@
 

State of Utah 

GARY R. HERBERT 

G(J1Iemor 

GREG BELL 

Lielllenant Governor 

January 12, 2010 

Mike Astin 

Department of 

Environmental Quality 

Amanda Smith 

Executive Director 

DIVISION OF AlR QUALITY
 

Cheryl Heying
 

Director 

DAQE-AN0101230031-10 

Holly Refining & Marketing Company 

393 S 800W 

Woods Cross, UT 840871435 

Dear Mr. Astin: 

( 

.	 . 

Re:	 Approval Order: Modifications to DAQE-ANOlO1230027-Q9 to Add Two Boilers 

Davis County; CDS A; MAcr (part 63), Major HAP source, NESHAP (part 61), NSPS (Part 

60), NSR, Nonattainment or Maintenance Area, PMlo SIP / Maint Plan: PSD, Title Y (part 70) 

Major source . . 

Project Number: N0101230031 

The attached document is the Approval Order for the above-referenced project. Future correspondence. 

on this ApprOVal Order should include the engineer's name as well as the DAQE number as shown on the 

upper right-hand comer of this letter. The project engineer for this action is Carmon Harry, who may be 

reached at (801) 536-4232. 

Sincerely, 

/'\'V\~ (\A _ f\' . . 

M. CberylHeYi~,~~ck~ Utah Air Quality Board tiV~

MCH:CAH:dn 

cc:	 Mike Owens 

Davis County Health Department 

150 North i 950 West· Salt Lake City, UT . 

Mailing Address: P.O. Box 144820· Salt Lake Cit;y, UT 84114-4820 

Telephone (801) 536-4000· Fax (801) 5364099· T.D.D. (801) 536-4414 

wl1I1p.deq.uU!h..go'll . 

Prin"'d on lOO\lb recycled paper 
STATE OF UTAH 

Department of Environmental Quality 

Division of Air Quality 

APPROVAL ORDER: Modifications to DAQE-ANOI01230027~09 . to Af,1d Two Boilers . \ 

\ 

Prepared By: Camron Harry, Engineer
 

Phone: (801) 536-4232
 

Email: caharry@utah.gov
 

APPROVAL ORDER NUMBER 

DAQE.A.N0101230031-10 

.... Date: January 12, 2010 

Holly Refining & Marketing Company
 

Woods Cross Refinery
 

Source Contact:
 

