P.1 

OAR Box 1784 

Prepped by Ollie Stewart 

Document Number: 

55) ll-D-7 

Docket Number: 

A--84-44 

Printed 10/31/2008 8:05:40 AM Sheet 55 of 143 
P.2 

LA GLORIA © 

Oil and Gas Company P. O. BOX 84O, TYLER, TEXAS 75710 

A TEXAS EASTERN COMPANY 

April 9, 1985 

J-i2 

Jr 'is/i 3-

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, we have completed and are returning the questionnaire 

regarding our refinery fuel gas and its H2S content monitoring and removal systems. All of the information requested in your Enclosure I 

is included except for the following sections: 

V. Primary Control(Amine Treaters) 

VI. Secondary Control(Sulfur Plants, etc.) 

VIII.4. Monitoring of Process Parameters. 

Information answering the questions in these sections will be forwarded 

at a later date. 

Please contact Philip Fox of La Gloria at (214) 595-4511 if further information is required. 

Yours truly, 

PFF:ab 

Attachments 

pc: L. B. Gatewood 

C. 0. Pett y 

D. H. France 

P. F. Fox 

,0&xftt ^r*TM*<F*e 

Alvie R. Livermore, P.E. 

Manager of Engineering 
P.3 

INFORMATION NEEDS FOR REVIEWING THE REFINERY FUEL GAS NSPS 

ITEM I: 

Introduction 

No answers are required 

ITEM II: 

Facility Description 

Figure I is a schematic of the refinery's fuel gas system. Sour gas 

from the FCC Unit, #2 coker, saturate gas plant and the //l HDS unit 

is treated at the DEA plant. The acid gas stream from the DEA unit 

and the sour water stripper off-gas make up the charge to the sulfur 

recovery unit (SRU). Sweet purchased natural gas and the separator 

gases from the #1 platformer, the #2 platformer, and the rheniformer 

are blended with the sweetened refinery gas from the DEA unit upstream in two parallel fuel gas mixing drums. There is a static 

inline mixer downstream of these two drums after the outlet lines 

combine. This fuel gas blend is used plant wide in the steam 

boilers, in the process unit heaters, at the SRU incinerator and at 

the refinery's flares. The monitor for the fuel gas H2S content is 

located downstream of the inline static mixer. Emission monitoring 

samples are taken from the sample draw line used for the continuous 

H2S monitor. 

ITEM III: 

Costs 

1. The total costs for materials and installation of the sulfur 

recovery unit and the DEA unit was $5,310,000. This cost was 

incurred during 1979 and 1980. The SRU and DEA units were constructed specifically for the purpose of meeting the NSPS for 

new combustion sources. The DEA unit is currently dedicated to 

refinery gas service only. 

2. Purchase Costs 

a. The purchased cost of the Sulfur Recovery and of the DEA unit 

together was about $2,046,000. The cost for the DEA unit 

alone is not available. 

1. Breakdown by major equipment: Not available 

2. Cost of initial chemical inventory: $4,000 for 20 drums 

of DEA @ $200 per drum. 

3. Installation Cost 

a. The installation cost for the SRU and DEA unit was about 

$3,262,000. The cost for the DEA unit alone is not readily 

available. 

- 1 -
P.4 

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1. Breakdown by direct and indirect costs: Not available 

2. Note specific costs attributable to retrofitting a new or 

expanded anine treater into an existing system: Not 

applicable. 

4. Annual Operating Costs 

a. (SRU and DEA Unit together: 1983) 

1. 9152 manhours/year @ $17.48/hour (estimated overhead 

included) 

2. Materials 

a. Replacement parts: $3500/year (est) 

b. 1100 gallons @$3.64/gallong for DEA 

3. Annual Steam: Nonerequired continuously 

4. Electricity: $35,576/year 

5. Water: Not available 

6. Fuel Gas: $32,450/year 

7. Sulfur recovered credits $116,917 (1983) 

5. Key Accounting Factors 

a. Lifetime of equipment: 16 years (est) 

b. Equipment amortization and depreciation rate straightline 

depreciation (16 year term) 

c. Labor and management charges (Not available) 

d. Overhead rate (50% used for labor) 

ITEM IV: 

Refinery Combustion Devices 

1. //of combustion sources at the refinery: 27 

2. General information about specific types of combustion sources: 

Size Costs Hours Other 

from TACB Capitol of Fuels 

Permits & Operating Operation Used 

#4 Crude Heater 8566 MCFD Not Readily Continuous None other 

(Process Heater) Fuel Gas Available Currently 

Blend 

Boiler #8 3744 MCFD 

Fuel Gas 

Blend 

Not Readily 

Available 

Continuous None other 

Currently 

#5 Flare 4.75 MCFD 

Fuel Gas 

Blend 

Not Readily 

Available 

Continuous None Other 

Currently 

- 2 -
P.6 

3. Units Affected by Combustion 

Device NSPS 

#4 Crude Heater 

Vacuum Unit Heater 

#2 Coker Heater 

It2 EDS Heater 

#2 Platformer Heater 

#9 Boiler Heater 

Flare #2 

Flare #3 

SRU Tail Gas Incinerator 

Compliance Methods 

New Amine Treater Added 

4. Level of ^ S and other sulfur compounds in the flue gas which would 

be acceptable before significant adverse corrosion of combustion 

equipment would occur: 2000 ppmiH2S 

5. Other state, federal and local environmental regulations applying 

to our combustion sources: The Texas Air Control Board Permit 

conditions limit our emissions from the sources listed in #2 to 

the equivalent of that occurring: when burning fuel oil with 0.7% 

sulfur by weight. 

ITEM V: 

Primary Control (Amine Treaters) 

Information to be forwarded at a later date. 

