P.1 

OAR Box 1784 

Prepped by Ollie Stewart 

Document Number: 

54) ll-D-6 

Docket Number: 

A-84-44 

Printed 10/31/2008 8:05:40 AM Sheet 54 of 143 
P.2 

A--84-'44 

Shell Oil Company 

One Shell Plaza 

P.O. Box 4320 

Houston, Texas 77210 

April 9, 1985 

Mr. Jack R. Fanner, Director 

Emission Standards and Engineering Division 

Office of Air Quality Planning and Standards 

United States Environmental Protection Agency 

Research Triangle Park, North Carolina 27711 

Dear Mr. Farmer: 

As requested in your letter of January 25, 1985, the attached information 

on process equipment and associated emission control equipment subject to 

the petroleum refinery fuel gas provisions of 40 CFR 60 Subpart J is 

forwarded for Shell Oil's Norco, LA, Wilmington, CA and Martinez, CA 

refineries. Please note that only cost and supplementary process information are provided for Norco refinery since the balance of the data were 

obtained during an EPA field trip to that facility. 

Our Wilmington refinery has identified three problem areas encountered in 

complying with the NSPS. These are the dual reporting of information to 

EPA and to the state agency, the short pre start-up notification of 30 to 

60 days, and possible difficulties in meeting the "performance test deadline of start-up plus 180 days. (See Section i-I, page 14 of Wilmington's response) 

We believe the attached data responds to all of the information requested 

in EPA's questionnaire. However, if clarification is required please 

feel free to contact me at (713) 241-1889. 

Very truly yours, 

J//A. Mullins, Manager 

Mvironmental Programs 

Environmental Affairs 

JAE/blv 

Attachment 

t,.. O ^y v * S <J 1 
P.3 

SHELL OIL COMPANY 

MARTINEZ MANUFACTURING COMPLEX 

RESPONSE TO EPA QUESTIONNAIRE 

NSPS - PETROLEUM REFINERIES -

FUEL GAS COMBUSTION DEVICES 

CR8509906 
P.4 

II. FACILITY DESCRIPTION 

The Martinez Manufacturing Complex (MMC) refinery fuel gas system utilizes 

various process streams including natural gas, dry gas, process unit vents, 

volatiles vaporized from storage, and vents from vapor recovery systems. 

Typical flows are Illustrated in Figure 1. The streams are blended together 

and routed to three separate processing areas: Operations Central (OPCEN), 

Light Oil Processing (LOP), and Heavy Oil Processing (HOP). Figures 2 and 

3 depict the combustion devices in LOP and OPCEN, respectively. HOP, 

which is not shown, contains nine process heaters. In addition to blended 

refinery fuel gas, several process heaters and boilers are equipped to 

burn low sulfur fuel oil and low BTU gas from our Flexlcoklng Unit. 

MMC has four amine treaters which remove H2S from refinery fuel gas (refer 

to Figure 4). All of the net dry gas produced at the Catalytic Cracking 

Unit is routed to refinery fuel after amine treatment in two parallel 

Treater Columns, Column 103 and Column 176. Dry gas produced at the Sats 

Gas Plant is treated for H2S removal in Column 97 after which 80% is used 

as Hydrogen Plant No. 1 feed gas and the remaining 20Z goes to refinery 

fuel. Dry gas from the Flexlcoklng Unit is treated in Column 215 and, 

again, 80Z is used as Hydrogen Plant No. 2 feed and 20Z is sent to refinery 

fuel blending. 

At MMC, Diethanolamine (DEA) is the amine used for fuel gas treating; 

three amine regenerators are used in parallel to service the amine system. 

H2S-rich acid gas from the regenerators is charged to three Claus Units. 

Sulfur Plant Nos. 1 and 2 are adjacent units located in Light Oil Processing and tail gas from each is combined and routed to a single SCOT tall 

gas unit (SCOT No. 1). Sulfur Plant No. 3 is located at Operations Central 

and has a dedicated SCOT unit (SCOT No. 3). 

The quantity of sulfur removed at the fuel gas treaters is 33 LT/D from 

Sats Gas Plant Column 97, 11 LT/D from OPCEN Column 215, and 26 LT/D from 

the Cat Cracker gas treaters Column 103 and Column 176. Therefore, the 

total is approximately 70 LT/D sulfur removal from dry gas streams being 

processed for refinery fuel or hydrogen plant feed. 

Because the lean DEA and rich DEA headers are common to all amine treaters, 

there is no segregation of sulfur-rich amine 6tream to any particular 

regenerator. Sulfur Plant No. 3 is base loaded for 30 LT/D sulfur recovery; 

this fixes the feed rate of rich amine to DEA No. 3 Regenerator. The 

remaining rich amine circulation is split between DEA Nos. 1 and 2 Regenerators, so that Sulfur Plant Nos. 1 arid- 2 process about 20 LT/D each.of 

the remaining sulfur removed from gas treating. In addition to amine acid 

gas, Sulfur Plant Nos. 1 and 2 also process acid gas from sour water 

strippers; Sulfur Plant No. 3 cannot process sour water acid gas. 

- 1 
III. COSTS 

P.5 

The following cost information has been included for our four amine 

treaters: 

b. 

c. 

Item 

Purchase Cost1/ 

Year Purchased 

Installation Cost£' 

Annual Operating Costs 

Labor Costs 

Hours/Day 

$/Hour£/ 

Materials 

Replacement Parts 

Chemicals 

Gallons 

$/Gallon 

Sulfur Credit^/ 

Steam 

Lb/Hr 

Pressure, psig 

Temperature 

Electricity^^ 

Water 

Col. 97 

Sat6 Gas 

Treater 

$14,535 

1965 

$29,000 

$23,600 

3.0 

$21.55 

$1,500 

$25,215 

6,150 

$4.10 

$915,400 

Col. 109 

Stripper 

No. 1 

6,300 

50 

325 

$150,000 

NA 

Col. 103 

CCU Gas 

Treater 

$11,994 

1965 

$24,000 

$9,450 

1.2 

$21.55 

$1,000 

$20,500 

5,000 

$4.10 

$360,600 

Col. 175 

Stripper 

No. 2 

6,700 

50 

325 

$150,000 

NA 

Col. 176 

CCU Gas 

Treater 

NA 

1973 

NA 

$9,450 

1.2 

$21.55 

$1,000 

$20,500 

5,000 

$4.10 

$360,600 

Col. 240 

Stripper 

No. 3 

6,700 

50 

325 

$150,000 

NA 

Col. 215 

OPCEN 

Treater 

$62,700 

1981 

$125,000 

$23,600 

3.0 

$21.55 

$1,500 

$14,785 

3,850 

$4.10 

$305,140 

d. Key Accounting Factors 

Lifetime of equipment - 20 years 

Equipment amortization and depreciation rate - 52 

Total 1984 labor/management charges - $42 MM 

Overhead rate - 11.54% of net manufacturing expense 

and variable cost) 

(total fixed 

1/ Purchase cost includes vessel and internals. Cost of initial chemical 

inventory not available. 

?J Installation cost is estimated and includes foundation, instrumentation, and labor. 

3/ Hourly rate includes burden. 

4/ Credit based on sulfur balance and $76/LT of recovered sulfur. 

][/ Electricity co6ts based on 300 HP. 

- 2 -
P.6 

IV. REFINERY COMBUSTION DEVICES 

1. Our refinery has 44 process heaters and 4 boilers which burn refinery 

fuel gas. 

2. Typical examples and ranges for process heaters and boilers are listed 

below: 

Process Heaters Boilers 

3. 

a. BTU Rating, MM BTU/HR (Released) 

Refinery Fuel Gas, MMSCFD 

b. Capital & Operating Costs 

Hours of Operation, 

Days per Year 

Type of Operation 

HR/D 

Typical Range 

93 6-599 

2.5 0.2-16.0 

Not Available 

24 24 

365 365 

Continuous 

— -

80 0-90 

0 0-490 

Typical Range 

232 232-269 

2.3 0.5-7.2 

Not Available 

24 24 

365 365 

Continuous 

52 50-54 

50 0-90 

228 0-390 

d. CCU Low BTU Gas1/ % of Duty 

FXU Low BTU Gas^/ % of Duty 

Low Sulfur Fuel Oil, B/D 

1/ CO ex CCU Regenerator burned in 3 CO Boilers only. 

21 Low BTU Gas ex FXU burned only in heaters listed in Section IV-3. 

Listed below are new and modified combustion devices which are subject to 

the NSPS. No steps were taken to comply with the NSPS because the existing 

H2S level (using existing amine treaters) was acceptable. 

Equipment 

No. 

F-40 

F-41A 

F-4 IB 

F-49 

F-50 

F-51 

F-59 

F-70 

F-71 

F-102 

F-104 

F-126 

F-128 

BTU Rating, 

MM BTU/Hr. 

Rel. 

238 

113 

113 

120 

156 

77 

104 

269 

100 

84 

347 

147 

90 

Service 

Crude Heater 

Vacuum Flasher Heater 

Vacuum Flasher Heater 

Cat Reformer Preheater 

Cat Reformer Interheater 

Cat Reformer Interheater 

Hydrocracker Reboiler Heater 

Station Boiler 

Hydrocracker Reboiler Heater 

Steam Superheater 

Steam Methane Reformer 

Crude Heater 

Cat Reformer Interheater 

Year 

Installed 

1966 

'1966 

1966 

1966 

1966 

1966 

1966 

1970 

1971 

1981 

1981 

1981 

1981 

Year 

Modified 

1981 

1981 

1981 

1981 

1981 

1981 

1981 

1981 

1981 

-

-

-

-

- 3 -
P.7 

IV. REFINERY COMBUSTION DEVICES -2-

4. Without the NSPS, an acceptable maximum limit for H2S in fuel gas would be 

710 ppm to prevent significant adverse corrosion of combustion equipment. 

This premise is based on acid dew point and contains no safety margin for 

the estimation of dew point temperature and heater tubewall temperature. 

Other constraints, such as plume opacity or fuel gas distribution system 

corrosion, were not considered. 

5. Bay Area Air Quality Management District Regulation 9, Rule 3, applies to 

N0X from heat transfer operations. Regulation 10, Rule 2, applies to 

emissions of SO2, N0X, and particulates from new, modified or reconstructed 

steam generators. Regulation 10, Rule 8, applies to the H2S content of 

fuel gas burned in new, modified, or reconstructed combustion devices. 

These regulations did not affect the design or modification of the combustion devices listed in IV-3. 

- 4 -
V. PRIMARY CONTROL (AMINE TREATERS) 

P.8 

Characteristics of the inlet gas to the four amine treaters are not 

available. Included below are typical characteristics and compositions 

of treated gas: 

Same Gas 

Col 97 Col 1( 

Component, %V 

(Typical) 

H2 

Cl 

C2 

C3 

C4 

C5 

C6 

N2 

CO 

CO2 

H2S, ppm 

Sp. Gr. 

LHV, Btu/SCF 

Refer to Figure 4 for a general schematic of the amine treaters. A 

further description is included below: . v 

Col 97 

Sats Gas 

Treater 

56.7 

21.0 

7.0 

3.1 

2.2 

0.2 

0 

9.8 

0 

0 

<50 

0.420 

605.3 

Col 103 Col 176 

CCU Gas CCU Gas 

Treater Treater 

22.5 

32.5 

22.8 

5.9 

1.1 

0.5 

0 

11.9 

0.7 

2.1 

<50 

0.705 

897.7 

Col 215 

OPCEN 

Treater 

25.2 

44.3 

19.9 

4.6 

0.8 

0 

0 

4.4 

0.8 

0 

<50 

0.592 

910.4 

Item 

Engineering Contractor 

Startup Year 

Operations, Hrs/Yr 

Design/Actual 

Gas Rate, MMSCFD 

Temperature, *F 

Pressure, PSIG 

Amine Circulation, MB/D 

Lean Amine Temp., °F 

Col 97 

Sats Gas 

Treater 

Fluor 

1966 

8760 

12.5/16.0 

111/90 

160/160 

9.6/8.0 

100/120 

Col 103 

Fuel Gas 

Treater 

Braun 

1966 

8760 

14.4/13.0 

115/100 

100/135 

3.5/4.5 

100/120 

Col 176 

Fuel Gas 

Treater 

Shell 

1975 

8760 

30.0/13.0 

115/100 

160/135 

10.0/8.4-

100/120 

Col 215 

OPCEN 

Treater 

Fluor 

1983 

8760 

12.3/10.0 

70/90 

* 163/160 

1.9/3.8 

120/110 

Percent of Treated Gas 

Sent to Fuel System 20% 100% 100% 20% 

- 5 -
P.9 

V. PRIMARY CONTROL (AMINE TREATERS) 

Design/Actual 

Feed Rate, MB/D 

Feed Temperature,

 CF 

Steam to Reboiler, MLB/Hr 

Col. 109 

Stripper 

No. 1 

17.0/9.5 

105/100 

25.0/14.1 

Col. 175 

Stripper 

No. 2 

21.2/10.5 

105/100 

33.3/16.5 

Col. 240 

Stripper 

No. 3 

16.5/9.0 

120/115 

24.8/15.4 

Total amine inventory for four treating columns, three strippers, and associated piping, exchangers, filters, and flash drums is 1500 barrels of 25% w 

DEA. 

3. Our only amine treater installed since the NSPS was in effect is the OPCEN 

Treater, Col. 215. This type of system would have been installed regardless 

of the NSPS because a portion of the treated gas is used as hydrogen plant 

feed and must be low in sulfur content. 

4. A complete maintenance history 6ince startup of each amine treater is not 

available. However, the most frequent maintenance performed during maintenance turnarounds is washing and inspection of the columns. Maintenance 

turnarounds are always performed in conjunction with the shutdown of upstream units. Therefore, no excess emissions occur. 

A typical annual make-up rate for MMC is 20,000 gallons of 85%w DEA. Amine 

losses do not result in excess emissions of SO2 from process heaters, but 

only affect the rate of replenishment. . v 

The greatest problem with amine systems is continual foaming. Foaming in 

treaters can result in increased amine losses by entrainment with the 

process gas flow. Foaming in strippers reduces regeneration efficiency. 

Foaming is controlled by continuous on-line filtration of particulate matter 

and periodic injection of anti-foam chemicals. 

5. Maintenance is typically very low. Amine make-up rates quoted by vendor 

are not available. Make-up rates vary with gas throughputs and frequency 

of major upsets and mechanical breakdowns. The typical annual make-up rate 

is 20,000 gallons of 85%w DEA. 

6. Records are not available for the amine treaters to compare scheduled versus 

unscheduled downtime. However, it can generally be stated that the amine 

treaters are very reliable units. Shutdowns only occur in conjunction with 

maintenance turnarounds of upstream units. Upset6 of the treaters are rare 

and of short duration. 

7. In the past we have inspected these amine treating vessels every three to 

five years. Our normal method of inspection includes visual and UT measurements for thickness. Normal inspections are performed by refinery inspectors whose qualifications exceed those required in API 510 - Pressure Vessel 

Inspection Code. 

- 6 -
P.10 

V. PRIMARY CONTROL (AMINE TREATERS) 

Because of problems experienced by others in the industry, we will inspect 

each vessel at the next scheduled shutdown for amine cracking. Selected 

welds will be inspected using the wet fluorescent magnetic particle testing 

method (WFMPT). This method will be performed by outside inspection 

personnel who are qualified in this procedure to ASNT Level II certification. 

8. For each amine treater the concentration of sulfides in the rich amine and 

the concentration of H2S in the treated gas are monitored daily to indicate 

proper performance. For each stripper the lean amine is monitored daily 

for %w DEA and concentration of sulfides. 

9. To control H2S in the treated gas or sulfides in the rich amine, operational 

adjustments are made to the circulation rates for the treaters and the 

steam rates to the stripper reboilers. 

- 7 -
P.11 

VI. SECONDARY CONTROL (SULFUR PLANTS) 

1. The concentrated H2S streams from the amine treaters are routed to 

Claus sulfur plants with SCOT tail gas units. Claus Plant No. 1 was 

Installed with construction of the Light Oil Processing facilities 

(Including Sats Gas Treater Column 97 and Fuel Gas Treater Column 103) 

in 1966. Clause Plant No. 2 was added in 1974 to provide .spare capacity 

for sulfur recovery operations. Claus Plant No. 3 was installed with 

construction of the Flexlcoker facilities (including OPCEN Treater 

Column 215) in 1981. SCOT No. 1 serves both Claus Plant No. 1 and 

Claus Plant No. 2. SCOT No. 3 serves Claus Plant No. 3. Below is a 

brief description of the plants: 

Claus Claus Claus SCOT SCOT 

No. 1 No. 2 No. 3 No. 1 No. 3 

Engineering Contractor Parsons Parsons Fluor Parsons Fluor 

Startup Year 1966 1974 1983 1981 1983 

Rated Capacity, LT/D 100 100 55 175 55 

2. Both SCOT units use MDEA as an amine solution to provide more selective 

H2S absorption than can be provided with DEA. Therefore, the two 

amine systems are segregated. MDEA is considerably more expensive 

than DEA. Its higher cost is justified for tail gas treating in which 

amine inventory is small and the recovered gas is recycled to the 

Claus plant. . For large volume amine Inventories, such as in the 

refinery fuel gas treating system, MDEA would be too expensive. 

- 8 -
P.12 

VII. EMISSION TESTING 

1. No emission tests have been performed on our amine treaters, other than 

manual sampling for H2S which is performed by unit operators. However, 

total blended fuel gas Is routinely tested three times per week by GC 

analysis. The tests are conducted by refinery Quality Assurance personnel and cost approximately $20 each. Reports for the first sample 

in each month of 1984 have been arbitrarily selected and Included in 

the appendix. Corresponding flows for all fuel gas blending components 

on the appropriate dates have also been included. 

2. Source tests performed by the Bay Area Air Quality Management District 

and the California Air Resources Board on our CO Boilers Nos. 1, 2, and 

3 and our Boiler No. 4 have been Included in the appendix. Pollutants 

included in the tests are SO2, N0X, CO, and particulates. 

In addition, MMC personnel conducted tests on the process heaters listed 

below for NOx during June through August, 1983. The heaters are 

described in Section IV-3. Estimated costs for the series of tests is 

$5,000. 

Equipment 

No. 

F-40 

F-41A 

F-4 IB 

F-49/50/51 

F-59 

F-70 

F-71 

F-102 

F-104 

F-126 

F-128 

Equipment 

No. 

F-40 

F-41A 

F-4 IB 

F-49/50/51 

F-59 

F-70 

F-71 

F-102 

F-104 

F-126 

F-128 

NOx 

ppm 

32 

20 

22 

23 

42 

99 

25 

38 

33 

12 

20 

N0X 

PP° 

42 

15 

13 

35 

52 

99 

12 

60 

25 

19 

27 

Test 

Refinery 

Fuel Gas, 

MMSCFD 

1.0 

0.5 

0.9 

1.3 

0 

0 

0.4 

0.5 

4.4 

1.6 

0.5 

Test 

Refinery 

Fuel Gas, 

MMSCFD 

2.1 

0.5 

0.4 

2.3 

0 

0 

0.4 

0.7 

3.2 

0.7 

0.4 

Run No. 1 

Flexlcoker 

Low BTU Gas 

MMSCFD 

24.8 

13.4 

10.8 

30.1 

6.1 

20.7 

6.4 

6.6 

27.7 

7.4 

6.5 

Run No. 2 

Flexlcoker 

Low BTU Gas 

MMSCFD 

14.8 

10.2 

10.6 

16.9 

6.0 

21.7 

5.8 

4.6 

41.7 

15.0 

5.6 

Low Sulfur 

Fuel Oil, 

B/D 

0 

0 

0 

0 

50 

350 

0 

0 

0 

0 

0 

Low Sulfur 

Fuel Oil, 

B/D 

-. 0 

0 

0 

0 

62 

370 

0 

0 

0 

0 

0 

- 9 -
P.13 

VII. EMISSION TESTING 

3. No state or local regulations require emission testing for existing 

sources or testing beyond the requirements of the NSPS. 

- 10 -
P.M 

VIII. MONITORING OF EMISSIONS AND PROCESS OPERATION 

2. Bay Area Air Quality Management District Regulation 10, Rule 8, requires 

that the H2S content of fuel gas burned in any refinery combustion 

device not exceed 0.10 grains/dscf as determined by continuous monitoring. 

3. a. Total blended fuel gas is monitored at one location with a continuous emission monitor immediately after blending. Continuous monitoring is performed primarily to demonstrate compliance with the 

NSPS. 

b. Manual sampling is performed once/shift (three times daily) u8ing 

colorimetric tubes such as Drager or Gastec. The sampling is 

done to verify proper operation of the amine treater and the 

continuous emission monitor. Cost of the indicating tubes is 

negligible. Accuracy appears to be + 10%. 

c. 1. The continuous emission monitor used is manufactured by 

Houston Atlas, Model 722R/102, paper tape type, with a range 

of 0-300 ppm. The monitor was placed in operation in the 

fourth quarter of 1983. The cost was $31,695 including shelter 

and sampling system, plus $5,000 for installation. 

2. The standard deviation for dally drift compared to 150 ppm 

calibration gas is + 5 ppm. Average breakdown frequency is 

once every 2-1/2 months and average outage is 6.75 hours. The 

sampling system is generally the cause of the breakdown. Cost 

of maintenance is $96 per week for labor, which Includes repair 

and preventative maintenance, and $81 per week for parts, 

which includes calibration gas cylinders. Normal preventative 

maintenance program is dally calibration and operation check, 

which requires 6 hours per week of mechanic's time. 

3. No routine quality assurance tests are performed for H2S. 

However, estimated costs for such tests are $70 each, assuming 

no interferences. The only manual sampling performed is done 

with Drager or Gastec tubes by the unit operator. 

4. Data is continuously recorded by instrument on a one inch per 

hour strip chart. The data i6 also transmitted to a process 

computer which is used for compiling and averaging. Records 

are retained for two years In short-term storage, then transferred to long-term storage. 

5. Available summaries for H2S have been provided in the appendix 

for December, 1984, and January and February, 1985. Typical 

operating conditions are included in Figure 1. Marginal 

excesses of the 3-hour standard occurred on December 8 and 9, 

1984, as a result of an upset at the Sats Gas Plant Dry Gas 

Treater. The unit was upset by an upstream processing unit 

- 11 -
P.15 

VIII. MONITORING OF EMISSIONS AND PROCESS OPERATION -2-

whlch was starting up after a maintenance turnaround. After 

operation at the upstream unit stabilized, the Dry Gas Treater 

returned to normal operation. 

4. a. Total blended fuel gas is monitored for pressure and specific 

gravity. All monitoring is done by continuous instruments. Cost 

of monitoring is approximately $40 per week. 

b. Neither of the process parameters monitored are good Indicators 

of proper amine treater performance or H2S concentration. The 

specific gravity of the blended fuel gas can be correlated with 

variations in fuel gas composition. 

5. There are currently no plans to replace the existing continuous emission 

monitor. 

