DEPARTMENT OF ENVIRONMENTAL CONSERVATION

AIR QUALITY CONSTRUCTION PERMIT

Permit No. 0073-AC023 Issue Date: Final 7/13/01

Revises Permit-to-Operate No. 9673-AA005

The Department of Environmental Conservation, under the authority of AS 46.03, 46.14,

6 AAC 50, 18 AAC 15, and 18 AAC 50, issues a Construction Permit to the Permittee, BP

Exploration (Alaska), Inc., for Phase II of the project at the Milne Point Production Facility.

Under AS 46.14.130(a), this permit allows the Permittee to modify the facility in accordance

with terms and conditions of this permit. This permit contains terms and conditions necessary to

ensure that the Permittee will build and operate the facility in accordance with

18 AAC 50.315(e).

_______________________________________ ________________________________

John F. Kuterbach, Manager Date

Air Permits Program

G:\AWQ\AWQ-PERMITS\AIRFACS\BPX MILNE POINT\CONSTRUCTION\X02\FINAL\BP FINAL PERMIT AND SOB.DOC
Permit No. 0073-AC023 Page 2 of 49

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Issued: Final 7/13/01

TABLE OF CONTENTS

Section 1. Identification................................................................................................................4

Section 2. Permit Continuity.........................................................................................................5

Section 3. Source Inventory and Description................................................................................6

Section 4. Source-Specific Requirements.....................................................................................7

Fuel Burning Equipment Standards – Turbines, Heaters, Engines and Flare..............................7

Federal Emission Standards.........................................................................................................8

Section 5. Ambient Air Quality Protection Requirements..........................................................13

Owner Requested Limits............................................................................................................13

BACT and PSD Avoidance Limits from Previous Permits.......................................................17

Section 6. Prevention of Significant Deterioration Avoidance for NOX, SO2 and PM ..............20

Owner Requested Limits............................................................................................................20

Section 7. Best Available Control Technology (BACT) for CO................................................24

Section 8. Generally Applicable Requirements..........................................................................26

Section 9. General Source Testing and Monitoring Requirements.............................................28

Section 10. General Recordkeeping, Reporting, and Compliance Certification Requirements...34

Section 11. Standard Conditions Not Otherwise Included in the Permit......................................37

Section 12. Visible Emissions and Particulate Matter Monitoring Plan.......................................39

Section 13. Visible Emission Evaluation Procedures...................................................................41

Visible Emissions Observation Record......................................................................................44

Section 14. ADEC Notification Form...........................................................................................45

Section 15. Permit Documentation................................................................................................46
Permit No. 0073-AC023 Page 3 of 49

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Issued: Final 7/13/01

List of Abbreviations Used in this Permit

AAC .....................Alaska Administrative Code

ADEC...................Alaska Department of Environmental Conservation

AS.........................Alaska Statutes

ASTM...................American Society of Testing and Materials

BACT...................Best Available Control Technology

CEMS...................Continuous Emission Monitoring System

CFR......................Code of Federal Regulations

COMS..................Continuous Opacity Monitoring System

dscf.......................Dry standard cubic feet

EPA......................US Environmental Protection Agency

gr/dscf...................Grain per dry standard cubic feet (1 pound = 7000 grains)

HAPS....................Hazardous Air Pollutants [hazardous air contaminants as defined in

AS 46.14.990(14)]

H2S.......................Hydrogen Sulfide

ID..........................Source Identification Number

MACT..................Maximum Achievable Control Technology

KPa.......................kiloPascals

Mlb .......................thousand pounds

MMBtu.................Million British Thermal Units

NAAQS................National Ambient Air Quality Standards

NAICS..................North American Industry Classification System

NESHAPs.............Federal National Emission Standards for Hazardous Air Pollutants [as

defined in 40 CFR 61]

NSPS....................Federal New Source Performance Standards [as defined in 40 CFR 60]

RM........................Reference Method

PEMS ...................Predictive Emission Monitoring System

pph........................Pounds per hour

PPM......................Parts per million

PPMvd..................Parts per millions by volume, dry

PS.........................Performance specification

PSD......................Prevention of Significant Deterioration

RA ........................Relative Accuracy

SIC........................Standard Industrial Classification

SO2 .......................Sulfur dioxide

TPH......................Tons per hour

TPY......................Tons per year

VOC.....................volatile organic compound [as defined in 18 AAC 50.990(103)]
Permit No. 0073-AC023 Page 4 of 49

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Issued: Final 7/13/01

Section 1. Identification

Names and Addresses

Permittee: BP Exploration (Alaska), Inc.

