Utah State Implementation Plan
 

Emission Limits
 

and Operating Practices
 

Section IX, Part H 

Adopted by the Air Quality Board
 

July 6. 2005
 
Adopted by the Air Quality Board 011 July 6. 2005 

Table of Contents 

IX.H.I General Requirements I
 

IX.H.2 Source-Specific Particulate Emission Limits for Salt Lake County 4
 

a. Bountiful City Power 4
 

b. Central Valley Water Reclamation Facility 5
 

c. Chevron Products Co 7
 

d. Flying J Inc., Big West Oil Co 9
 

e. Geneva Rock Products, Point of the Mountain 12
 

f. Holly Refining and Marketing Co 13
 

g. Interstate Brick 15
 

h. Kennecott Utah Copper: Mine and Coppenon Concentrator 16
 

J. Kennecott Utah Copper: Power Plant and Tailings Impoundment.. 17
 

j. Kennecott Utah Copper: Smelter and Refinery 21
 

k. PacifiCorp, Gadsby Power Plant 26
 

1. Tesoro West Coast 27
 

m West Valley Leasing CO,tLC: West Valley Power Plant 28
 

urce-5pecific Particulate Emission Limits for Utah County 30
 

a. Altemative Requirements 35
 

b. Demonstrating Equivalency of an Altemative Requirement 35
 

c. Procedure 36
 

Section IX, Part H, page 2 
Adopted by the Air Quality Board on July 6, 2005 

IX.H EMISSION LIMITS AND OPERATING PRACTICES 

(Adopted 24 September 1990 and updated June 28,1991; February 27,1997; July 3,2002; and July 6, 

2005.) 

IX.H.I General Requirements. 

The terms and conditions of this Subsection IX.H.l shall apply to all sources subsequently addressed in 

Subsection IX.H.2 and 3. Should any inconsistencies exist between these two subsections, the sourcespecific conditions listed in IX.H.2 and 3 shall lake precedence. 

a.	 Stack testing to show compliance with the emission limitations for the sources in this appendix shall 

be perfonned in accordance with 40 CPR 60, Appendix. A; 40 CFR 51 Appendix M; and R307-30S-5. 

The back half condensibles are required for inventory purposes. The following test methods shall be 

used for the indicated air contaminants: 

'(1) PMIQ	 For stacks in which no liquid drops are present, the following methods shall be used: 

40 CPR 51, Appendix M, Methods 201 or 201a plus the back half condensibles using 

Method 202, or other appropriate EPA approved reference method, 

For stacks in which liquid drops are present, methods to eliminate the liquid drops 

should be explored. If no reasonable method to eliminate the drops exists, then the 

following methOds shall be used: 40 CPR 60, Appendix. A, Method 5, Sa, 5d, 5e, 

plus back half condensibles using method 202, or other appropriate EPA approved 

reference method. All particulate captured in the back half shall be considered PMIO• 

The PMIO captured in the front half shall be considered for compliance purposes. 

Appendix A. Method 6, 6A, 6B or 6C 

(3) NOx	 Appendix A, Method 7, 7A. 7B, 7C, 7D or 7E 

(4) Sample	 Appendix A, Method I
 

Location
 

(5) Volumetric	 Appendix A, Method 2
 

Flow Rate
 

(6) Calculations To determine mass emission rates, the pollutant concentration as dctennined by the 

appropriate methods above shall be multiplied by the volumetric flow ratc and any 

necessary conversion factors to give the results in the specified units of the emission 

limitation. 

Notification of the test date shall be provided at least 30 days prior to the test. A pretest conference 

shall be held if directed by the Executive Secretary. The emission point shall be designed to conform 

to the requirements of 40 CFR 60, Appendix A, Method I, and Occupational Safety and Health 

Administration (OSHA) approvabJe access shall be provided to the test location. The production rate 

during all compliance testing shall be no less than 90% of the maximum production achieved in the 

previous three (3) years. 

Section IX, Part H, page 1 
Adopted by the Air Quality Board all July 6. 2005 

b.	 Compliance with the annual limitations shall be determined based on a rolling 12-month total. By the 

last day of each month a new 12-month total shall be calculated using data from the previous 12 

months. 

c.	 Any information used to determine compliance shall be recorded for all periods when the plant is in 

operation, and such records shall be kept for a minimum of five years. Any or all of these records 

shall be made available to the Executive Secretary upon request. 

d.	 All installations and facilities authorized by this regulation shall be adequately and properly 

maintained. . 

e.	 The definitions contained in R307-101-2, Definitions, apply to Section IX, Part H. 

f.	 Visible emissions shall be as follows except as otherwise designated in specific source subsections: 

* baghouse applications shall not exceed 10% opacity;
 

'" scrubber and ESP applications shall not exceed 15% opacity;
 

'" combustion sources without control facilities shall not exceed 10% opacity;
 

* fugitive emissions shall not exceed 15% opacity; and
 

'" fugitive dust and all other sources shall not exceed 20% opacity.
 

g.	 Opacity observations of emissions from stationary sources shall be conducted in accordance with 40 