ITEM VI: 

Secondary Control (Sulfur Plant) 

Information to be forwarded at a later date) 

ITEM VII: 

Emission Testing 

(Provide a copy of all emissions tests performed on fuel gas from your 

amine treaters) The copy supplied is for a test conducted downstream 

of our inline static mixer. It doesn't include just gas off the amine 

treaters. Gas from other process units and natural gas are included 

in the blend monitored at this point. 

1. a. cost of emission test: Not available 

b. Testing conducted by a consultant 

c. The gas stream was only tested for H2S content 

d. The test site was downstream of the parallel fuel gas mixing 

drums and after the inline static mixer. The composition of 

the blended fuel gas is estimated to have been: 

Amine treated fuel gas 31.8% 

Non treated process unit off gas 55.7% 

Sweet Natural gas 12.5% 

) 

) November, 1983 

) 

- 3 -
P.7 

2. Other combustion source emission test: No other emission tests 

have been conducted other than an opacity test on our waste heat 

boiler 119. 

3. Are there any state or local regulations requiring testing of fuel 

gas of existing sources or which require testing of new sources 

beyond the requirements of the NSPS: No 

ITEM VIII: 

Monitoring of Emissions and Process Operations 

1. Discussion: No answer required. 

2. Are there any state or local regulations requiring monitoring? 

No monitoring other than that required by the NSPS regulations 

is required. Our State of Texas operating permit references the 

EPA's NSPS. 

3. a. Description of the H2S monitoring system: The H2S concentration of our fuel gas is measured in one location only with 

a continuous instrument. The sample for this instrument is 

obtained through a sample line from a point downstream of the 

fuel gas mixing drums and downstream of the inline static 

mixer. The primary reason for monitoring this stream is to 

demonstrate compliance with the NSPS. 

b. Manual sampling procedures: Manual sampling of the refinery 

fuel gas is done periodically to provide a check for the 

continuous emission monitor described in the previous paragraph. The results are not necessarily written down and are 

conducted as a ball park check of the CEM's calibration. 

c. Instrument emission monitor information: 

1. Vendor: Houston Atlas, Inc. 

Model No: 722R -

Date Installed: 1980 

Cost to purchase and install: Not readily available. 

2. Maintenance history: Frequent problems were experienced 

during the first few years of operation of this instrument. 

Repairs made about one year ago have made this instrument's 

reliability record improve significantly. A calibration 

is normally required about twice per year. Our in-house 

instrument technician spends about 8-10 hours per calibration or about 16 to 20 hours per year. In addition, 

an overhaul costing between $1000 and $2000 can be expected 

to be necessary about once per year. This is normally 

performed by the manufacturer. 

- 4 -
P.8 

3. Comparison data for the CEMS versus manual monitoring: 

The Draegar tube method is routinely used as a double 

check of the CEMS's calibration. Only one set of data 

could be readily located documenting the comparison at 

hand. On November 12, 1984, two Draegar tests indicated 

70 ppm & 60 ppm and the CEMS was indicating 68 ppm. The 

Draegar tube's accuracy is ± 10%, therefore the CEMS's 

calibration was satisfactory based upon the Draegar test's 

known accuracy range. 

4. Data recording/reduction: The data from the fuel gas H2S 

concentration CEMS is recorded continuously on a strip 

chart. The raw data from this tape is reduced and analyzed 

manually. Approximately eight hours per quarter is required to manually reduce the data from this CEMS and our 

opacity monitor. All data from this recorder has been 

retained since it was installed. 

5. A copy of our quarterly report of excess emissions for the 

fourth quarter of 1984 is attached. 

4. Monitoring of process parameters: 

To be forwarded at a later date. 

5. Replacement plans for the fuel gas H2S CEMS: There are no plans 

to replace the existing CEMS. We are planning to wait until the 

performance specifications for this devise are promulgated before 

a new instrument is purchased. 

6. Is the CEM for the fuel gas H2S content integrated into the process 

as a control system? NO 

ITEM IX: 

General Refinery Information: 

1. 49,500 barrels per stream day (nominal refinery size). 35,000 to 

49,500 BPD (current operating level). Operations at the refinery 

are continuous (24 hrs/day; 7 days/week) Parameters affecting the 

DEA's unit operation: 

a. Crude unit charge rate 

b. Cat cracker operating rate 

c. Crude sulphur content 

d. Operation of the sulfur recovery unit 

2. Crude oil sulphur range: 0.1% - 0.2% 

Crude oil sulphur typical: 0.12% 

Operation of the DEA unit has not been affected significantly to 

date due to crude sulfur content fluctuation. 

- 5 
P.9 

3. With our current refinery setup, the operation of our naphtha 

hydrotreaters does not significantly affect the operation of our 

DEA unit. The installation of additional intermediate or product 

hydrotreating could significantly affect the required size of our 

DEA unit. 

4. Blending of refinery gas with natural gas: Approximately 10 to 

15% of the refinery's fuel gas is typically composed of added 

sweet purchased natural gas. This gas is added in order to maintain a steady flow of gas to the refinery's process heaters. 

ITEM X: 

General Regulatory Information: 

1. Interpretation problems: NSPS: We have experienced very few 

interpretation problemns with the refinery gas determinations 

required by the NSPS. 

Attainment problems: NSPS: The primary attainment problem for 

the Fuel Gas NSPS is the capitol expenditure required. 

Control System operating problems: The three problems we most 

often experience are: 

a. Scanner failures for the flame sensing system in the sulfur 

recovery unit's waste heat boiler. Without the sulfur plant 

operating, the DEA unit is not necessary because no sulfur is 

being removed from the system. 

b. Corrosion in various difficult-to-repair areas throughout the 

sulfur recovery plant and the DEA unit. 

c. Insufficient sulfur production is just as much of a problem 

as too much sulfur production. In our case it is normally 

not possible to operate the SRU and thus the DEA unit if the 

Fluid Catalytic Cracker is not operating due to insufficient 

H2S make from the other sour gas sources. 