6. The continuous emission monitor is not integrated into the process as 

a control system. 

- 12 -
P.16 

IX. GENERAL REFINERY INFORMATION 

1. Nominal size of our refinery is 110 thousand barrels per day. For 1984 

average operating level was 100 ..thousand barrels of crude per day. 

The refinery operates 365 days per year. The gravity, sulfur content, 

and Intake of crude can all affect sizing and operation of the amine 

treaters. 

2. Typical crude oil sulfur content is 1.2%w, with a range of 0.7%w to 

1.2%w. Feed rate to the amine treaters will vary directly with crude 

oil sulfur content. Operation of the treaters is adjusted to maintain 

a low level of H2S in the treated gas and operation of the strippers 

is adjusted to maintain a proper level of sulfides in the DEA. The 

level of H2S and other sulfur compounds is rarely affected by changes 

in crude oil sulfur content because of excess treating and stripping 

capacity. 

3. Operation of the amine treating systems is not affected by other 

refinery operating factors because of excess capacity available. 

4. Typically, our total blended refinery fuel gas is 50 MMSCFD, of which 

35% is natural gas. Natural gas makeup can vary from 10% to 60%. The 

blending is done to provide a constant flow of fuel gas to process 

units. 

- 13 -
P.17 

X. GENERAL REGULATORY INFORMATION 

1. No problems have been experienced in interpreting, achieving, or 

complying with the NSPS. , ., 

2. No problems have been experienced in performing testing, monitoring, or 

recordkeeping for the NSPS. 

3. Costs for recordkeeping and reporting are negligible. Refer to Section 

XIII-3-C-5 for a copy of the report form used. 

XI. CONTACTS FOR FURTHER INFORMATION 

J. C. Moorad 

Manager 

Environmental Conservation Department 

(415) 228-6161 

D. F. Obenauer 

Environmental Engineer 

Environmental Conservation Department 

(415) 228-6161 

- 14 -
Fit,uae. I 

3 

FUEL GAS BLENDING 

SAC 

PGE 

CCU 

SGP 

CGP 

SGP 

SGP 

RXV GAS = 

NAT GAS = 

DRY GAS = 

DRY GAS = 

PROPANE = 

PROPANE = 

BUTANE = 

ALKY PROPANE= 

DIMR PROPANE;= 

TOT 

SM. 

LG. 

H2 VENTS= 

> 

VPRZR C3 

VPR2R C3= 

MISC VENTS .,= 

VAPOR RECOV = 

FXU DRY GAS = 

5. 8 

7. 1 

24.3 

3. 8 

e. e 

e. i 

e. e 

e. e 

e. i 

3.7 

e.e 

*s ) 

3. 8 

e. e 

UH 

FUEL GAS BLEND DRUH 

PRESSURE 75.1 PSIG 

SP. GRAVITY 

FM LIMITER 0.59 

FH 9ARH13 

NITROGEN 

MINIMUM SRG 

TO BLN DRUM 

H2S 

HEAT VALUE 

BALANCE 

(IN/OUT) 

e.59 

7.45 'A 

> 

3. ee 

> 

22 PPM 

858.4 BTU/SCF 

1. 63 

11 MAR 85 

15:28:48 

DIS 5151 

NOTE: ALL 

FLOWS ARE 

IN MMSCFD 

NAT GAS 

INFO ON 

DISPLAY 

5156 

TRENDS 

410 > 

412 > 

FLOW 

FH DRUH 

r 

FUEL 

GAS 

BLEND 

DRUH 

4 8 . 4 

• 

e y. 

OPEN 

AuALYses. 

A FLARE 

• 

4 . 8 

TO OP 

CENTRAL 

• 

4e. s TO LOP 

• 

3 . 6 TO HOP 

• 
Fi6ua.e 2. 

E 

40. 5 

MB/D 

LOP REFINERY FUEL GAS DISRIBUTION 

i . O 

F-4 0 

O. 8 

F-41 A 

O. 7 

4- F-41 B 

e. e 

F-4 2 

e . 9 

F*-43 

e . 3 

F-4 4 

i. e 

F-4 S 

O. 7 

F-4 6 

O. 8 

F-4 7 

O. 5 

F-4 9 

O. 7 

F-5 e 

e . 2 

F-5 1 

e . 4 

F-5 2 

e. i 

F-5 3 

e. 6 

F-12 6 

O. 5 

f- F-12 8 

QUfiD f\ 

3 . 3 

F-5 5 

2 . 0 

F-5 7 

O. 9 

+ F-5 8 

O. 3 

+E 5 9 

4 . 9 

F-60 N 

5 . e 

F-66 S 

1 . 4 

F-7 1 

QUA D 

B 

11 MAR 85 

15:29:26 

DIS 5152 

3 . 8 

F-6 6 

O. 5 

F-6 7 

QUfiD 

C 

e. o 

F-6 1 

e. l 

QUfiD 

D 

F-6 3 

3 . 4 

COB 1 

3 . 1 

-i COB 2 UT I L 

3 . 7 

COB 3 

e. e 

BLR 4 

TOTAL TO LOP 

FURNACES 

4 1 . i 

BALANCE 

(SUPPLY/DEMAND) 

O. 98 
FlfclA ae 

® 

4. 66 

76 « 

RFG FH 

LOP 

O. OO 

OPERATIONS CENTRAL FUEL GAS CONSUMERS/PRODUCERS 11 MAR 85 

15:30:09 

DIS 5153 

SP2200 

2201 

F-161 

1. 25 

F-162 

HF OHD 

KDG 

0.03 CLEAN I DRY FUEL GAS 

E 1. 47 

H 1. 55 

F-164 

e.ee 

rl 

e.ee 

"—|H*

 PRP 1 

SPLT C3 

e. is 

— 1 PPR P C^ 

HIXD GAS 

TO LOP 

RFG BLND 

F X U H P 2 DMS 

-HE ies 

-ME 1 6 6 

F-16 7 

F-16 8 

k 

f 

e . 6 2 

F-16 9 

SRU 3 

+FLARE 

INST . 

-fPURGE 

6.3 4 
•EPORT* 30? CHANNEL:, 8 

". . ( • 

SAMPLE< LOP FUEL GAS INJECTED AT 

P.21 

QUflL ASSURE HEP'T 

9:35:27 ON JAN 2, 1984 

IORM-METHOD': CARL5T SEQ: *SEQ6S SUBSQ/SAMP: 1/ 1 

;L-MDTH MV/HIN 

.566 .166 

:UP-UNK DVT 

NO 6.66 

ACTUAL RUN TIME: 

. r-

• $ 

t "W ( S 

et 

15 ^ 7 

16

16 * \-A 4> H 

17 3 r \7] 

19 

19 

22.t-r <c£.z4tt 

23.88 23.88 

25.95 25.95 

26.49 26.51 

27.65 27.66 

28.95 23.96 

32.22 32.22# 

DELAY 

1.66 

ID-LVL 

566 

MIH-AR 

566 

REF-RTW 

.366 

41.617 MINUTES 

. 

V 

5787 

4686 

1684 

1394 

2152 

1911 

3683 

BB 

BB 

BB 

BB 

BB 

BB 

BB 

i 

MOLE '4 

5.653 

.114 

3.424 

7.967 

3E- 6 

•.226 

3.196 

,.846 

.455 

;E- 6 

.192 

E- 5 

E- 4 

E- 4 

.342 

..436 

.351 

.275 

.653 

.671 

.116 

.693 

.268 

BUNCH 

NO 

MRTW *DIL-F I 

3.666 106.66 YES 

NAME 

ttHYDROGEN 

C02 

ETHYLENE 

ttETHANE 

ARTIFACT 

02 + ARGON 

ftNITROGEN 

METHANE 

CARB MONOX 

C6+ 

BACKFLUSH 

MIXTURE 

MIXTURE 

PROPANE 

PROPYLENE 

#ISOBUTANE 

N-BUTANE 

BUTENE-1 

ISOBUTYLEN 

TRANS BUTCIS BUT-2-

ttlSOPENTAN 

TOTAL AREA = 1752869 

PROCESSED DATA FILE: PCB25 

TOTAL MOLE 'A = 160.666 

RAW DATA FILE: RCB25 

MOLOCULAR WEIGHT* 

GAS GRAVITY (BASIS AIR 

GROSS BTU PER SCF* 

NET BTU PER SCF* 

H2/C WEIGHT RATIO* 

18.6829 

1.666)* .625446 

985.486 

896.955 

.312599 

40TE COMPOSITION RESULTS ACCURATE TO 0.1* 

^CALCULATED VALUES GOOD TO 3 SIGNIFICANT FIGURES 

LOP TECH MANAGER 

LOP: PROCESS MANAGER QUAD A B C H UTIL 

CA: SPEC'S FOREMAN FILE P-l-R 
P.22 

REPORT: v 433 . CHANNEL: 8 

SflHPCE: LOP' FUEL GAS INJEtTED AT 

W RM METHOD: CARL5T SEQ: *SEQ6S 

QUAL H.-rUftE DEP'Tv 

9:13:35 ON FEB 3» 1984 

SUBSQ/SAMP: \/ 1 

5L-WDTH 

. 566 

3UP-UNK 

NO 

MV/MIN 

.160 

DVT 

0.00 

DELAY 

1.00 

ID-LVL 

500 

MIN-flR 

500 

REF-RTW 

.300 

ACTUAL RUN TIME: 41.008 MINUTES 

BUNCH 

NO 

JiRTW 

6.00 0 

2DIL-F I 

160.60 YES 

RT ITM AREA MOLE V. NAME 

1.44 

2.52 

3.27 

3.93 

5.77 

5.92 

6.96 

8.40 

9.77 

15.67 

16.20 

16.35 

17.23 

19.12 

26.00 

22.29 

23.96 

32.33 

1.44# 

2.52 

3.27 

3.93# 

5.77 

5.92 

6.96« 

8.47 

9.79 

15.71 

16.28 

16.36 

17.23 

19.12 

19.99 

22.29# 

23.95 

32.33# 

35696 

1846 

53893 

122412 

646 

4965 

74504 

578102 

6303 

137358 

67997 

482513 

145996 

29255 

15962 

5160 

3573 

4122 

BV 

BB 

BV 

VB 

BH 

HS 

BB 

HS 

TT 

BV 

VV 

VB 

BB 

BB 

BB 

BB 

BB 

BB 

15.392 

.132 

3.737 

7.902 

4.IE- 7 

3.2E- 6 

. 6.401 

^b.93^ 

.585 

6.287 

4.4E- 5 

3.IE- 4 

9.4E- 5 

1.886 

1.899 

.287 

.221 

.214 

^HYDROGEN 

C02 

ETHYLENE 

#ETHANE 

ARTIFACT 

ARTIFACT 

<#NllkULLH> 

"' METHANE 

CARB MONOX 

C6+ 

BACKFLUSH 

MIXTURE 

MIXTURE 

PROPANE 

PROPYLENE 

#ISOBUTANE 

N-BUTANE 

ttlSOPENTAN 

TOTAL AREA = 1776381 

PROCESSED DATA FILE: P68A16 

TOTAL MOLE JJ = 166.660 

RAW DATA FILE: R08A16 

MOLECULAR WEIGHT* 

GAS GRAVITY (BASIS AIR 

GROSS BTU PER SCF* 

NET BTU PER SCF* 

H2/C WEIGHT RATIO* 

21.8614 ". 

1.000)* .753771 

1204.24 

1102.39 

.281547 

NOTE COMPOSITION RESULTS ACCURATE TO 0.1* 

CALCULATED VALUES GOOD TO 3 SIGNIFICANT FIGURES 

LOP TECH MANAGER 

LOP: PROCESS MANAGER QUAD A B C D UTIL 

QA: SPEC'S FOREMAN FILE P-l-R 

i 
REPORT: 779 CHANNEL: 2 QUAL ASSURE DEP'T 

SAMPLE,: LOP FUEL GAS INJECiED AT 9:36:64 ON MAR 2> 1984 

NORM METHOD: CARL IT SEQ: *SEQ62 SUBSQ/SAMP: 1/ 1 

SL-WDTH 

. 500 

SUP-UNK 

NO 

MV/MIH 

.106 

DVT 

0.00 

DELAY 

2.40 

ID-LVL 

500 

MIN-AR 

750 

REF-RTW 

.300 

RCTUAL RUN TIME: 44.668 MINUTES 

EXCESS NEG INPUT 

BUNCH 

NO 

5SRTIT 

5.660 

5JDIL-F I 

166.66 YES 

RT ITM AREA MOLE '4 NAME 

2.82 

4.14 

4.76 

6.69 

7.84 

9.37 

18.87 

12.14 

13.89 

22.79 

23.32 

23.49 

24.35 

25.69 

25.81 

28.63 

28.51 

28.76 

29.41 

30.78 

32.68 

2.76 

4.12 

4.71 

6.69# 

7.91 

9.31 

11.13 

12.24 

14.27 

22.79# 

23.36 

23.46 

24.39 

25.13 

25.81* 

27.87 

28.66 

29.41ft 

36.86 

32.93 

362881 

146226 

86516 

21662 

6434 

4387 

3381 

2987 

12558 

167215 

3457 

. 166683 

2993 

167388 

199471 

1653 

14371 

782 

193178 

1147647 

8846 

BB 

BV 

VB 

BB 

BB 

BB 

BB 

BB 

BB 

VB 

BS 

TT 

BB 

BV 

VB 

BB 

BS 

VT 

BVr 

VV 

VB 

1.6E- 4 

3.993 

2.282 

.493 

.148 

.165 

.679 

.676 

.252 

17.351 

1.2E- 6 

3.4E- 5 

.112 

3.850 

6.684 

5.5E- 7 

.655 

.626 

^J^S4 

55.728 

.418 

MIXTURE 

PROPANE 

PROPYLENE 

ttlSOBUTANE 

N-BUTANE 

BUTENES 

TRANS-2 

BUTADIENE 

#ISOPENTAN 

^HYDROGEN 

ARTIFACT 

ARTIFACT 

C02 

ETHYLENE 

#ETHANE 

ARTIFACT 

02+ARGON 

#NITROGEhD 

METHANE 

CO 

TOTAL AREA = 2467448 

»ROCESSED DATA FILE: P6A219 

TOTAL MOLE X = 160.OOO 

RAW DATA FILE: R0A219 

MOLECULAR WEIGHT* 

GAS GRAVITY (BASIS AIR 

GROSS BTU PER SCF* 

NET BTU PER SCF* 

H2/C WEIGHT RATIO* 

18.123 

1.000)* .626113 

1000.41 

965.111 

.367844 

IOTE COMPOSITION RESULTS ACCURATE TO 6.1* 

CALCULATED VALUES GOOD TO 3 SIGNIFICANT FIGURES 

.OP TECH MANAGER 

:.OP: PROCESS MANAGER QUAD A B C D UTIL 

«fl: SPEC'S FOREMAN FILE P-l-R 
REPORT: 671.11 CHANNEL: 

S INJEC 

o 

SAMPLE* LOP FUEL GA 

KiRM METHOD: CARL5T 

TED AT 

QUflL ASSURE DEP'T 

7:43:49 OH APR 4» 1984 

5L-WDTH 

. 560 

5UP-UNK 

NO 

MV/MIN 

.156 

DVT 

0.00 

SEQ: *SEQ03 SUBSQ/SAMP: 1/ 1 

DELAY 

1.00 

ID-LVL 

500 

MIN-AR 

500 

REF-RTW 

.300 

ACTUAL RUN TIME: 41.668 MINUTES 

BUNCH 

NO 

*RTW * 

6.000 

*DIL-F I 

100.00 YES 

RT ITM AREA MOLE * NAME 

1.87 

2.59 

3.45 

4.22 

5.77 

5.96 

6.21 

7.14 

8.74 

16.68 

15.74 

16.27 

16.43 

17.32 

19.23 

28.12 

22.44 

24.11 

32.57 

1.87 

2.57 

3.44 

4.22# 

5.77 

5.96 

6.19 

7.14# 

8.76 

16.68 

15.75 

16.28 

16.44 

17.33 

19.24 

26.12 

22.44* 

24.11 

32.57* 

6131 

1336 

48785 

99895 

973 

1674 

5324 

112638 

493466 

4688 

6686 

85766 

491681 

142734 

17918 

26212 

6788 

3385 

4431 

BB 5.5E- 6 

BB .133 

BB 4.763 

BB 8.965 

BB 8.7E- 7 

BS 1.5E- 6 

BB .665 

BBC.13.454 

BS tt.y^y 

BB .665 

BV .426 

VV 7.7E- 5 

VB 4.4E- 4 

BB1.3E- 4 

BB 1.666 

BB 1.935 

BB .525 

BB .291 

BB .326 

ARTIFACT 

C02 

ETHYLENE 

ttETHANE 

ARTIFACT 

ARTIFACT 

n? + ARHON 

#NITROGEFP) 

" METHANE 

CARB MONOX 

C6+ 

MIXTURE 

MIXTURE 

MIXTURE 

PROPANE 

PROPYLENE 

ttlSOBUTANE 

N-BUTANE 

#ISOPENTAN 

TOTAL AREA = 1553781 

>ROCESSED DATA FILE: P08A19 

TOTAL MOLE * = 18,6.666 

RAW DATA FILE: R68A19 

MOLECULAR WEIGHT* 21.4557 

GAS GRAVITY (BASIS AIR = 1.666)* .741868 

GROSS BTU PER SCF* 1657.19 

NET BTU PER~SCF* 966.148 

H2/C WEIGHT RATIO* - .284194 

IOTE COMPOSITION RESULTS ACCURATE TO 0.1* 

CALCULATED VALUES GOOD TO 3 SIGNIFICANT FIGURES 

\ 

LOP TECH MANAGER 

LOP: PROCESS MANAGER QUAD A B C D UTIL 

QA: SPEC'S FOREMAN FILE P-l-R 
.'REPORT: 763 CHANNEL: 8 

SAMPLE-: LOP FUEL GAS IHJEoTED AT 6: 

NORM METHOD: CARL5T SEQ: *SEQ68 SUE 

SL-WDTH MV/MIN DELAY MIN-AR 

.500 .150 l.OO 560 

SUP-UNK DVT ID-LVL REF-RTW 

NO 0.00 500 .306 

26:12 UN 

;SQ/SAMP: 

BUNCH 

NO 

*RTW 

6.000 

QUAL ASSURE DEP'T' 

MAY T«fc*984 

1/ 1 

*DIL-F I 

100.00 YES 

P.25 

ACTUAL RUN TIME: 41.017 MINUTES 

RT ITM AREA MOLE * NAME 

1.40 

1.88 

2.59 

3.45 

4.20 

5.99 

7.61 

8.57 

18.12 

15.75 

16.28 

16.44 

17.32 

19.22 

26.69 

22.41 

24.68 

26.16 

26.62 

27.86 

29.16 

32.49 

1.46* 

1.88 

2.57 

3.43 

4.26* 

5.98 

7.61* 

8.64 

16.21 

15.73 

16.28 

16.45 

17.33 

19.23 

26.69 

22.41* 

24.69 

26.16 

26.63 

27.81 

29.12 

32.49* 

52785 

5311 

1235 

59419 

138214 

1526 

55066 

465553 

6981 

9882 

64359 

415216 

193882 

29438 

29229 

8642 

4516 

1648 

1531 

2198 

1457 

5566 

BB 

BB 

BB 

BB 

BB 

BB 

BB 

BS 

BB 

BV 

VV 

VB 

BB 

BB 

BB 

BB 

BB 

BB 

BB 

BB 

BB 

BB 

26.837 

4.6E- 6 

.162 

4.751 

16.289 

1.1E- 6 

<^.455 

4b":253 

.747 

.515 

4.8E- 5 

3.IE- 4 

1.4E- 4 

2.189 

2.321 

.554 

.322 

.658 

.683 

.118 

.675 

.336 

*HYDROGEN 

ARTIFACT 

C02 

ETHYLENE 

*ETHANE 

ARTIFACT 

*NITROCEi£> 

METHANE 

CARB MONOX 

C6+ 

MIXTURE 

MIXTURE 

MIXTURE 

PROPANE 

PROPYLENE 

#ISOBUTANE 

N-BUTANE 

BUTENE-1 

ISOBUTYLEN 

TRANS BUTCIS BUT-2-

*ISOPENTAN 

TOTAL AREA = 1492176 

PROCESSED DATA FILE: P68A12 

TOTAL MOLE * = 166.660 

RAW DATA FILE: R03A12 

MOLECULAR WEIGHT* 

GAS GRAVITY <BASIS AIR = 

GROSS BTU PER SCF* 

NET BTU PER SCF* 

H2/C WEIGHT RATIO* 

17.2534 

1.000)* .596635 

992.949 

899.886 

.313273 

NOTE COMPOSITION RESULTS ACCURATE TO 6.1* 

CALCULATED VALUES GOOD TO 3 SIGNIFICANT FIGURES 

LOP TECH MANAGER 

LOP: PROCESS MANAGER QUAD A B C D UTIL 

QA: SPEC'S FOREMAN FILE P-l-R 
r-truki: tic.* thMNUhL: a 

f 

SAMPLE: LOP FUEL GAS 

NORM METHOD: CARL5T 

SL-WDTH MV/MIN 

.586 .158 

SUP-UNK DVT 

NO 0.66 

^ INJEuTED AT 9: 

SEQ: *SEQ68 SUE 

DELAY MIN-AR 

1.06 560 

ID-LVL REF-RTW 

500 .3O0 

52:40 ON 

SQ/SAMP: 

BUNCH 

NO 

*RTW 

6.060 

QUAL ASSURE DEP'T 

( 

JUN IJ- 19*84 

1/ 1 

*DIL-F I 

100.00 YES 

P,26 

ACTUAL RUN TIME: 41.017 MINUTES 

RT ITM AREA MOLE * NAME 

1.38 

2.55 

3.39 

4.13 

5.79 

6.82 

6.14 

6.86 

8.38 

9.59 

15.75 

16.29 

16.45 

17.32 

19.22 

26.67 

22.39 

24.65 

26.59 

32.41 

1.38* 

2.55 

3.39 

4.13* 

5.76 

5.99 

6.13 

6.86* 

8.44 

9.66 

15.76 

16.27 

16.44 

17.31 

19.21 

26.66 

22.39* 

24.65 

26.59 

32.41* 

37967 

1382 

54777 

128592 

2837 

1123 

817 

68179 

428592 

5844 

6955 

78626 

436146 

182552 

34423 

45678 

7423 

3738 

1658 

4153 

BB 

BB 

BB 

BB 

BS 

BB 

BB 

BB 

BS 

BB 

BV 

VV 

VB 

BB 

BB 

BB 

BB 

BB 

BB 

BB 

26.654 

.119 

4.556 

9.945 

2.2E- 6 

8.7E- 7 

.R8A 

(17.018 

45.684 

.650 

.376 

6.IE- 5 

3.4E- 4 

1.4E- 4 

2.659 

3.767 

.495 

.277 

.059 

.258 

*HYDROGEN 

C02 

ETHYLENE 

*ETHANE 

ARTIFACT 

ARTIFACT 

_ fl? + ARHON 

*NITROGEN) 