Mr. Bo Bothwell
 

Phone: (801) 299·6619
 

~~~g~ Executive Secretary . 

Utah Air Quality Board 
Abstract 

Holly Refin41g & Marketing Company (Holly) Woods Cross Refinery is requesting to install two (2) new 

75,000 pounds of steamlhour steam boilers, Boiler #9 and Boiler #10. Holly is in the process ofinstalling 

and operating new sulfur removal units for on and offroad fuels in order to comply with federal 

regulations. These sulfur removal units have been built and as a result the refinery's steam demand has 

increased. Wbile the possibility of debottlenecking exists with the increased steam capacity, the source 

wide emissions are capped by the Utah PMIO SlP. One of the additional boilers is needed to meet current 

steam requirements and the second boiler is needed to provide redundancy when a boiler is shut down for 

maintenance Or during a process upset. 

This modification will.result, in tOns per year, in the following PTE increases: PMIO +7.82, NOx +15.65, 

S02 +20.69, CO + 28.94. While this is an increase over the values from Holly's existing AO, the new 

totals are less than the existing limitations from section lX.H.2.f of the PM10 SIP. . 

Holly is located in West Bountiful, Davis County. Davis County is a maintenance area for ozone. Holly 

is located 4 miles north ofSalt Lake County and is defined as a con1n'buting source for the Salt Lake 

County PM10 nonattainment area: While this source is located in an area currently designated as 

nonattainment for PM2.5, the preparation ofthis document was completed prior to the effective date of 

that designation. 

The Project has been evaluated and found to be oonsistent with the requirements of the Utah 

Administrative Code Rule 307 (UAC R307). A public comment period was held in accordance with 

UAC R307-401·7 and no comments were received.' 

This air quality AO authorizes the project with the following conditions, and failure to comply with any 

oftbe conditions may constitute a violation ofthis approval order. This AO is issued to, and applies to 

the following: 

Name of Permittee: Permitted Location: 

Holly Refining& Marketing Company Woods Cross Refinery 

393 S 800W 393 South 800 West 

Woods Cross, UT 840811435 Woods Cross, UT 84087-143.5 

UTM coordinates: 424,000 m Basting, 4,526,277'm Northing 

SIC code: 2911 (pe1r9Ieum Refining) 

Section I: GENERAL PROVISIONS 

I,1	 ;All definitions, terms, abbreviations, and ref~ences used in this AO conform to those used in 

.the UAC R307 and 40 CFR. Unless noted otherwise, references cited in these AO conditions 

refer to those rules. [R307-101] 

I,2	 The limits set forth in this AO shall not be exceeded without prior approval. [R307-401] 

Mqdifications to the equipment or processes approved by this AO that could affect the 

~tnissions covered by this AO must be reviewed and approved. [R307-401-1] 

I.3 
DAQE-ANOI01230031-10 

Page 3	 . 

I.4	 All records referenced in this AO or in other applicable rules, which are required to be kept by 

the owner/operator, shall be made available to the Executive Secretary or Executive Secretary's 

representative upon request, and the records shall include the two-year peribd prior to the date of 

the request. Unless otherwise specified in this AQ or in other applicable state and federal rul,es, 

records shall be kept for a minimum oHive (5) years. [R307-401] 

I.5	 At all times, including periods of startup, shutdown, and malfunction, owners and operators 

shall, to the extent practicable, maintain and operate any equipment approved under this AO, 

including associated air pollution control equipment, in a manner consistent with good air 

pollution control practice for minimizing emissions. Determination of whether acceptable. 

operating and niaintenance procedures are being used will be based on information available to 

the Executive Secretary which may, include, but is not limited to, monitoring results, opacity 

observations, review of operating Ipld maintenance procedures, and inspection of the source. 

All maintenance performed on equipment authorized by this AO shall be recorded. 

[R307-401-4] 

I.6	 The o.:.vner/operatorshall comply with R307-150 Series. Inventories, resti~g and Monitoring. 

[R307-150] . 

I.7	 The owner/operator shall comply with VAC R307-107. General Requirements: Unavoidable 

Breakdowns. [R301-107] , . 

1.8	 Holly Refining and Marketing shall continue to install the vacuum tower, associated heaters, 

upgrade the FCCU and solvent deasphalting unit, make the required changes in storage tanks, 

install boilers #9 and #10, and operate its facility in accordance with the tenns and conditions of 

this AO that were written pursuant to Holly's notice ofintent submitted to the Division of Air 

Quality on October 5, 2006. 

Holly shall notify the Executive Secretary in writing when the installation of the equipment has 

been completed and the equipment is operational, as an initial compliance inspection is required. 

To insure proper credit when notifying the Executive Secretary, send your correspondence to the 

Executive Secretary, attn: Compliance Section. 

If construction andlor installation have not been completed within eighteen months from the 

date of this AO, the Executive Secretary shall be notified in writj,ng on the status of the 

construction andlor installation. At that time, the Executive Secretary shall require 

documentation of the continuous construction and/or installation of the operation and may 

revoke the AO in accordance with R307-401-18. [R307-401] 