2. NSPS performance testing, monitoring & recordkeeping difficulties: 

Testing and monitoring is not normally a major problem since we 

have only one H2S monitor currently. If monitors were required, 

on more than a very few streams, more problems could be anticipated due to preventative maintenance problems. Recordkeeping 

and reporting has been a real time consumer due to the long hours 

required to reduce the data to report format. A reduction or 

streamlining of reporting requirements would certainly help in 

reducing regulatory burden. Monitoring of the H2S content of the 

refinery fuel gas blend is certainly preferrable to the monitoring 

of the SO2 concentration in the various refinery combustion devices' stacks due to preventative maintenance headaches and large 

maintenance and operating costs. The online record of our system 

is certainly comparable to that which would be expected for a 

good SO2 monitoring system. 

6 -
P.10 

3. Recordkeeping and reporting costs and report examples: Actual 

time spent by myself and the person's responsible for the day to 

day monitoring of the CEMS is about $2000 per year. All recordkeeping is done in the logbook for the boiler plant (unit responsible for the operation of the H2S monitor) and of the responsible instrument technicians. ; Because of the use of the log 

books for recordkeeping purposes, no forms are used or are available. A copy of a sample quarterly excess emissions report for 

this monitor is attached. 

ITEM XI: 

Information Contact 

Philip F. Fox (Environmental Engineer) (214) 595-4511. 

PFF:ab 

- 7 -
P.11 

MULLINS ENVIRONMENTAL TESTING CO., INC. 

P.O. Box 598 

Addison. Tx 75001 

(214)980-1843 

TT\ 

] 

] 

FUEL GAS ANALYSIS 

LA GLORIA OIL S GAS COMPANY 

TYLER, TEXAS 

NOVEMBER 1980 

FILE NUMBER 80-65 

MULLINS ENVIRONMENTAL TESTING CO., INC. 

»4Ms^mMUkwmmmxiir^ymLwm m^myfMamamummi^jJMjmmmimm 
P.12 

" • ' l u ' " 

1 

1 

1 

] 

TABLE OF CONTENTS 

INTRODUCTION 

SUMMARY OF RESULTS 

DISCUSSION OF RESULTS 

DESCRIPTION OF SAMPLING LOCATION 

SAMPLING AND ANALYTICAL PROCEDURES 

DESCRIPTION OF TESTS 

APPENDICES 

A. Calibration Data 

B. Field Testing Data 

C. Chain of Custody 

D. Resumes of Test Personnel 

PAGE NO. 

1 

2 

4 

5 

6 

7 

8 

80-65 

MULLINS ENVIRONMENTAL TESTING CO., INC. 
P.13 

FUEL GAS ANALYSIS 

LA GLORIA OIL 5 GAS COMPANY 

TYLER, TEXAS 

FILE NUMBER 80-65 

INTRODUCTION 

Mullins Environmental Testing Co., Inc., Dallas, Texas, conducted 

sampling at La Gloria Oil 6 Gas Company located in Tyler, Texas, 

on November 20, 1980. The purpose of these tests was to determine 

the concentrations of hydrogen sulfide in the fuel gas stream. 

The sampling followed the procedures set forth in Appendix A to the 

Code of Federal Regulations, Title 40, Chapter I, Part 60. 

80-65 -1-

MULLINS ENVIRONMENTAL TESTING CO., INC. 

„ 
P.14 

SUMMARY OF RESULTS 

The principal conclusion is as follows: 

The concentration of hydrogen sulfide in the fuel gas stream was 

equal to 12.5 milligrams per dry standard cubic meter, based on 

the average of three tests consisting of two samples in each test. 

The allowable concentration is 230 milligrams per dry standard cubic 

meter. The concentration of hydrogen sulfide in the fuel gas stream 

was 5.4 percent of the allowable concentration. 

80-65 -2-

MULLINS ENVIRONMENTAL TESTING CO., INC. 

ii_iMU-^«M»awim_,i^^ 
______ 

l ^ ' Vii 

SUMMARY OF RESULTS 

Hydrogen Sulfide 

J 

j 

j 

J 

J 

j 

1 

.1 

I 

Run No. 

Sample 

Nl 

Vj, ml 

% 

V-, ml 

Vj Blank, ml 

Vs Blank, ml 

V , liters m , ' 

std 

CH2S» mg/dscm 

Av

~

 C H2 S 

1 

A 

0.00996 

50 

0.00996 

47.0 

50 

49.5 

16.657 

25.5 

B 

0.00996 

50 

0.00996 

48.4 

50 

49.5 

14.883 

12.5 

19.0 

2 

A 

0.00996 

50 

0.00996 

48.8 

50 

49.5 

15.394 

7.7 

B 

0.00996 

50 

0.00996 

49.0 

50 

49.5 

15.423 

5.5 

6.6 

3 

A 

0.00996 

50 

0.00996 

48.7 

50 

49.5 

15.053 

9.0 

B 

0.00996 

50 

0.00996 

48.2 

50 

49.5 

14.851 

14.9 

12.0 

C H2 S = K (V-N- - VgNg)sample - (V-N- - VgNg)blank 

m std 

4.? S 

K * 

Vl 

Nl 

vs 

NS 

mstd 

Concentration of H2S at standard conditions, mg/dscm 

Conversion factor = 17.04 x 10^ 

Volume of standard iodine solution, ml 

Normality of standard iodine solution 

Volume of standard sodium thiosulfate solution, ml 

Normality of standard sodium thiosulfate solution 

Dry Gas Volume at standard conditions, liters 

80-65 

MULLINS ENVIRONMENTAL TESTING CO.. INC. 
P.16 

fry \ m W\ 

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DISCUSSION OF RESULTS 

The results of two tests were within the limits of detectability 

(8 mg/dscm - 740 mg/dscm). One test fell below the lower limit 

of detectability of the method as described in Appendix A of the 

Code of Federal Regulations, Title 40, Chapter I, Part 60. 