METHANE 

CARB MONOX 

C6+ 

MIXTURE 

MIXTURE 

MIXTURE 

PROPANE 

PROPYLENE 

*ISOBUTANE 

N-BUTANE 

ISOBUTYLEN 

*ISOPENTAN 

TOTAL AREA = 1530842 

PROCESSED DATA FILE: P08A12 

TOTAL MOLE * = 108.000 

RAW DATA FILE: R08A12 

MOLECULAR WEIGHT* 

GAS GRAVITY (BASIS AIR = 

GROSS BTU PER SCF* 

NET BTU PER SCF* 

H2/C WEIGHT RATIO* 

18.6096 

1.666)* .643689 

1634.43 

938.469 

.366638 

NOTE COMPOSITION RESULTS ACCURATE TO 6.1* 

CALCULATED VALUES GOOD TO 3 SIGNIFICANT FIGURES 

LOP TECH MANAGER 

LOP: PROCESS MANAGER QUAD A B C D UTIL 

QA: SPEC'S FOREMAN FILE P-l-R 

i 
P.27 

• . •— • v*»•• '. 111111111_ i. •;.".M 11_ i ••C'Ur.i: i«L.i I 

( 

SAMPLE: LOP FUEL GAS INJECTED AT 9:24:67 ON JUL 2. '1984 

NORM METHOI 

SL-WDTH 

. 560 

SUP-UNK 

NO 

: CARL5T 

MV/MIN 

• ISO 

DVT 

6.60 

SEQ: 

DELAY 

1.00 

ID-LVL 

500 

*SEQ68 SUBS 

MIN-AR 

500 

REF-RTW 

. 300 

•Q/SAMP: 

BUNCH 

NO 

*RTW 

6~. 006 

1/ 1 

*DIL-F 

100.00 

I 

YES 

ACTUAL RUN TIME: 41.617 MINUTES 

RT ITM AREA MOLE * NAME 

1.38 

1.82 

1.87 

2.54 

3.39 

4.13 

5.79 

6.62 

6.81 

8.29 

9.37 

13.29 

15.73 

16.28 

16.44 

17.32 

19.21 

28.68 

22.38 

24.63 

26.65 

26.59 

27.74 

29.64 

32.36 

1.38* 

1.84 

1.89 

2.55 

3.39 

4.13* 

5.77 

6.61 

6.81* 

8.36 

9.46 

13.96 

15.71 

16.28 

16.45 

17.32 

19.21 

26.68 

22.38* 

24.04 

26.89 

26.62 

27.79 

29.68 

32.36* 

26632 

547 

14248 

889 

42439 

166296 

1366 

1269 

75652 

491888 

4376 

42568 

5246 

81516 

569083 

149629 

36460 

24849 

5555 

3863 

563 

789 

1719 

1581 

4281 

BB 

BB 

BB 

BB 

BB 

BB 

BS 

BB 

BB 

BS 

BB 

BB 

BV 

VV 

VB 

BB 

BB 

BB 

BB 

BB 

BB 

BB 

BB 

BB 

BB 

14.496 

4.4E- 7 

1.IE- 5 

.679 

3.633 

8.471 

1.6E- "6 

1.6E- 6 

le.ezs 

58.763 

.561 

3.4E- 5 

.293 

6.5E- 5 

4.IE- 4 

1.2E- 4 

2.428 

2.112 

.381 

.296 

.034 

.041 

.099 

.087 

.274 

#HYDROGEN 

ARTIFACT 

ARTIFACT 

C02 

ETHYLENE 

*ETHANE 

ARTIFACT 

ARTIFACL 

ttN!IRQGEK> 

METHANE 

CARB MONOX 

ARTIFACT 

C6+ 

MIXTURE 

MIXTURE 

MIXTURE 

PROPANE 

PROPYLENE 

#ISOBUTANE 

N-BUTANE 

BUTENE-1 

ISOBUTYLEN 

TRANS 6UTCIS BUT-2-

*ISOPENTAN 

TOTAL AREA = 1626969 

PROCESSED DATA FILE: P68A61 

TOTAL MOLE * - 166.666 

RAW DATA FILE: R68A61 

MOLECULAR WEIGHT* 

GAS GRAVITY (BASIS AIR = 

GROSS BTU PER SCF* 

NET BTU PER SCF* 

H2/C WEIGHT RATIO* 

18.584 

1.600)* .642788 

1018.48 

922.151 

.385537 

NOTE COMPOSITION RESULTS ACCURATE TO 0.1* 

CALCULATED VALUES GOOD TO 3 SIGNIFICANT FIGURES 

LOP TECH MANAGER 

LOP: PROCESS MANAGER QUAD A B C D UTIL 

QA: SPEC'S FOREMAN FILE P-l-R 
SAMPLE: 

40 RM 11 El 

••L-WDTH 

. 566 

5UP-UNK 

NO 

•* • 

LOP 

rHOD 

/FUEL/GAS 

: CARL5T 

MV/MIN 

.150 

DVT 

0.00 

INJECTED AT 8: 

SEQ: *SEQ08 SUE 

DELAY 

1.00 

ID-LVL 

500 

MIN-AR 

500 

REF-RTW 

.300 

32:47 ON 

SQ/SAHP: 

BUNCH 

NO 

*RTW 

6.0O6 

AUG IJ 1984 

1/ 1 

*DIL-F I 

100.00 YES 

P.28 

ACTUAL RUN TIME: 41.008 MINUTES 

RT ITM AREA MOLE * NAME 

1.37 

1.87 

2.56 

3.48 

4.13 

6.02 

6.80 

8.32 

9.30 

15.74 

16.28 

16.44 

17.31 

19.21 

20.08 

22.39 

24.03 

26.09 

26.62 

27.80 

29.10 

32.45 

1.37* 

1.87 

2.52 

3.40 

4.13* 

6.01 

6.86* 

8.36 

9.38 

15.72 

16.29 

16.45 

17.32 

19.22 

26.69 

22.39* 

24.85 

26.16 

26.76 

27.82 

29.11 

32.45* 

41378 

5213 

611 

63616 

148446 

1422 

77554 

341464 

9569 

8873 

91442 

367817 

212396 

31430 

31668 

8412 

68794 

1084 

1481 

2559 

1583 

10309 

BB 

BB 

BB 

BB 

BB 

BS 

BB 

BS 

BB 

BV 

VV 

VB 

BB 

BB 

BB 

BB 

BB 

BB 

BB 

BB 

BB 

BB 

22.180 

4.IE- 6 

.053 

5.344 

11.608 

1.IE- 6 

lft.ft7? 

48.026 

1.669 

.486 

7.2E- 5 

2.9E- 4 

1.7E- 4 

2.455 

2.642 

.567 

4.553 

.663 

.684 

.145 

.685 

.648 

*HYDROGEN 

ARTIFACT 

C02 

ETHYLENE 

*ETHANE 

ARTIFACT 

-«! * 

CARB MONOX 

C6+ 

MIXTURE 

MIXTURE 

MIXTURE 

PROPANE 

PROPYLENE 

*ISOBUTANE 

N-BUTANE 

BUTENE-1 

ISOBUTYLEN 

TRANS BUTCIS BUT-2-

*ISOPENTAN 

TOTAL AREA = 1519664 TOTAL MOLE * = 166.666 

•ROCESSED DATA FILE: P68A13 RAW DATA FILE: R68A13 

MOLECULAR WEIGHT* 

GAS GRAVITY (BASIS AIR 

GROSS BTU PER SCF* 

NET BTU PER SCF* 

H2/C WEIGHT RATIO* 

26.6144 

1.666)* .712829 

1128.19 

1026.57 

"* .283886 

IOTE COMPOSITION RESULTS ACCURATE TO 0.1* 

CALCULATED VALUES GOOD TO 3 SIGNIFICANT FIGURES 

LOP TECH MANAGER 

LOP: PROCESS MANAGER QUAD A B C D UTIL 

QA: SPEC'S FOREMAN FILE P-l-R-
( 

SAMPLE: LOP FUEL GAS INJECTED AT 9:44:22 ON SEP 3J 1984 

NORM METHOD: CARL5T SEQ: *SEQ88 SUBSQ/SAMP: 1/ 1 

P.29 

SL-WDTH 

.500 

SUP-UNK 

NO 

MV/MIN 

.150 

DVT 

0.00 

DELAY 

1.66 

ID-LVL 

566 

MIN-AR 

566 

REF-RTW 

.366 

BUNCH 

NO 

*RTW 

6.660 

*DIL-F I 

100.60 YES 

ACTUAL RUN TIME: 41.017 MINUTES 

RT 

1.38 

2.57 

3.41 

4.15 

6.62 

6.78 

8.27 

9.22 

15.63 

15.74 

16.28 

16.43 

17.31 

19.26 

28.07 

22.38 

24.85 

26.60 

27.78 

29.87 

32.41 

ITM 

1.38* 

2.56 

3.48 

4.15* 

6.02 

6.78* 

8.32 

9.24 

14.96 

15.71 

16.28 

16.45 

17.31 

19.21 

26.07 

22.38* 

24.65 

26.62 

27.79 

29.68 

32.41* 

AREA 

35716 BB 

910 BB 

58687 BB 

147581 BB 

8469 BB 

75216 BB 

399599 BS 

6375 BB 

23139 BB 

5666 BV 

88235 VV 

443288 VB 

207915 BB 

52356 BB 

39402 BB 

6816 BB 

3884 BB 

1057 BB 

1972 BB 

1288 BB 

5213 BB 

MOLE * 

19.073 

.079 

4.929 

11.539 

6.6E- 6 

7.827 

46.833 

.717 

1.8E- 5 

.310 

6.9E- 5 

3.5E- 4 

1.6E- 4 

4.089 

3.286 

.459 

.291 

.666 

.112 

.669 

.328 

NAME 

*HYDROGEN 

C02 

ETHYLENE 

*ETHANE 

ARTIFACT 

*NITROGEN 

METHANE 

CARB MONOX 

ARTIFACT 

C6+ 

MIXTURE 

MIXTURE 

MIXTURE 

PROPANE 

PROPYLENE 

*ISOBUTANE 

N-BUTANE 

ISOBUTYLEN 

TRANS BUTCIS BUT-2-

*ISOPENTAN 

TOTAL AREA = 1612777 

PROCESSED DATA FILE: P68A36 

TOTAL MOLE * = 160.066 

RAW DATA FILE: R68A36 

MOLECULAR WEIGHT* 

GAS GRAVITY (BASIS AIR 

GROSS BTU PER SCF* 

NET BTU PER SCF* 

H2/C WEIGHT RATIO* 

19.364 

1.666)* .676176 

1664.29 

965.873 

.293784 

NOTE COMPOSITION RESULTS ACCURATE TO 6.1* 

CALCULATED VALUES GOOD TO 3 SIGNIFICANT FIGURES 

LOP TECH MANAGER 

LOP: PROCESS MANAGER QUAD A B C D UTIL 

QA: SPEC'S FOREMAN FILE P-l-R 
P.30 

SAMPLE: LOP/FUEL/GAS INJECTED AT 8:69:34 ON OCT IJ 1984 

NORI1 METHOD: CARL5T SEQ: *SEQ68 SUBSQ/SAHP: 1/ 1 

SL-WDTH 

.566 

SUP-UNK 

NO 

MV/MIN 

.156 

DVT 

6.60 

DELAY 

1.00 

ID-LVL 

500 

MIN-AR 

500 

REF-RTW 

.300 

BUNCH 

NO 

*RTW 

6.000 

*DIL-F I 

100.66 YES 

ACTUAL RUN TIME: 41.625 MINUTES 

RT ITM AREA MOLE * NAME 

1.39 

1.89 

2.58 

3.43 

4.19 

6.75 

8.24 

9.14 

15.76 

16.28 

16.44 

17.31 

19.21 

26.67 

22.39 

24.65 

26.07 

26.60 

27.79 

29.09 

32.45 

1.39* 

1.89 

2.58 

3.43 

4.19* 

6.75* 

8.28 

9.16 

15.71 

16.27 

16.44 

17.31 

19.21 

26.67 

22.39* 

24.06 

26.68 

26.62 

27.86 

29.09 

32.45* 

37851 

13842 

924 

58632 

123369 

100820 

413313 

5879 

4153 

112266 

441730 

181616 

24839 

34683 

5141 

3484 

1639 

1487 

1903 

1277 

4568 

BB 

BB 

BB 

BB 

BB 

BB 

BS 

BB 

BB 

BV 

VB 

BB 

BB 

BB 

BB 

BB 

BB 

BB 

BB 

BB 

BB 

28.678 

1.1E- 5 

.686 

4.842 

9.577 

*HYDROGEN 

ARTIFACT 

C02 

ETHYLENE 

*ETHANE . 

TU.liy METHANE 

.657 

.226 

8.7E- 5 

3.4E- 4 

1.4E- 4 

1.927 

2.873 

.344 

.253 

.660 

.084 

.167 

.666 

.282 

CARB MONOX 

C6+ 

MIXTURE 

MIXTURE 

MIXTURE 

PROPANE 

PROPYLENE 

*ISOBUTANE 

N-BUTANE 

BUTENE-1 

ISOBUTYLEN 

TRANS BUTCIS BUT-2-

*ISOPENTAN 

TOTAL AREA = 1571421 TOTAL MOLE * = 166.600 

PROCESSED DATA FILE: P68A61 RAW DATA FILE: R68A61 

MOLECULAR WEIGHT* 

GAS GRAVITY (BASIS AIR 

GROSS BTU PER SCF* 

NET BTU PER SCF* 

H2/C WEIGHT RATIO* 

18.4132 .:•-. 

1.666)* .636691 

969.923 

879.063 

.305146 

NOTE COMPOSITION RESULTS ACCURATE TO 0.1* 

CALCULATED VALUES GOOD TO 3 SIGNIFICANT FIGURES 

LOP TECH MANAGER 

LOP: PROCESS MANAGER QUAD A B C D UTIL 

QA: SPEC'S FOREMAN FILE P-l-R 
P.31 

SHMPLfc: LOP/FUEL/GAS INJECTED Ml 7:43:50 ON NOV o» 1984 

NORM METHOD: CARL5T SEQ: *SEQ68 SUBSQ/SAMP: 1/ 1 

SL-WDTH 

. 560 

SUP-UNK 

NO 

MV/MIN 

.150 

DVT 

6.60 

DELAY 

1.66 

ID-LVL 

560 

MIN-AR 

500 

REF-RTW 

.366 • 

ACTUAL RUN TIME: 41.668 MINUTES 

BUNCH 

NO 

*RTW 

6.666 

*DIL-F I 

166.66 YES 

RT ITM AREA MOLE * NAME 

1.36 

1.87 

2.55 

3.46 

4.12 

5.78 

6.10 

6.74 

8.25 

9.08 

15.73 

16.28 

16.45 

17.31 

19.22 

20.08 

22.41 

24.08 

26.64 

27.83 

32.48 

35.52 

1.36* 

1.88 

2.56 

3.48 

4.12* 

5.81 

6.12 

6.74* 

8.23 

9.86 

15.75 

16.28 

16.46 

17.32 

19.23 

20.09 

22.41* 

24.07 

26.63 

27.81 

32.48* 

35.49 

47468 BB 

16814 BB 

2173 BB 

60117 BB 

166825 BB 

1246 BB 

4439 BS 

77268 BB 

340411 BS 

6713 BB 

8047 BV 

89616 VV 

345016 VB 

225595 BB 

65653 BB 

36183 BB 

24252 BB 

34294 BB 

1018 BB 

1582 BB 

31086 BB 

18641 BB 

21.154 

1.2E- 5 

.179 

4.797 

12.393 

9.3E- 7 

3.3E- 6 

_7.640 

37.908 

.717 

.418 

6.7E- 5 

2.6E- 4 

1.7E- 4 

4.828 

2.867 

1.552 

2.446 

.655 

.681 

1.852 

1.117 

*HYDROGEN 

ARTIFACT 

C02 

ETHYLENE 

*ETHANE 

ARTIFACT 

ARTIFACT 

ftNTTRfinFM^ 

METHANE 

CARB MONOX 

C6+ 

BACKFLUSH 

MIXTURE 

MIXTURE 

PROPANE 

PROPYLENE 

*ISOBUTANE 

N-BUTANE 

ISOBUTYLEN 

TRANS BUT-

#ISOPENTAN 

N-PENTANE 

TOTAL AREA = 1663691 

PROCESSED DATA FILE: P68A81 

TOTAL MOLE * = 166.666 

RAW DATA FILE: R68A61 

MOLECULAR WEIGHT* 

GAS GRAVITY (BASIS AIR 

GROSS BTU PER SCF* 

NET BTU PER SCF* 

H2/C WEIGHT RATIO* 

22.1756 

1.666)* .767482 

1226.91 

1116.76 

.27513 

.NOTE COMPOSITION RESULTS ACCURATE TO 6.1* 

CALCULATED VALUES GOOD TO 3 SIGNIFICANT FIGURES 

LOP TECH MANAGER 

LOP: PROCESS MANAGER QUAD A B C D UTIL 

QA: SPEC'S FOREMAN FILE P-l-R 

i 
P.32 

REPORT: 288 CHANNEL: 8 QUAL ASSURE DEP'T 

SAMPLE: I HP run CQQ INJECTED AT 9:67:44 ON DEC 5, 1984 

NORM METHOD: CARL5T SEQ: SEQ8A SUBSQ/SAMP: 1/ 1 BTL: 1 

SL-WDTH 

.566 

SUP-UNK 

NO 

MV/MIN 

.156 

DVT 

6.66 

DELAY 

1.66 

ID-LVL 

566 

MIN-AR 

566 

REF-RTW 

.366 

BUNCH 

NO 

*RTW 

6.666 

*DIL-F I 

166.66 NO 

ACTUAL RUN TIME: 41.617 MINUTES 

RT ITM AREA MOLE * NAME 

1.36 

1.88 

2.54 

3.38 

4.12 

6.11 

6.72 

8.21 

9.66 

15.73 

16.36 

16.47 

17.34 

19.23 

20.1O 

22.41 

24.07 

26.08 

26.61 

27.80 

29.10 

32.43 

35.45 

1.36* 

1.88 

2.54 

3.38 

4.12* 

6.18 

6.72* 

8.23 

9.02 

15.72 

16.29 

16.45 

17.32 

19.22 

20.08 

22.41* 

24.07 

26.08 

26.61 

27.79 

29.88 

32.43* 

35.49 

TOTAL AREA = 

48269 

5038 

2128 

52755 

121215 

4987 

80268 

368625 

2451 

13861 

88643 

372491 

173677 

62875 

26912 

28368 

33871 

2835 

4287 

3516 

2435 

28649 

19725 

154692G 

BB 

BB 

BB 

BB 

BB 

BB 

BB 

BS 

BB 

BV 

VV 

VB 

BB 

BB 

BB 

BB 

BB 

BV 

VB 

BB 

BB 

BB 

BB 

\ 

21.626 

3.8E- 6 

.176 

4.232 

9.651 

3.7E- 6 

7.978 

4^^5w 

.263 

.683 

6.6E- 5 

2.8E- 4 

1.3E- 4 

4.696 

2.144 

1.825 

2.422 

.159 

.229 

.190 

.125 

1.720 

1.228 

ftHYDROGEN 

ARTIFACT 

C02 

ETHYLENE 

#ETHANE 

ARTIFACT 

#MTTPnGFN, 

" METHANE 

CARB MONOX 

C6+ 

MIXTURE 

MIXTURE 

MIXTURE 

PROPANE 

PROPYLENE 

*ISOBUTANE 

N-BUTANE 

BUTENE-1 

ISOBUTYLEN 

TRANS BUTCIS BUT-2-

*ISOPEHTAN 

N-PENTANE 

TOTAL MOLE * = 

v 

180.000 

PROCESSED DATA FILE: P08A1 RAW DATA FILE: R08A1 

MOLECULAR WEIGHT* 

GAS GRAVITY (BASIS AIR 

GROSS BTU PER SCF* 

NET BTU PER SCF* 

H2/C WEIGHT RATIO* 

NOTE COMPOSITION RESULTS ACCURATE TO 6.1* 

CALCULATED VALUES GOOD TO 3 SIGNIFICANT 

21.7777 

1.800)* .753769 

1199.44 

1090.88 

.279538 

FIGURES 

LOP TECH MANAGER 

LOP: PROCESS MANAGER QUAD A B C D UTIL 

«- » i i— i-. < _ r.. 
FUEL GAS BLEND DRUM COMPONENT STREAMS. MMSCFD 

/&/ ^ ^ &e /"' 

liil"/ 

1984 

Jan. 2 

Feb. 3 

Mar. 2 

Apr. 4 

May 2 

June 1 

July 2 

Aug. 1 

Sept. 3 

Oct. 1 

Nov. 6 

Dec. 5-

Sacramento 

River Gas 

20.64 

22.69 

19.70 

22.98 

9.23 

12.55 

18.86 

6.77 

8.57 

10.57 

5.19 

7.72 

PG&E Nat. 

Gas 

0 

0 

0 

0 

0 

0 

0 

' 0 

0 

0 

0 

0 

CGP Dry 

Gaa 

17.31 

20.6 

21.42 

23.78 

25.25 

22.69 

18.47 

23.19 

20.89 

21.61 

20.73 

19.41 

SGP Dry 

Gas 

5.50 

6.02 

5.05 

7.74 

7.39 

7.62 

7.16 

7.20 

7.00 

6.79 

0 

0 

Coker 

Dry Gas 

7.94 

5.89 

0 

0 

9.49 

7.51 

8.67 

9.01 

10.40 

7.59 

4.64 

2.35 

Dlmersol 

Propane 

0.613 

0.974 

0.710 

0 

0 

0 

0 

0 

0 

0 

0 

0.175 

Vaporized 

Propane 

0.569 

0.196 

0 

0 

0.183 

0.194 

0.231 

0.128 

0.729 

0.180 

0 

0.275 

Vaporized 

Butane 

0 

0 

0 

0 

0 

0 

0 

0. 

0. 

0 

0 

0 

./ 

641 

223 

Misc. 

Vent 8 

0 

0 

0 

0 

0 

0 

0 

0 

0 

0 

9.53 

11.52 

DFOilp (3.50) 

3/27/85 
.JTRI8UT.0N: 

Firm ' 

Permit Services 

Enforcement 

Technical Services 

Source Inventory 

Requester 

D.A.P.C.O. 

P.34 

BAY AREA ) 

AIR QUALITY MANAGEMENT DISTRICT 

939 ELLIS STREET 

SAN FRANCISCO. CALIFORNIA 94109 

(415) 771-6000 

SUMMARY OF 

SOURCE TEST RE?'" TS 

R.POINO.

 85 °2 6

, 

I... o.t K ..9/5/84 

Test Times: 

Run A-...1.255-1.3.45. 

