octane 

0.156 

0.174 

0.128 

0.153 

Design 

100.1 

100.1 

100.1 

100.1 

102.4 

Unit Feed 

Rate (BPD) 

44,997 

45,019 

45,006 

45,007 

45,000 

Heat Release 

(MMBTU/HR) 

102.5 

101.5 

98.0 

100.7 

198.54 

Normal 

Maximum 98.0 52,000 125.0 

* Emissions given as lbs/hr. 
TABLE 3-6 

Summary of Results 

Test Date July 28, 1984 

Nitrogen Oxides - Upper Oxygen Limit Observations 

Sample 

ID 

4A 

4B 

4C 

4D 

Average 

(Test Set 

5A 

5B 

5C 

5D 

Average 

(Test Set 

6A 

6B 

6C 

6D 

Average 

(Test Set 

Permit 

Limit 

3) 

4) 

5) 

NO 

lbs/fir 

16.0 

15.1 

15.2 

14.8 

15.3 

20.0 

24.7 

21.2 

21.7 

21.9 

17.4 

16.7 

17.0 

17.0 

17.0 

37.6 

Emissions 

lbs/MMBTU 

0.163 

0.154 

0.155 

0.151 

0.156 

0.211 

0.261 

0.224 

0.229 

0.231 

0.182 

0.174 

0.177 

0.177 

0.178 

0.190 . 

Oxyg. 

B-501 

2.9 

3.1 

3.2 

1.9 

2.8 

4.6 

5.3 

5.9 

5.7 

5.4 

4.1 

3.6 

4.1 

4.1 

4.0 

-

en Levels 

B-502 

6.4 

6.8 

6.7 

6.2 

6.5 

7.5 

8.3 

7.6 

7.9 

7.8 

7.5 

7.8 

8.1 

8.8 

8.1 

-

B-506 

3.2 

3.3 

3.1 

1.8 

2.9 

4.6 

5.6 

5.4 

5.5 

5.3 

4.4 

3.8 

2.9 

3.1 

3.6 

-

Weighted^. 

Average 

4.5 

4.8 

4.7 

3.9 

4.5 

5.9 

6.7 

6.5 

6.6 

6.4 

5.6 

5.4 

5.4 

5.7 

5.6 

-

* Weighted by fuel gas consumption 
P.29 

TABLE 3-7 

Summary of Results and Operating Levels 

Coker II Performance Testing - Carbon Monoxide for B-202 Furnace 

Test Date July 28, 1984 

Run 

No. 

1 

2 

3 

Average 

Carbon 

Limit 

-

-

-

5.467 

Monoxide* 

Actual 

< 0.13 

< 0.12 

<0.12 

<0.12 

Unit Feed 

Rate (BPD) 

26,370 

26,251 

26,536 

26,386 

Heat Release 

(MMBTU/HR) 

122.6 

120.7 

120.7 

121.3 

Design 35,000 158.8 

Normal Maximum 44,000 125.0 

*Emissions given as lbs/hr. 
ATTACHMENT 4 

H2S Monitoring Data for Last Quarter 

Citgo Petroleum Corporation 

P. 0. Box 1562 

Lake Charles, LA 70602 

CONTENTS 

Attachment 4-1 Hourly Analyzer and Draeger Tube readings for F-2 Drum 

Attachment 4-2 Draeger Tube Readings for F-104 Drum 
P.32 

ATTACHMENT 4-1 

H2S Hourly Data - F-2 Drum 

//H2 S JCC 7^00,'L A TALLMA.V-.CLAS S =X . -"SCCL -V SS = 

LCO IEFAC3 I '-'2S STATE D T I YE = 1 A . 5 5 . 32 

LOG IEF'*CA[ "2 S SV-DE3 T IYS = 1 A . 5 6 . 35 

//JG.SLI S 

//STEP 1 

CO 

EXEC 

OS,J = OL.PE . LOPS. DISP =SHR 

PG.-1-=H2SPRINT 

//FTO6c001 

//FT1AF0O1 

OO 

00 

SYSJUT=X 

OSNrQL.PE.H-JH2S.DISP=(OLD,KESP ) 

IEF236I »LLOC. FOR H2 3 STEP1 

IEF237I 1 

'EF237I 5 

53 

AC 

ALLOCATED TO JGBLIri 

ALLOCATE1? TQ FnAFOO l 

SF1A2I 

IFF2<?5I 

ST- o 

OL.P F 

WAS 

• LO : 

E*ECJTSD - CO.NO -COOE OOOO 

... . ^OJ I V: L SE R NO S 

IEF285 I CL.PE.HWH2 S 

IEF285 I VOL SE* NOS 

IEF373 I <TE 3 /STEP 1 

IEF37A I STEP /STE? l 

IEF235 I OL.PE.LOP G 

IEF2S5 I VOL SES 

ICF293 I H2S 

IEF375 I JCB 'H?S 

TEF376 I JCB /H2 S 

10 1 SA 1 

10 1 3A 2 

10 i 9A 3 

10 I IA - A 

10 1 iA S 

NOS 

SYS 

r AAAAAA. 