The tests appeared to be valid representations of the actual concentrations of hydrogen sulfide in the fuel gas stream. All leak 

checks before and after sampling were within the acceptable limits 

of the method. 

1 

'J 

] 

3 

] 

] 

] 

80-65 _4_ 

MULLINS ENVIRONMENTAL TESTING CO., INC. 
P.17 

(TT A (17 v 

.]. 

1 

1 

1 

3 

DESCRIPTION OF SAMPLING LOCATION 

Samples were taken at ground level from a valve on the fuel gas 

line. 

80-65 -5-

MULLINS ENVIRONMENTAL TESTING CO., INC. 

ll.L-__ll.,l„_lH_l_IWm'i_LLlL. 
V__h_________/

 vvv

 -*-

SAMPLING AND ANALYTICAL PROCEDURES 

The sampling followed the procedures:outlined in Method 11 in the 

Appendix to the Code of Federal Regulations, Title 40, Chapter I, 

Part 60. 

All samples were taken for fifteen minutes at a rate of approximately 

one liter per minute. Following each test the sample train was purged 

for fifteen minutes with ambient air drawn through a tube of activated 

charcoal at the same rate as the sample was taken. 

The sample train was leak-checked under pressure before and after each 

test. This was performed to predetermine the possibility of a diluted 

sample. 

The concentration of hydrogen sulfide in the samples was determined 

on site iodometrically. 

80-65 

MULLINS ENVIRONMENTAL TESTING CO., INC. 
P.19 

DESCRIPTION OR TESTS 

Personnel arrived at the plant at 11:30 a.m. on Thursday, November 20, 

1980. The equipment was set up for testing hydrogen sulfide in the 

fuel gas and the first test for hydrogen sulfide began at 2:21 p.m. 

Testing continued without difficulty until completion of the third 

test at 6:13 p.m. The samples were recovered and analyzed on site. 

The equipment was secured for the night at 7:30 p.m. 

On Friday, November 21, work began at 8:00 a.m. The equipment was 

set up on the FCC Stack and was prepared for testing. It was decided 

by piant personnel to postpone further testing due to operational 

problems with the electrostatic precipitator. 

The equipment was moved off the stack and loaded into the sampling 

van. 

I 

I 

1 

! 

Operations at the La Gloria Oil § Gas Company refinery in Tyler, 

Texas were completed at 11:00 a.m. on Friday, November 21, 1980. 

Billy J. Mullins, Jr., K.E. 

President 

80-65 

MULLINS ENVIRONMENTAL TESTING CO., INC. 

s-c 
VJ_» / vii iu 

APPENDICES 

A. Calibration Data 

B. Field Testing Data 

C. Chain of Custody 

D. Resumes of Test Personnel 

80-65 

1 

- 8 -

MULLINS ENVIRONMENTAL TESTING CO.. INC. 
P.21 

Vii. / Vii. 

APPENDIX A 

Calibration Data 

Equipment Calibration Factor 

Dry Gas Meter #3 1.000 

Calibration Date 

10/31/80 

L 

80-65 

MULLINS ENVIRONMENTAL TESTING CO., INC. 

. . 
P.22 

ft \ fit Vf. 

Vi____/ 

DRY GAS METER CALIBRATION 

Meter Number: 3 

Date: lo/aifo 

Calibrator: 4>V.Jr )•.• \\ *X<-J\ A< 7s 

~^7 ~ ^ T 

Wet Test Meter V 

m 

Calibration Factor (C-.,,) 

Db 

Run No: 1 £. \.0 

std 

Dry Gas Meter V 

m std 

End 

Start 

Time 

IH'6 

I<AO£ 

Wet Test Meter 

Meter 

Reading Temp. 

Lr,U<6i c f ^3.0°F 

o.O cf 13>,0OF 

V. 

1°..L^ "Hg 

Control Module Vacuum 3>. 3> "Hg 

'm 

Meter 

Reading 

Dry Gas Meter 

Temp. 

In Out 

'm 

cf 13),0OF -z.K"H20 zil.Lol __!_ i_rL __L__2___1H2° 

LlpS^ c f 12.0-? -2^S*..H,o k.^Mc f °l2oF 84 «>F j , O "H?0 

Wet Test Meter V = 17.65 x L.fag! 

std 

Dry Gas Meter V = 17.65 x ^.K1 

m std 

• _L_H\ 

\ ss

 + 460

 / 

2°|.6M + 13.6 \ x|,ot>l ^.S ^ dscf 

q^ • 460 / (Cf) 

= I.^IPH dscf 

'DG 

t»S17 

6>.HtL» 

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J 

MULLINS ENVIRONMENTAL TESTING CO.. INC. 
P.23 

4TH QUARTER EXCESS EMISSIONS REPORT 

Periods of Excess H?S Content in the Refinery Fuel Gas 

1. The sulfur recovery plant was down between 7:00 a.m. 10-1-84 and 7:30 a.m. 

11-5-84 for the plant turnaround. The #2 delayed coker and the FCCU, which 

produce the bulk of the plant's sour gas, were down between 7:00 a.m. 10-1-

84 and 7:00 p.m. 11-5-84. Between 10-8-84 and 10-30-84, the rest of the 

plant was down for turnaround. Therefore, the gas which could have contained H2S was produced on a much reduced scale, but not sweetened, between 

10-1-84 and 10-8-84 and again between 10-30-84 and 11-5-84. The H2S monitor 

chart for the period 7:00 a.m. 10-1-84 until 4:00 p.m. 10-2-84 was above our 

compliance limit of 230 mg/dscm. No chart was available for the period between 4:00 p.m. 10-2-84 and 10-8-84. The chart for the period 8:00 a.m. 