Section II: SPECIAL PROVISIONS 

n.A The approved installations shall consist of the following equipment: 

II.A.l	 Holly Refinery 

Perm,itted Source 
/ 

DAQE-ANOI0123003I-iO 

Page 4 

II.A.2, 

II.A.3 

ILA.4 ' 

II.A.S 

II.A.6 I 

II.A.7 

II.A.8 

II.A.9 

II.A.lO 

ll.A.I1 

H.A.12 

II.A.l3 

ll.A.14 

ll.A.15 

ll.A.16 

II.A.I7 

IIA.18' 

(4·1) 4H1: FCC feed heater 

68.4 MMBtulhrprocess furnace, fired on plant gas, restricted to 39.9 MMBtuIhr, equipped 

with Iow-NOx burners '. 

(4.4a) 4K1A: KVG compressor west 

660 hp internal combustion engine, fired on natural gas 

(4·4b) 4K1B: KVG compressor east 

660 hp internal combustion engine, fIred on natural gas 

(6·1) 6HI: Reformer charge and reheater furnace 

54.7MMBtuIbr process furnace, fired on plant gas 

(6-2) 6H3: Reformer reheat furnace 

37.7 MMBtulbr process furnace, fIred on plant gas 

(6-3) 6H2: Prefrllctlonator reboiler heater 

12.0 MMBtulhr process furnace, fIred on plant gas 

(6·4a) 6K1 SVG compressor east 

325 hp internal combustion engine, fired on'natural gas 

(6·4b) 610: SVG compressor west 

325 hp internal combustion engine, PIed on natural gas 

(7-1) 7H3: HF alkylation depropanizer reboiler 

33.3 MMBtuIhr process furnace, fired OJ;! plant gas 

(7-2) 7H1: HF alkylation regeneration furnace 

4.4 M:MBtuJhr process furnace, fIred on plant gas 

(8-1) 8H1: Crude furnace 

99.0 MMBtu/br process furnace, fIred on plant gas, equipped with NGULNB 

(9-1) 9Hl: DIIT reactor charge heater 

8.1 MMBtulhr process furnace, fIred on plant gas 

(9-2) 9H2: DIIT stripper reboiler 

4.1 MMBtulbr process furnace, fIred on plant gas 

(10-2) 10Rl: Asphalt mix heater 

13.2 MMBtulbrprocess furnace, fIred on plant gas 

(11·1) I1Hl: SRGP depentanizer reboiler 

24.2 MMBtulhr process furnace, fired on plant gas 

(11·2) 11Kl: Clark compressor 

600 hp internal combustion engine, fired on natural gas 

(12-1) 12H1: NHDS reactor charge furnace 

50.2 MMBtu/br process furnace, flIed on plant gas, equipped with :NGULNB 
®
 

DAQE-ANOIOI230031-1O 

Page 5 

ll.A.19 

ll.A20 

II.A.21 

ILA.22 

TI.A.23 

TI.A.24 

n.A.25 

IIA.26 

ll.A.27 

II.A.28 

II.A.29 

ll.A.30 

II.A.31 

TI.A.32 

ll.A.33 

ll.A.34 

II.A.35 

(13-1) 13H1: Isomerization reactor feed furnace 

6.5 11MBtu/hr process furnace, fIred on plant gas 

(17-1) SRU - tailgas incinerator 

For SRU under 20 LTPD 

(19-1) DHT reactor charge heater 

18.llVIMBtulbr Processs Furnace, fired on plant gas, equipped with low-NOx burners 

20H1: Reactor charge heater 

14.9lVIMBtulhr process furnace, fired on plant gas, equipped with ULNB 

20H2: Fractionator charge heater, 

47.1 :MMBtulbr process furnace, fIred on plant gas, equipped with ULNB 

(45-1) 45H1: Asphalt mix and storage furnace , 

15.3 MMBtu/hr process furnace, fired on plant gas, equipped with low-NOx burners 

(68-2) 68H2: North in-tank asphalt heater 

0.8- MMBtulbr tank he~ter, fIred with natural gas 

(68·3) 68H3: South in-tank asphalt heater, 

0.8 MMBtu/hr tank heater, fired with natural gas 

(51-4) Boiler #4 

35.6 MMBtulhr boiler. fired on plant gas 

(51-5) Boiler #5 

70.0 MMBtufhr boiler, fired on plant gas 

(51~6) CO boilerfFCC scrubber 

60.0 MlYlBtu/hr boiler, fired on plant gas 

(51-7) FCC 34" CO boiler bypass 

34" Stack 

(51-8) Boiler #8 

92.7 MJ:v1Btulhr boiler" fired on plant gas, equipped with low-NOx burner 

(51-9) Boiler #9 

89.3 MMBtulhr boiler, fired on plant gas using SCR 

(51-10) Boiler #10 

89.3 MNfBtu/hr boiler, fired on plant gas using $CR 

(56) Watewater Treatment Plant 

(66-1) ProceSs flare south 

Flare 
DAQE-AN0101230031-10 

Page 6 

ll.A.36 

IIA.37 

IIA.38 

,	 IT.A.39 

IT.A.40 

II.A.41 

II.A.42 

II.A,43 

II.A.44 

IT.A.45 

1I.A.46 

II.A.47 

n.A.48 

II.A.49 

(66.2) Process flare north 

Flare 

(68-1) Propane piUlare 

Flare 

Tank 23: Storage'vessel • petroleum liquids 

14,600 Bbl capacity storage tank with a fixed roof 

, 

Tank 35: Storage vesSel - petroleum liquids
 

105,000 Bbl capacity storage tank with a ftxed roof
 

Tank 71: Storage vessel- petroleum liquids
 

67,155 Bbl capacity storage tank with'internal floatingro9f, primary anI! secondary seals
 

Tank 72: Storage vessel- petroleum liquids
 

124,388 bbl storage vessel with floating roof, primary and secondary seals
 

Tank 79
 

10,000 Bbl capacity storage tank with a fixed roof
 

Tank 167
 

1,300,000 gallon sbur water storage ,tank
 

Tank 323: Storage vessel- petrole~ liquids ,
 

14,686 bbl capacity storage tank with internal floating roof, 'and primary seal
 

Storage tanks
 

Three 14,000 Bbl NaSH tanks (two currently installed)
 

Two 7,100 Bbl caustic tanks (one currently installed)
 

One 80,000 Bbl fuel oil tank (not yet installed)
 

One 50,000 Bbl cutter tank (riot yet installed)
 

Emergency equipment
 

L Diesel powered water well No.3
 

2.	 Caterpillar diesel fire pump No.1 

3. CaterpiJ.lar diesel fire pump No.2' 

4, Detroit Diesel fire pump 

5. Diesel powered plant air backup compressors (3) 

6. Diesel powered standby generator, Boiler House 

7. Diesel powered standby generator, Central Control RooJ,n 

Three amine units 

Two new units 

Fluid catalytic cracking unit 

FCC includes 02 skid, item #4-97-0010 

DHT 

Distillate hydro-desulfurization treatment unit 
DAQE-AN0101230031-10 

Page? 

II.A.50 

II.A.51 , 

II.A.52 

II.A53 

II.A.54 

II.A55 

II.A.56 

II.A.57. 

II,A,58 

II.AS9 

II.A60 

II.A.61 

Cooling tower #7 

Gas oil hydrocracking unit 

Includes reactor charge heater and fractionator charge heater 