•= FAGEPK. 

/ STAP.T HA319.1A5 5 

/ STOP 3A319.1A5 6 

: AAAAAA. 

OUT=X. 

/ START 3A319.1A5 5 

/ STOP SA319.1A5 6 

50.9 3 

A7.Q 3 

A7.6 3 

<-=:.i2 

3 1 . = A 

CPU 

C°U 

0."I N 

CMIN 

K-PT 

0J.J2SE C ST?* VP T 

<=PT 

•? ? . •?.? S r C 

Dr^Q-^^ s 

<Ci\£€^&L<U 

•S"< / 

A2-< 

IC 

12 ro.7 ; 

10 

10 

10 

I ?A 

I SA 3 9 . 

27 

SA 

I

 S

.A 

1 SA 

10 

S2 

,"7 

. 1 1 JLL 

10 

I C 

10 

10 

10 

1 2A 

1 JA 

1 2A 

1 3A 

1 SA 

12 

13. 

IA 

15 

16 

17 

5 5.2 0 

5A.5 0 

56.6 2 

5S.2 1 

5 7 . A*, 

57.6 5 

10 

10 

10 

10 

1 3A 

1 SA 

13 

19 

6 6 . 

5 A. 

53 

87 

1 dA 

1 oA 

20 

21 

kC 

. 5A 

.A9 

10 

IC 

10 

10 

IC 

10 

10 

10 

10 

10 

"ry 

10 

10 

1 9A 

I -3A 

2 2 

23 

A 7 . 3A 

17 

1 dA 

2 SA 

2A 

1 •2. 

1 3 

21 

2 6A 

2 ?A 

5 2 . 

5 1 . 

0 9 

5 7 

2 SA 

50 

.6A 

. ' 5 

Z SA 

2 £A 

A?. 

5 1. 

26 

79 

JJs: 

3A 6 5 . 

67 

9A 

SA 

10 

11 

5 5 . 61 

0 3 Al. 

10_ 

0 

10 

L '-a . 

2 j-. 

2 SA 

1 - H 

12 

1? 

IA 

15 

6 2 . 

S?.. 

6 7 . 

7 0 . 

20 

i_l_ 

70 

02 
P.33 

10 10 

'15 

, 10 

J , 1? ^ 10 f "10 10 10 10 10 10 10 10 10 • '• 10 10 1 0 

••'-. 1 0 10 ' ': 1 0 10 lo 10 1 0 10 lo 10 10 10 10 10 l o 

\ 10 ; i o 1 , IC 10 i 10 10 1 2 

•If. 10 10 10 10 10 IC 10 i :• 10 l o 10 10 10 10 10 I C 10 10 10 10 l u l u 10 

-—•at — 

L 

i *> 

3 

3 

3 

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P.66 
P.67 

Attachment 5 

CITGO Petroleum Corporation Lake Charles Operations 

Box 1562 

Lake Charles. LA 70502 

January 8, 1985 

Mr. Gus Von Bodungen 

Department of Environmental Quality 

Air Quality Division 

P. 0. Box 44066 

Baton Rouge, LA 70804 

Gentlemen: 

Re: Quarterly Emissions Report-4th Quarter, 1984 

Citgo Petroleum Corporation 

B-101 Heater, 'B' Light Cycle Oil Hydrotreater 

B-4 Heater, *A' Topping Unit 

B-104 Heater, 'B' Topping Unit 

B-201, B-202 Heater, Coker II 

B-501, B-502, B-506 Heater, 'C Reformer 

B-503, B-504, B-505 Heater, 'C* Reformer 

B-l, B-2, B-3, B-4, B-5 Heater, Unicracker 

In accordance with 40 CFR 60,7 (c) of the regulations on New Source 

Performance Standard, attached is our quarterly report on emissions for the 

'B' LCOH, 'A' Topping, and 'B' Topping sources. Since all three sources are 

supplied by the same fuel gas source, the H2S levels are essentially the same 

for each source and were monitored by the same continuous monitoring 

analyzer. The analyzer produces H2S readings approximately every five minutes 

and the readings are recorded in our computer system. Hourly averages were 

taken from the system and averaged into three hour periods. Periods of excess 

emissions were then compiled in tabular form by month. A monthly log has been 

included with the report to identify periods of excess emissions and briefly 

explain their cause. 