900 East Benson Boulevard

Anchorage, AK 99508

Facility: The CFP, B-Pad, and E-Pad at the

Milne Point Production Facility

Physical Address: Milne Point Unit, North Slope, Alaska

70 deg 24 min N and 147 deg 54 min W

Owner: BP Exploration (Alaska), Inc.

900 East Benson Boulevard

Anchorage, AK 99519-6612

Operator: BP Exploration (Alaska) Inc.

900 East Benson Boulevard

Anchorage, AK 99508

Permittee’s Responsible Official Philip Aldis

Production and Field Manager

Designated Agent: CT Corporation System

801 West 10th Street, Suite 300

Juneau, AK 99801

Facility and Building Contact: Operations Supervisor

(907) 670-3331

SIC Code of the Facility: 1311

NAICS code of the Facility: 211111

[18 AAC 50.320(a)(1), 1/18/97]
Permit No. 0073-AC023 Page 5 of 49

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Issued: Final 7/13/01

Section 2. Permit Continuity

1. Except as revised or as rescinded herein, or as superseded by an Air Quality Permit issued

under the authority of AS 46.14.170, the Permittee shall comply with terms and conditions

of Air Quality Control Permit to Operate No. 9673-AA005 as amended through

January 17, 1997.

2. If permit terms and conditions listed in this permit conflict with those of Air Quality

Control Permit to Operate No. 9673-AA005, the Permittee shall comply with terms and

conditions listed herein.

3. The terms and conditions, and Exhibits A through C of Air Quality Permit-to-Operate

9673-AA005 are rescinded and replaced with the terms and conditions of this permit.

4. Exhibit E, Permit Documentation of Permit to Operate No. 9673-AA005 is rescinded and

replaced by Section 15 of this permit.

[18 AAC 50.340(i), 7/2/00]
Permit No. 0073-AC023 Page 6 of 49

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Issued: Final 7/13/01

Section 3. Source Inventory and Description

Regulated sources at the facility are shown below. Source descriptions and ratings are shown

for identification purposes only.

[18 AAC 50.335(e), 1/18/97]