Vacuum tower and vacuum furnace heJlter 

15.2 MMBtulhr using ultra low-NOlt burners 

Hot oil heater
 

99 MMBtu/hr using ultra low-NOlt burners
 

Asphalt tank heaters
 

two new in-tank heaters sized at 0.8 MM:J3tu1br each
 

SRUrrGI (2)
 

Two new Claus sulfur recovery units with tail gas recovery, each sized at 50 long tons of
 

sulfur per day .
 

Sour water strippers (2)
 

One existing unit (#18), and one new unit (#22) with ammonia stripper
 

NaSH sour gas treatment unit
 

Sized at 50 long tons of sulfur per day
 

Hydrogen plant
 

Two hydrogen reforn;ter feed furnaces, each sized at 123.1 MMBtu/hr using ultra low-NOlt
 

burners "
 

Crude heater
 

35 MMBtu/hr using ultra low-NOlt burners
 

ETF portable diesel generator 

135 kW diesel-fired generator 

SOz Emissions Cap Sources 

S02. Emissions Cap Sources: includes (4-4b) 4K1B: KVO compressor east, (8-1) 8Rl: Crude 

furnace, (10-2) 10Rl: Asphalt mix heater, 20H2: Fractionator charge heater, ETF portable 

diesel generator, (4-4a) 4K1A: KVGcompressor west,(51-8) Boiler #8, Hydrogen plant, (6­

1) 6H1: Reformer charge and reheaterfurnace, (7-2) 7HL HF alkylation regeneration' 

furnace, (51-4) Boiler #4, (68-2) 68H2: North in-tank asphalt heater, (51-9) Boiler #9, (6-4a) 

6Kl SVG compressor east, (7-1) 7H3: HF alkylation depropanizer reboiler, (9-1) 9Hl: DHT 

reactor charge heater, 20H1: Reactor charge heater, (6-2) 6H3: Reformer reheat furnace, (45­

1) 45HL Asphalt mix and storage furnace, (19:1) DIIT reactor charge heater, (4-1) 4Rl: 

FCC feed heater. (6-3) 6H2: Prefi:actionator reboiler heater,' (13-1) 13H1: Isomerization . 

reactor feed furnace. Vacuum tower and vacuum furnace heater, Asphalt tank heaters, (12-1) 

12R1: NHDS reactor charge furnace, (51·5) Boiler #5, Hot oil heater, (9-2) 9H2: DHT 

stripper reboiler, (11-1) I1Hl: SROP depentanizer reboiler, (68-3) 68H3: South in-tank 

asphalt heater. (6-4b) 6K2: ;3VO compressor west, (51-10) Boiler #10 
DAQE-AN0101230031-10 

Page 8 

II.A.62	 NO" Emissions Cap Sources 

NOx Emissions Cap Sources: includes (4-4b) 4KIB: KVG compressor east, (8-1) 8H1: Crude 

furnace. (10-2) 10H1: Asphalt mix heater. 20H2: Fractionator charge heater, ETF portable 

diesel generator, (4-4a) 4K1A: KVG compressor west, (51-8) Boiler #8, Hydrogen plant, (6­

1) 6H1: Reformer charge and reheater furnace, (7-2) ?HI: HF alkylation regeneration 

fwnace, (~1-4) Boiler #4, (68-2) 68H2: North in-tank asphalt heater. (51-9) Boiler #9, (6-4a) 

6K1 SVG compressor east, (7-1) 7H3: HF alkylation depropanizer reboiler. (9-1) 9H1: DHr 

reactor charge heater. (17-1) SRU - tailgas incinerator, 20HI: Reactor charge heater, S02 

Emissions Cap Sources, (6-2) 6H3: Reformer reheat furnace, (45-1) 45H1: Asphalt mix and 

storage furnace, (19-1) DHTreactor charge heater, SRUITGI (2), (4-1) 4Hl: FCC feed 

heater, (6-3) 6H2: Prefractionator reboiler heater, (13-1) 13H1: Isomerization reactor feed 

furnace, (51-7) FCC 34" CO boiler bypass, Vacuum tower and vacuum furnace heater, 

Asphalt tank heaters, (12-1) 12Hl: NHDS reactor charge furnace. (51-5) Boiler #5, Hot oil 

heater, (9-2) 9H2: DHT stripper reboUer, (ll-l) llHl: SRGP depentanizer reboiler, (51-6) 

CO boilerlFCC scrubber, (68-3) 68H3: South in-tank asphalt heater, (6-4b) 6K2: SVG 

compressor west, (51-10) Boiler #10 . 

II.A.63	 PMlo Emissions Cap Sources 

PM10 Emissions Cap Sources: includes (8-1) 8Rl: Crude furnace. (10-2) lOH1: Asphalt mix 

heater, 20H2: Fractionil-tor charge heater. BTF portable diesel generator, (51-8) Boiler #8, 

Hydrogen plant, (6-1) 6H1: Reformer charge and reheater furnace, (7-2) 7H1: HF alkylation 

regeneration'furnace, (51-4) Boiler #4, (68-2) 68H2: North in-tank asphalt heater, (51-9) , 

Boiler #9. (7-1) 7H3: HF alkylation depropanizer reboiler, (9-1) 9H1: DHT reactor charge 

heater. (1771) SRU - tailgas incinerator, ZOH1: Reactor charge heater, (6-Z) 6H3: Reformer 

reheat furnace, (45-1) 45Hl: 'Asphalt mix and storage furnace, (19-1) DHT reactor charge 

heater, SRUrrGI (2), (4-1) 4H1: FCC feed heater, (6-3) 6HZ: Prefractionator reboiler heater. , ! 

(13-1) 13H1: Isomerization reactor feed furnace, Vacuup:1 tower and vacuum furnace heater, 

Asphalt tank heaters, (12-1) 12H1: NHDS reactor charge furnace, (51-5) Boiler #5, Hot oil 

heater, (9-2) 9H2: DHT stripper reboiler, (11-1) 11H1: SRGP depentanizer reboiler, (51-6) 

CO boilerlFCC scrubber, (68-3) 68H3: South in-tank asphalt heater, (51-10) Boiler #10 

n.B Requirements and Limitations 

n.B.1	 Conditions on Permitted Source 

n.B.l.a	 Stack testing to detennine compliance shall be performed in accordance·with the requirements
 

of Section IX.H.loa of the PMIQ SIP. The source shall be tested if directed by the Executive
 

Secretary., .
 

The (51-6) CO BoilerlFCC Scrubber shall be tested for PMIQ compliance at least once every 

five years. [R307-150] 

n.B.lob	 The emissions of NO" from heaters 8H1 and 12H1 shall not exceed 0.10 Ib/mmBtu on a 3­


hour average basis each. Compliance shall be determined by stack test to be performed every
 

five (5) years.
 

. The emissions of NOx from boilers #9 and #10 shall not exceed 0.020 Ib/mmBtu on a 3-hour 

average basis each. Compliance shall be determined by stack test to be performed every five 

(5) years, 
DAQE-AN010123003i-10 

Page 9 ' 

Except as specified below, emissions ofNOx shall be determined through use of 40 CPR 60, 

Appendix A. Method 7. 7A, 7B, 7C, ID, 7E, or other testing methods approved by the 

Executive Secretary. 

Emissions ofNOx and S02 from the FCCU ~hall be determined through use of it CEM. The 