Overall operation of the H2S treating unit was exceptional this 

quarter. Only 1-3 hour average exceedence was experienced at the ' B' LCOH, 

'A' Topping, and 'B' Topping sources. 

In addition this letter serves as our quarterly report on emissions 

from the Coker II, ' C Reformer and Unicracker sources. Since all the heaters 

are supplied by the same fuel gas source, the H2S levels are essentially the 

same for each source and are monitored by draeger tubes taken from the F-104 

fuel gas system. As per our March 13, 1984 letter to your office, subsequent 

to the certification of these heaters, we initiated a once per shift draeger 

tube monitoring system with additional samplings in times of operational upsets. 
P.68 

Your office was notified of exceedences of the standard during this 

quarter by our letter of October 16, 1984. Exceedences on October 26 and 28 

were single draeger tube readings above 200 ppm H2S which were not reported by 

a separate letter. The episodes can be attributed to a combination of higher 

than normal lean amine H2S concentrations being received by the Coker II unit 

for processing in the off gas absorber tower and operation of the Coker II 

absorber at an elevated temperature which reduces efficiency. Operational 

adjustments to the Central Amine and Coker II systems resolved the situation. 

In addition, on October 28, the charge rate to the Coker II unit was reduced 

for a period of time to allow a more rapid return to compliance. 

If there are any questions concerning this report, please contract 

my staff at (318) 491-6318. 

Very truly yours 

J.vE^Thompson 

General Manager, Operations 

LAT/sal 

Attachments 
CITGO PETROLEUM CORPORATION 

LAKE CHARLES OPERATIONS 

EXCESSIVE AVERAGE H S READING - "B" LCOH B-101 HEATER 

1

 "A" TOPPING B-4 HEATER 

OCTOBER 1984 "B" TOPPING B-104 HEATER 

Day 0300 0600 

3-Hr. Period Ending at Hour: 

0900 1200 1500 1800 2100 2400 

Total Excess 

Emission Periods 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 - - - -

25 

26 

27 

28 

29 

30 - - - - -

31 - • -

NOTES: 

1. All readings in ppmv; ppmv x 1.4167 = mg/dscm @ 20°C. 

2. ND means analyzer data was not available. 

3. Averages during periods in compliance not shown. 

239 

0 

0 

0 

0 

0 

0 

0 

0 

0 

0 

0 

0 

0 

0. 

0 

0 

0 

0 

0 

0 

0 

0 

1 

0 

0 

0 

0 

0 

0 

0 

0 
CITGO PETROLEUM CORPORATION 

LAKE CHARLES OPERATIONS 

EXCESSIVE AVERAGE H S READING - "B" LCOH B-101 MATER 

"A" TOPPING B-4 HEATER 

NOVEMBER 1984 "B" TOPPING B-104 HEATER 

o 

3-Hr. Period Ending at Hour: Total Excess 

Day 0300 0600 0900 1200 1500 1800 2100 2400 Emission Periods 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

16 

18 

19 

20 

21 

23 

24 

25 

26 

27 

^ - - - . -

29- ... . -. 

30 

31 

NOTES: 

1. All readings in ppmv; ppmv x 1.4167 = mg/dscm @ 20°C. 

2. ND means analyzer data was not available. 

3. Averages during periods in compliance not shown. 

0 

0 

0 

0 

0 

0 

0 

0 

0 

0 

0 

0 

0 

0 

15 . . . - - . - - 0 

0 

17 . . . . . - - . • - _ o 

0 

0 

0 

0 

22------- - 0 

0 

0 

0 

0 

0 

0 

0 

0 

0 
CITGO PETROLEUM CORPORATION 

LAKE CHARLES OPERATIONS 

EXCESSIVE AVERAGE H S READING - "B" LCOH B-101 HEATER 

1

 "A" TOPPING B-4 HEATER 

DECEMBER 1984 "B" TOPPING B-104 HEATER 

3-Hr. Period Ending at Hour: Total Excess 

Day 0300 0600 0900 1200 1500 1800 2100 2400 Emission Periods 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

20 - - -

21 

22 - -

23 - - - - ' -

24 

25 

26 

27 

28 

29 ... . 