11-1-84 to 4:00 a.m. 11-6-84 also recorded H2S content greater than 230 

mb/dscm. 

2. The SRU was down between 9:00 p.m. 11-11-84 and 9:00 a.m. 11-12-84 due to 

a problem at the sour water stripper. No chart from the H2S monitor is 

available because the lead acetate paper had run out, therefore no measure 

of the fuel gas H2S content is available. 

3. The SRU was down between 8:00 a.m. and 7:00 p.m. 11-30-84 due to a flame 

sensor problem in the waste heat boiler of the SRU. No chart from the H2S 

monitor is available because the lead acetate paper had run out, therefore 

no measure of the fuel gas H2S content is available. 

4. The SRU was down between 7:30 p.m. 12-9-84 and 6:00 p.m. 12-10-84 due to 

bearing vibration on one of the conbustion air blowers. The spare blower 

was out of service due to a bearing which had been running hot. No chart 

from the H2S monitor is available because the lead acetate paper had run 

out, therefore no measure of the fuel gas H2S content is available. 
Ik/1 T7T 

vv

 J t u J

-

P.24 

DRY GAS METER CALIBRATION 

Meter Number : 3 Calibrator 

Date: 10>/_>I| j?P 

Wet Test Meter V 

m 

Calibration Factor (CDG) = 

std 

Dry Gas Meter V, 

m std 

Run No: ^ O.S" 29. <W "Hg 

Control Module Vacuum 2. 2 "Hg 

Wet Test Meter 

Meter 

Time Reading Temp. 'm 

Meter 

Reading 

Dry Gas Meter 

Temp. 

In Out 'm 

End ,qo ^ C.ZMrc f ^. ^ -^°" H2 ° 3"7J.3_T3cf V °F ? 4 'F O,S "H20 

Start /S-To O.o cf 7Z.-7F -)tqQ"H70 3-±^Jj£_ il _ _£o_ Q,£" "H?0 

S.2H^ c f 7 *.S°F "I.TO-H O S.zl l Cf ^ W ^ 2 o F °<$ "H20 

Wet Test Meter V_ 

m 

= 17.65 x £ ( 2 H£ 

std 

Dry Gas Meter V = 17.65 x ^.11°\ 

m std 

f l^.bl * 13.6 A 

\ %b * 460 / 

2<,,(W+ 13.6 \ xj.ool -^.HSdsc f 

72.b + 460 J (Cf) 

= S,^ ^ dscf 

£.HC 

'DG £,0(j>-\ 

I.02.2-

MULLINS ENVIRONMENTAL TESTING CO., INC. 

pm.i-u'-wijjjjjMMM-iUpm 
P.25 

K/l E n* •* 

Meter Number: ^ 

Date: \pj\ i I Ho 

DRY GAS METER CALIBRATION 

; Calibrator: \j\>l L K *&o3Uc 

Wet Test Meter V 

m 

Calibration Factor (C^-) = 

Uu 

std 

Dry Gas Meter V 

m std 

Run No: l@.' /, g~ 2%'+-! 

Wet Test Meter 

Meter 

Time Reading Temp. 

"Hg 

'ro 

Control Module Vacuum 2, . "Hg 

Dry Gas Meter 

Meter Temp. 

Reading In Out _ •m 

End mil. IhOlb c f TZ,COF . i>iS -"H2 0 2><fa28Hcf ^'" F ^ Z °F /, ^ "H20 

Start /q_/8_ 0.0 cf fosT'F '3,Su"H70 S??, ^ <?3> JL L /.S& "H90 

ll.02C»cf 73._T°F ' 3'

S

3'»H2 0 ;i-2S^c f ?H° F 8 3 «F ^ D" H 2 0 

Wet Test Meter V = 17.65 x /|,OZ0» 

mstd 

Dry Gas Meter V = 17.65 x /). 

std 

'i___t'l , a 

2%u><-)* 13.6 \ x (.co? = /c>.g|L/ dscf 

ll.S + 460 J (Cf) ii. 

2°t.6>W+ 13.6 ^ = /o.l^ S dscf 

9"l 

~SsY ^^ L)+ 13.6 N = /0.1 

\ 9"1 * 460 / 

/O.&N 

'DG /o.-?6>_» 

^ 

-QQS 

MULLINS ENVIRONMENTAL TESTING CO., INC. 

W«J^_«WW.MJW-_-yiAA'!I.WBy»^B|i 
IK/1 

Meter Number 

Date: ) o/si/go 

DRY GAS METER CALIBRATION 

Calibrator :^A\VA:. 

(i 

\ i 

[

>j.Cy-.; 

Wet Test Meter V, 

m 

Calibration Factor CCnr0 = 

std 

Dry Gas Meter V, 

m std 

Run No: j® 2.0 

Wet Test Meter 

Meter 

Time Reading Temp. 

2=.,13 "Hg 

'm 

Control Module Vacuum 3.8 "Hg 

Dry Gas Meter 

Meter Temp. 

Reading In Out _ 'm 

End 

Start 

m i /O.IU cf 73,£°F-^/S*"H2 0 U0 | . o /oc f <.<-/°F 2 0 ° F 2 .O"H2 0 

IHlC O.O cf ?S.b°F-^.sC"H7 0 jfr.k6S Ji i _M . 2>0 "H90 

10.1^1 c f ^3.r. F "«-l,S-3„ H 2 0 Jo.Uo^c f ^ t' ° F

 ?2s F 2 ' ° "H20 

Wet Test Meter V_ 

m 

= 17.65 x 

std 

Dry Gas Meter V = 17.65 x |o. Ho£ 

m std 

, ( 2c..6>3, » 13.6 \ x| . 