Run BL.1.40.7-145.7 

SOURCE INFORMATION 

Firm Name and Address 

Shel l Oi l 

P.O. Box 711 

Martinez . CA 94553 

Permit Conditions 

Firm Representative and Title 

Dal e Obenhauer, Eng 

Phone No. 228-616 1 

Source: 

CO Boile r #3 ; 

Plan t #11 

^M^k^ljL-^ 

None 

Operating Parameters 

Normal 

Operates 24 hr/day&365 

Applicable Regulations: Reg. 6 Sec. 310,31 1 VN Recommended: NO 

Test Results and Comments: 

METHOD TEST 

ST-17 Stack Volume Flowrate, SDCFM 

Stack Gas Temperature, °F 

ST-23 Water content, Volume % 

ST-14 Oxygen, Volume % 

ST-5 Carbon Dioxide, Volume % 

ST-6 Carbon Monoxide, ppm 

Carbon Monoxide, lb/hr 

ST-15 Particulate, gr/SDCF 

Particulate, lb/hr 

RUN A 

15. 6 

2 . 9 

15. 6 

40 

12 

0.04 6 

26 

RUN B AVG. 

66,10 0 

470 

16. 5 16. 1 

0 . 9 1.9 

14. 6 ,15. 1 

40 40 

12 12 

0.05 3 0.05 0 

30 28" 

REG. 

LIMIT 

0.1 5 

40 -

NO COMMERCIAL USE OF THESE RESULTS IS AUTHORIZED 

Source Test Team Leader 

W. Hammel 

,.^->L. 

Date 

9/IT/B'T ' 

Approved—Chief of Source Test » Date 

f/lfa/ 
P.35 

'Firm 

'* Permit Services 

Enforcement 

Technical Services 

Source Inventory 

Requester 

D.A.P.C.O. 

J BAY AREA ) 

A.H QUALITY MANAGEMENT DISTRICT 

939 ELLIS STREET 

SAN FRANCISCO. CALIFORNIA 94109 

(41S) 7714000 

REPORT OF 

CONTINUOUS EMISSION MONITOR 

FIELD ACCURACY TESTS 

i*f«^/t,/f i »•*#. 

Test Date 

Test Times 

Run A: 

Run B: 

7/18/84 

!1034-1105 

1115-1146 

Run Ci 1151-1220 

SOURCE INFORMATION 

Firm Name and Address 

Shel l Oi l 

P.O. Box 711 

Martinez, CA 9553 

Conditions During Tests 

Normal 

Firm Representative and Title 

Dale Obenhauer, Engineer 

Phone No. 228-6161 

Monitors) Tested: ~~ 

EDC Monitor § COB 11 

Parameters Tested: 

S02/02/C02/NOx/flow 

PROCEDURAL DATA 

Yes No 

Dally zero & span check made? ^0 D 

Records maintained for 2 yrs? ^99 D 

Calibration gases acceptable? 309 D 

V/N Recommended? • (x% 

BAAQMD Representatives 

B. Bartley 

Alex Ezersky 

Ed Wyatt 

Test Results and Comments: 

METHOD TEST 

ST-19A SO2; ppm (dry) 

ST-19A S02? lbs/hr 

ST-17 Volume Flowrate; SDCFM 

ST-5 C02; % Volume (dry) 

ST-14 02? % Volume (dry) 

ST-13A NOxr ppm (dry) 

ST-23 H20% Volume 

ST-13A NOx; lbs/hr 

•Although the SO2 ppm & lbs/hr are greater than ± 20% relative 

accuracy; they do meet the ± 10% of emission limitation criteria . --... _ 

BAAQMD 

RESULTS 

116 

99.2 

86,000 

14.4 

2.1 

91 

16.6 

56.0 

SHELL OIL 

RESULTS 

67 

58.7 

88,000 

— 

— 

PERCEN 

DIFFERE 

-42.2 

-48.8 

+2.4 

— . -

_ __ 

NO COMMERCIAL USE OF THESE RESULTS IS AUTHORIZED 

Source Test Team Leader 

B. Bartley 

Date Approved—Chief of Source Test 

JUL 2 6 193; 

,

^ J . Karels 

Date 

7/&I11 
P.36 

/ 

.jTRIBUTION: 

>#Flrm 

Permit Services 

Enforcement 

Technical Services 

Source Inventory 

Requester 

D.A.P.C.O. 

Al 4 BAY AREA ) 

QUALITY MANAGEMENT DISTRICT 

939 ELLIS STREET 

SAN FRANCISCO. CALIFORNIA 94109 

(415) 771-6000 

REPORT OF 

CONTINUOUS EMISSION MONITOR 

FIELD ACCURACY TESTS 

Report No. 

Test Dale- V.18/8 4 

Test Times: 

Run A: 13.08-1338. 

Run B:. 134 5-1416. 

Ruft

 & 1421-1452 

SOURCE INFORMATION PROCEDURAL DATA 

Firm Name and Address 

Shel l Oil 

P.O. Box 711 

Martinez , CA 94533 

Conditions During Tests 

COB12 - Normal 

Firm Representative and Title 

Dal e Obenhauer, Engineetoally 

Yes Nc 

zero & span check made? 3Q3 D 

Phone No. 228-616 1 

Monitors) Tested: ~ 

EDC Monitor § COB #2 

Records maintained for 2 yrs? -X29 O 

Calibration gases acceptable? ) S C 

V/N Recommended? D]x> 

Parameters Tested: 

S 0 2 /02/C02/NOx /Flow 

BAAQMD Representatives 

Bob Bartle y 

Alex Ezersky 

Ed Wyatt 

Test Results and Comments: 

METHOD TEST 

ST^ISA S02# ppm (dry) 

ST-19A SO2, lbs/hr 

ST-17 Volume Flowrate SDCFM 

ST-5 C02 % Volume (dry) 

ST-14 O2 % Volume (dry) 

ST-23 H2O, % Volume 

ST-13A N0X; ppm (dry) 

ST-13A N0X; lbs/hr 

•Although the S02 ppm & lbs/hr do not meet the ± 20% relative 

accuracy requirement; they do meet: the ± 10% of emission 

limitation criteria. 

BAAQMD 

RESULTS 

115 

115 

101,000 

15.0 

1.5 

17.7 

88 

63.5 

SHELL OIL 

RESULTS 

77 

83.5 . 

109,000 

_—_ 

PERCENT 

DIFFERE1 

-33.0* 

-27.4' 

-7.9 

• — 

—.— 

NO COMMERCIAL USE OF THESE RESULTS IS AUTHORIZED 

Source Test Team Leader Date 

l^s JwL «. [. ::j'r 

B. Bartley f 

Approved—Chief of Source Test 

G. Karels 

Dat 

•>/zol& W 
P.37 

/ 

rlSTRIBUTION: 

Flrm_ 

Permit Services 

Enforcement 

Technical Services 

Source Inventory 

Requester 

D.A.P.C.O. 

> 1 

BAY AREA 

AIR QUALITY MANAGEMENT DISTRICT 

939 ELLIS STREET 

SAN FRANCISCO. CALIFORNIA 94109 

(415) 771-6000 

REPORT OF Run B:. 

CONTINUOUS EMISSION MONITOR 

FIELD ACCURACY TESTS THflRMOXRu 

Report No. 

Test Date:.. 

Test Times: 

Run A 

IEDC t 

97-84 

5/3/84 

1045-1115 

1126-1157 

n C:^1. 

VI 

207-1237 

1245-1316 

SOURCE INFORMATION PROCEDURAL DATA 

Firm Name and Address 

Shell Oil 

P.O. Box 711 

Martinez, CA 94553 

Conditions During Tests 

Fuel Usage: 

Flexigas-128 mmBTU/hr 

Refinery Gas-26 mmBTU/hr 

LSFO-67 mmBTU/hr 

TOTAL: 221 BTU/hr 

Firm Representative and Title 

Dale Obenauer, Engineer 

Phone No.228-6161 ' 

Monitors) Tested: 

Thermox Monitors at 

Boiler #4 

Yes No 

Daily zero & span check made? ED D 

Records maintained (or 2 yrs? 0 D 

Calibration gases acceptable? {D D 

V/N Recommended? O (R) 

Parameters Tested: 

NOx/C0 2 / 0 2 /lbs-h r 

BAAQMD Representatives 

B. Bartle y 

Test Results and Comments: 

METHOD TEST 

ST-13A NOx, ppm (dry) 

ST-13A NOx, lb/hr 

ST-14 02%, Volume (dry) 

ST-5 C02 , % Volume (dry) 

Volume Flowrate, SDCFM 

ST-19A S02, ppm (dry) 

ST-19A S02, lbs/hr 

•Calculated using combustion data. 

**Shell data obtained from Thermox Analyzer location, not EDC 

analyzer location. Data obtained from the EDC analyzer location on this test date indicate a leak in the system. 

***Meets ± 5% of full scale criteria. 

BAAQMD 

RESULTS 

101 

27.9* 

3.2 

14.4 

38,600* 

84 

32.3 

SHELL OIL** 

RESULTS 

112 

35.2 

3.5 

44,000 

_ __ 

PERCE) 

DIFFEPJ 

+10.9 

+26.2 

+9.4 

+14.0 

CORRECTED COPY 

NO COMMERCIAL USE OF THESE RESULTS IS AUTHORIZED 

Source Test Team Leader Date 

B. Bartley jr 

Approved—Chief of Source Test Da 

£&&& 

G. Karels 

?//*/* 
/ 

STRIBUTlON: 

'Firm 

Permit'Services 

Enforcement 

Technical Services 

Source Inventory 

Requester 

D.A.P.C.O. 

- BAY AREA \ 

AIR QUALITY MANAGEMENT DISTRICT 

939 ELLIS STREET 

SAN FRANCISCO. CALIFORNIA 94109 

(415)771*000 

REPORT OF 

CONTINUOUS EMISSION MONITOR 

FIELD ACCURACY TESTS 

Report No. _/~9. 4 ... 

Test Date: $/..}./.$.$.... 

Test Times: 

Run A.1P.45-.1115 

EDC R5B:1126-1.15 7 

Run C: 

SOURCE INFORMATION 

Firm Name and Address 

Shel l Oi l 

P.O. Box 711 

Martinez , CA 94553 

Conditions During Tests 

FUEL USAGE: 

Flexigas-12 8 mmBTU/hr 

Refiner y Gas-26 mmBTU/hr 

LSFO-67 mmBTU/hr 

TOTAL=221 mmBTU/hr 

Firm Representative and Title 

Dal e Obenauer, Enginee r 

Phone No? 2ft-iSI 61 

Monitors) Tested: ' 

EDC a t Boile r #4 

PROCEDURAL DATA 

Parameters Tested: 

NOx/C02/0 2 /lbs-h r 

Yes No 

Daily zero & span check made? £ t D 

Records maintained for 2 yrs? j Q O 

Calibration gases acceptable? 90 D 

V/N Recommended? J$k* 0 / 

BAAQMD Representatives 

B. Bartle y 

Test Results and Comments: 

METHOD TEST 

ST-13A NOx, ppm (dry) 

ST-13A NOx, lb/hr 

ST-14 02%, Volume (dry) 

ST-5 C02, % Volume (dry) 

ST-23 H20, % Volume 

ST-19A S02, ppm (dry) 

Volume Flowrate, SDCFM 

ST-19A S02, lbs/hr 

BAAQMD 

RESULTS 

84 

26.0 

5.1V 

12.8 

10.7 

72 

43,300 

31.0 

SHELL OIL* 

RESULTS 

112 

35.2 

3.5 

- — 

-44,000 

___ 

PERCENT 

DIFFERED 

+33.3* 

+35.4** 

-31.4 

-1.6 

___ 

*The data at the EDC site compared to the data at the 

Thermox site indicate a leak at the EDC site. 

**Meets the ± 5% of full scale critera. 

CORRECTED COPY 

NO COMMERCIAL USE OF THESE RESULTS IS AUTHORIZED 

Source Test Team Leader Date Approved—Chief of Source Test 

B. Bartley 

Stf \ \ ®fi 

Dat 

*/i*k 

' 
P.39 

DISTRIBUTION: 

Firm 

Permit Services 

Enforcement 

Technical Services 

Source Inventory 

Requester 

D.A.P.C.O. 

BAY AREA . 

r...\ QUALITY MANAGEMENT DIS.JGT 

939 ELLIS STREET 

SAN FRANCISCO. CALIFORNIA 94109 

(415) 771«)00 

REPORT OF 

CONTINUOUS EMISSION MONITOR 

FIELD ACCURACY TESTS 

Hepori NO. 

2/28/84 Test Date:. 

Test Times: 

Run A:.. 1034-1102_ 

Run 6:1112-1143. 

Run C,ll.5.9.-1221. 

SOURCE INFORMATION PROCEDURAL DATA 

Firm Name and Address 

Sheli Oil 

P.O. Box 711 

Martinez, CA 94553 

Conditions During Tests 

Mixed Fuela; 

Nat. Gas: 77 mm btr/hr 

Fuel Oils 219mm btu/hr 

Firm Representative and Title 

Dale Obenhauer, 

Engineer 

Phone No. 228-6161 

Monltor(s) Tested: 

EDC Monitor § Boile r #4 

Yes No 

Dally zero & span check made? B D 

Records maintained for 2 yrs? B D 

Calibration gases acceptable? D D 

V/N recommended? g t D 

Parameters Tested: 

N Ox /C0 2 /02/flo w 

BAAQMD Representatives 

B. Bartley 

Test Results and Comments: CORRECTED COPY 

METHOD TEST 

ST-13A NOx, ppm (dry) 

ST-13A NOx, lb/hr 

ST-14 02%, Volume (dry) 

ST-5 CO2, % Volume (dry) 

Volume Flowrate, SDCFM 

ST-19A SO2, ppm (dry) 

ST-19A S02, lbs/hr 

ST-23 H20, % Volume 

*The CO2 monitor is no longer required. 

BAAQMD 

RESULTS 

162 

52.0 

6.6, 

10.6 

44,900 

160 

71.5 

12.6 

SHELL OIL 

RESULTS 

183 

53.7 

4.8 

7.6 

41,000 

-

— ._ 

PERCENT 

DIFFEREN( 

+13.0 

+3.3 

-27.3 

-28.3* 

-8.7 

— 

;.;> C:A 

NO COMMERCIAL USE OF THESE RESULTS IS AUTHORIZED 

Source Test Team Leader Date 

P. Bartley £_ 

Approved—Chief of Source Test 

G. Karels 

Date 

^ b 
.IBUTION: 

iSrmit Services 

*/Cn(orcement 

Technical Services 

Source Inventory 

Requester 

D.A.P.CO. 

P.40 

) BAY AREA ) 

AiR QUALITY MANAGEMENT DISThiCT 

939 ELLIS STREET 

SAN FRANCISCO. CALIFORNIA 94109 

(415) 771-6000 

REPORT OF 

CONTINUOUS EMISSION MONITOR 

FIELD ACCURACY TESTS 

Itfl^W I • *%%*.. 

Test Dale:. 

Test Times: 

Run Ai 

Run 8*. 

Run C: 

10/13/83 

1124-1154 

1234-1305 

1307-1337 

SOURCE INFORMATION PROCEDURAL DATA 

Firm Name and Address 

Shell Oil.Company 

P.O. Box 711 

Martinez, CA 94533 

Firm Representative and Title 

Dale Obenauer, Environjnental Engineer^,. PhoneTfo. * 2 2 ft - ft 1 fi 1 

Conditions During Tests 

Normal 

Monltor(s) Tested: 

EDC 8 COBoiler #1 

Yes No 

Dally zero & span check made? El D 

Records maintained for 2 yrs? Q D 

Calibration gases acceptable? \~) D 

/N recommended? Q CD 

Parameters Tested: 

so2/o2/co2 

BAAQMD Representatives 

B. Bartley 

A. Ezersky 

Test Results and Comments: 

METHOD TEST 

ST-19A 

ST-19A 

ST-5 

ST-14 

ST-2 3 

S02; ppm (dry) 

S02; lb/hr 

C02; * volume (dry) 

02; % volume (dry) 

H20; % volume 

Volume flowrate; SDCFM 

BAAQMD 

RESULTS 

131 

111 

14.0 

2.6 

15.4 

85,100 

SHELL 

OIL* 

RESULTS 

71 

71.3 

- «, — — « 

101,000 

PERCENT 

DIFFERENCE 

-45.8* 

. -35.8* 

+18.7 

•Although the SO2 ppm (dry) and S02 lbs/hr do not meet 

the±201 relative accuracy requirement; they do meet the 

10* of emission limitation criteria. 

NO COMMERCIAL USE OF THESE RESULTS IS AUTHORIZED 

Source Test Team Leader Date Approved—Chief of Source Test 

fe*gB. Bartley 

'OCT f 6 1983 G. Karels 

Date 

'°/u/?l 
. / 

P.41 

BUTION: 

srmlt Services 

'Enforcement 

Technical Services 

Source Inventory 

Requester 

O.A.P.C.O. 

) BAY AREA ' 

AIR QUALITY MANAGEMENT DISTRICT 

939 ELLIS STREET 

SAN FRANCISCO. CALIFORNIA 94109 

(415) 771-6000 

REPORT OF 

CONTINUOUS EMISSION MONITOR 

FIELD ACCURACY TESTS 

Report No. 

~> j - •>• 

10/11/83 

1338-1408_ 

Run B:..l.4..

2

.

6

.:15p.O 

RunC,15?6:lS41_ 

Test Date-. 

Test Times: 

Run A: 

SOURCE INFORMATION PROCEDURAL DATA 

Firm Name and Address 

Shell Oil Company 

P.O. Box 711 

Martinez, CA 94533 

Conditions During Tests 

Normal 

Firm Representative and Title 

Dale Obenauer 

Environmental Engineer Phone No. >>>>o_6161

6

 _ 

Monitor(s) TesWbT 

CO Boile r »2 

Yes No 

Dally zero & span check made? S Q 

Records maintained for 2 yrs? 0 Q 

Calibration gases acceptable? jjp D 

Parameters Tested: 

so2/o2/co2 

BAAQMD Representatives 

Bob Bartley 

Alex Ezersky 

Test Results and Comments: 

METHOD TEST 

ST-19A S02; ppm (dry) 

ST-19A S02; lb/hr 

ST-S CO ; % volume (dry) 

me 

ST-14 02; t volume (dry) 

ST-23 H20; % volume 

Flowrate; SCDFM 

BAAQMD 

RESULTS 

120 

123 

13.4 

3.1 

18.7 

SHELL OIL 

RESULTS 

80 

82.0 

_ - _ 

PERCENT 

DIFFERENCE 

-33.3* 

-33.3* 

em mm em 

. .. 

• - -

103,000 

*A1though the SO? ppm (dry) and S02 lb/hr are .greater 

than —20*;. they do meet the 10* of emission standard 

criteria. 

CORRECTED COPY 

NO COMMERCIAL USE OF THESE RESULTS IS AUTHORIZED 

Source Test Team Leader 

B. Bartley 10/18/83 

Date | Approved—Chief of Source Test 

G. Karels 

Date 
P.42 

• 

SHELL OIL COMPANY 

MARTINEZ MANUFACTURING COMPLEX 

BOILER A CONTINUOUS EMISSION MONITOR 

FIELD ACCURACY TEST 

JULY 31, 1983 

Test Time: 1010 Hours - 1140 Hours 

Shell Quality Boiler 14 Continuous 

Test Assurance Dept. Van Emission Monitor 

NOX, PP°»

 dr y 

NOx, lb./hr . 

Volume Flowrate, SCFM 

H20, X Vol. 15.2 

100 

46.3 

— 

118 

54.6 

75,000 

DEC:lp (2.73) 

8/21/83 
« • i Services 

•orcement 

Technical Services 

Source Inventory 

Requester 

D.A.P.C.O. 

BAY AREA 

AIR QUALITY MANAGEMENT DISTRICT 

939 ELLIS STREET 

SAN FRANCISCO. CALIFORNIA 94109 

(415) 771-6000 

REPORT OF 

CONTINUOUS EMISSION MONITOR 

FIELD ACCURACY TESTS 

P.43 

Report No. 

w t i _/ 

Test Dele: 5/19/83 . 

Test Times: 

RunA:....l.!\.4.-1104 

Run B:... 11.1 .P-.11.42. 

RunC:....1149:l220. 

SOURCE INFORMATION 

Firm Name and Address 

Shell Oil Company 

P.O. Box 711 

Martinez, CA 

94SS3 

Conditions During Tests 

NORMAL 

Firm Representative and Title 

Dan Glaze-Env . Enginee r 

Phone No. 228-616 1 

Monitor(s) Tested: 

Thermo-Electronaon 

BOILER 14 

Parameters Tested: 

NO /C02 /02 /H2 0 

Test Results and Comments: 

METHOD TEST 

ST-13A N0 X , ppm (dry ) 

/—ST-13A N0 X , lb/hr . 

ST-5 C0 2 P X Volume (dry) 

ST-19A S02„ ppm (dry) 

ST-19A S02 , lb/hr , 

ST-14 02, X Volume (dry) 

Volume Flowrate, SDCFM 

ST-23 Water Vapor, X Volume 

PROCEDURAL DATA 

Yes No 

Dally zero & span check made? GJ D 

Records maintained for 2 yrs? QJ D 

Calibration oases acceptable? D8 D 

VN Recommended? X 

BAAQMD Representatives 

Bob Bartley 

BAAQMD 

RESULTS 

220 

115 

9.0 

32 

-23.2 

5.7 

' -• _•- ** 

16.7 

SHELL OIL 

RESULTS 

1S6 

81.4 

6.5 

-• * v 

em> mm em -

em em em 

73,000* 

r 

PERCENT 

DIFFERENCE 

-29.1 

-29.2 

-27.8 

em «•> em 

** em mm em 

* Data supplied by Shell Oil. 

C NO COMMERCIAL USE OF THESE RESULTS IS AUTHORIZED 

,ource Test Team Leader Date 

Q>et-&z*}»* 

Bob BartleyK 

JUN 1 0 1983 

Date 
P.44 

DISTRIBUTION: 

firm 

Permit Services 

Enforcement 

Technical Services 

Source inventory 

Requester 

D.A.P.C.O. 

• BAY AREA l 

Alri QUALITY MANAGEMENT DISTRICT 

939 ELLIS STREET 

SAN FRANCISCO. CALIFORNIA 94109 

(415) 771-6000 

REPORT OF 

CONTINUOUS EMISSION MONITOR 

FIELD ACCURACY TESTS 

SOURCE INFORMATION 

Firm Name and Address 

Shel l Oi l Company 

P.O. Box 711 

Martinez , CA 94533 

Conditions During Tests 

Normal 

Firm Representative and Title 

Dan Glaze , Engineer 

Phone No. 228-6161 

Monitors) Tested: 

EDC Monitor on CO 

Boile r 92 

Parameters Tested: 

S 0 2 / 0 2 /C0 2 /NO x 

Report No ->'-o.> 

T.,,0.,.: .3/11/83 

TestTlmes: u . 5 1 _ 1 2 . 2 2 

Run A-......!.„ *

 l*" .. 

RunB,.. 1.

2

::. 3.