30 

31 

NOTES: 

1. All readings in ppmv; ppmv x 1.4167 = mg/dscm @ 20°C. 

2. ND means analyzer data was not available. 

3. Averages during periods in compliance not shown. 

0 

0 

0 

0 

0 

0 

0 

0 

0 

0 

0 

0 

0 

0 

0 

0 

0 

0 

19 - - . . - - - - - - 0 

0 

0 

- - . - . - o 

- • _ - . - o 

0 

0 

0 

0 

0 

0 

0 
P.72 

CITGO PETROLEUM CORPORATION 

LAKE CHARLES OPERATIONS 

EXPLANATION CODES FOR EXCESSIVE H S READINGS 

Code Explanation 

1 Fuel Gas Process Unit - Process Upset 

2 Light Ends Recovery Unit - Process Upset 

3 Fuel Gas Process Unit - Mechanical Failure 

4 Light Ends Recovery Unit - Mechanical Failure 

5 Minor Upsets - Exact Cause Undetermined 

6 Monitor out of service 

7 Data not recovered 

8 , Computer out of service 

9 Other - comment will be provided 
P.73 

CITGO PETROLEUM CORPORATION 

LAKE CHARLES OPERATIONS 

EXPLANATION LOG FOR EXCESSIVE EMISSIONS 

"B" LCOH B-101 HEATER 

"A" TOPPING B-4 HEATER 

"B" TOPPING B-104 HEATER 

OCTOBER 1984 

Day 

23 

Ending Hours of Periods 

of Excess Emissions 

0600 

Code Comments 

Hydrocarbon carryover to 

amine system. 

"B" LCOH B-101 Heater Operating Period(s): 

October 1 through October 31 

"A" Topping B-4 Heater Operating Period(s): 

October 1 through October 31 

"B" Topping B-104 Heater Operating Period(s): 

October 1 through October 31 

Coker II B-201, B-202 Heater Operating Period(s): 

October 1 through October 31 

"C" Reformer B-501, B-502, B-506 Heater Operating Period(s): 

October 1 through October 31 

"C" Reformer B-503, B-504, B-505 Heater Operating Period(s): 

October 1 through October 31 

Unicracker B-l, B-2, B-3, B-4, B-5 Heater Operating Period(s) 

October 1 through October 31 

NOTE: 

Explanation of codes available in attachment 
P.74 

CITGO PETROLEUM CORPORATION 

LAKE CHARLES OPERATIONS 

EXPLANATION LOG FOR EXCESSIVE EMISSIONS 

"B" LCOH B-101 HEATER 

"A" TOPPING B-4 HEATER 

"B" TOPPING B-104 HEATER 

NOVEMBER 1984 

Ending Hours of Periods 

Day of Excess Emissions Code Comments 

No exceedences 

"B" LCOH B-101 Heater Operating Periods(s): 

November 1 through November 30 

"A" Topping B-4 Heater Operating Period(s): 

November 1 through November 30 

"B" Topping B-104 Heater Operating Period(s): 

November 1 through November 2 

November 19 through November 30 

Coker II B-201, B-202 Heaters Operating Period(s): 

November 1 through November 5 

November 19 through November 30 

"C" Reformer B-501, B-502, B-506 Heaters Operating Period(s): 

November 1 through November 30 

'C Reformer B-503, B-504, B-505 Heaters Operating Period(s): 

November 1 through November 30 

Unicracker B-l, B-2, B-3, B-4, B-5 Heater Operating Period(s) 

November 1 through November 8 

November 19 through November 30 

NOTE: 

Explanation of codes availabl e in attachment 
P.75 

CITGO PETROLEUM CORPORATION 

LAKE CHARLES OPERATIONS 

EXPLANATION LOG FOR EXCESSIVE EMISSIONS 

MB" LCOH B-101 HEATER 

"A" TOPPING B-4 HEATER 

"B" TOPPING B-104 HEATER 

DECEMBER 1984 

Day 

Ending Hours of Periods 

of Excess Emissions Code Comments 

No exceedences 

"B" LCOH B-101 Heater Operating Period(s): 

December 1 through December 31 

"A" Topping B-4 Heater Operating Period(s): 

December 1 through December 21 

"B" Topping B-104 Heater Operating Period(s): 