I 7S-C + 460 J ( 

f 2°l.f,$ + 13.6 \ 

\ 9« + 460 / 

00°\ = l^qldsc f 

(C£J 

= Vf ^ dscf . 

V H 2 

'DG ^ - °i 9 ^ 

P.^k 

MULLINS ENVIRONMENTAL TESTING CO.. INC. 
P.27 

(TJ Wv 

Meter Number: 

Date: )oj\lfeo 

DRY GAS METER CALIBRATION 

Calibrator = gy,a. 0 %J$.M, ^r 

Calibration Factor (CnJ) 

Wet Test Meter V 

m std 

Dry Gas Meter V 

m std 

Run No: j@ g,, O V- 2°i,U3 "Hg 

Control Module Vacuum ^/. O "Hg 

Wet Test Meter 

Meter 

Time Reading Temp. 'm 

Meter 

Reading 

Dry Gas Meter 

Temp. 

In Out 

'm 

End IMS'o lO.-Ll^cf 7 ^ •F-S.'.S* "H20 -4,12.11 b <-£ *^ ° F

 !Z ° F 2>.°"H2° 

Start }UUo O.O cf lLl°¥- (p,Q "H70 t/O/kSZ V± 8 2 3,0 "H?0 

,0,71t <

 cf 7' / °F'^ 8" H 2 0 l^^ y Cf ^ °F 8 ° °F 3, 0 "H20 

Wet Test Meter V_ 

m 

= 17.65 x /0-21M 

std 

2%l*3> • 13.6 ^ x /.oo"? = 10.OOL&scf 

,^ + 460 J (C.) 

Dry Gas Meter V 

m 

= 17.65 x )0>S~SL 

std y 8 7 + 460 / 

0.|6>S dscf 

'DG 

10,002-

/o.i_>: 

o,^1 

MULLINS ENVIRONMENTAL TESTING CO.. INC. 

«Mf l 
IK/I > 

... _ 

P.28 

1

 • 

ri / 

DRY GAS METER CALIBRATION 

Meter Number: J> 

Date: 

Calibrator 

" ic>l%>l%< 

> 

^ 0 

Wet Test Meter V 

m 

Calibration Factor (C__) = 

DG 

Std 

Dry Gas Meter V 

m std 

Run No: <? 4.o p • 2-V.pl> 

Control Module Vacuum 3>-~7 

_"Hg 

"Hg 

Wet Test Meter 

Meter 

Time Reading Temp. 'n 

Meter 

Reading 

Dry Gas Meter 

Temp. 

In Out m 

End /O.S"l° cf 7M °F -l.^SnH2 0 ^2M-oSOc f t-\ °F ^" F M-O"H20 

Start /qqb 6,Q cf ^ 'F -3.kS"H?0 M/3_2i_S_ I£ _ 3LL M-Q "H?0 

to.Sio c f m oF -l.fro„H0 /^g^ b c f C]b»F * ° °F M.d>»H20 

Wet Test Meter V = 17.65 x /0 . £ , 

std 

Dry Gas Meter Vm = 17.65 x |0,g2»$ f 2 % k ^ 

Z^63 » 13.6 | x/,oo 

?<•/ + 460 J (Cf; 

) -/6.HOdsc f 

std 

f 2<j.fo£* 13.6 \ 

\ #2 + 460 / 

• ) 

= fD»HH3) dscf 

'DG 

to. fl O 

/a«-/w3 

M 1U> 

MULLINS ENVIRONMENTAL TESTING CO.. INC. 
P.29 

(tt Th 

APPENDIX B 

Field Testing Data 

1 

80-65 

MULLINS ENVIRONMENTAL TESTING CO., INC. 
P.30 

La.^oc'i<\ °M Co. 

•20 lOour^SfcR- %o 

\\x<3 A4etVod \V 

i±L__lX 

/vnt.a i l^tft.^2c(L ___£1£^jWUJ 

yy^cA 

Pu.^« ""*• *\TA CyX*. "»-' 

Ll 

J f.'vJl ^JXAl l 

ft • 

- 66 L-CL 

2 1^<" 

6 1_ _^ i 

67 

7"/ »VL< 

I 

Jy^-df!* ^ ^ * **n X^M «^~ -

 u t

 */~: 

J — 

J 

J ^fxj ^.A-i toz&^ 

P a , f Vx^-ifZiiili ? 

/UA&- T***(> 

r* 0*Jr 

FivA-_y 

<H«f.l M __2_L -31-

•7 2. 

I W | t .'(Vj) ^ PP Cy*l«y<*y 

iT.lU 0.0 0 t,+4»yy^ 

f)*vc£ 

* I.O0G - 0,^3- 6 cC 

-, 14.1*3 JL 
V -l v 

P.31 

^ U^jZ- A 

.^eh Q: — / -

P*rj* to _Xl____i_2i=^ 

Pi^JLiir" 

I UITM L ^ 

0,$ 4 IO 

TVU t-iiSAi:

 v J^££. 

O.^ 3- cC 

^i 

54^ 53 ° ^0.036 acc ^ l.** 6 jt/j 

\ 3 

I y+'y\ji.'T \.yy*. tvv^ Mf-f7»» 

F.uii @ lli i ev^Ua0 <£__!___c^/^' 

64 

T.w^ PA2^gg6~? Ml 

- 6 1 . .4. 

6><? 