0

: . 1300, 

R-C..?:?.:.??:.".:*? 

PROCEDURAL DATA 

Yes No 

Daily zero & span check made? D9 D 

Records malntai ned for 2 yrs? QI D 

Calibration gases acceptable? 13 D 

VN Recommended? X 

BAAQMD Representatives 

Bob Bartley 

Test Results and Comments: 

METHOD TEST 

ST-19A S02, ppm (dry) 

ST-19A S02, lb/hr. 

ST-14 02, X Volume (dry) 

ST-5 C02, X Volume (dry) 

ST-13A N0X, ppm (dry) 

H20, X Volume 

Flowrate, SDCFM 

BAAQMD 

RESULTS 

107 

119 

2.9 

13. 4 

174 

16.3 * 

SHELL 

RESULTS 

108 

120 

- - -

. . . 

PERCENT 

DIFFERENCE 

0.9 

0.8 

112,000** 

* This H20* value was obtained by averaging the last four source 

tests' water data. 

** This flow was obtained using Shell Oil data. 

NO COMMERCIAL USE OF THESE RESULTS IS AUTHORIZED 

Source Test Team Leader Date 

Bob Bartl/y IW H • " 

Approv Chief of Source Test 

Gale Karel s 

Date 

3^/? 
P.45 

DISTRIBUTION: 

Firm 

Permit Services 

Enforcement 

Technical Services 

Source Inventory 

Requester 

O.A.P.C.O. 

> BAY AREA > 

AIR QUALITY MANAGEMENT DISTRICT 

939 ELLIS STREET 

SAN FRANCISCO. CALIFORNIA 94109 

(415) 771-6000 

REPORT OF 

CONTINUOUS EMISSION MONITOR 

FIELD ACCURACY TESTS 

Report No. 30-83 . 

Test Date: 3/1/8 3 

Test Times: 

Run A: 1333.-14.10 

Run B_....16.05-16.36. 

RunC: 16.46.-r.17.07. 

SOURCE INFORMATION PROCEDURAL DATA 

Firm Name and Address 

Shel l Oil Company 

P.O. Box 711 

Martinez , CA 94533 

Conditions During Tests 

C0B# 1 - Normal 

COB* 2 - Not in operatioA1 

Firm Representative and Title 

Dan Glaze 

Phone No. 228-6 1 61 

Monitor(s) Tested: 

CO BOILER #1 

Parameters Tested: 

S 0 2 / 0 2 /C0 2 /flow 

Yes No 

Daily zero & span check made? j p D 

Records maintained (or 2 yrs? Jp D 

Calibration gases acceptable? jp D 

VN RecomnmnrlftH? 

BAAQMD Representatives 

Bob Bartley 

Test Results and Comments: 

METHOD 

ST-19A 

ST-19A 

ST-S 

ST-14 

TEST 

S02, ppm (dry} 

S02, lb/hr. 

C02, * Volume (dry) 

02, X Volume (dry) 

H20, X Volume 

Vdlume Flowrate, SDCFM 

BAAQMD 

RESULTS 

170 

219 

14.4 

3.2 

12 

SHELL 

RESULTS 

102 

131 

129,400** 

PERCENT 

DIFFERENCF. 

-40.0* 

-40.2* 

* Although the S02 ppm and lb/hr do not meet the ±20t accuracy 

tolerance, they do meet the IO* of emission standard criteria, 

For the S02 ppm the values are 170 ±100ppm, and for the S02 

lb/hr the values are 219 ±129 lb/hr. 

- ~.. -~. 

** Calculated value using Shell Oil equation and velocity data. 

NO COMMERCIAL USE OF THESE RESULTS IS AUTHORIZED 

Source Test[Tea Teamm Leade Leader r ^ Date Approved—Chief of Sou 

Bob Bartle y /T ^tfal c Karels f 

Approved—Chief of Source Test Dah 

*hlr. 
P.46 

^ainiuunwn, 

F^rm 

Permit Services 

' Enforcement 

Technical Services 

Source Inventory 

Requester 

O.A.P.C.O. 

, BAY AREA 

Airt QUALITY MANAGEMENT DISTRICT 

939 ELLIS STREET 

SAN FRANCISCO. CALIFORNIA 94109 

(415) 771-6000 

REPORT OF 

CONTINUOUS EMISSION MONITOR 

FIELD ACCURACY TESTS 

SOURCE INFORMATION 

Firm Name and Address 

Shel l Oi l Company 

P.O. Box 711 

Martinez , CA 94553 

Conditions During Tests 

Refinery HasSri725 SCFM 

Fuel Oil — 416 lb/ h r. 

Firm Representative and Title 

Dan Glaze , Env. Enpr. 

Phone No. 228-6163 

Monitors) Tested: 

BOILER #4 

Parameters Tested: 

N O x / 0 2 /C0 2 /S0 2 

Test Data....1.1./1.0/A2..'.... 

Test Times: 

Run A-.1/1:4.5*11:24 

Rune-. 1 1 . / 3 0 "

1 2 '0 7 

RUN D:12:S1-13:3 0 

PROCEDURAL DATA 

Yes No 

Dally zero & span check made? Bl D 

Records maintained (or 2 yrs? 53 D 

Calibration gases acceptable? Ixl D 

BAAQMD Representatives 

Bob Bartle y 

Test Results and Comments: 

METHOD TEST 

ST-13A MOx , ppm (dry) 

ST-13A N0 X , lb/hr. 

ST-19A S02e ppm (dry) 

ST-19A S0 2 , lb/hr. 

ST-5 CO», X Volume (dry) 

ST-14 02„ X Volume (dry) 

Volume Flowrate, SDCFM 

ST-23 Water Vapor, * Volume 

BAAQMD 

RESULTS 

166 

57. 2 

84 

39.8 

9.6 

5.8 

47,600* 

10.2** 

SPELL 

RESULTS 

117 

39.8 

— 

k 

8.0 

6.2 

• 

••» •» 

PERCENT 

DIFFERENCE 

-29. 5 *** 

-30.4 *** 

m m 

em m 

-16. 7 

•6. 9 

— 

. -

* Supplied by Shell Oil. 

** Supplied bv CARB -

*** Emission standards are also 5% of full scale or in this case 

168 ppm * 50 PPM, ranp.e 116-216 PPM and 39.5-73.5 lb/hr. 

NOTE: CARB test site was downstream of BAAQMD test site. 

NO COMMERCIAL USE OF THESE RESULTS IS AUTHORIZED 

Source Test Team Leader 

BOR BARTLEY^ 

/Z. •A/fca. 

Date I Approved—Chief ot Source Test Date 

*/n/fi 
P.47 

TAL. 1 

. , California Air Resources Board 

Enforcement Division 

SUMMARY OF SOURCE TEST RESULTS 

TEL.'IIMES: 

11/10/82 

Run #1 1030 

Run #2 1115 

Run #3 1200 

1100 hrs. 

1145 hrs. 

1230 hrs 

SOURCE INFORMATION ARB REPRESENTATIVES 

SOURCE NAME AND ADDRESS 

Shell Oil Gcmpany 

P. O. Box 711 

Martinez, CA 94553 

SOURCE REPRESENTATIVE 

Judith C. Mcorad 

PHONE NO. (415) 228-6161 

ENGINEERS 

G. Zimrerman 

M. del Castillo 

TECHNICIANS 

J. KatyrynuiX 

R. Simunek 

DEVICE TESTED: 

Boiler #4 

OPERATING PARAMETERS: 

See. attached. 

PARAMETER MEASURED TEST RESULT 

Run»l Run#2 Run#3 Ave. 

'REGULATORY LIMIT 

Stack Gas Flowrate, SDCFM 37,850 

Moisture Content, % by Vol — 

Oxygen, % by Vol (dry) 8.1 

Carbon Dioxide, % by Vol (dry) 8.0 

Oxides of Nitrogen, ppmv (dry) 145 

Oxides of Nitrogen, (lb/hr) 39.2 

Sulfur Dioxide, ppmv (dry) 76 

Sulfur Dioxide, (lb/hr) 28.6 

CEM Relative* Accuracy, % (ppm) 

NC" Channel 

37,570 38,033. 37,820 

— — 10.2 

8.5 8.0 

8.5 8.0 

143 153 

38.3 41.5 

76 79 

28.4 29.8 

8.2 

8:0 

147 

39.7 

77 

28.9 

-20(-31) 

300 

+ 20% of reference or 

+ 5% of full scale 

(+ 50 ppm), whichever 

is" greater 

//ftr/fr 

M S 

^ 

DATE 

SECTION MANAGER 

-yy 

ENGINEER IN CHARGE ENGINEER 
P.48 

/ 

/IHIbUllON: 

Jrm 

''Permit Services 

Enforcement 

Technical Services 

Source Inventory 

Requester 

D.A.P.C.O. 

BAY AREA > 

AIM QUALITY MANAGEMENT DISTRIOT 

939 ELLIS STREET 

SAN FRANCISCO. CALIFORNIA 94109 

(415) 771-6000 

REPORT OF 

CONTINUOUS EMISSION MONITOR 

FIELD ACCURACY TESTS 

Report No A.9.~.!*_ 

Test Date: I.P./?/8 1 

Test Times: 

Run Ai. 12:00-12 : 3Q 

Run B: 13:00-13:3 0 

Run c- «:.50-14:2 0 

SOURCE INFORMATION 

Firm Name and Address 

Shel l Oil Company 

P.O. Box 711 

Martinez , CA 94553 

Conditions During Tests 

Normal fo r COB#l 

COB #3 no t operatin g 

Firm Representative and Title 

Dan Glaze-Env. Enqr. 

Phone No. 228-6161 , x348 

Monitor(s) Tested: 

CO BOILER # 1 

Parameters Tested: 

S 0 2 /Opacit y 

PROCEDURAL DATA 

Yes No 

Dally zero & span check made? LB D 

Records maintained for 2 yrs? 0 D 

Calibration gases acceptable? Q D 

BAAQMD Representatives 

B. Bartle y 

J . Buchan 

E. Dardon 

Test Results and Comments: 

METHOD 

ST-19A 

ST-19A 

ST-5 

ST-23 

ST-17 

TEST 

S02 Dpm(dry) 

S02, lb/hr 

C02# % Volume (dry) 

Water, % Volume 

Volume Flowrate, 

* 

SDCFM* 

BAAOMD 

RESULTS 

119 

132 

15.8 

11.6 

111,700 

SHELL 

RESULTS 

40 

44.4 

16.1** 

V 

PERCENT 

DIFFERENCE 

-66.4 

-66.4 

+1.9 

* Data provided by S.T.# 82062 

** Data provided by Shell's CO Boiler #2 COj monitor. 

Although the percent difference between results is greater than 

±20%; Shell Oil is still in compliance using the 10% of emission 

standard rule, (M.O.P. Volume V, Se&tion 6.2) This rule allows 

COBfl to be within 100 ppm of BAAOMD concentrations. 

NO COMMERCIAL USE OF THESE RESULTS IS AUTHORIZED 

Source Test Team Leader 

Bob Bartley/' 

Date Approved—Chief of Source Test Date 

/*-/-* / 
P.49 

.•tIBUTION: j 

;

 irm 

.Permit Services • 

Enforcement ' 

Technical Services ' 

Source Inventor 

Requester I 

D.A.P.C0. ' 

> BAY AREA » 

AIR QUALITY MANAGEMENT DISTRICT 

939 ELLIS STREET 

SAN FRANCISCO. CALIFORNIA 94109 

(415) 771-6000 

SUMMARY OF 

SOURCE TEST RESULTS 

Report No.. 

Test Date:. 

Test Times: 

Run A: 

Run B: 

Run C: 

02062 

10/8/8 1 

11-

12 

13 

30-

•10-

45-

-12 

-13 

-14 

:20 

:30 

:45 

SOURCE INFORMATION BAAQMD REPRESENTATIVES 

Firm Name and Address 

Shel l Oil Company 

P.O. Box 711 

Martinez , CA 94553 

Permit Conditions 

NONE 

Firm Representative and Title 

Judy Moorad-Env . Engr . 

Phone No. 228-616 1 

Source Test Engineers 

B. Bartle y J . Buchan 

E. Dardon 

Source: BOILER #1 Permit Services Division 

Permit No. P.N . 64 

Operates 24 hr/day&365 days/yr 

Enforcement Division 

Operating Parameters 

SEE SOURCE TEST FILE Test Requested by: 

G. Karels (CDS) 

Applicable Regulations: 6-310,31 1 11-1-30 1 VN Recommended: NO 

Test Results and Comments: 

METHOD TEST RUN A RUN B RUN C AVG. 

ST-17 Stack volume flowrate, SDCFM H2,323 

Stack Gas temperature, °F. 

ST-23 Water content, volune % 

ST-14 Oxygen, volume % 

ST-5 Carbon Dioxide, Volume % 

ST-19 Sulfur Dioxide, ppm 

ST-15 Particulate, Gr/SDCF 

Particulate, lbs/hr 

Lead Particulate, lbs/hr 

Lead particulate, lbs/day 

* 20 lb/hr reg limit is based on dividinq 40 lbs/hr by 2 operating 

stacks. No velocity traverse was taken on #2. Because fuel and 

CO qas feeds to the two units were equal, exhaust gas flowrates 

would have been equal also. 

NO COMMERCIAL USE OF THESE RESULTS IS AUTHORIZED 

112,32 3 

550 

11. 8 

.009 

8.3 0 

.012 

.29 

111,9 3 

546 

11. 7 

.007 

6.4 2 

.012 

. 2 9 

8» 110,75 8 

550 

11. 3 

.01 1 

10.5 5 

.012 

.29 

111 , 

549 

11. 6 

1.3 

15. 8 

119 

.009 

8.4 3 

.012 

.29 

1' 

Source Test Team Leader Date 

JrtC facfa. &*'* 

John ?>uchan 

Approved—Chiel of Source Test Date 

"/'/ll 
P.50 

TEST RESULTS AND COMMENTS 

Oxides of Nitrogen ppm at 3% O2* = 284 

Sulfur Dioxide ppm* = 190 

Oxygen* % by Volume* = 5.7 

Carbon Dioxide % by Volume* * 9.2% 

Carbon Monoxide ppm* = Negligible 

Moisture Content % by volume - 13 

CEM Accuracy % =-4 

of<r 

0

 TABLE 1 

1. * • J 

CALIFORNIA AIR RESOURCES BOARD 

ENFORCEMENT DIVISION 

SUMMARY OF SOURCE TEST RESULTS 

SOURCE INFORMATION 

SOURCE NAME ANO ADDRESS 

Shell Oi l Company 

P.O. Box 711 

Martinez, CA. 94553 

1 

SOURCE REPRESENTATIVE 

Judith C. Moorad 

PHONE NO. (415)228-6161 

DEVICE TESTED: 

Boiler #4 

OPERATING PARAMETERS: 

Steam Flowrate 

126,500 lb/hr a t 745°F and 650 psi 

• 

T£ST TIMES: 

7/22/81 

1030 - 1430 hours 

ARO REPRESENTATIVES 

ENGINEERING TECHNICAL 

R. Tyler D. Wilson 

H. Weishahn 

REGULATION LIMITS 

300 

+20 

*A11 valjjes averaged over test as they were nearly constant 
P.51 

/ , DISTRIBUTION: 

/ , ,Firm 

- Permit Services 

Enlorcement 

Technical Services 

Source Inventory 

Requester 

D.A.P.C.O. 

\ BAY AREA 'l 

AiR QUALITY MANAGEMENT DISlrtlCT 

939 ELLIS STREET 

SAN FRANCISCO, CALIFORNIA 94109 

(415) 771-6000 

SUMMARY OF 

SOURCE TEST RESULTS 

** 

SOURCE INFORMATION 

Firm Name and Address 

Shell Oil Co. 

P.O. Box 711 

Martinez , CA 94553 

Permit Conditions 

None 

Firm Representative and Title 

Judy Moorad-Env. Engr. 

Phone No. 228-6161 

Source: ^ BU1LKR #3 

Permit No. Plan t #64 

Operates 24 nr/day & 365(jays/yr 

Operating Parameters 

CONFIDENTIAL 

Applicable Regulations: b-JlU , b-J.1 

Report NO. . . 81154 

Test Date:.. 3/10/81 

Test Times: 

Run A: 1:14-2:0 4 

RunB: 2..:. .3.0. - 3. J. 2 Q. 

Run C: 3..:..4.0.-.4..:.3.0.. 

BAAQMD REPRESENTATIVES 

Source Test Engineers 

E. Dardon J . Buchan 

B. Bartley 

Permit Services Division 

Enforcement Division 

Test Requested by: 

G. Karel s (CDS) 

VN Recommended: 

Test Results and Comments: 

METHOD TEST 

ST-17 Stack Volume Flowrate, SDCFM 

Stack Gas Temperature, F.,Avg. 

ST-23 Water, Volume % 

ST-14 Oxygen, Volume % 

ST-15 Particulate, Gr/SDCF 

Particulate, lbs/hr 

Ringelmann No., Range 

Ringelmann No., Avg. 

* This limit is based on dividing 40 lbs/hr by 3 CO Boilers 

NO COMMERCIAL USE OF THESE RESULTS IS AUTHORIZED 

RUN A 

n i l 

n i l 

RUN B 

78,00 0 

510 

9 . 5 

3 . 6 

.0008 

.567 

0 

0 

RUN C 

76,60 0 

510 

11. 5 

3 . 6 

• .0032 

2.0 9 

0 

0 

AVG. 

77,30 0 

510 

10. 5 

3 .6 

.0020 

1.32 

0 

0 

LIMI'. 

• . 

1. 

• 

Source Test Team Leader Date 

J ^ &.M'^ 2OM** &I 

John Buchan 

Approved—Chief of Source Test Dal' 

3-23- *. 
DISTRIBUTION: 

Firm 

> Permit Services 

Enlorcement 

Technical Services 

Source Inventory 

Requester 

D.A.P.C.O. 

' BAY AREA 

AIR QUALITY MANAGEMENT DISTRICT 

939 ELLIS STREET 

SAN FRANCISCO. CALIFORNIA 94109 

(41S) 771-6000 

REPORT OF 

CONTINUOUS EMISSION MONITOR 

FIELD ACCURACY TESTS 

Report No 

Test Date:... 

Test Times: 

Run A:.. 

Run B:.. 

Run C:.. 

PS? 

3/10/81 

1600-1730 

SOURCE INFORMATION PROCEDURAL DATA 

Firm Name and Address 

Shel l Oi l Co. 

P.O. Box 711 

Martinez , CA 94553 

Conditions During Tests 

NORMAL 

Firm Representative and Title 

Judy Moorad - Env. Engr, 

Phone No. 228-616 1 

Monitor(s) Tested: 

CO BOILER #2 

CO BOILER §3 

Yes No 

Daily zero & span check made? sQ D 

Records maintained for 2 yrs? Q O 

Calibration gases acceptable? LjJ D 

Parameters Tested: 

S 0 2 , Flowrat e 

BAAQMD Representatives 

B. Bartle y 

J . Buchan 

E. Dardon 

Test Results and Comments: 

METHOD TEST 

BAAQJI) 

RESULTS 

ST-23 Water Content, % Volume* 14.1 

ST-17 Stack Flowrate; SDCFM* 85,400 

ST-19A SO2 Avg. Cone, ppm(dry)** 80 

S02 avg. emission rate, lb/hr** 67.8 

ST-14 Oxygen content, % Volume 3.4 

SHELL OIL 

RESULTS 

82,900 

29.7 

PERCENT 

DIFFERET 

-2.9 

-56 

-56 

** 

Data was obtained from particulate source test #81154, 

which was performed simultaneously. 

+ 

Although the % difference between results is greater than -20%; 

Shell oil still comes within compliance using the 10% of emission 

standard rule (MOP Volume V, Section 6.2). This allows COR *2 to 

be within 100 ppm of BAAQMD concentrations. 

COE 13 opacity transnissoneter is found to be in compliance. 

NO COMMERCIAL USE OF THESE RESULTS IS AUTHORIZED 

Source Test Team Leader 

H>Cr(?- &tt<7ti&4p 

UoL> Bartle y 

Date 

>/^w« . %l 

Approved—Chief ol Source Test 

Ga)o G. Karels 

D; 

3-3/-.' 
'/. 

" " r 

> 

jiSh^ll Oil Company 

Martinez Manufacturing Complex 

P.53 

Source Monitored: *ufL 

Pollutant: H*^ 

Month, Year 

'.. 

DAY 

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 

•2V 

130 

,31 

AVG. 24 HR. 

CONC (ppm) 

3W 

HO 

<*<* 

HZzf 

z.* 

?>*> 

5*2-

8-1 

7 7 

31 

H9 

V3 

Hi 

IC 

Z5 

Z T -

2M 

Z7 

Z-7 

Z5* 

Z3 

*-Z3H 

7~\ 

n 

£ $ • 

31 

53 

HO 

3 3 

MAX. 1 HR. 

CONC (ppm) 

(0(7 

67 

/ HH 

159 

Z7 

iW3 

fez. 

IkO 

/ ^ 3 

/?>5 

3«7 

/W 

/oz. 

lo2-

3 0 

33 

3fe 

\vz 

31 

7 2 . 

.fz . 

31 

4 7 

79 

z c 

•3o 

37 

Hz. 

H3 

9 ( 

/o<y 

TOTAL MASS EMISSIONS 

(TONS) 

-

REG. EXCESSES 

'• 

5re exc«s a&otr 

cee occfjf ftpft>itT 

. 

- • . 

INSTRUMENT DOW> 

TIME (HRS.) 

* 

• 

. 

Total Mass Emission For Month 

Comments: 

Tons 

id, ^. .D^KU^-L , (fao/&r' 

Signal ure. Dote 
P.54 

MONIHLY IN-STACK. MUNMOKlNv, KI:IVM< i 

"Shell Oil Company 

Martinez Manufacturing Complex 

.3*N - {**? 

Source Monitored: fu6 i fr** SrVr 

Pollutant: ^i * 

DAY 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

II 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

26 

27 

| » 

\M 

.30 

i» 

Month. Year 

AVG. 24 HR. 

CONC (ppm) 

3 0 

31 

31 

3H 

3H 

33" 

?H 

Z | 

in. 

T-9 

3 3 

3Z 

1*1 

T>S 

Z(, 

zc 

-2.fr 

Z(* 

-z-i 

zc* 

2U 

TU7 

Z7 

•Z7 

i * 

3 o 

t? 

IS 

2 3 

Z3 

z. 

MAX 1 HR. 

CONC (ppm) 

SC 

W9 

Ml 

5 7 

L>o 

<*\ 

1*1 

?<\ 

?>* 

H7 

H<\ 

W<* 

3U 

35? 

Hi 

HI 

HS3 / 

SO 

3 o 

31 

39 

wo 

3H 

HO 

WO 

3 ^ 

Wl 

^sHo 

H7_ 

•v. 

TOTAL MASS EMISSIONS 

(TONS) 

V 

"" 

REG. EXCESSES 

_ 

..-• ' • 

. 