monitoring system shall comply with all applicable sections ofR307-170-1, and 40 CFR 60. 

App~ndix B, Specifications 2 (NOJ and 3 (02), [R307-401, R307-170] 

II.B.l.c	 The applicant shall provide a notification of any performance test date at least 30 days prior to 

the test A pretest conference shall be held if directed by the Executive Secretary. It shall be 

held at least 30 days prior to the test between the qwner/operator. the tester, and the Executive 

Secretary. The emission point shall be designed to conform to the l-equirements of 40 CPR 60, 

Appendix A, Method 1, and of the Occupational Safety and Health Administration (OSHA) or 

Mine Safety and Health Administration (MSHA). 

A sample location shall be chosen as outlined in 40 CPR 60 Appendix A. Method 1. The 

volumetric flow rate shall be determined by 40 CPR 60 Appendix A, Method 2. 

To determine mass emission rates, the pollutant concentration as determined Oy the 

appropriate methods above shall be multiplied by the volumetric flow rate an~ 'any necessary 

conversion factors determined by the Executive Secretary to give the results in the ·~pecifi.ed

units of the emission limitation. 

For an existing sourcelemissionpQint. the production rate during fl1l compliance testing shall 

be no less than 90% of the maximum production achieved in the previous three years. [R307­

165]	 . " 

IT.B.l.d	 Visible emissions shall not exceed the following specifications: 

All scrubbers: 15% opacity 

All baghouses: 10% opacity' 

All combustion sources without controls: 10% opacity 

FCC Unit/(51-6): 20% opacity 

(8-1) 8Rl Crude Furnace: 20% opacity 

Flares - 20% opacity . 

All fugitive emission points - 20% opacity 

Opacity observations of emissions from stationary sources shall be conducted in accordance' 

with 40 CPR 60, Appendix. A, Method 9. [R307-401] 

IT.B.1.e	 The amine plants shall reduce the HiS content of the refinery fuel gas to 0.10 grainldscf (160 

ppm) or less. The owner/operator has installed and maintains a continuous monitoring system 

for monitoring the H2S content of the refinery fuel gas and a continuous recorder to record the 

H2S in the refinery fuel gas. The monitoring system shall comply with all applicable sections 

ofR307-170-1, and 40 CPR 60, Appendix B. Specification 7. [R307-40l] 

n.B.l.f	 Except as outlined in conditions n.B.1.g and n.B.1.h, the total hours of operation for testing 

and maintenance purposes for all emergency diesel-powered equipment shall not exceed 300 

hours per 12-month period, without priQr approval in accordance with R307-401. Compliance 

with the annual limitation shall be determined.on a rolling 12-month total. By th~ last day o~

each month a new l1-moritb total shall be calculatedusing the previous 12 months. Records 
DAQE-ANOlOI230031-10 

Page 10 

of the hours of operation shall be kept for all.periods ~hen the plant is in operation. Records 

of the hours of operation shall be made available to the Executive Secretary or the Executive 

, Secretary's representative upon request, and shall include a period of two years encling with the 

date of the request The total hours of operation may be determined by an engine hour 

totalizer installed on each engine, but a separate record of non-emergency hours shall be kept 

on a weekly basis. Emissions from this equipment shall not be included under the emissions 

cap. [R307-401] 

Il.B.l.g Except for use in emergency generators, fuel oil shall not be burned in any existing 

, combustion device at the refinery except during periods of natural gas curtailment. 

Emergency generators shall be used for electricity producing operation only during the perio~s

when electric power from the public utilities is intemlpted, or for regular maintenance of the 

generators. ,Records documenting generator usage shall be kept in a log and they shall show 

the date the generator was used, the duration in hours of the generator usage, and the reason 

for each generator usage. 

Torch oil may be burned in the FCC(] regenerator to assist in starting, restarting, maintaining 

hot standby, or maintaining regenerator heat balance. 

Small (<100 HP) portable fuel oil-powered equipment is exempt from the requirements of this 

AO and related emissions are not to be used for purposes of deteImining compliance. [R307­

401] 

II.B.l.h 

I 

The ETF portable diesel generator shall not be operated more than 1,300 hours per rolling 12­

month period without prior approval in accordance with R307-401. The total hours of 

operation shall be determined by ,an engine hour totalizer or by supervisor monitoring and 

maintaining of an operationslog. [R307-40lJ 

Il.B.l.i The throughput of the catalytic cracking unit shall not exceed 3,250,000 balTels per rolling 12­

month period. Compliance with the annual throughput limit shall be measured with a 

throughput ~low meter. [R307-401J 

!I.B.l.j Compli~ce with fueannuallirnitations shall be deterririned on a rolling 12-month total except 

where specifically exempted or otherwise provided for. By the last day of each month, a new 

12-month total shall ,be calcula.ted using the previous 12 months. Records shall be kept for a 

period of five years. [R307-40J.] 

II.B.2 Conditions on the SRU/Tail gas incinerators (3 units) 

II.B.'2.a Copies of the SRU Operating Instruction/Standard shall be made available to the Executive 

Secretary upon request. [R307-401] 

!I.B.2.b Holly shall utilize monitors to measure volumetric flow rates from the Unit 17 SRU stack. 