Table 1 – Source Inventory

Facility Tag Location Description Nominal

Capacity

Maximum Rate/Capacity Fuel Type

Turbines

PU-0701,

PU-0801

CFP GE LM-2500 29,500 hp 29,500 hp Natural Gas and

Diesel

Heaters

H-5302A CFP Thermoflux 30.0 MMBtu/hr 35.0 MMBtu/hr Natural Gas

H-5302B CFP Thermoflux 30.0 MMBtu/hr 35.0 MMBtu/hr Natural Gas

H-4510A E-pad Latoka 14.4 MMBtu/hr 14.4 MMBtu/hr Natural Gas

H-4510B E-pad Latoka 14.4 MMBtu/hr 14.4 MMBtu/hr Natural Gas

H-5701A CFP Thermoflux 22.7 MMBtu/hr 29.0 MMBtu/hr Natural Gas and

Diesel

H-5701B CFP Thermoflux 22.7 MMBtu/hr 29.0 MMBtu/hr Natural Gas and

Diesel

H-2001A B-pad Thermoflux 13.1 MMBtu/hr 17.5 MMBtu/hr Natural Gas

H-2001B B-pad Thermoflux 13.1 MMBtu/hr 17.5 MMBtu/hr Natural Gas

Engines

PU-0101A CFP Detroit Diesel 1,500 hp 1.5 MW Diesel

PU-0101B CFP Detroit Diesel 1,500 hp 1.5 MW Diesel

PU-0101C CFP Detroit Diesel 1,500 hp 1.5 MW Diesel

PU-0110A CFP Cummins 187 hp 187 hp Diesel

PU-0110B CFP Cummins 187 hp 187 hp Diesel

PU-47031 CFP Cat 3304 120 hp 120 hp Diesel

PU-2004 B-pad Cummins 600 hp 0.448 MW Diesel

Flare2

(no ID) CFP National, Inc. 0.34 MMscf/day 83 MMscf/day Natural Gas

NSPS Tanks

T-6101A CFP Fixed Roof 147,000 gallons 147,000 gallons Arctic Diesel

T-2002 B-pad Fixed Roof 11,800gallons 11,800gallons Methanol

Vents

Oil Reserve Tanks (T-6001, T-6101B)

Flotation Cells

Compressor Vents

TEG Reboiler

Vent Header

Drain Purge, Vent Purge Gas, Backwash Clarifier , Produced Water Surge

Tank, Tank T-5853, and Sand Slurry Tank (nitrogen purge)

CFP Vents CFP

Other Tanks (T-2001, T-6102A, T-6102B)

 

1

 PU-4703 is a non-road engine.

2

 Flare nominal capacity is for pilot and purge only.
Permit No. 0073-AC023 Page 7 of 49

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Issued: Final 7/13/01

Section 4. Source-Specific Requirements

Fuel Burning Equipment Standards – Turbines, Heaters, Engines and Flare

5. Visible Emissions. The Permittee shall not cause or allow visible emissions, excluding

condensed water vapor, emitted from Sources PU-0701, PU-0801, H-5302A & B, H4510A & B, H-5701A & B, PU-0110A & B, and the flare reduce visibility through the

exhaust effluent by greater than 20 percent for more than three minutes in any one hour.

[18 AAC 50.055(a)(1), 1/18/97]

[18 AAC 50.320(a)(2), 7/2/00]

5.1 Monitor, record and report according to Section 12.

[18 AAC 50.320(a)(2), 7/2/00]

6. Particulate Matter. The Permittee shall not cause or allow particulate matter emitted

from Sources PU-0701, PU-0801, H-5302A & B, H-4510A & B, H-5701A & B, PU0110A & B, and the flare to exceed 0.05 grains per cubic foot of exhaust gas corrected to

standard conditions and averaged over three hours. This particulate matter limit applies on

a per emission source basis.

[18 AAC 50.055(b)(1), 1/18/97]

[18 AAC 50.320(a)(2), 7/2/00]

6.1 Monitor, record, and report according to Section 12.

[18 AAC 50.320(a)(2), 7/2/00]

7. Sulfur Compound Emissions. The Permittee shall not cause or allow sulfur compound

emissions, expressed as SO2, from Sources PU-0701, PU-0801, H-5302A & B, H-4510A

& B, H-5701A & B, PU-0110A & B, and the flare to exceed 500 PPM averaged over three

hours.

[18 AAC 50.055(c), 1/18/97]

[18 AAC 50.320(a)(2), 7/2/00]

7.1 Comply with Conditions 18 and 19 that require the Permittee to use fuel oil with no

greater than 0.3% sulfur by weight and natural gas with no greater than 100 PPMvd

H2S. Fuel that complies with the sulfur limits in Conditions 18 and 19 complies with

Condition 7.

7.2 Monitor, record and report the fuel oil sulfur and the natural gas H2S content as

described under Conditions 11.2a, 11.2b, 18.1b, 18.1d, 18.1e, 19.2, 19.4, and 19.5 to

demonstrate compliance with Condition 7.

[18 AAC 50.320(a)(2), 7/2/00]
Permit No. 0073-AC023 Page 8 of 49

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Issued: Final 7/13/01

Federal Emission Standards

This section contains federal NSPS requirements. Turbines PU-0701 and PU-0801 are subject

to 40 CFR 60, Subparts A and GG. Heaters H-5302A & B are subject to 40 CFR 60, Subparts A

and Dc. Tanks T-6101A and T-2002 are subject to Subpart Kb.