INSTRUMENT DOS 

TIME (HRS.) 

- -

Total Mass Emission For Month 

Comments: 

Tons 

Siprunirr. Date 
P.55 

iWU.xiIILt IN-blAL K MUMlOKlMLi KfcfUKT 

«. *» %)SVell Oil Company 

' Martinez Manufacturing Complex 

Source Monitored: t~<-U-L t'Ay '-'VVf. 

Pollutant: M •& S 

Month. 'Year 

DAY 

I 

2 

3 

4 

5 

6 

7 

8 

9 

10 

II 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

26 

27 

28 

! » 

.30 

i

3

' 

AVG. 24 HR. 

CONC (ppm) 

29 

zsZC 

7 9 

Z z . 

\p 

Z\ 

Z Z, 

ZH 

"LH 

11 

19 

^f 

ZS 

\s1 \ 

'9 

IS 

Z9 

ie 

ii* 

i s 

2 0 

ZC 

ZJ 

Z3 

£ 3 

Z-| 

• 

MAX. 1 HR. 

CONC (ppm) 

3 7 

31 

1 3 3 

Hf 

l i 

Trie 

3 3 

3 4 

H3 

SS 

9 3 

1 H7 

3 / 

s r 

Hz. 

W3 

? l 

HG 

vy 

HC 

</3 

3 0 

V3 

W3 

3F 

3 i 

3g3-7 

TOTAL MASS EMISSIONS 

(TONS) 

"-

REG. EXCESSES 

: 

% >

_ 

-."* ' 

. 

INSTRUMENT DOWf 

TIME (HRS.) 

* 

- -

Total Mass Emission For Month 

Comments: 

Tons 

Signature. Dote 
P.56 

* ' 

Shell Oil Company 

One Shell Plaza 

P.O. Box 4320 

Houston, Texas 77210 

d^-tW^-

April 9, 1985 

Mr. Jack R. Fanner, Director 

Emission Standards and Engineering Division 

Office of Air Quality Planning and Standards 

United States Environmental Protection Agency 

Research Triangle Park, North Carolina 27711 

Dear Mr. Farmer: 

As requested in your letter of January 25, 1985, the attached information 

on process equipment and associated emission control equipment subject to 

the petroleum refinery fuel gas provisions of 40 CFR 60 Subpart J is 

forwarded for Shell Oil's Norco, LA, Wilmington, CA and Martinez, CA 

refineries. Please note that only cost and supplementary process information are provided for Norco refinery since the balance of the data were 

obtained during an EPA field trip to that facility. 

Our Wilmington refinery has identified three problem areas encountered in 

complying with the NSPS. These are the dual reporting of information to 

EPA and to the state agency; the short pre start-up notification of 30 to 

60 days, and possible difficulties in meeting the performance test deadline of start-up plus 180 days. (See Section X-I, page 14 of Wilmington's response) 

We believe the attached data responds to all of the information requested 

in EPA's questionnaire. However, if clarification is required please 

feel free to contact me at (713) 241-1889. 

Very truly yours,

 r. 

J//A. Mullins, Manager 

ivironmental Programs 

Environmental Affairs 

JAE/blv 

Attachment 

CAS50990] 
V P.57 

<;.. « 

SHELL OIL COMPANY 

WILMINGTON MANUFACTURING COMPLEX 

RESPONSE TO EPA QUESTIONNAIRE 

- i 

KSPS - PETROLEUM REFINERIES -

r 

FUEL GAS COMBUSTION DEVICES 

CRC509906 
P.58 

& 

WILMINGTON MANUFACTURING COMPLEX 

RESPONSE TO EPA QUESTIONNAIRE 

NSPSV-PETROI£UM^REFINERIES, FUEL GAS COMBUSTION DEVICES 

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), H^S concentrations, 

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

and where process monitoring and emission monitoring samples are taken-'. ~ 

The Wilmington Manufacturing Complex has both a low and high pressure fuel 

system at the Dominguez portion of the Complex and a high pressure fuel 

system at the Wilmington Section. The fuel gas system typically has <160 

ppm H2S and is used as fuel at 30 different combustion sources (furnaces, 

boilers and flares.) A diethanol amine (DEA) treating system is used to 

remove the H2S -from the fuel gas. The stripped H2S is converted to 

elemental sulfur with a Claus Unit. Off gases from the Claus Unit are 

treated by a SCOT Tail Gas Unit that recovers over 99% of the remaining 

H2S which is recycled back to the Claus Unit.. Scrubbed gases from the 

SCOT Unit are incinerated to convert any residual H.2S to S02. Schematics 

are enclosed that give a general description of these systems (see 

Attachments 1 and 2.) Fuel usage for thte combustion units is given in JII 

(2) and a typical mass balance for our sulfur recovery system is given in 

V (1). 

II. COSTS 

We would like separate capital and operating costs of your primary 

emission control systems (amine treater, FGD, or other processing 

unit). The costs requested are for the entire control system, but 

we are also interested in the costs associated with the additional 

absorption capacity required for treating the fuel gas .that is 

routed to new combustion sources. Please provide a breakdown (or 

factor) for just the fuel gas treatment, if possible. 

Our primary control device is an amine treating system that removes 

the H2S from the fuel gas prior to its combustion in furnaces or 

boilers. Capital and annual operating costs are maintained for each 

major processing unit which may include an amine stripper or 

absorber. However, the costs are not broken down by individual 

vessel (such as the amine stripper) within the major processing unit. 

Therefore, accurate capital and operating costs are not available for 

our amine treating system nor are costs available for our fuel gas 

BFG850603-1 
P.59 

treatment system. Additional adsorption capacity was not needed to meet the 

NSPS limit of 160 ppm H2S in our fuel gas system. 

Please provide the following cost information. Index costs to year 

and month. 

a. Purchase cost (explain what is included) 

b. Installation cost (explain what is included) 

c. Annual operating costs 

As explained in (1) above, costs are maintained for each major 

process unit but they are not broken down for each vessel within 

the unit such as an amine absorber or treater. 

d. Key accounting factors

 v

_ • i. I'>M1. Lifetime of equipment 

Twenty years is"the generally the book life value for oil 

refinery equipment. 

2. Equipment amortization and depreciation rate 

Amortization refers to nontangible properties and thus is 

not applicable to equipment. We use both the book (20 

years) and tax lives (5 years) to depreciate our assets. 

3. Labor and management charges ,' 

Direct operating overhead charges are included in annual 

operating costs. 

4. Overhead rate " - -• 

These overhead rates vary depending on the type.of service 

and period. Thus, specific rates cannot be furnished. 

III. REFINERY COMBUSTION DEVICES 

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

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

others)? 

There are 30 combustion sources at the Wilmington Manufacturing 

Complex. 

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

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

and ranges): a) Size - capacity, BTU rating, fuel consumption, > 

BFGc-50603-1 
P.60 

b) Costs - capital and operating, c) Hours of operation and d) Other 

fuels used. ..--•• 

\-««i¥S. Listed below is the data you requested except for capital and . 

operating costs. Our accounting system does not break the costs down 

by heater, boiler, or flare. 

Shell 

Equip. 

No. 

EA-10 

BA-11 

BL-12 

BI/-13 

CC-14 

CC-15 

CF-14 

CF-20A 

AB-17 

GH-18 

GH-19 

PT-24 

PT-35 

PT-25 

PT-26 

PT-29 

PT-30 

CK-31 

CK-32 

FR-33 

FR-34 

HP-3e 

DH-40 

DU-255 

CL-48 

CU-53 

SA-4 

SA-6 

Doming. 

Doming. 

Type 

Boiler 

Boiler 

Boiler 

Boiler 

Waste Ht. Boiler 

Waste Bt. Boiler 

Furnace 

Furnace 

Furnace 

Furnace 

Furnace 

Furnace 

Furnace 

Furnace 

Furnace 

Furnace 

Furnace 

Furnace 

Furnace 

Furnace 

Furnace 

. Furnace 

Furnace 

Furnace 

Thermal Xncin. 

Cat. Incin. 

Flare - Wilm. East 

Flare - Wilm. West 

Flare 

Flare 

Design 

Heat Release 

10 BTU/hr 

350-t 

350-» 

291 

291 

157.5 

157.5 

60 

B8 

190 

54 

40 

39"l 

28J 

117 n 

128 J 

66"t 

25-J 

126n 

126 J 

122-1 

122-J 

340' 

50 

231 

27.5-1 

15 J 

::3 

:n 

1984 Fuel 

Consumption 

10 SCF 

26 

1002 

1060 

435 

370 

2 

126 

327 

82 

51 

120 

470 

• < 

324' 

;1840 , 

1592 

990 

122 

1551 

180 

292 

"650 

Hours 

of "Operation 

Continuous 

Continuous 

Continuous 

Continuous 

Continuous 

Continuous-.. 

Continuous 

Continuous 

Continuous 

Continuous 

Continuous 

Continuous 

Continuous 

Continuous 

Continuous 

Continuous 

Continuous 

Continuous 

Continuous 

Continuous 

Continuous 

Continuous 

Continuous 

Continuous 

Continuous 

Continuous 

Continuous 

Spare 

Continuous 

Spare 

Fuels 

Used 

Gas 

Gas 

Gas 

Gas 

Gas, 

,- jGas " 

^Gas^-

Gas 

Gas 

Gas 

Gas 

Gas 

Gas 

Gas 

Gas 

Gas 

Gas 

Gas 

GasGas 

Gas 

Gas 

, Gas 

"* Gas 

Gas 

Gas 

Gas 

Gas 

Gas 

Gas 

Please list and describe any new, modified, or reconstructed 

combustion devices you have that are subject to the NSPS, and 

the dates of installation. For these affected combustion 

devices, describe how you complied with the NSPS and the resulting 

decrease in H,S concentration. Estimate, if possible, the 

incremental cost of compliance and the resulting SO, emission 

reduction. 

EFGe50603-l 
P.61 

The following is the information you requested: 

DESCRIPTION """"" 

SHELL-. 

EQUIP. 

NO. 

BL-12 

BL-13 

HP-38 

DH-40 

DU-255 

CL-48 

CU-53 

4. 

,'.- --Mr: :^^a; 

TYPE 

Boiler 

Boiler 

Furnace 

Furnace 

Furnace 

Thermal 

Incin. 

Cat. Incin 

Without 

fuel gas 

adverse 

the 

DESIGN .DATES OF 

HT, RELEASE' INSTALLATION' 

10° BTU/HR (STARTUP) 

291 05-76 

291 05-76 

340 04-83 

50 04-83 

231 02-84 

27.5 04-83 

15 04-83 

METHOD 

OF 

COMPLIANCE 

Existing H2S 

level was 

acceptable 

NSPS, what level of H?S and other sulfur co 

would be acceptable before there 

corrosion of combustion equipment? 

would be sign 

- V 

COST TO 

COMPLY S02 

REDUCTION 

None 

it 

n 

II 

HI _. _ . 

It 

II 

mpounds in 

ificant 

Excursions up to about 800 ppm total sulfur content can be tolerated 

for periods up to approximately eight hours provided the temperature 

stays above the sulfuric acid dew point temperature. In normal 

operation, we try to keep the sulfur level below 160 ppm to avoid 

corrosion. 

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? 

Listed below are the environmental (sulfur) regulations that impact 

our combustion devices. Our SCOT Tail Gas Unit was installed totreat the off gases from the Claus Sulfur Recovery Unit-and our 

Fluidized Catalytic Cracking Unit (FCCU) was upgraded, in part, to 

allow for the use of SO capture catalysts to meet South Coast Air 

Quality Management District (SC-AQMD) Rule 1105. 

BFG850603-1 
P.62 

AGENCY RULE NO. AND NAME 

SC-AQMD 407 "Liquid and Gaseous Air Contaminants" 

SC-AQMD 431.1 "Sulfur Content of Gaseous Fuels" 

SC-AQMD 431.2 "Sulfur Content of Liquid Fuels" 

SC-AQMD 468 "Sulfur Recovery Unit" 

SC-AQMD 903 "Standards of Performance for Fossil 

Fuel-Fired Steam Generators" 

SC-AQMD 909 "Standards of Performance 

for Petroleum Refineries" 

SC-AQMD 1105 "Fluid Catalytic Cracking 

Units-Oxides of Sulfur 

EPA •. 40 CFR 60.43 "Subpart D - Standards 

of Performance for Fossil - Fuel 

Fired Steam Generators for which 

construction is commenced after 

August 17, 1971." 

IV. PRIMARY CONTROL (AMINE TREATERS) 

REMARKS 

Max. 500 ppm from any 

discharge point to the 

atmosphere. 

800 ppm max. total 

sulfur compounds in 

gaseous fuels. 

Max. 0.25%w sulfur in 

liquid fuels. 

Max. 500 ppm S02 and 

Max. 10 ppm H2S. 

Max. 0.80' lb S02710.6-

BTU for liquids-fuel^ 

burning. 

Max. 160 ppm H2S 

(0.10 grains/SCF) in 

the gaseous fuel. 

Max. 130 kg. S02/M 

bbls. of feed which 

reduces to 60 kg/M 

bbls of feed on 1/1/87. 

Max. 0.80 lb S02/106 

BTU for liquid fuel 

burning. 

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)? 

There are two kinds of feed gases treated by our amine system. One 

results from cracking operations, while the other is a vent gas from 

hydrotreating operations. The cracked gases are primarily methane, 

ethane, and hydrogen contaminated with H2S and C02. The hydrotreater 

vents are primarily hydrogen with some methane and ethane plus minor 

amounts of heavier hydrocarbons. The H2S concentration in the inlet 

streams vary up to approximately 20% H2S and the treated (outlet) gas 

contains less than 160 ppm H2S. 

BFG650603-1 
P.63 

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

treater system, describe only the systems that provide 'fuel gas to 

combustion sources subject to the NSPS. 

The gas amine treating system contains eleven absorbers, two* 

strippers, and five flash/skim vessels. It is operated as one 

system. Seven of the absorbers treat gas that goes to the fuel 

system. The enclosed flow diagram (Attachment 1) and table describe 

the system. 

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

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

The same type of system would have been installed. 

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. 

The treating system is maintained during routine maintenance 

shutdowns. It is quite reliable and there is no history of excessive 

emissions that required corrective action resulting from maintenance 

problems. There have been occasional foaming problems in the past 

that resulted in significant losses of the amine. Since startup of 

the new sulfur recovery unit in 1983 and integration of the system 

there has not been any serious foaming. The amine can become 

contaminated with hydrocarbon, which is removed in flash/skim 

vessels. Particulate contaminants are removed by filtering. 

Corrosion is below 5 mils per year. 

5. Are the maintenance requirements and amine replacement rates more 

excessive than that indicated by the vendor? 

The maintenance requirements are normal. The amine'replacement is 

above the expected amount which is being reviewed. 

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

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

downtime)? 

The system has been quite reliable since startup. There have been no 

unscheduled shutdowns. Scheduled shutdowns are taken in conjunction 

with boiler inspections and the inspection or maintenance of associated 

units. 

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

system, and what types of personnel perform these inspections? 

BFG850603-1 
P.64 

Our Inspection Department is staffed with professional and paraprofessional personnel who inspect equipment internally during shutdowns 

and with appropriate external methods during operation. Inspection 

methods include, wet magnetic fluorescent particle, ultrasonic, and 

""•"- : - -

? X - r a y .--••••'•-•••'- " ' .-:.—;'C~ .. -.••- -/'•'•• . ".' ; 

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)? 

The gas is tested for H2S content. The amine is tested for acid gas 

loading, beat stable salts, foaming tendency, and strength. 

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

for varying conditions and inlet loadings so that a low H9S concentration 

can be maintained at the outlet? 

Flow rate of DEA is adjusted for variations in flow rate and HgS-^^ 

content of the treated streams. H2S content and strength of the lean 

solution are monitored to maintain 0.05 moles H2S/mole DEA and 35% 

DEA concentration. 

V. SECONDARY CONTROL (SULFUR PLANTS, ETC.) 

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

handled (sulfuric acid plant, Claus sulfur plant with tail gas 

treater, thiosulfate plant, sold to another'•firm)? Briefly describe 

this secondary control system, including design size, vendor, year 

installed, and sulfur mass balances. Was this secondary control 

system installed separately or as part of a package with the amine 

treater? 

The'concentrated H2S stream is sent to one of two Claus sulfur units 

that operate at approximately 95% efficiency in converting the H2S to 

sulfur. The off-gases from the Claus units are then fed to aJSC0T 

tail gas unit that recovers over 99% of the H2S. The scrubbed gases 

from the SCOT unit then go to a catalytic incinerator where any 

residual H2S is converted to S02. A typical mass balance for this 

system is: (1) 280M pounds/day of H2S are fed to the Claus unit, (2) 

95% or 266M pounds of the H2S are initially converted to sulfur by 

the Claus unit, and (3) all of the remaining 12M pounds of H2S except 

for around 10-20 pounds are recovered in the SCOT unit and are 

diverted back to the Claus plant. The remaining 10-20 pounds leaving 

the SCOT unit are fed to a catalytic oxidizer where the H2S is 

converted to S02 

Two amine strippers were installed the same time as the Claus, SCOT 

and incinerator units. Their design size, vendor and year of 

installation are: 

BFG850603-1 
P.65 

I. Claus Unit ^ 

2. SCOT Unit 

3. Incinerator 

Design Size 

Long Tons/ 

Sulfur/Day MMSCFD 

-,iiV^ . .. -*^ ..... 

200 each — 

20 — 

30 

4. Amine Strippers 

FOOTNOTE: (a) C. F. Braun was the General 

2. If the tail gas unit uses amine s< 

Capacity 

M bbls Vendor 

, -__ V--,-•,. • -(ay;. . 

(a) 

(a) 

25 (a) 

Contractor. 

rrubbing, is it now (or are 

Year of 

Install. 

1983 

1983 

1983 

1983 

you 

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

What are the advantages and disadvantages of this approach? — ZL-.ZZT -"*"* 

Our SCOT unit does use amine scrubbing but we do not combine the tail 

gas and fuel gas for amine stripping. We have not considered this 

approach and thus cannot offer any comment on its advantages and 

disadvantages. 

VI. 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. In addition, please provide the following information: 

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

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

c. Besides H?S, what other compounds were tested for, (such -as 

COS, CS?, mercaptans, total sulfur, etc.)? Provide a summary 

of those results. 

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

blending with natural gas or other refinery gas? I-f after 

blending, what volume of other gases were blended with the 

treated fuel gas? 

Each eight-hour shift, the H2S content in the fuel gas is 

normally check with Draeger tubes at the locations identified 

in VII (2)(a) of this questionnaire. These are screening checks 

to ensure the amine treating system and/or operations are 

normal. The H2S levels are typically <160 ppm. The cost of 

each Draeger test is approximately $20. Records are available 

for review. In addition to the Draeger tests, the following 

total sulfur test was made by Shell in 1984. 

BFG850603-1 
TEST PROCESS 

DATE CONDITION 

08-01-84* Normal ' ^ 

Operation 

08-23-84 Normal 

Operation 

LOCATION 

Wilmington 

Boiler House 

CCU - after 

Blend Drum 

TEST 

METHOD 

EPA Method 

Microcoulometer 

EST. 

COST 

$200 

$200 

TOTAL 

SULFUR, 

PPM 

— 

104 

H2S 

PPM 

18.1 

11.5 

FOOTNOTE: Date of our report to EPA; the 18.1 ppm value was the average of 

two tests conducted on 07/02/83 and the 11.5 ppm value was the 

average of six tests determined on 08/24/83. 

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

been performed at the outlet of combustion devices which buri-ufuel 

gas. Describe the combustion devices tested. In addition oiEffiiiJ ~~ 

types of information listed above, we are interested in a sumnarys^. 

of the emission data for any other pollutants/compounds (S0?, total 

sulfur, NO , CO, hydrocarbons, etc.) 

During 1984, our heaters and boilers were tested for NO .emission ' 

. under varying loads. This testing was performed to establish NO 

profiles required by SC-AQMD Rule 1109 (NO limits for refinery

 X 

heaters and boilers.) NO testing was also performed on our steam 

methane reformer heater stack pursuant to a SC-AQMD permit Condition. 

Also Kew Source Performance Emission Tests" were conducted at the 

Distilling Unit No. 5 heater and CCU CO Boiler Stacks. Lastly, we 

checked the emission at our sulfur unit's thermal incinerator and the 

SC-AQMD compliance tested our CO Boiler Stack emissions. Records ,of 

these tests are available for review. 

3. Are' there any state or local regulations thaf require testing of 

fuel gas for existing sources, or that require additional testing 

for new sources' beyond that required by the NSPS? r 

There are no testing requirements for air monitoring purposes. 

VII. MONITORING OF EMISSIONS AND PROCESS OPERATION 

1. Please describe any state or local regulations that require you to' 

monitor. 

South Coast Air Quality Management District's Regulation 909 will 

require us to monitor H2S levels in the fuel gas once an approved 

instrument is identified. 

2.. Emi 

a. 

ssion 

How 

monitoring of H2S 

do you 

(continuous 

monitor the 

concentration in the fuel 

H?S concentration of the 

instruments, periodic grab samples)' 

gas: 

fuel 

> Do 

8

as» 

you 

EFG85GS03-1 
10 

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 have three continuous H2S monitors at the following 

locations: 

LOCATION 

(1) Dominguez Boiler House 

(2) FCCU 

(3) Wilmington Boiler House 

REMARKS 

Monitors the H2S in the low pressure 

fuel system. 

The monitor is located downstream of 

the gas blend drum but before combustion in the furnaces. '.'--_._-:--^-x' 

The monitor is located downstream of 

the gas blend drum but before combustion in the furnaces and boilers. 

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. 

V 

In addition to the continuous H2S monitoring described in 3a 

above, Draeger test samples are normally taken once per 8-hour 

'•* shift. The cost per test is approximately $20. Daily costs , 

would be $180. 

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

1. Describe the monitors, including vendor," model number, 

date installed, and costs to purchase and install. 

LOCATION 

DOMINGUEZ 

BOILER HOUSE 

WILMINGTON 

BOILER HOUSE 

FCCU 

The following is the information on 

DESCRIPTIOh 

VENDOR 

HOUSTON 

ATLAS 

HOUSTON 

ATLAS 

HOUSTON 

ATLAS 

MODEL i 

722 

722 

722 

! 

( TYPE 

CONTINUOUS 

CONTINUOUS 

CONTINUOUS 

APPROX. 

YEAR OF 

INSTALLATION 

1977 

1983 

1977 

our monitors 

EST. -

PURCHASE 

PRICE 

$39M 

$50M 

$30M 

: 

COST TO" 

INSTALL 

$15M 

$25M 

$15M 

BFG850603-1 
P.68 

11 

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. 

We have encountered a wide variety of problems with these 

instruments. For illustrative purposes, we have enclosed 

(Attachment 3) a maintenance log for one one of our 

analyzers covering part of 1984. Note, the lead acetate 

tape had to be replaced above every two weeks and was the 

most predominate problem. Also, the photocell either 

needed replacing or recalibration several times. Our 

preventative maintenance program is to check the - M>"•'•..~ 

instruments weekly and recalibrate as necessary. '"Ab'e'nt^^ 

four hours/week are spent by an analyzer technician • 

checking and recalibrating the instruments. 