The flow measurement shall be in accordance w,ith the requirements of 40 CPR 52, Appendix 

E; 40 CPR 60 Appendix B; or 40 CFR 75, Appendix A. [R307-40 1] 

II.B.2.c The three SRUs shall each achieve 95% reco)'ery efficiency for all periods of operation except 

during periods of startup, shutdown or malfunction of the SRU [R307-40 IJ 
DAQE-ANOI01230031-10
 

Page 11 

n.B.2.d	 The Unit 17 SRUITail gas incinerator shall be equipped with a CEMS to measure S02 

emissions. The95% recovery efficiency shall be determined on a daily basis; however 

compliance shall be determined on a 30-day rolling average basis by measuring the flow rate 

and concentration of hydrogen sulfide (H2S) in the feed streams going to the Unit 17 SRU and 

by measuring the S02 emissions with the CEMS at the ~RU incinerator. The flow rate shall 

be determined continuously; the H2S concentration ~hall be determined quarterly for the first 

four quarters and at least semiannually thereafter. The flow rate and the H2S concentration 

values shall be used to determine the daily feed rate.· 

The 95% recovery efficiency for the new SRVs shall be determined on a daily basis; however 

compliance shall be determined as outlined in Se~tion IX.H.l.i of the PM\o SIP. [R307-401] 

n.B.2.e	 .An sulfur pit emissions shall be routed to an SRU inc~eJ;:ator. [R307-401] 

1I.B.2,f	 Ifsulfur input to the Unit 17 SRU exceoos 20 long tons per day, NSPS Subparts A and J shall 

apply. (40 CPR 60 Subpart J]' . 

n.B.2.g	 The refinery may exercise an option to trade allowed annual SRU S02 emissions for cap 

sources' S02 emissions in the event the Unit 17 SRU is operating at better than 95% 

efficiency. This option shall not be made available until at least one year of data (12 

efficiency determinations), as described below, has been collected and a trade-off request is 

submitted to and approved by the Executive Secretary. The (Unit 17 SRU) 24-hour minimum 

.operating efficiency shall have been demonstrated to be no less than 95%. When the SRU 

efficiency, as determined below, is greater than 95%, adjustments to the annual S02 emission 

limit fOJ; 'cap sources (see Special Provisions ILA.61(S02), JI.A.62 (NOJ, and 1I.A.63 (pM10) 

for ~e definitions of cap sources] may be made by the following procedure: 

An adjusted alUlUal cap emission limit is the annual cap sources' emission limit adjusted 

upward. This adjustment is derived from S02 emission decreases resulting from a better than 

95% efficient SRU operation. 

The adjusted annual cap emissi.9n limit shall only be used for compliance demonstration 

purposes. The combined annual total cap sources' and SRU S02limit used for attainment and 

maintenance demonstration shall not be increased. 

Daily compliance limits shall not be adjusted. [R307-401) . . 

n.B.3	 Conditions on SO~ emissions sources 

n.B.3.a	 The emission of S02 into the atmosphere [excluding the (51-6) CO BoilerlFCC Scrubber, 

emissi.ons from flar~ and during SRU down times} shall not exceed 954 tons/year. 

Emissions of S02 shall be limited as follows: 

Emission Points	 EInissions (TPD) Total Emissions (tons/yr)' 

.(17-1) SRU Tail Gas Incinerator 1.60 582 

SRU Tail Gas Incinerator #1 0.25 90 

SRU Tail Gas Incinerator #2 0.25 90 

Emission Cap sources 0.53 192 
DAQE-AN0101230031-10
 

Page 12 

Tons Per Day (TPD) =Daily 24-hol,U" total. Daily means an interval oHime between two 

con'secutive midnights. 

. For all above listed emission points a CEM shall be used to determine compliance as oulined 

in II.B.3.d. [R307-401] 

n.B.3.b	 Prior to the installation of the FCC Scrubber but not aft~r December 31, 20 12, the emissions of 

S02 into the atmosphere from the (51-6) CO Boiler shall not exceed the following: 3.147 TPD 

or 1148.83 tons/year . 

Upon installation of the FCC Scrubber but no latter than December 31, 2012, the emissions Qf 

S02 into the atmosphere from die (5106) CO BoilerlFCC Scrubber shall not exceed the 

following: 1.93 TP~ or 706 tons/year. 

Tons Per Day (TPD) = Daily 24-hour total. Daily means an interval oftime between two 

consecutive midnights. 

For emission point (51-6) stack testing shall be performed as outlined in condition n.B.l.a.. 

[R307-401] 

n.B.3.c	 The follm.ying sources shall not be regulated for S02 emissions, nor shall they be included in 

the emission limitation totals herein: 

(66-1) Process Flare South
 

(66-2) Process Flare North
 

(68-1) Propane Pit Flare
 

Emergency Equipment
 

[R307-401] 

n.B.3.d	 S02 emissions for the emissions cap sources shall be determined 'by applying the following 

emission factors or emission factors determined from the most current performance testing to 

the relevant quantities of fuel burned. S02 emission factors for the various fuels shall be as. 

follows: 

Natural gas - 0.60 lb S02ftv.lMscf (Compressors Only) 

Plant gas - The emission factor to be used in conjunction with plant gas combustion shall be 

determined through the use of a continuous emissions monitor which will measure the H2S ' 

content of the fuel gas in parts per million by volume (ppmv). Daily emission factors Shall be 

calculated using average daily H2S content data from the continuous emissions monitor . 

(CEM). The emission factor shall be calculated as follows: . 

(lb S02fMMscf gas) = (24 hr avg. ppmv H2S)/l01\6 '" (64lb S02/lb mole) '" (10~

scflM:M:scf)/(379 scf lIb mole) 

Fuel oil - The emission factor to be ·used in conjunction with fuel oil combustion (during 

natural gas curtailments) shall be calculated based on the weight percent of sulfur, as 