CPR 60. Appendix A, Method 9. For intermittent sources and mobile sources opacity observations 

shall be conducted using procedures similar to Method 9, but the requirement for observations to be 

made at I5-second intervals over a six minute period shall not apply. . 

h.	 All unpaved roads and other unpaved operational areas that are used by mobile equipment shall be 

water sprayed and/or chemically treated to control fugitive dust. Treatment shall be of sufficient 

frequency and quantity to maintain the surface material in a damp or moist condition. unless the 

ambient temperature is below freezing. The opacity shall not exceed 20% during all times. If 

chemical treatment other than magnesium chloride is to be used, the plan must be approved by the 

executive secretary. Records of water and/or chemical treatment shall be kept for all periods when 

the plant is in operation. The records shall include the following items: 

A.	 Date; 

B.	 Number of treatments made. dilution ratio, and quantity; 

C.	 Rainfall received, if any, and approximate amount; and 

D.	 Time of day treatments were made. 

Records of treatment shall be made avai lable to the executive secretary upon request and shall include 

a period of two years ending with the date of the request. 

1. Petroleum Retineries. 

(1) All petroleum refineries in or affecting the PM10 nonattainmentlmaintenance area shall, for the 

purpose of this PMIO SIP: 

(a)	 remove a minimum of 95% of the sulfur from feed streams processed by the sulfur recovery unit 

(SRU) for all periods of operation except for startup, shutdown, or malfunction of the SRU. The 

feed streams to be processed shall include the acid gas from the amine regeneration unit and the 

sour-water stripper. SRU efficiency shall be estimated and reported to the Executive Secretary a 

minimum of once per year. 

Section IX, Part H, page 2 
Adopted by the Air Quality Board on July 6, 2005 

(b) reduce the H2S content of the refinery plant gas to 0.10 grainJdscf (160 ppm) or less, except 

during startup, shutdown, or malfunction of the amine plant. Compliance shall be based on a 

roUing average of 24 hours. The owner/operator shall install and maintain a continuous 

monitoring system for monitoring the H2S content of the refinery plant gas and a continuous 

recorder to record the H2S in the plant fuel gas. The monitoring system shall comply with all 

applicable sections ofR307-170 and 40 CPR 50, Appendix B. Specification 7. As used herein, 

refinery "plant gas" shall have the meaning of "fuel gas" as defined in 40 CPR 60, Subpart J, and 

may be used interchangeably. 

If the monitor reading is not available, the refinery plant gas shall be sampled as closely to the 

monitor location as safely possible at least once each day. The sample shall be analyzed for 

sulfur content by use of a chemical detector tube capable of reading the required concentration 

(e.g., Drager Hydrogen Sulfide No. lID or equivalent). 

For natural gas, compliance is assumed while the fuel comes from a public utility. 

(c)	 no longer burn fuel oil in external combustion equipment, except during periods of natural 

gas curtailment or as specified in IX.H.2. External combustion shall mean combustion that 

takes place at no greater pressure than one inch of mercury above ambient pressure. 

(d) achieve an emission rate equivalent to no more than 9.8 kg of S02 per 1,000 kg of coke burnoff from any Catalytic Cracking unit by use of low-SOx catalyst or equivalent emission 

reduction techniques or procedures, including those outlined in 40 CPR 60, Subpart J. Unless 

otherwise specified in IX.H.2, compliance shall be determined daily based on a rolling sevenday average. 

(e)	 not exceed 20% opacity at any process flare. Opacity at catalytic cracking units, including 

those with ESP facilities, shall not exceed 20%, with compliance to be determined in 

accordance with Subsection (g) above. 

(2) Compliance Demonstrations. 

(a) (a)Compliance with the maximum daily (24-hr) plant-wide emission limitations for PMlO, 

S02, and NOx shall be determined by adding the calculated emission estimates for all fuel 

burning process equipment to those from any stack-tested or CEM-measured source 

components. NOx and PMIO emission factors shall be determined from AP-42 or from test 

data. 

For SOx. the emission factors are: 

Natural gas: EF =0.60 IblMMscf 

Propane: EF = 0.60 Ib/MMscf 

Plant gas: the emission factor shall be calculated from the H2S measurement required in 

IX.H.I.i( l)(b). The emission factor, where appropriate, shall be calculated as follows: 

(lb SOlMMscf gas) =(24 hr avg. ppmv H2S)/106 * (64 lb SOz/lb mole) * (106 

scflMMscf) 1(379 scf lib mole) 

Section IX. Part H, page 3 
Adopted by the Air Quality Board on July 6. 2005 

Fuel oils (when permitted): The emission factor shall be calculated based on the weight 

percent of sulfur, as detennined by ASTM Method D-4294-89 or approved equivalent, and the 

density of the fuel oil, as follows: 

EF (lb SO:z/k gal) = density (lblgal) * (1000 gallk gal)'" wt.% SIlOO * (64lb SOi32lb S) 

Where mixtures of fuel are used in an affected unit. the above factors shaH be weighted 

according to the use of each fuel. 