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. 

As pointed our earlier, Draeger samples are drawn once each 

shift and the H2S results are compared to those obtained by 

the Houston Atlas monitor.' Our;Instrumentation Department 

is notified of any discrepancies and corrective actions are 

taken as appropriate. Draeger test data is not retained. 

Kow 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 data is recorded continuously by the instruments 

described earlier in C (1). The four inch strip charts 

give H2S readings directly in "ppm" and the records are 

kept two years. 

5. Please provide a summary of monitoring data for the 

H?S content of fuel gas with corresponding process 

conditions for the last three months, (daily averages 

and ranges, noting any three-hour periods of excess 

emissions). For periods of excess emissions, explain 

the causes and corrective action taken. 

During the last three months, the H2S levels typically were 

<160 ppm. There were no three-hour periods of H2S levels , 

BFG85G603-1 
P.69 

12 

exceeding 160 ppm and the amine treating system was 

operating normally. 

.3. - ^Monitoring of process parameters:.. ,M;,_ -^r --..„,,... . 

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? 

The following process parameters are monitored: (1) process and 

DEA flow rates, (2) H2S concentration in the products, and (3) 

acid gas loading rates in the lean and fat DEA. Manual sampling 

and instruments are used to monitor these parameters. The 

process and DEA flow rates are monitored continuously and the 

lean DEA streams are sampled each shift. The fat DEA stream.is 

sampled periodically (weekly or longer) depending on the ^••y<~ 

variability of the feed composition. j' -.-**— 

b. Which process parameters are good indicators of the proper 

performance of the amine treater and of low H2S concentration 

at the outlet? How well do the process parameters correlate 

with H?S concentrations? 

We believe the following process parameters are good indicators 

of proper amine treater performance and ..correlate well with H2S 

concentration: 

1. H2S content in the fuel gas , 

2. DEA to product flow rate 

3. DEA concentration in the circulating DEA 

4. Acid gas loading in the lean and fat DEA. ;".. . 

All these parameters provide useful data to ensure low levels of 

H2S are maintained in the fuel system. 

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

why and with what type? 

There are no plans to replace our present monitors. 

5. Are any of the instrument monitors integrated into the process 

as a control system? 

None of the H2S monitors are integrated into the process as a control 

system. 

BFG850603-1 
P.70 

13 

1- " What is the normal size of your refine'ry 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? .... ^k-.'-.:-

Our rated crude capacity is 108M bbls/day and we are now processing 

around 113M bbls of crude/stream day. We are currently at capacity 

and operate 24 hours a day, 365 days per year. The gas flow rate 

from our Coker, CCU, and hydrotreaters affect the sizing and 

operation our amine treaters. 

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

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

treaters and the level of H?S and other sulfur compounds in the 

fuel gas? 

***** *"-,... 

The sulfur content of our crude in 1984 averaged approximately ;fl r5<%w 

sulfur. Typical ranges were between 0.7 and 4.5% w sulfur. As^'iaie 

sulfur content varied, the DEA circulation rate was adjusted to 

ensure sufficient removal of H2S from the gas. 

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

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

treating system? 

The degree of desulfurization in the hydrotreaters affects the size 

and operation of the amine treates. The type of sulfur compounds in 

the crude also affect the size /and operation of the treaters. Our 

current amine treating system described earlier is adequate to handle 

the sulfur variation in the crude. 

4. Kow much natural gas (if any) is blended wi~.h the refinery fuel gas 

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

primarily to keep-a constant flow of gas to process units or to 

dilute the H?S concentration to an acceptable level? -

In 1984, about 10 MM SCF per day was blended with our refinery fuel 

to meet gas demands and not for H2S dilution. 

X. 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 not had any specific problems in interpreting the NSPS or 

operating the control systems to comply with the NSPS. However, we 

have the following comments concerning the achievement of the NSPS 

requirements: 

£FG£50603-i 
P.71 

14 

a. General comments on 40 CFR 60.7 - Notification and Recordkeeping 

We are required to notify both the EPA and the SC-AQMD. It 

would ease the administrative burden by eliminating the EPA 

notification and recordkeeping requirements where the local air 

district (such as the SC-AQM in our case) has equivalent or more 

restrictive rules. 

b. 40 CFR 60.7(a)(2) - Prestartup notification between 30-60 days 

The 30-60 day period is extremely short and we suggest extending 

it to 120 days. Problems are often encountered during the 

commissioning of a unit which could easily delay startup a month 

or so. 

c. 40 CFR 60.8(a) - Performance tests no later than 180 days after 

startup .'_... >-i-•"•— 

We suggest that an extension be allowed to cover unforeseen 

problems that delay the performance tests beyond the 180-day 

period. 

2. What problems or difficulties, if any, have you experienced ^i~ n 

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? 

We do not have any particular problems except as noted above. 

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

recordkeeping for the NSPS? Do you have any suggestions. Please 

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

sample of a report. 

We do not maintain separate financial records on the cost of NSPS 

recordkeeping. Copies of our reports are available for review. 

XI. CONTACTS FOR FURTHER INFORMATION 

Please include the names and telephone numbers of appropriate contacts 

should clarification of the above information be needed. 

NAME 

C. U. Graham 

J. D. Joyce 

TELEPHONE NO. 

(213) 513-2026 

(213) 513-2070 

BFG850603-1 
ATTACHMENT 1 - GENERAL SCHEMATIC 

DEA FUEL GAS AND SULFUR TREATMENT SYSTEM 

WILMINGTON MANUFACTURING COMPLEX 

• .-.••. . 

[-0 CAM OUT 

CAT CRACKING UNIT 

t-DEA ABSORBER 

«*"lJ 

HYDROPROCESS1NG 

3-DEA ABSORBERS 

QA«mJ 

IEAN DCA 

COKER 

t-DEA ABSOt-SQM

lH 

HYDROTREATER 

(DHT 3) 

t-DEA ABSORBER 

<m~l -

TAT KAjmtiL 

TO DOMtNQUEZ WCH PRESSURE FUEL CAS *fY5TEM ( <100 PPM H3S ) 

BSORBER "-n 

J

 1 fDEA" 

XESS1NG W 

i«nfmrn>* **> 

"ER " X 

jy-^-^j^ 

REATER j Jj 

FAT DEA FROM SOURCES 

NOT ASSOCIATED WTH 

FUEL OAS SYSTEM 

TWO DEA 

STRIPPERS 

H28 

SULFUR PLANT 

SULFUR 

SCRUBBED CAS ( <tOO PPM H2S ) TO WUtrNCTrOH FUa •*rt*STEM 

SCOT 

TAL OAS UNIT 

ATTACHMENT 2 

•3V 

..*«• 

A • 

SOS 

tNaNERATOR 

SEE ATTACHMENT 2 

0% .BASSTBEAMS. 

*0 H2S CONCENTRATIONS CHECKED 

WTH DRAEGER TUBES 

O i£AHJDEAJIIJEAM-t___ _ !' ' 

MONITOR m TEsTraatxitCAU.Yt 

TEMPERATURE. ACID OAS (LOAOMO, FOAMtNO TENDENCY. 

DCA .STRENGTH AND HEAT STABLE SALT CONCENTRATION 

!• 

* f;?iS3 
STVEET VENT STREAMS 

FROM AIXYUTION UNIT 

NATURAL OAS 

AS NEEDED 

. FROM ATTACHMENT 1 

HIGH PRESSURE FUEL CAS 

<tOO PPM H2S 

NATURAL OAS 

AS NEEDED 

FROM AnACHMENT 1 

WLMINOTON CAS 

<tOO PPM H2S 

• EXCESS CAS FROM DOMINCUEZ 

• WATSON LANDFIIL OAS 

• OIST. UNIT VENT OAS 

• TANK FARM VENT OAS 

• MISC. SWEET VENT CASES 

ATTACHMENT 2 - GENERAL SCHEMATIC 

FUEL GAS AND COMBUSTION SYSTEM 

WILMINGTON MANUFACTURING COMPLEX 

TANK FARM 

VENT GASES 

H2S 

; MONITOR; 

PRESSURE 

REDUCER 

PRESSURE 

REDUCER 

- * - TO BOTLERS 12 AND 13 

- * • TO CCU HEATER . 

TO OTHER HEATERS 

ATDOMMOUEZ 

-+~ EXCESS TO -t-LMtNCTCN 

- » • TO B0t£R 8 10 AND 11 

TO HEATERS 

AT -MLMtNOTON 

vi'V 
V, J : 

ATTACHMENT III 

MAINTENANCE RECORD FOR ANALYZER 

'•SC.. AR 185 - SERVICE H?S FUEL GAS BLEND DRUM 

WILMINGTON BOILSE HOUSE 

OPERATION 

DATE TIME Sat. Unsat. O/S 

CALIBRATION 

OK Required 

AUTO 

"ZERO COMMENTS 

02-07-84 1400 X Repl. tape and check 

zero - Rich & 

Willie 

02-17-84 0800 X Replaced tape, 

drainout^ water from 

fuel line,...caii.b~ 

02-28-84 0815 Replaced tape, zero 

check - Willie 

03-09-84 0750 X Replaced tape, zero 

& cal - Richard 

03-19-84 0900 X X Replaced tape and 

two cylinders - RCG 

03-30-84 

04-10-84 

04-19-84 

05-11-84 

0810 

"N 

0815 

0819 

X 

X 

X 

X 

05-23-84 0900 X 

05-29-84 1230 X 

x, 

X' 

X 

X 

X 

X 

X 

X 

CK 

OK 

OK 

Replaced tape - R.G. 

Replaced tape - R.G. 

Replaced Tape - R.G. 

Cal. photocells -

replaced tape - R.G. 

Aligned photocell 

tape replaced -

Willie 

Calib. replaced 

nitrogen bottle -

Willie 

06-01-84 1010 X Aligned photocell 

and calib - Willie 

06-04-84 0930 X X Routine calibration 

Willie 

EFGS507902 
ATTACHMENT III (Cont'd) 

DATE 

06-13-84 

06-28-84 

07-09-84 

08-01-84 

08-15-84 

08-24-84 

TIME 

0840 

1245 

0815 

1515 

0930 

0800 

Sat. 

X 

X 

X 

X 

X 

OPERATION 

Unsat. O/S 

•"• ^-.'^•' . "v" - " r-v'/T---

-

CALIBRATION 

OK Required 

••;•--.-'*;-•-X•••**• -

X 

X 

AUTO 

ZERO 

••"•Tr""' 

X 

X 

X 

X 

COMMENTS 

• • ••.,... •• ..or^j;'. , 

Replace tape -

Willie 

Replaced tape, 

replaced H2 

cylinder & cal. -

Willie 

Replaced tape -

Willie 

Check and replace 

tape - Willie_ .."i1""— 

Replaced tape* -

check zero - Willie 

Analyzer do not 

respond to calib 

* . • 

08-27-84 1040 X 

08-27-84 

08-31-84 

09-27/84 1000 Out of Service for Repair 1000-1100 

1040 Analyzer Back on Service _ 

* 

0830 Analyzer Back on Service X 

10/01/84 0930 Routine Calibration 

10/08/84 0810 Routine Calibration 

10/19/84 0735 Routine Calibration 

10/24/84 0800 Routine Calibration 

Photocell replaced 

light aligned 

Electronic Check 

Willie 

X Electronic CheckWillie 

X Replaced, Balance 

photocell - calibration '- Willie 

X Willie Back on 

Service 0945 

X Replaced tape - * 

Willie 

X Replaced tape -

Willie 

EFGE507902 
MAINTENANCE RECORD FOR ANALYZER 

AR-185 - SERVICE H,S FUEL GAS BLEND 

OPERATION CALIBRATION PHOTO 

DATE TIME Sat. Unsat. O/S ' OK Required CELL COMMENTS 

10-31 0755 -.'• M *• X-••*"• Replaced Tape -

'..,-.•- «... Willie 

11-12 X X Replaced Tape -• JWL 

11-21 X X Meas. Replace Tape and 

3/36K Balanced Photocell -

RC 

12-3 1030 X X Opened up Nitrogen -

Replace Tape and 

Balanced Photocell 

RC '^ ;_ M>---

X X Replace SJ0- 7l25~~ 

Opened 

X X Replace Tape -

Balanced Photocell 

X X H 2 S SJO - Unsatisfactory - Low ppm 

"*. Reading - 70 ppm 

a 

•' •:,« replacemen t 

2-16 X X Replace Tape Pickup 

n ot turning -

Replaced Std 52 ppm 

12-

12-

12-

-13 

-17 

-23- 84 

1200 

1400 

BFGE507902 
^ 

SYSTEM DDEA SYSTEM DESCRIPTION 

PLANT 

VESSEL 

ERV1CE 

A: 

RATE 

TEHP. 

ODUCT: 

NAME 

RATE 

PRESSURE 

TEHP. 

PLANT 

VESSEL 

SERVICE 

DEA: 

RATE 

TEHP. 

PRODUCT: 

NAHE 

RATE 

SULFUR 

RECOVERY 

UNIT 

V-2570 

SULFUR SULFUR 

RECOVERY RECOVERY 

UNIT 

DA-2B2 

UNIT 

V-2572 

SULFUR 

RECOVERY 

UNIT 

DA-2BJ 

DEA FLASH STRIPPER DEA FLASH STRIPPER 

25gpa 

U O F 

DEA 

375gp« 

PRESSURE fcOpsicj 

TEHP. 110 F 

Ogpi 

110 F 

DEA 

•lOOgpa 

25psig 

190 F 

25gpi 

110 F 

DEA 

375gpi 

tOpsig 

U O F 

Ogpi 

U O F 

DEA 

400gpi 

25psig 

190 F 

STEAH -

METHANE 

REFORMER 

2522 

ABSORBER 

70gpi 

110 F 

TABL E 1 

WI1WINGTC N h*IM*lFACIlJRING COMPLE X 

DHT-3 

HP-275 

COKER COKER COKER 

22J4 CK:8 2257 

CCU CCU 

1223/1225 HS-2 

CCU 

2415 

HYDRO 

SHU-4 

ABSORBER ABSORBER ABSORBER DEA FLASH ABSORBER ABSORBER DEA FLASH ABSORBER 

150gpi 

110 F 

SMR FEED RECYCL H2 

20HH SCFD 

90 psig 

70 F 

60gpi 160gpa 15gpa 

-

C3/C4 DRY 6AS DEA 

100MN SCFD 2500B/D 18MH SCFD 220gp« 

900psig 

135 F 

240psig 140 PS16 5 PS16 

BO F 70 F 110 F 

40gpi 130gpi 

C3/C4 DRY GAS 

5HB/D 11MH SCFD 

200psit) 140 PSI6 

BO F 80 F 

15gpi 

DEA 

170gpi 

60 PSIG 

U O F 

35gpi 

. i 

HYDRO 

6HU 

ABSORBER 

35gpi 

HYDRO HYDRO 

PT-3 PT-4 

ABSORBER ABSORBER 

80gpi 30gpi 

GASOLINE RECYCL H2 RECYCL H2 RECYCL H2 

IOMB/D 

100 PSI6 

150 F 

srn SCFD 

600 PSIG 

90 F 

BHH SCFD lOriH SCFD 

700 PS16 600 PSIG 

100 F 100 F 

HYDf)0 

PT-6 

FLASHER 

ISgpr 

DEA 

180gpa 

90 PS1B 

90 F 

• i t '• 'i- -
P.78 

8s.» 

sr.. 

rv. 

9—' 

*? h 

n 

.•• •? 3 

3* **« 

— ! »— i 

v -J 

1O1 

i - ! 

-*rs 

tr f * 

•n 

•*• 

X 

* 

c -1 

5* 

JC 

H 

i 

-o 

r 

-o 3 

0 

m 

JO 

m 

> 

r 

0) 

H 

m 

2 
V 

Shell Oil Company 

One Shell Plaza 

P.O. Box 4320 

Houston, Texas 77210 

DoJcJr I 

April 9, 1985 

Mr. Jack R. Farmer, Director 

Emission Standards and Engineering Division 

Office of Air Quality Planning and Standards 

United States Environmental Protection Agency 

Research Triangle Park, North Carolina 27711 

Dear Mr. Farmer: 

As requested in your letter of January 25, 1985, the attached information 

on process equipment and associated emission control equipment subject to 

the petroleum refinery fuel gas provisions of 40 CFR 60 Subpart J is 

forwarded for Shell Oil's Norco, LA, Wilmington, CA and Martinez, CA 

refineries. Please note that only cost and supplementary process information are provided for Norco refinery since the balance of the data were 

obtained during an EPA field trip to that facility. 

Our Wilmington refinery has identified three problem areas encountered in 

complying with the NSPS. These are the dual reporting of information to 

EPA and to the state agency; the short pre start-up notification of 30 to 

60 days, and possible difficulties in meeting the performance test deadline of start-up plus 180 days. (See Section X-I, pa^e 14 of Wilmington's response) 

We believe the attached data responds to all of the information requested 

in EPA's questionnaire. However, if clarification is required please 

feel free to contact me at (713) 241-1889. 

Very truly yours, r 

J//A. Mullins, Manager 

Environmental Programs 

Environmental Affairs 

JAE/blv 

Attachment 

CAS509901 
D 

SHELL OIL COMPANY 

NORCO MANUFACTURING COMPLEX 

RESPONSE TO EPA QUESTIONNAIRE 

NSPS - PETROLEUM REFINERIES -

FUEL GAS COMBUSTION DEVICES 

CR8509906 
P.81 

TABLE 1 

RESPONSE TO REFINERY FUEL GAS NSPS QUESTIONNAIRE 

(Section V,.Questions 1-9) 

V. PRIMARY CONTROL (Amine Treaters) 

1. Characteristics/Composition of Fuel Gas 

2. 

3. 

a. 

b. 

c. 

d. 

Ami 

a. 

b. 

c. 

d. 

e. 

f. 

gFlow rate 

Heating value 

Temperature and pressure 

Composition 

(1) H2S 

(2) Sulfur compounds 

(3) C02 

ne Treater Description 

General schematic 

Manufacturer/vendor 

Start-up date 

Design capacity and range 

Hours of operation, Hr/Yr 

Number of vessels 

Amine inventory 

13-27MM SCFD 

900-1400 BTU/SCF 

60-100°F, 70-100 PSIG 

7%w 

l%w 

Unknown 

See attachment 1 

Standard tool 

1980 

20MM SCFD, 10-28 SCFD 

8760 

1 absorber, 1 stripper 

(1) Total inventory 

(

f2) Amine circulation rate 

h. Absorber design/operating 

condition 

i. Stripper design/operating 

condition 

j. Type of Amine 

k. Other important design/ 

operating criteria 

Type of system, if NSPS had not 

been in effect 

4. Maintenance History 

1200 gallons 

300, gpm (1983), 200 gpm (1984) 

See attachment 2 

See attachment 3 

DEA (Diethanolamine) 

None 

None 

a. 

b. 

c. 

d. 

e. 

Degradation/Loss 

Foaming 

Amine contamination 

Vessel/Piping Corrosion 

Excessive emission 

(1) 3Q 1983 

(2) 4Q 1983 

(3) 1Q 1984 

(4) 2Q 1984 

10 inventories (1983), 

4.5 inventories (1984) 

None 

Hydrocarbon* 

None 

97.3% Compliance rate 

90.2% Compliance rate 

94.8% Compliance rate 

93.8% Compliance rate 

*Knock-out Pot was installed to minimize entrained hydrocarbon. 

is routed to slop oil system. 

BLAS8508102 

Liquid 
P.82 

5. 

6. 

7. 

8. 

.9. 

Amine replacement/maintenance 

above vendor specification 

Annual Amine treatment reliability 

Inspection schedules/practices 

a. 

b. 

Schedule 

Personnel 

Monitoring required to assess 

performance of Amine treatment 

system 

Amine treater operating parameter 

used by operators to maintain 

specified H?S concentration in 

amine treater outlet gas 

None 

99+% stream factor 

2-2$ years T/A cycle 

Shell inspectors 

H^S concentration in amine 

treater outlet gas 

DEA flow 

BLAS8508102 
ATTACHMENT III 

V 

\ 

Date 

7-15-83 

See note 1. 

7-19-83 

See note 2. 

7-20-83 

7-20-f83 

9-20-83 

Source 

Ho. 

422 

420 

421 

417 

418 

423 

419 

Boiler 

Ho. 

2-4 

2-5 

2-6 

2-2 

2-3 

2-1 

2-8 

TABLE I 

PHILLIPS PETROLEUM COMPANY 

BORCSR REFINERY 

NOg TEST OH SEVEN STEAM BOILERS 

Sise 

»/hr 

390,000 

100,000 

100,000 

100,000 

100,000 

150,000 

100,000 

Load HO NO2. 02 

f/hr ppav ppav X 

244,253 139.2 4.8 3.4 

69,637 103.6 2.6 3.8 

107,860 64.5 15.6 4.5 

123,062 160.7 7.3 2.6 

84,700 128 6.6 3.0 

*Average of eight, fifteen minute staples. 

Note 1. Result* froa Boiler 2-6 were less then 70Z of Perait Liait. 

Note 2. Results froa Boiler 2-3 were lees then 70Z of Perait Liait. 

Eaission Rate* 

#N0z/MMBT0 

0.119 

0.089 

0.077 

0.133 

0.110 

Perait Liait 

#HOx/MMBT0 

0.14 

0.14 

0.14 

0.14 

0.14 

0.14 

0.14 

'V 

•A 

. > 

8. 

• V'; " 

« 

•H 

r-tfr 

1 

HOPidsg/022 

- 7 -
P.84 

•wuecMtAnatifWa a 

I. *•»•••!••• mt » iifrnurt 

•Mrinmung von H J in laf) mt m MM* * I 

Zur Hondbobuag imGmwiWm mt tm I 

4. OlOMT C4OrQV0tW'**lV~RjWfHJ M M \fOOJTOWti*MOH 

bit n r vella* 

Onmminulion ot H 4 la air mt tn Nitiiiuil M m 

far urn or) tap O n Barnaul mar) taa MA<& » Tubal, 

Oparaling laalnmioat) aad tnitractiam tor Ur» 041 a. 

3. 

S M iflullialian. 

Opininting timl a {duration of om puma 

: III 

ttroaa anfil mt limit drain It caaplaMn) 

1 und i ommmottmt Spinoff 

3 JduaJMlMia 

4 Anzaigaidlidit (wars) rail Skolrja; 

ZoMWmrta . ppaV Hi 

5 Hail (tail bol dar Mla a «»r 

Pumpa waiun) 

«>Md tip. 

writing turfaca 

r

trial mm 

valval a 

arraw (matt point lowardt i 

PPmH £ 

a. MiMi r e ikai »°C nn••*>, 

•ai I Hub: 10 bit m ppm Hfi. 

•ai 10 HObaat 1 bit 20 ppai »£». 