determined by ASTM Method 0-4294-89 or approved equivalent, and the density of the fuel. 

oil, as follows: 
· DAQE-AN0101230031-10
 

Page 13
 

(lb of S02l'kgal) =(density lb/gal) * (1000 gal/kgal) * (wt. %S)/100 >I< (64 g SOz/32 g S)
 

The weight percent sulfur and the fuel oil density shall be recorded for each day any fuel oil is
 

combusted. Fuel oil may be combusted only during periods of natural gas curtailment. The
 

sulfur content of the fuel oilshall be tested if directed by the Executive Secretary.
 

Fuel Consumption shall be measured as follows:
 

Natural gas consumption shall be detennined by the meter totalizer on the natural gas supplied
 

to the plant. '
 

Plant gas consumption shall be determined through the use of flow meters.
 

Fuel oil consumption shall be measured each day by means of leveling'gauges on all tanks that
 

supply oil to combustion sources. .
 

The equations used to determine emissions for the emission cap'sources shall be as follows:
 

Emissions (tons/day) =Emission Factor (lblMMscf) * Natural GaS Consumption
 

(MMscfi'day)/(2,OOO lb/ton)
 

, Emissions (tons/day) =Emission Factor (lblMMscf) .,. Plant Gas Consumption 

(MMscf/day)/(2,OOO lb/ton) 

Emissions (tons/day) =Emission Factor (lblkgal) *Fuel Oil.Consumption (kgal/24 hrq)/(2,OOO 

IMon) 

Total daily S02 emissions for the sources included in the emissions cap shall be calculated by 

adding the daily results of the above'S02 emissions equations for natural gas, plant gas, and 

fuel oil combustion; Results shall be tabulated for every day, and records shall be kept which 

include the CEM readings for H2S (averaged for each one:-hour period), all meter readings (in 

the appropriate units), fuel oil parameters (density and wt. %8, recorded for. each day any fuel, 

oil is.burned), and the calculated emissions. [R307-40lJ . 

II.B.4	 Conditions on NO~ emissions sources 

II.BA.a MaximumNOx emissions to the atmosphere shall not exceed 2.09 tons per day. The emissions (. of NO. from all sources shan not exceed 669 tons/year. [R307-401] 

ILBA.b	 The following sources shall not be regulated for NOx emissions, nor shall they be included in 

the emission limitation totals herein: 

(66-1) Process Flare South
 

(66-2) Process Plare North
 

(68-1) Propane Pit Flare
 

Emergency Equipment
 

[R307401J 

II.B.4.c	 NO. emissions for the Emissions Cap Sources shall be determined by applying the following 

emission factors or emission factors determined from the most current performance testing to 

the relevant quantities of fuel combusted. 
DAQE-ANOlO123003l-l0 

Page 14 

Boilers and Furnaces: 

Natural gas/refinery fuel gas combusted using Low NO. burners: BllbslMMscf 

Natural gas/refinery fuel gas combusted using Ultra-Low NO. burners: 4llbsIMMscf 

Natural gas/refmery ftlel gas combusted using all other burners: 140 IbslMMscf 

Natural gas/refmery fuel gas combusted u'sing SCR: 4llbslMMscf 

All fuel oil combustion:· l20lbsIKgal 

Where "Natural gaskefinery fuel gas" shall repres~nt any combustion ofnaturaI gas, refinery 

fuel gas, or combination of the two in the associated burner. 

Daily natural gas consumption shall be determined by the meter totalizer on the natural gas 

supplied to the plant. 

Daily plant gas consumption shall be determined through the use of flow meters. 

Daily fuel oil consumption shall be monitored by means of leveling gauges on all tanks that 

supply combustion sourcell. Fuel oil consumption shall be allowed only during periods of 

natural gas curtailment. 

The equations used to determine emissions for the boilers and furnaces shall be as follows: 

Emissions (tons/day) =Emission Factor (lbJMM:scf) *Natural Gas Consumption 

(N.lMscflday)/(2,OOO lb/ton) 

Emissions (tons/day) = Emission Factor (lblMMscf) *Plant Gas Consumption 

(M1vfscf/day)/(2,OOO lb/ton) 

Emissions (tons/day) = Emission Factor (lblkgal) *Fuel Oil Consumption (lcgal/day)/(2,OOO 

lb/ton) . 

Compressor~:

The NOx Emission Factor for natural gas (finn supply) combustion in the compressor drivers 

shall be 3400 lblMMscf. 

Daily natural gas (fum supply) consumption for the compressor drivers shall be quantified by 

meters, which shall be installed if necessary, that will differentiate the flow of natural gas to 

the compressors from the flow to the boilers and furnaces. 

The eInissions shall then be determined using the following equation: 

Emissions (tons/day) =Emission Factor (lblNlMscf) *Natural Gas Consumption 

CMMscflday)/(2,OOO lb/ton) 

Total 24-hour NO. emissions for sources included in the emissions cap shall be calculated by 

adding the results of the above NOx equations for plant gas, fuel oil, and natural gas 

combustion. Results sliall be tabulated for every day, and records shall be kept which include 

the meter readings (in the appropriate units), emission factors, and the calculated emissions. 

See Section IX.H.l.i(2) of the PMIO SIP for details of compliance determination. [R307-401] 
DAQE-ANOI01230031-10 

Page 15 

n.B.5 Conditions on PM10 emissions sources 

n.B.5.a Prior to the installation of the FCC Scrubber. but no later than December 31. 2012. the 

emissions ofPM1o into the atmosphere from the (51-6) CO Boiler shall not exceed 0.36 TPD 

or 131.4 tons/year. PMIO emissions from the emission capped sources shall not exceed 0.13 

TPD or 47 tons/year. 

n.B.5.b 

Upon the installation of the FCC Scrubber. but no later than December 31,2012. the . 

emissions ofPM1o into the atmosphere from the (51-6) CO BoilerlFCC Scrubber shall not 