(b) Daily emission estimates for stack-tested source components shall be made by multiplying 

the latest stack-tested hourly emission rate times the logged hours of operation (or other 

relevant parameter) for that source component for each day. This shall not preclude a source 

from determining emissions through the use of a CEM that meets the requirements ofR307­

170. 

(c) The sulfur dioxide concentration in the flue gas of Sulfur Recovery Units shall be determined 

by a continuous emission monitor that meets or exceeds the requirements contained in 40 

CFR 60, Appendix B, Performance Specification 2. The monitor shall be maintained and 

calibrated in accordance with R307- 170. The mass flow rate of the flue gas shall be 

detennined by a volumetric flow measurement device that meets or exceeds the requirements 

contained in 40 CPR 52 Appendix E. 

(d) Any parameters necessary to determine compliance, including but not limited to: CEM data, 

fuel gas meter readings, hours of operation for stack-tested source components, and the 

calculated emissions, shall be recorded on a daily basis. These records shall be kept for a 

minimum of five years. Any or all of these records shall be made available to the Executive 

Secretary upon request. 

(e) The emissions increase (above normal operations) experienced during the SRU routine 

turnarounds shall not be included in the daily (24-hr) or annual compliance demonstrations. 

(f)	 Emissions due to upset flaring shall not be included in the daily (24-hr) or annual compliance 

demonstrations. 

(3) SRU maintenance period 

(a) The routine turnaround maintenance period (expected every 2 to 5 years for approximately a 

15 day period) for a Sulfur Recovery Unit shall only be scheduled during the period of April 

1 through October 31. The projected SRU turnaround period shall be submitted to the 

Executive Secretary by April 1 of each year in which a turnaround is planned. Notice shall 

also be provided the Executive Secretary 30 days prior to the planned turnaround. 

(b) Alternatively, a source may choose to conduct its turnaround maintenance outside of the 

window identified in paragraph 3.A above; however, in such case the exemption provided in 

Subsection IX.H.1.i(2)(e) above shall no longer apply. 

Section IX, Part H, page 4 
Adopted by the Air Qualiry Board on July 6, 2005 

f. HOLLY REFINING AND MARKETING CO. 

(1) PM 10 Emissions 

DAILY LIMIT: 

Combined emissions of PM10 from all external combustion process equipment, including the 

Sulfur Recovery Unit Tail Gas Incinerator, shall be no greater than 0.444 tons per day. 

Emissions for the group of external combustion process equipment shall be determined daily by 

multiplying the appropriate emission factor from section IX.H.l.i.2 or from testing below by the 

relevant parameter (e.g. hours of operation. feed rate, or quantity offueI cornbusted) at each 

affected unit, and summing the results for the group of affected units. 

The emission factor for the (51-6) CO Boiler shall be determined by stack test. Testing is required 

once at least every five years. 

(2) S02 Emissions 

DAILY LIMIT: 

Combined emissions of S02 from gas-fired compressor drivers and all external combustion 

process equipment, including the Sulfur Recovery Unit Tail Gas Incinerator, shall be no greater 

than 4.714 tons per day. 

Emissions for gas-rued compressor drivers and the group of external combustion process 

equipment shall be determined daily by multiplying the appropriate emission factor from section 

IX.HJ.i.2 or from testing below by the relevant parameter (e.g. hours of operation. feed rate, or 

quantity of fuel combusted) at each affected unit, and summing the results for the group of 

affected units. 

Fuel Oil - 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 in external combustion process equipment only 

during periods of natural gas curtailment. 

The emission factor for the (51-6) CO Boiler shall be determined by stack test. Testing is required 

at least once every five years. Compliance with Subsection IX.H.I.i.(I)(d) above shall be 

determined as part of each test. Alternatively, S02 emissions from the (51-6) CO Boiler may be 

determined using a Continuous Emissions Monitor (CEM) in accordance with rx.H.l.i.2.b. 

Emissions from the SRUrrGI sha]] be determined daily by multiplying the sulfur dioxide 

concentration in the flue gas by the mass flow of the flue gas. 

(3) NOx Emissions: 

(a) DAlLY LIMIT: 

Combined emissions of NOx from gas-fired compressor drivers and all external combustion 

process equipment, including the Sulfur Recovery Unit Tail Gas Incinerator. shall be no greater 

than 2.20 tons per day. 

Section IX, Part H, page 13 
Adopted by the Air Quality Board on July 6, 2005 

Emissions for gas-fired compressor drivers and the group of external combustion process 

equipment shall be detennined daily by multiplying the appropriate emission factor from section 

IX.H.1.i.2 by the relevant parameter (e.g. hours of operation, feed rate, or quantity offuel 

combusted) at each affected unit, and summing the results for the group of affected units. 

(b) 12-MONTH LIMIT: 

Combined emissions ofNOx from gas-fired compressor drivers and all external combustion 

process equipment. including the Sulfur Recovery Unit Tail Gas Incinerator. shall be no greater 

than 693.0 tons per rolling twelve-month period. 

Section IX. Part H. page 14