Conditions 8 and 9 apply to Turbines PU-0701 and PU-0801, and Heaters H-5302A & B.

8. The Permittee shall maintain records of the occurrence and duration of any startup,

shutdown, or malfunction in the operation of an affected facility; any malfunction of the air

pollution control equipment; or any periods during which a continuous monitoring device

is inoperative.

[40 CFR 60.7(b), Subpart A, 7/1/99]

9. The Permittee shall not build, erect, install, or use any article, machine, equipment, or

process, the use of which conceals an emission which would otherwise constitute a

violation of an applicable standard.

[40 CFR 60.12, Subpart A, 7/1/99]

[18 AAC 50.045(c), 1/18/97]

Conditions 10 and 11 apply to Turbines PU-0701 and PU-0801.

10. The Permittee shall comply with the applicable provisions of 40 CFR 60, Subpart A as

follows:

[40 CFR 60, Subpart A, 7/1/99]

[18 AAC 50.040(a)(2)(V), 1/18/97]

10.1 Except as provided in Condition 10.2, submit an excess emissions and monitoring

system performance report containing the following information, for any time the

water-to-fuel ratio falls below the ratio established in Condition10.3c, and any time

the fuel oil sulfur content or natural gas H2S content exceeds the limits in

Conditions 11.2a(iii) or 11.2b(ii), respectively. Submit the reports on a quarterly

basis, postmarked no later than 30 days after the end of the last calendar quarter.

[40 CFR 60.7(c), Subpart A, 7/1/00]

a. The magnitude of excess emissions computed in accordance with

Condition 10.6, any conversion factors used, the date and time of

commencement and completion of each time period of excess emissions, and

the process operating time during the reporting period.

[40 CFR 60.7(c)(1), Subpart A, 7/1/99]

b. Identification of each period of excess emissions that occurred during startup,

shutdown, and malfunction of turbines PU-0701 and PU-0801; and the nature

and cause of any malfunction, and the corrective action taken or preventative

measures adopted.

[40 CFR 60.7(c)(2), Subpart A, 7/1/99]

c. The date and time identifying each period during which the flow meters were

inoperative except for zero and span checks and the nature of any repairs or

adjustments.
Permit No. 0073-AC023 Page 9 of 49

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Issued: Final 7/13/01

[40 CFR 60.7(c)(3), Subpart A, 7/1/99]

d. A statement indicating whether or not any excess emissions occurred or the

flow meters were inoperative, repaired, or adjusted, at any time during the

reporting period.

[40 CFR 60.7(c)(4), Subpart A, 7/1/99]

10.2 Submit a summary report form for excess emissions and monitoring system

performance in the format shown in Figure 1 of 40 CFR 60.7 as follows:

a. If the total duration of excess emissions for the reporting period is less than

1 percent of the total operating time for the reporting period and flow meter

downtime for the reporting period is less than 5 percent of the total operating

time for the reporting period, submit a summary report form instead of the

excess emissions report described in Condition 10.1, otherwise

[40 CFR 60.7(d)(1), Subpart A, 7/1/99]

b. submit both the summary report form and the excess emission report in

Condition 10.1.

[40 CFR 60.7(d)(2), Subpart A, 7/1/99]

10.3 No later than 180 days after installation of Direct Water Injection (DWI), and within

90 days after achieving the maximum production rate at which the affected facility

will be operated while using DWI, conduct source tests for NOX while using DWI

for natural gas and fuel oil as follows:

[40 CFR 60.8, Subpart A, 7/1/99]

a. Use reference methods and procedures approved by the Department.