exceed 0.09 TPD or 32 tons/year. PM10 emissions from the emission capped sources shall not 

exceed 0.13 TPD or 47 tons/year.. [R307-401] 

The following sources shall not be regulated for PM10 emissions, nor shall they be included in 

.the emission limitation totals herein: . 

(4-4a) 4K1A KVG Compressor West 

(4-4b) 4K1B KVG Compressor East 

(6-4a) 6Kl SVG Compressor East 

(6-4b) 6K2 SVG Compressor West 

(66-1) Process Flare South 

(66-2) Process Flare North 

(68-1) Propane Pit Flare . 

Emergency Equipment 

[R307-401] 

n.B.5.c PM10 emissions for the Emissions Cap Sources shall be determined by applyingtbe following 

emission factors or emission factors determined from the most current performance testing to 

the relevant quantities of fuel combusted in eachunit. PMIO Emission Factors for the 

combustion sources will be as follows: 

Natural gas: 5 lb PM1ofIv[M:scf 

Plant gas: 5 lb PMll/MMscf 

The PM10 emission factor for fuel oil combustion shall be determined based on the H2S '. 

content of the fuel oil as follows: . -

PMlO (lblkgal) = (10 ;I; wt%S) + 3 

Daily natural gas consumption for each cap source shan be detenni.ned by the meter totalizer 

on the natural gas supplied to the pICUlt. . 

Daily plant gas consumption for each cap source shall be determined through the use of flow 

meters. 

, Daily fuel oil.consumption shall be monitored by means of leveling gages on all tanks that 

supply fuel oil to combustion sources. Fuel oil consumption shall be allowed only during 

periods of natural gas curtailment. . . 

The equations used to determine emissions for the boilers and furnaces shall be as follows: 
DAQE-AN0101230031-10
 

Page 16
 

Emissions (tons/day) =Emission Factor (lblMMscf) * Natural Gas Consumption 

(MMscflday)/(2,000 lb/ton)' , 

Emissions (tons/day) =Emission Factor (lblMMscf) ole Plant Gas Consumption 

(MMscf/day)/(2,OOO lb/ton) 

Emissions (tons/day) ;:::; Emission Factor (lblkgal) * Fuel Oil Consumption (kgallday)/(2,OOO . I lb/ton) 

Total 24-hour PMIO emissions for the sources included in the einissions cap shall be calculated 

by adding the daily results ofthe above PM10 .emissions equations for natural gas, plant gas, 

ancI fuel oil coinbustio~. Result& shall be tabulated for every day, and records shall be kept 

which include all meter readings (in the .appropriate units), fuel oil parameters (wt. %S), and 

the calculated emissions. For the details of compliance demonstration, refer to Section 

IX.H.1.i(2) of the PM10 SIP. [R307-401] 

Section ill: APPLICABLE FEDERAL REQumEMENTS 

In addition to the requirements of this AO, all applicable provisions of the following federal programs 

have been found to apply to this installation. This AO in no way releases the owner or operator from any 

liability for compliance with another applicable federal, st~te, and local regulations including UAC 

R307. 

NSPS (part 60), J: Petroleum Refmeries
 

NSPS (Part 60), Dc: Small Indus Com InstitnSteamGenratr·
 I 

I MACT (part 63), CC: .Petroleum Refineries . I,: 

I	 NBSHAP (Part 61), FF: Benzene Waste Operations 

NSPS (part 60), GOG: VOC Equip Leaks Petro Refineries. 

/' MACT (Part 63), ZZZZ: Recipro. Int. Comb Engine (RlCE) l' NSPS (Part 60), QQQ: VOC Bmis Petro RefWastewtr Sys 

NSPS (part 60), A: General Provisions 

MACT (Part 63), UUU:Petro Refineries Cat Crkg,Ref,SPU 

MACT(part 63), R: Gasoline Distribution 

NSPS (Part 60), Kb: VolatLiqlPetroStorageVesseI7/23/84 

PERMIT HISTORY 

This AO is based On the following documents: 

. . 

Is Delived From 

.Supersedes 

Is Derived From 

Is Derived From 

Addi~onalInformation: CO Source Wide PTEs dated November 

17,2009 

DAQE-ANOr01230027-C9 dated November 3, 2009 

Updated NO! dated October 19,2009 

NO! dated September 28, 2009 
" 

DAQE-ANO101230031-10
 

Page 17
 

ACRONYMS 

The following lists cOmlnonly used acronyms and associated translations as they apply to tbis document: 

40CFR
 

AO
 

BACT
 

CAA
 

CAAA
 

CDS
 

CEM"
 

CEMS
 

CPR 

CO 

COM 

DAQ 

DAQE 

EPA 

HAP6rHAP~

ITA· 

LBIHR
 

MACT
 

MMBTU
 

NAA
 

NAAQS
 

NESHAP
 

.. Nor 

NOx
 

NSPS
 

NSR
 

PM10
 

PM2.5
 

PSD
 

PTE 

R307
 

R307-401
 

S02 

Title IV 

Title V 

TPY 

UAC 

UDAQ
 

VOC
 

Title 40 of the Code ofFederal Regulations 

Approval Order 

Best Available Control Technology 

Clean Air Act 

Clean Air Act Amendments 

Classification Data System (used by EPA to classify sources by size/type) 

Continuous emissions monitor 

Continuous emissions monitoring system 

Code of Federal Regulations 

Carbon monoxide 

Continuous opacity monitor 

Division of Air QuaJ.i~ (typically interchangeable with UDAQ) 

This is a document tracking code for internal UDAQ use 

Environmental Protection Agency 

Hazardous air pol1utant(s) . 

Intent to Approve 

Pounds per hour . 

Maximum Achievable Control Technology 

Million British Thermal Units 

Nonattainment Area 

.National Ambient Air Quauty Standards 

National Emission Standards for ~ardous Air Pollutants 

Notice of Intent 

Oxides of mtrogen . 

New Source Performance Standard 

New Source Review . . " 

Particulate matter less than 10 microns in size 

Particulate matter less than 2.5 microns in size 

Prevention of Significant Deterioration 

Potential to Emit 

Rules Series 307 

Rules Series 307 - Section 401 

Sulfur dioxide 

Title IV of the Clean Air Act· 

Title V of the Clean Air Act 

Tons per year 

Utah Administrative Code 

Utah Division of Air Quality (typically interchangeable with DAQ) 

Volatile organ.lc compounds