December 1 through December 31 

Coker II B-201, B-202 Heaters Operating Period(s): 

December 1 through December 3 

December 16 through December 31 

*C' Reformer B-501, B-502, B-506 

December 1 through December 31 

Unicracker B-l, B-2, B-3, B-4, BDecember 1 through December 31 

•C Reformer B-503, B-504, B-505 

Heaters Operating Period(s): 

-5 Heater Operating Period(s) 

Heaters Operating Period(s): 

December 1 through December 31 

NOTE: 

Explanation of codes available in attachment 
Attachment 6 

P.77 

CITGO REFINERY 

SAMPLE AND TEST SCHEDULE 

SCHEDULE 7 

ISSUE: 85-1 

CENTRAL AMINE UNIT 

SAMPLE 

DESCRIPTION 

MEA Lean 

MEA Lean 

MEA Rich 

H2S, Stream 

F-221 Reflux 

\ NOTES ~

c< 

* • * 

1 

2 

3 

>SAMPLE TIME^> 

3iAM 12MN 6PM &! 

X X X 

X 

X 

X 

x 

REQUIRED 

ANALYSIS 

% MEA, M/M H2S, M/M C02 

TSS, Iron ppm, Heat 

Stable Salts 

% MEA, M/M H2S, M/M C02 

M.S. 

pH 

SAMPLE 

SIZE 

1 Qt. 

1 Qt. 

1 Qt. 

Finger Bom 

1 Qt. 

* Samples should be ready for pickup 15 minutes prior to time indicated. 

(1) First Monday of every month only. 

(2) Tuesday and Friday only. 

(3) Monday only. 

CHANGED \V ** Reflects change in sample time. 

Issued by 

CITGO LABORATORIE: 

on 2/14/85 
P.79 

ATTACHMENT 7 

H2S in Fuel Gas Analyzer Performance Test 

Citgo Petroleum Corporation 

P. 0. Box 1562 

Lake Charles, LA 70602 

CONTENTS 

Attachment 7-1 Notification of Performance Testing 

Attachment 7-2 Report on Performance Testing 
Attachment 7-1 

CITIES SERVICE COMPANY 

BOX 156 2 

LAKE CHARLES. LOUISIANA 70602 

July 15, 1981 

Director, Enforcement Division (6E) 

Environmental Protection Agency 

First International Building 

1201 Elm Street 

Dallas, TX 75270 

Gentlemen: 

Re: Performance Test - H2S in Fuel 

Gas On-line Gas Chromatograph 

A performance evaluation test for the H2S in fuel gas analyzer 

for our "B" LCOH B-101 heater is scheduled for Wednesday, August 5, 1981. 

As mentioned in our letter of April 8, 1981 on the results of the compliance performance test on this unit, a Bendix Model 7000 Gas Chromatograph 

was chosen as the instrument to meet the monitoring and reporting requirements of the New Source Performance Requirements. Since that instrument 

was not performing adequately at the time of the performance test, compliance 

monitoring since that time has been the use of "Draeger" absorption tubes 

and regular grab samples for laboratory gas chromatograph analyses. We 

now feel that the reliability of the instrument has been improved and are 

therefore scheduling the performance evaluation test as mentioned above. 

It is our understanding that performance specifications have not 

been promulgated for H2S in fuel gas analyzers. Accordingly, we plan to 

measure the performance of the analyzer in the following manner: 

Four sets of H2S in fuel gas analyses will be performed using 

the EPA Reference Method 11. The samples will be taken one hour apart. 

Since the H2S analyzer is an extractive type monitor and has a cycle 

length of about five minutes, all of the readings taken from five minutes 

prior to the start of sampling to five minutes after the sampling will be 

averaged to yield a comparable value to what the Method 11 analyses should 

show. The results of the four sets of analyses will be averaged. The 

percentage difference between the two methods should agree within ±5% 

or the test will be repeated. 

We trust that the above method of evaluating the performance of 

the H2S analyzer will meet the intent of the New Source Performance Standards 

for Subpart J. If you have any questions concerning this test or wish to 

observe, please call my staff at (318) 491-6318. 