^jjsJjL 

DcS^] _c ^ •jpU) ffi£!il

 * i°P D - _£ 

^ > A..H" ? J»_i« * % f - ^~ ^ - (i^. ^ 

0,Gll£-

eJU •=. . I.OJLfT ^ / 

j 
7f 

P.32 

1 

f^Atiir 113 1-17^ <_^ 

y« 

1 Ai)ry ^ Ki^ 

[ £_JjJ illl_l_ J 

| XiAJ __£_LS_____-

}^jM -Jh&&*~ < J°°0 

I KJ Q-Ay 

"7_A 

^ 

•£*.** -

*\. *ro - P.tS' ^ 0_£2l - 7 ^

 , _^1_ ^ ^I_«i-« 

0, 0 3 5 ols* «i 

« . -tin 

0,51 4 

^ ,6 ^ JJJ5± 

Lol> 

1 

* K ~ ——• 

6XA 

1 

O.QXCS My * Ad^-

A 

~J/~ 
P.33 

. N. _» J.. 

APPENDIX C 

Chain of Custody 

80-65 

MULLINS ENVIRONMENTAL TESTING CO., INC. 

J 
P.34 

MULLINS ENVIRONMENTAL TESTING CO., INC. 

Chain of Custody 

Job Number %Q-/fl>C 

Job Name L,<-A (-}\C*C\C\ 0\ \

 L

- (DUS, 0-^0'=^^\ 

Location ~Ty,\^ r " \ 9 ^n s 

Unit Tested pu. ) G^ c SaPfau i 

Date(s) Sampled \\hoh° 

Number of Tests UA\ I 

Description 

Front Wash 

Back Wash 

Impinger No. 1 

Impinger No. 2 

Impinger No. 3 

Filter Container 

Sample Containers 

No. of Containers Remarks 

/"-/MO 

Sample No. ]_£_ Recovered by: U^,U.__'l: Ucj$^||te : tl/zg/ftjime: , < ^ Location: 0l A C,AP 

Sample No. 2 A Recovered by: ^\ofYU A K bL^^gfte s />/WgoTime: nt o Location: o ^ <.Af 

_e;

Sample No. ?, to, Recovered by: l^^y ^ j / ^ M /i/2o/^Time: /y ^ Location: ^ <_^Ae_ 

(3 " 

Samples Received by: 

Samples Received at Lab by 

Samples Analyzed by: fr.p \zkfo. 

/ill S.c~w.p/e-S. c-_wcJl-| t_ J ov\ _.jr 

for Transport Date: 

Date: 

Date 

Time: — 

Time: — 

:

 lll?o/\ KJI. Time: lL

}HO- l°[ 
P.35 

\________s '" "• 

APPENDIX D 

Resumes of Test Personnel 

80-65 

MULLINS ENVIRONMENTAL TESTING CO., INC. 
P.36 

MULLINS ENVIRONMENTAL TESTING CO., INC. 

P.O. Box 598 

Addison, Tx 75001 

(214)960-1843 U___ 

BILLY J. MULLINS, JR., President 

Education Post Graduate Study in Environmental Engineering at 

Southern Methodist University, Dallas, Texas, 1970. 

M.S. 1969, New York University, New York, New York, 

in Civil Engineering (Air Resources). 

B.S. 1968, Texas Tech University, Lubbock, Texas, in 

Civil Engineering (Water Resources). 

Studies in Engineering at U.S. Naval Academy, Annapolis, 

Maryland, 1963-1964. 

Professional 

Training 

Courses 

Attended Short Course on Air Pollution Engineering at 

the University of Texas at Austin, February 1970. 

Attended four-week management course presented by the 

American Management Association, 1976. 

Certification Registered Professional Engineer 

Certified Visible Emissions Evaluator 

Certified Fallout Shelter Analyst 

Licensed Private Pilot (Single Engine-Land) 

Professional 

Memberships 

Air Pollution Control Association - Past Chairman, 

Southwest Section 

Source Evaluation Society 

American Society of Civil Engineers 

Texas Society of Professional Engineers 

National Society of Professional Engineers 

American Management Association 

Technical Association of the Pulp and Paper Industry 

Technical Directed and performed stack sampling on over 600 

Experience sources of which over 60 were sampled simultaneously 

using more than one sampling train at several points 

in the flue gas stream. 1972-present. 

Directed and performed over 70 short-term ambient air 

studies using mobile sampling vans and various ambient 

air sampling equipment. 1972-present. 

MULLINS ENVIRONMENTAL TESTING CO., INC. 
P.37 

iV Tt\ 

J W. Jll 

Mullins 

Research 

Projects 

Publications 

Designed, directed and operated over 20 permanent 

ambient air networks of various size and duration 

for a variety of parameters. 1972-present. 

Designed surface and underground drainage systems 

for residential subdivisions, public works projects, 

and shopping centers. '•. 1969-1972. 

Designed several residential subdivisions including 

lot layout, street design, drainage design, and 

utility design. 1969-1972. 

Supervised and conducted a study made by the Hawaiian 

Sugar Planters' Association to characterize the emissions 

for several bagasse-fired boilers. April-May 1976. 

Supervised and conducted a study made by the Rio Grande 

Valley Sugar Growers, Inc. to determine the area 

affected by the burning of sugarcane fields prior to 

harvesting. November 1974-April 1975. 

Supervised and conducted a study by a lightweight 

aggregate manufacturer to develop a material balance 

around the process through sampling and analysis of 

several parameters. November 1973. 

Conducted a study in New York City to attempt to develop a correlation in the ambient air between carbon 

dioxide and sulfur dioxide to provide a tool for 

predicting air pollution episodes. January-May 1969. 

Co-authored "Sulfur Compound Emissions of the Petroleum 

Production Industry," December 1974. 

Co-authored "Field Procedure for Stabilizing Hydrogen 

Sulfide Samples to be Analyzed Using Modified Methylene 

Blue Technique," presented at the Conference on Ambient 

Air Quality Measurements, Austin, Texas, March 1975. 

Co-authored "Atmospheric Emissions Survey of the Sour 

Gas Industry," October 1975. 