J jffaJJlVJ'ty'S-) -*°C """*-

4.1. Pumpa vor jadar MatVaJha tail ungaoffnattm Uhnhan Qui Die»rti.il prijlu. 

IX Spinas O M OUGEt-Uhrdujat abbradiaa. 

4J. OKAGEK-tthrdKHi didii in dan Pumpantopf timattan (Hail aattt a » 

4.4. PrWgat noddul n t 1 Hob dunk dm DIXGEt-Mkniiaa tauoorv liagt 

HS vor, to varfdrbt tidl dia aarSa Antaiaairtiidrt hallbraua. Unga dar 

Varforbang • Mot lir dia M**>onnm>tion. Airl dar IHvb-Skolo Kontaatrolian in ppm ablatio. Uaot dar Wart Soar 20 ppm. ta ttt dia Fruhmg 

baaadat. Waraan aanigar alt 20 ppm apgalwan, to in dia Prolong mil v 

araiMran (olio inigatoml 10 HGban lorawatua. H^-KonnMratiM in ppm 

iatd out dar 10-Hub-Skola oblawri. 

Nodi nagotivam Prfltbotund kena dot DMGEI-tMrdian HA Mt am talban 

Tag bit zu zahnmal banutzt wordon: nodi poiitivom Bafund nroHt mabr varwandbor. Varfdrbungon tind tonga Zait hullbor, arjnn Spilxan mit Gummikap. 

tab. a * . •!••••' 

DiaOtAGEt-Mlvdian Unarm in ainam Timpmlutbaraid. ¥Oa 0 bit 40° C 

»

,

aafcwanoat tifjatfoan. 

12. Ftaditigkail 

Im laraidi von 3 bit 30 mg H,0 pra Utar hat dia Nadltigkatt kainan Ein. 

ftu* out dia Aiuaiga. 

• J. Umuruc* 

Zur KonMRur oat OmckaMlimai tit dta Anaiga (nn dma Ugandan Piktor nt mulltplt1013 

i 

j 

TS 

Korraklurfaktor -

Konakturttfctor -

i O . 

tatUcnucMr I idtdrwt (in naar) 

(inTorr) 

apIT ITliiill) 

Anxaiga baruM out Forbraafclion mit ataivarbindungi at anltttht hallbrounat 

•labutlid. 

In Qtgtiwri arMnrar SO,KonxantnitiaaM MUi dia H,S-Aiuaiga 

bad! out (s. I . Gamut* voa 3 ppm M J md 40 ppm SO, argibt Ai 

atwo I ppm Hfi), SO, allain varMtbt dia Aiuaigaamidit nil'-

Andara Gota und Ddrnpla baainflustan dia H^Amaiaa nic 

dil. 

nidtt. 

Varbrouditdotum und luuwlampaiulur vgl. Angoban out dar londaroto. 

Ja kSMar diti DUGaSmim* galagt' 

nutoian Eignstoiofttia ariwItM. 

Ilalad l ArtaitipamtonMiviniluntMAIC): lOppm(Biii<dlapiiolt>Ow>l»elilid taW. 

f

lla n Tabatta 4»a» aMMM ilplnHilliai guraait dia mil DUOtt-tUkrdian 

maftbaran Oaat aad Dtrnpta, widtfiga ,li|iHaaiS i aad n Itlliglid i DaNa 

{aa r Oata aad Oampta totma lila»alui*iaaain. 

litta, lordara tta diata Toballa bai uat aa. 

I VmaiaaUm OUCU-iahrdma aa*l aaVUt brtamttaa, domrt tia aidtt in Klaidtrtl 

VaratdiMaj voa DMO H 

i OWJ«3t*»Vgar*. . 

"e la r VaratdiMaj voa PtWOfl Mrndiaa •* . aadt a Mg a dar .Mimilungan 

3. laaga at 

(20"C, 1013 n*ar. cortatpoading to 20« t It M maart 

With 1 ttrokai 10 lo M0 ppm H J 

Willi 10 iliuati. 1 to » ppm H,f 

4. Tatt aaej batMllcai mi ffka aowli 

4.1. lafora aodi %tm of maowraiwantt, tatt Mia pwnp for tiQhtfia-a «-w-»« oa 

4.2. Iraafc«ff th* tips of tha OIAOER Tuba. 

40. lAMrt the 0RACEI twfaa HaMty ia H * pun** aaod (orrow point* kremrxh 

4.4. First tud tha oir sorepla throogh ttw lute with 1 pump firoka. IC HS i% 

prosaatp lha whita indkatiiig kiyar tumt pat* brawn. Tha laaath of tha 

o^BcotoroHon it o mmo$w ol lha Hfi comwiiTotioo. Raad-oH tha cancafitrotion ia ppm on tha 1-stroka wot*. If tha volua it abowa 20 ppm. lha 

tact it cempMad. If it is lata than 20 ppm. tha last -uhottid bo continuad 

with 9 furthar fo total of 10) ttrokai. Now raod-off lha H,S coneantrotion 

<n ppm on tha 10-streka scola. 

1 

Attar o napotiva last rasult, tha H,S 1/e Tuba out ba utmd up to tan >\mm oa 

tha torn* day. The tuba cannot ba wad opoin after a positiva r+tvtt. OtKOlorotions con ba kapt for a long tima if tha tips are saolaa with rubbar cops. 

4. trnMrnrnmu *4 Awalin -taodliiaai m *m Uwmtt mt • wi i 

6.I.Tamp8iuitfi 

ThaOiwC 

4.2. Humidity 

6J.Tampliulur» 

Tha DRAGEft Tobas con bo usad in o tamparotura roitoo of from 0 to 40° C 

dkotion. 

3 and X mg H,0 par litra, homidity has no itiffoanca on tha i 

6 J. Atmospharic prasiura 

*or p*aaaura corractton, muRlpty tha tuba faadtng by tha IWlowing factor 

Convora*ton (actor • 

Comoraion tsctor • 

{In moan 

prassura (in Torr) 

7. lasiin-Jty (Cr»JB«->aaiiilt>.ry) 

Indication it bosad on a cofour rtoction with a laod compound — pola brown 

faod swlphida it producad. 

In tha prasanca of foirly high SO, concontroriont, lha indication it tomawhot 

too high (a. g. o miatura of 5 ppm H,S and 40 ppm SO, givas on indicotton of 

about I ppm H,S); SO, OIWM doas not chonga ma colour of lha indicating 

leyar. 

Ofhar floitt ond vopoun da no* bffact ma H,S indication. 

So» axpirotton dota ond storogo tamparotura oa total of tha box. Tha lowar 

lha tantparetura at which tha OKXCE R Tubas ora itorad, tha imallar tha chonga 

in lhair chamicol propartias. 

f. Tamicttr Oa«s 

nmhom unto volua: 10 ppm (USA 1940). 

Our taa*t tM a contains in •l»habiMeol ordar tha f^aaa mmd tap sirs maoj-pfoWa with OIAOEK Tutea, iopnilast phpsliaf aad loKltilaglaiTda-aj of lha 

goaas and vopotrrs as wall m Mo y raftvonoM to litorohjra. 

This tobla will ba sont to you on ragwast. 

Oo aot allow OtAO M Tubas to M l into lha hands of Aikkan. 

Con ian ti ora toffiiuval 

Par dMtrovin, OWOf t Tufeaa, ratar la Inajrmatim, tbaal No. a 

OIXOItWfl K • AO • 1USICK • OltMAN Y Prinma ,. m. Ndni t^Aii. <d o—o-y 
P.85 

.. A..:*-'.-r froiTi^iivnMm--^^ 

1-OftlrtAJOftUPOT^ 

*-**" *--—>»•'»>> thpai (HailwleTSlwtt»oetyV 

Tmm.»— %h1111as Patrolaua Coapany ^ -

BoVger Refinery e H6L Procass Center 

-tra^e--, , P-0> Box 271 ^ Borgtr ^ Taxas „ 79008-0271 

Owear, Opantor oa 

TaatelWaJtt NUADSf 

9mfeuM,Mumtmwt f i e • W"4»—fff •«••) **>•»•— • w 

(806) 273-2831. extension 8-287-1201 

fetm of *Jeit or focsa Attach 

Sulfur Recovery Unit 43 and A-lna/Sour Water Unit 44 

iDtlnifforShauioaratseStsn-ap October 2, 1984 (2:00PM - 4:15PM) 

TawaedEayctrtDwifltjeef F>LWI I EmiatogB October 2 (2:05PM - 4:20PM) 

Q MaerUpat fT ] 

The Sulfur Recovery Unit 43 shutdown at 2:00PM due to low add gas flow. The 

shutdown occurred when the AiMne/Sour Water Unit 44 became upset. The Claus Section of 

Unit 43 was started up at 3:00PM and the SCOT Tall Gas Section was started up at 4:15PM. 

leva! of Emtaton* (pv* bus for aatimaia): Phyaeal ind Chamkal CompotritJoo, Rats. Conctntfilion, and Duration 

anH fmm th* Tall Ga« Incinerator for 2 hours 15 minutes at 

1000 ppm. 

-

•WMMifts (to tx) Tiktn to ItlKtnto Ojtnuty and Dun 

Steos were immediately taken to stabilize unit operations. 

auicklv as safety would permit. 

Malawi (lo ba) Takae to ftenat tUcurraoca (If not oatannfatd yat, gfrc data whan a 

Plant personnel reviewed operational procedures. 

a concentration 1n excess of 

The unit was started up as 

eatuias wiQ ba nibmittad) 

IVa.iVw.aadMcamoftiotiflcatkM 

E«acou»gObactor Mr. David HenHchs, Austin, Texas — by copy of this report 

tetjosdOflks Mr. Ken Bowers, Lubbock, Texas by telephone October 4, 1934 

•dual fti.|HMi 

n^. October 10, 1984 

*•*•» • Stoned . . 

« j S. > . Fink (RC) S6-5(9) " J JU136M U. Lewi 4, Hinadei1 

_J_IL____ 
P.86 

ATTACHMENT VI 

• 1 

UFS: S6-5(9) 

PHILLIPS PETROLEUM COMPANY 

BQRGER REFINEY & NGL PROCESS CENTER 

POST OFFICE BOX 271 

BORGER, TEXAS 79008-0271 

January 11, 1985 

Mr. Bill Stewart, P.E. 

Executive Director 

Texas Air Control Board 

6330 Highway 290 East 

Austin, Texas 78723 

PSD-TX-102M3 and TACB Permit C-7553 

Sulfur Recovery Unit 43 

Excessive Emissions Report 

Fourth Quarter 1984 

Dear Sir: 

Special Provision 2. of the above-mentioned permits states that the 

permitted facilities must comply with all the requirements of 40 CFR 60, 

Subparts A and J (Standards of Performance for New Stationary Sources). 

In accordance with Subpart A, Section 60.7(c), attached is the Fourth 

Quarter 1984 Excessive Emissions Report for the Sulfur Recovery Unit 43. 

The values stated have not been corrected to zero percent oxygen due to 

operational problems with the oxygen continuous emission monitor. The 

instrument is being repaired and will be placed in service at the 

earliest opportunity. If there are any questions or additional 

information is needed, please contact H. J. Strick (extension 1568) 

collect at 806/273-2831. 

Very truly yours. 

i J John 0. Lewis 

J0L:GEF:gj 

Attachment 

cc: Gerald Hudson, TACB, Lubbock 

R. W. Johnson 

B. F. Ballard 

6. E. Fink (RC) $6-5(9) 

Reading File 
F

# : •freyg 

Borger Re-fi 

ur Di 

nsry 

Sulfur Rett* 

liv t Emission* Report 'frourl 

a *' _i« 

*-£ !'t## t*#>r 

Excessive Sulfur Dioxide Emissions 

(Corrected to ' %t dry conditions ) 

Magnitude 

Date/Time (Hourly Avg.>, 

Explanation 

aw 

Major Upset 

Scheduled Maintenance 

Oct. 2 <2I03PM-4I20PM> 1000+ppm 

(2hrs ISmins) 

MUt Unit 43 shutdown due to low 

acid gas -flow, which resulted 

1 when Unit 44 became upset. 

Operational procedures were reviewed. Refer to TACB report 

submitted October IO, 1984. 

Oct. IS <7i30AM>-

Oct. 19 (4.00PM) 

Oct. 31 QOiSOPM)-

Nov. 2 <1:30PM) 

Nov. 3 <10i00AM-12:30PM) 

72S ppm 

(41hrs SSmins) 

1000+ppm 

(103hrs 45mins) 

SMt Unit 42 was shutdown to 

replace catalyst irv guard 

reactors. Consequently, Unit 

43 also shutdown for maintenance. Both units started up 

however Unit 43 shutdown again 

when shutdown system was inadvertently tripped. Preventative 

maintenance work was performed 

during the shutdown. Re-fer to 

TACB report submitted Nov. 12, 

1984. 

Nov. 2 HUB computer failure, no data 

printed out. Emissions occurred 

as indicated above. 

Nov. 3 (12:30PM)-

Nov. 5 (11:10AM) 

CEM data incorrsctj S02 CEM 

shutdown to replace stack probe 

ceramic filter. No excessive 

emissions occurred (150ppm). 

Nov. 9 HUB computer failure, no data 

printed out. No excessive 

emissions occurred. 

Nov. 18 HUB computer failure, no data 

printed out. No excessive 

emissions occurred. 
P.88 

:

.&3j^g3a«jr*5^ 

Borgar Refinery and NGfc. Process (Utotrnt*'';;;;•: 

Sul-fur Racovary Uni t 43 

Excassiva Emissions Raport Fourth Quartar 1964 

-I 

Excessive Sul-fur Dioxide Emissions 

(Corrected to *8< dry conditions) 

Magnitude 

Date/Tiaa v (Hourly Avg.) 

Explanation 

MU - Major Upset 

SM » Scheduled Maintenanci 

Nov. 21 - Nov. 24 HUB computer failure, no data 

printed out. Working with computer personnel to attempt to 

locate cause of problem. No excessive emissions occurred. 

Nov. 29 (9:35AM-11.50PM) 602 ppm 

(40mins) 

1000+ppm 

(13hrs 35mins) 

MUi Unit 43 SCOT Section shutdown due to high temperature in 

the tail gas reactor, caused by 

excessive combustion air in the 

in-line burner mixer. Operational procedures were reviewed. Refer to TACB report submitted Dec. 4, 1984. 

Nov. 30 - Dec. 1 HUB computer failure, no data 

printed out. Continued attempts to, locate problem. No 

excessive emissions occurred, 

except as indicated below. 

Dec. 1 (9:00AM)-

Dec. 9 <1.00AM) 

572 ppm 

(104hrs 40mins) 

1000+ppm 

(SOhrs 35mins) 

SM: Unit 42 was shutdown to 

perform maintenance work on the 

main fractionator. Consequently 

Unit 43 also shutdown. During 

Unit 43 startup procedures a 

hotspot developed on.the combustion so the unit was shutdown for repairs. Monitoring 

Unit 42 main fractionator ope.— 

ation to determine source of 

problem. Refer to TACB report 

submitted Dec. 12, 1984. 

Dec. 10.(7:45AM-1:40PM) 359 ppm 

(5hrs lOmins) 

1000+ppm 

(45mins) 

SM: Unit 43 was shutdown to 

repair a broken sight glass 

on the combustion furnace. 

Refer to TACB report submitted 

Dec. 13, 19S4. 
P.89 

m; :-i^"-

*5? 

Borger Refinery and N6L Process Canter 

Sulfur Recovery Unit 43 

Excessive Emissions Report Fourth Quarter 1984 

! 

Excessive Sulfur Dioxide Emissions 

(Corrected to * It dry conditions) 

Magnitude 

Date/Time (Hourly Avg.) 

Explanation 

MU - Major Upset 

SM • Scheduled Maintenanci 

Dec. 11 Determined and corrected problem with HUB computer which was 

causing CEM data to be lost. No 

further problems expected. 

Dec. 13 (8:00PM)-

Dec. 14 (12:30AM) 

1000+ppm 

(4hrs 30mins) 

MU: Unit 43 shutdown due to low 

air flow to the combustion 

furnace. The low air flow resulted when the instrument air 

line broke off the combustion 

air controller. The instrument 

air line was repaired. Refer to 

TACB report submitted Dec. 18, 

1984. 

Dec. 14 (12:35PM-2:00PM> 294 ppm 

(35mins) 

1000+ 

(50mins) 

MU: Unit 43 shutdown due to low 

acid gas flow. However the condition di*d not exist and so the 

cause was determined to be an 

instrument malfunction. The instrument was repaired. Refer to 

TACB report submitted Dec. 18, 

1984. 

Dec. 14 (7:35PM>-

Dec. 15 (4:00AM) 

557 ppm 

(4hrs 40mins) 

1000+ppm 

(3hrs 45mins) 

Excessive sulfur dioxide emissions due to instrument problems. Unit remained on line; 

the instrument was repaired. 

Dec. 18 (7:00AM-7:00PM) 268 ppm 

(12hrs) 

Sulfur dioxide emissions in excess of 250ppm averaged over a 

12 hour period (NSPS Subpart J, 

Section 60.105(e)(3)(ii). 
P.90 

~|>^**~"(,<i ' ajH|H[jS)ia y (•• -• J*--^'- ""•*»?-%»'• am* a*.'., •- "', ^?B|SiJBMS**ij"'-'"~ '"^'^flsHfcoiJaaaSaaaa'^^.j ' -*" -

r

" * • ** '>r^MSHMEtf aaV4'f^j'' HC-43 

Borger Refinery and N8L Process Cantar.. " '"''^^M-^^^''V A^ 

Sulfur Recovery Unit 43 . * *• 

Excessive Emissions Report Fourth Quarter 1984 

t JT

 l 

Excessive Sulfur Dioxide Emissions Explanation "*' 

(Corrected to "& dry conditions) 

Magnitude MU • Major Upset 

Date/Time (Hourly Avg.), SM " Scheduled Maintenance 

Dec. 19 (8:S0AM-11:45AM) 1000+ppm 

(2hrs 55mins) 

SM: The Unit 43 SCOT Section 

was shutdown to allow a startup circulation line to be installed. The new line will 

allow the Claus Section to be 

started up more quickly after 

a shutdown. Tha new line will 

therefore reduce the amount of 

sulfur emission during future 

shutdowns. Refer to TACB report 

submitted Dec. 19, 1984. 

Dec. 20 (9:00AM-9:00PM) 324 ppm 

(12hrs) 

Sulfur dioxide emissions in excess of 250ppm averaged over a 

12 hour period (NSPS Subpart J, 

Section 60.105(e>(3)<ii>. 
ATTACHMENT 2 

P.91 

' I-S330 SHUTDOWN SrSHH IS W ClECTROMIC SYSTEM A.V3 LOOTED 

" ON THE COMPRESSOR FRAHE. THE SHUTDOWN STSTEH IS ACTIMTEO 

IT 0E-ENERSIZ1NS THE SHUTDOWN CIRCUIT. THE SHWt. 

SIGNIFIES THE INTERFACE SETVEEK T * SHUTDOWN 

1 STSTEH M D THE SHUTDOWN INSTRUMENTATION IN THE 

I/MIS H LEVEL! 

.CeVSkr-Q -0 -

I MK5M Lfv a LOW 

PV-199. Fl . 

(LAM-2081) P*t-

! /T V J PV-199. . »*£iJCS 

*—\* 0 ' (LAM-208 - " 

MitwTEva 

,PV-I9S3, 

(LAH-»S4) 

y-—<? 

i 

t-

?,„,>,,/, , »>>!>>> J»>/»//»»/r7T7T77r . 

Tne 

iijl / 

< ^ 7 

I-&UO 

ssr* ^ 

*icu*c HO 1 5 

DU-rwS FEEO HYDROTREATER 

avg<a#y«»£:xiE 

W»r**OC€»l CO»»fttHOBt 
£.-.z. pFA V^'PP^ J-teS^ 

P.92 

VS.": 

1. IMEMA: c-ir:ct P.C. :S:::STM. 

2. :;•.< ELM-ET cr.!E«-."ir. .:\'. :"i:,--:c<. FU'S.-E 

E;.:Er/v*:.'.'". EiiiiiR •:=•.-.. TJ i-»;'.;-.Ji AT I V -I O SV; 

*20 vK.'i;.. 

(52 -:>-.::-" : LI'-ES DEMTE FLOW RJT- 'CR FLUSH:S 

:«t L£= F:;- --•: TSA'.iFt- .:*.r:.is: £-222:. n%> 

p-«3«« A< B 

_ ' U» N DE. 

CIRCULATION PUMPS 
P.93 

ATTACHMENT 3 
* 

z z z 

tfMft <A 

o o o 

moo — t* •* r» p« r« « M M 61 

# 

? *i 

ml 

r 

**n 

0 

r 

• 

CA 

**5 

r 

.1* 

£ *» 

H 

> 

r •> - a 

<T» VA 

t 

*J 

3 IN 

jft> r. i. 

fe 

fc 
P.95 

3 

* »_&*) £ CAarrWl-*! IC AM [lCi*TO>M:|* t.Itri . ...a. 

NOTES: 

1 . 1-5329 AND I-S330 RECYCLE MYCROMN 

CUINDCRS CO IE ICAX ; IN STEPS OF 

ot. a>v AND ::« . 

2. 1-5329 ANO 1-1330 MFC'.. HYDROGEN 

CTLISOERS CAN EE LOADED -.1 STEPS l ' 

oi. 2St. sos. is: AND IMI . 

3. REFER TO FI&JPES 30 AND 44 FOR 

OETAILS OF Tff CCW-RESSOS PACKING 

VENT AND OISTA.SCE..PJECE VtNT PIPING. 

« . OPERATING CO>:IT;OR S SHMI FOR 

1-5329 AND J-S350 ARE MARINE 

CAPACITY NUftERS, NOT PLANT DESIGN. 

£0T*_^T£a._ONUR £**«.--#-, _ 

432. SHUT0O.1 IS AN ELECTRONIC SYSTEliI AND LOUIEO » S 

COtWESSOR FRAK. THE SHUTOCVt SYSTEM IS ACTIVATEO IT 

0£.£NE.S:iZI*G T«£ SHUTDOWN CIRCUIT. THE STieOL 

SIGNIFIES THE IkTEOFACE DETWIEN THE SMUTOOUN 

STSTEH ANO THE SrrjTDOtfN INSTPUMENTATlOlf IN THE 

S/S///SS /)>>>>>>>,>,>,, Illli If 

T ' 

I 

I 

I 

"T 

I 

t _ 

I r-0-^ 

• I uC U ICufl ifta.ii M 

_^ I HI6H LEVEL LOW CUBE OIL 

MrGMlEVB. 

PVH9SJ-

(LAH-rOSr3 

>>»»}»»///>/;//////»»/»;;/>>>y,V 

«EFI"**»T oOOPSfSH-j 

, HIGH PRESSURE VEMT 

fc TO^PUir-

'^LSMMSCfO'LlMLBrlTM 

lifW r lAAAfl A * 

IOJ«Lft/Mfi