[40 CFR 60.335(b), Subpart GG, 7/1/99]

b. Use Equation 1 to compute the NOX emission rate in volume percent:

Equation 1

0.5 19( 0.00633) 1.53 ( )( / ) (288 / )

a

H NOX NOXo Pr Po

e K T

O = °

−

Where:

NOX = emission rate of NOX at 15 percent O2 and ISO standard day

conditions3, volume percent

NOXo = observed NOX concentration corrected to 15 percent O2, PPM by

volume

Pr = reference combustor inlet absolute pressure at 101.3 kilopascals

ambient pressure, mm Hg

Po = observed combustor inlet absolute pressure at test, mm Hg

Ho = observed humidity of ambient air, g H2O/g air

 

3

ISO standard day conditions are defined as 288 °K (59 °F), 60% relative humidity and 101.3 kilopascals pressure

in 40 CFR 60.331(g).
Permit No. 0073-AC023 Page 10 of 49

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Issued: Final 7/13/01

e = transcendental constant, 2.718

Ta = ambient temperature, °K

[40 CFR 60.335(c)(1), Subpart GG, 7/1/99]

Multiply the NOX emission rate in volume percent by 10,000 to obtain the

NOX emission rate in PPM by volume.

c. Use the flow meters to measure the fuel consumption and water-to-fuel ratio

necessary to comply with the NOX standard in Condition 11.1 at 30, 50, 75,

and 100 percent of peak load or at four points in the normal operating range of

the turbine, including the minimum point in the range and peak load. All loads

shall be corrected to ISO standard day conditions using the appropriate

equations supplied by the manufacturer.

[40 CFR 60.335(c)(2), Subpart GG, 7/1/99]

d. Use Method 20 to determine the NOX and O2 concentrations. The span values

shall be 300 PPM of NOX and 21 percent O2. The NOX emissions shall be

determined at each of the load conditions specified in Condition 10.3c.

[40 CFR 60.335(c)(3), Subpart GG, 7/1/99]

10.4 Operate the flow meters required by Condition 11.1a continuously.

[40 CFR 60.13(e), Subpart A, 7/1/99]

10.5 Install the flow meters required by Condition 11.1a such that representative

measurements of natural gas and fuel oil usage and mass ratio of water to fuel are

obtained.

[40 CFR 60.13(f), Subpart A, 7/1/99]

10.6 Reduce data from the flow meters required by Condition 11.1a to 1-hour time

periods (60-minute commencing on the hour) computed from four or more data

points equally spaced over each 1-hour period. Data recorded during periods of flow

meter breakdowns, repairs, calibrations checks, and zero and span adjustments shall

not be included in the data averages computed under this condition. An arithmetic or

integrated average of all data may be used. The data shall be in units of a ratio of

water-to-fuel.

[40 CFR 60.13(h), Subpart A, 7/1/99]

11. The Permittee shall comply with the applicable provisions of 40 CFR 60, Subpart GG as

follows:

[40 CFR 60, Subpart GG, 7/1/99]

[18 AAC 50.040(a)(2)(V), 1/18/97

11.1 Do not exceed the NSPS NOX emission limit of 206.7 PPMvd, at 15 percent O2 and

ISO standard day conditions, 4 for each turbine.

[40 CFR 60.332(a)(2), Subpart GG, 7/1/99]

 

4

ISO standard day conditions are defined as 288 °K (59 °F), 60% relative humidity and 101.3 kilopascals pressure

in 40 CFR 60.331(g).
Permit No. 0073-AC023 Page 11 of 49

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Issued: Final 7/13/01

a. At the same time that Direct Water Injection (DWI) is installed on each turbine

as required under Condition 25.1, install, calibrate, and operate fuel flow

meters to measure natural gas and fuel oil usage and ratio of water to fuel.

Maintain at the facility copies of documentation showing that the meters were

calibrated to an accuracy of plus or minus five percent.

[40 CFR 60.334(a), Subpart GG, 7/1/99]

b. For the purpose of the reports required by Conditions 10.1 and 10.2, report as

excess emissions any 1-hour time period that the average water-to-fuel ratio, as

measured by the flow meters, falls below the water-to-fuel determined to show

compliance with the NOX standard in Condition 11.1 by the source test in

Condition 10.3. Each report shall include the average water-to-fuel ratio,

average fuel consumption, ambient temperature, and turbine load during the

period of excess emissions.