Co-authored "Technique for Insuring the Validity of 

Samples for High Concentrations of Sulfur Dioxide 

Using the EPA Method 5 Sampling Train," presented at 

the Third National Conference on Energy and the 

Environment, College Corner, Ohio, September 1975. 

MULLINS ENVIRONMENTAL TESTING CO., INC. 
(TJ \ 

Mullins 

Teaching Served as a lecturer in the Environmental Protection 

Experience Agency's training course number 450, "Source Sampling 

for Particulate Pollutants" for two years from 

January 1974 to October 1975. 

Conducted a two-day training course entitled "Technical 

Assistance in Source Sampling" at Iowa State University, 

Ames, Iowa for the Environmental Protection Agency, 

October 1974. 

Conducted EPA's training course number 450, "Source 

Sampling for Particulate Pollutants" for the EPA at 

Research Triangle Park, North Carolina, September 1975. 

Conducted a two-day short course entitled "Performing 

and Observing Source Sampling" at Dallas, Texas, 

July 1976, May 1977, October 1977; at Lake Charles, 

Louisiana, May 1977; and at Casper, Wyoming, May 1977. 

Served as a lecturer in the Environmental Protection 

Agency's two-day seminar entitled "Asphalt Industry 

Environmental Solutions," presented in Dallas, Texas 

on March 21 and 22, 1979. 

MULLINS ENVIRONMENTAL TESTING CO.. INC. 
P.39 

MULLINS ENVIRONMENTAL TESTING CO., INC. 

P. 0 Box 598 

Addison. Texas 75001 • (214) 980-1843 

v______/ Vii. 

r 

DON C. ALEXANDER, Field Technician 

Education B.S. 1978, Angelo State University, San Angelo, 

Texas, in Biology with a minor in Chemistry. 

Technical Participated in the sampling of over 150 sources, 

Experience including several which were sampled simultaneously 

using more than one sampling train. 

MULLINS ENVIRONMENTAL TESTING CO., INC. 
P.40 

MULLINS ENVIRONMENTAL TESTING CO., INC. 

P.O. Box 598 

Addison. Tx 75001 

(214)980-1843 

DOUGLAS RAY SAATHOFF, Environmental Technician 

Education B.S. 1978, The University of Texas at Austin, 

Austin, Texas, in Biology with a minor in 

Chemistry. 

Technical Research Assistant at The University of Texas 

Experience at Port Aransas, Summers 1976 and 1977. 

Laboratory Technician for The Texas State 

Department of Health, Dallas, Texas. 

Participated in the sampling of over 50 sources, 

and analysis of commercial cylinder gases of 

Nitric Oxide and Sulfur Dioxide. 

One year experience with EPA and Texas Air 

Control Board methods of analysis of both 

source and ambient air samples for particulates, 

S02, S03, H2SO4, H2S, HCl, CI2, and N0X. Both 

laboratory and on-site analysis performed. 

MULLINS ENVIRONMENTAL TESTING CO., INC. 
P.41 

MULLINS ENVIRONMENTAL TESTING CO., INC. 

P.O. Box 598 

Addison. Tx 75001 

(214)980-1843 ____ liLJU 

RANDY PIPKA, Environmental Field Technician 

Education B.S. 1976, St. Anselm's College, Manchester, 

New Hampshire, in Biology with a minor in Chemistry. 

Technical One year source and personal sampling with RSR 

Experience Corporation. Since joining METCO, has participated 

in the sampling of over 30 sources. 

MULLINS ENVIRONMENTAL TESTING CO., INC. 
P.42 

LA GLORIA © 

Oil and Gas Company P. O. BOX MO, ma, TEXAS 75710 

A TEXAS EASTERN COMPANY 

February 7, 1985 

Mr. SabinO Gomez 

Compliance Division 

TEXAS AIR CONTROL BOARD 

6330 Hwy. 290 East 

Austin, Texas 78723 

Dear Mr. Gomez: 

Attached is La Gloria Oil and Gas Company's written 

report of excess emissions our Tyler Refinery for the 

fourth quarter of 1984. 

Appropriate measures are being taken to assure that 

both our H2S monitor and our opacity monitor are measuring 

and recording their respective streams as much of the time 

as is possible. 

Please contact us at (214) 595-4511 if further information is required. Thank you for your cooperation. 

Yours very truly, 

Alvie R. Livermore, P.E. 

Manager of Engineering 

PFF:ab 

Attachment 

pc: Richard Leard, TACB 
P.43 

4TH QUARTER EXCESS EMISSIONS REPORT 

H?S Monitor Operation Summary 

1. Between 5:00 p.m. 10-2-84 and 8:00 a.m. 11-1-84, the H2S monitor a t the 

fuel gas mixing drum was out of recorder chart paper. 

2. Between 9:00 p.m. 11-11-84 and 8:00 A.M. 11-12-84, the monitor's lead 

acetat e paper had run out. Therefore no measure of the H2S content of 

the fuel gas is available for this time period. 

3. Between 2:00 p.m. and 4:45 p.m. on 11-14-84 the chart recorder's paper 

was removed so that copies could be made of it . The copies were to be 

part of a report to the TACB regional office as part of our annual 

inspection. 

4. Between 7:30 p.m. on 11-24-84 and 2:00 p.m. 11-30-84, the monitor's lead 

acetat e paper had run out. Therefore no measure of the H2S content of 

the fuel gas is available for this time period. 

5. Between 2:00 P.M. 11-30-84 and 10:00 a.m. 12-4-84, the H2S monitor a t 

the fuel gas mixing drum was out of recorder chart paper. 

6. Between 10:00 a.m. 12-4-84 and midnight on 12-31-84, the monitor's lead 

acetat e paper had run out. Therefore no measure of the H2S content of 

the fuel gas is available for this time period.