\ery truly yours, 

<J-JE. Thompsron 

Manager Operations Engineering 

DKM/tb 

cc: Louisiana Dept. of Natural Resources 

Air Quality Division 
P.81 

f 

Attachment 7-2 

CITIES SERVICE COMPANY 

BOX 1562 

LAKE CHARLES. LOUISIANA 70602 

August 13, 1981 

Director, Enforcement Division (6E) 

Environmental Protection Agency 

First International Building 

1201 Elm Street 

Dallas, TX 75270 

Gentlemen: 

Re: Performance Test - H2S in Fuel 

Gas On-line Gas Chromatograph 

A performance evaluation test for the H2S in fuel gas analyzer for 

our "B" Light Cycle Oil Hydrotreater B-101 heater was conducted on August 5, 

and August 10 of this year in accordance with our letter of July 15, 1981. 

The analyzer, a Bendix Model 7000 Gas Chromatograph, performed adequately 

during the tests, and is therefore designated as our official means of 

compliance with 40 CFR 60.105 (a)(4) (Subpart J - Petroleum Refineries). 

The test was conducted by making four runs with Method 11, each 

at least one hour apart, while collecting data from the same period with 

the analyzer. The first sample was obtained on the morning of August 5, 

1981. Since this sample showed very low levels of H2S, the remainder of 

the runs were postponed until August 10, at which time the levels were 

higher and more within the range of the instrument. The data obtained 

during the four runs are given in Table I attached. 

The analyzer had an average positive bias of 11.9 PPM (16.9 mg/dscm). 

This is easily explainable as an error of only ZA% in the setting of the 

zero with a full scale (span) value of 500 PPM. The four sets of data were 

subjected to a Least Squares Curve Fit which gave a straight line with a 

slope of 0.926 and an intercept of 14.8. A correlation coefficient of 0.9998 

indicates that the correlation was very linear. By extrapolating the data to 

the standard of 230 mg/dscm, the analyzer would read 233 mg/dscm, for an error 

of 1.3%, which is well within our target of plus or minus 5%. 

We trust that this evaluation of the performance of the H2S in fuel 

gas analyzer will meet the intent of the New Source Performance Standards for 

Subpart J. This instrument will now be used for all reporting and monitoring 

requirements in accordance with 40 CFR Subpart J. If you have any questions 

concerning this matter, please call my staff at (318) 491-6318. 

Very truly yours, 

JVE . Thompson 

Manager Operations Engineering 

DKM/tb 

Attachments 

xc: Louisiana Dept. of Natural Resources 

Air Quality Division 
P.82 

TABLE I 

CITIES SERVICE COMPANY 

« 

INSTRUMENT PERFORMANCE EVALUATION 

BENDIX MODEL 7000 GAS CHROMATOGRAPH 

H2S IN FUEL GAS 

LEAST SQUARES CURVE FIT 

Slope =0.926 

Intercept =14.8 

Correlation Coefficient = 0.9998 

Date • 

8/05/81 

8/10/81 

8/10/81 

8/10/81 

An 

Time 

9:44- 9:56 A.M. 

8:49- 8:59 A.M. 

10:43-10:58 A.M. 

12:47-12:57 A.M. 

thmetic Mean 

Analvzer 

PPM 

24.0 

62.7 

59.0 

57.9 

50.9 

Method 

PPM 

10 

52 

48 

46 

39 

11 Difference 

PPM 

14.0 

10.7 

11.C 

11.9 

11.9 

DKM/tb 

08/13/81 
P.84 

ATTACHMENT 8 

Copy of Forms used for Recordkeeping 

and Reporting 

Citgo Petroleum Corporation 

P. 0. Box 1562 

Lake Charles, LA 70602 

CONTENTS 

Attachment 8-1 Shift Reports of H2S in Fuel Gas from AI-507 Analyzer 

Attachment 8-2 Calendar Year Summary Report 
Attachment 8-1 

(io.^'G>b\ ... 0.pev<xW-V .^VJNJL.dtNcL-ivSL^fiii.. 

_ ... _ <6y.Cee.c| <zj>AC.e _ _... 

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112 b LMISSIOI-Ib I EXCEEDENCE VW THE 1TIUI:E HOUI? t%MOU ENIHNO AT 6--W. EMIbblONS = 2M.'i'A PMM. 

PROVIDE AU EXPL .NATION BELOW l-OR EACH Ol-" THE AMOVE bTATEO EXCEEPEIICEb: 

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CCA^LA DpevoAt-v s SVA l Zi\k \j:piA 

SUMMARY OF II2S EMISSION EXCEEDENCES 

FOH THE SHIFT END ING AT 6:4' j ON 03-O'j-M-j 

1HEIVE r/EHE NO H2S EMISblO EXCEEDENCES l)UI,'IN(; THIS SHIFT 
P.87 

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