 [40 CFR 60.334(c)(1), Subpart GG, 7/1/99]

11.2 Either do not emit from the turbines exhaust that contains SO2 in excess of 0.015

percent by volume at 15 percent O2 on a dry basis, or do not burn in the turbines any

fuel that contains in excess of 0.8 percent sulfur by weight.

[40 CFR 60.333(a) & (b), Subpart GG, 7/1/99]

a. Monitor turbine liquid fuel sulfur content as follows:

(i) Until an alternative monitoring plan in Condition 11.2a(ii) is approved by

EPA, determine the sulfur content and nitrogen content of each shipment

of liquid fuel. Use ASTM method D 2880-71 to determine the sulfur

content and use ASTM method 3431-80 to determine the nitrogen content.

The analysis may be performed by the Permittee or by any other qualified

individual or organization.

[40 CFR 60.334(b)(1), Subpart GG, 7/1/99]

[40 CFR 60.335(a), (d), & (e), Subpart GG, 7/1/00]

(ii) Submit EPA approval of an alternative monitoring plan to the Department

within 30 days of approval.

[40 CFR 60.334(b)(2), Subpart GG, 7/1/99]

(iii) For the purpose of the reports required by Conditions 10.1 and 10.2, report

as excess emissions under NSPS anytime the liquid fuel sulfur content

exceeds 0.8 percent sulfur by weight.

[40 CFR 60.334(c)(2), Subpart GG, 7/1/99]

b. Monitor turbine gaseous fuel sulfur content monthly using length-of-stain tube

analysis as indicated in EPA approval letter dated January 18, 1990, and as

follows:

 [40 CFR 60.334(b)(2), Subpart GG, 7/1/99]

[EPA Approval letter, 1/18/90]
Permit No. 0073-AC023 Page 12 of 49

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Issued: Final 7/13/01

(i) Until a revised alternative monitoring plan in Condition 11.2b(ii) is

approved by EPA, if the gaseous fuel sulfur content as measured in

Condition 11.2b is greater than 50 PPM, analyze the H2S content of

natural gas daily using ASTM method D 1072-80, D 3031-81, D 4084-82,

or D 3246-81. The analysis may be performed by the Permittee or by any

other qualified individual or organization. Dilution of samples before

analysis may used with the approval of the Department.

[40 CFR 60.334(b)(1), Subpart GG, 7/1/99]

[40 CFR 60.335(d), Subpart GG, 7/1/99]

[40 CFR 60.335(e), Subpart GG, 7/1/99]

(ii) Submit EPA approval of a revised alternative monitoring plan to the

Department within 30 days of approval.

[40 CFR 60.334(b)(2), Subpart GG, 7/1/99]

(iii) For the purpose of the reports required by Conditions 10.1 and 10.2, report

as excess emissions under NSPS anytime the H2S content in the gaseous

fuel exceeds 0.8 percent sulfur by weight (4389 PPM).

[40 CFR 60.334(c)(2), Subpart GG, 7/1/99]

Condition 12 applies to Heaters H-5302A & B.

12. The Permittee shall comply with the applicable provisions of 40 CFR 60, Subpart Dc as

follows:

[40 CFR 60, Subpart Dc, 7/1/99]

[18 AAC 50.040(a)(2)(E), 1/18/97

12.1 Record and maintain records of the amount of natural gas combusted in H-5302A &

B each day.

 [40 CFR 60.48c(g), Subpart Dc, 7/1/99]

12.2 Comply with the recordkeeping requirements in Condition 8.

[40 CFR 60.48c(i), Subpart Dc, 7/1/99]

[40 CFR 60.7(f), Subpart A, 7/1/99]

Conditions 13 and 14 apply to Tanks T-6101A and T-2002.

13. The Permittee shall keep readily accessible records showing the dimension of the fuel

storage tank vessel and an analysis showing the capacity of the storage vessel.

[18 AAC 50.040(a)(2)(M), 1/18/97]

[40 CFR 60.110b(c), 40 CFR 60.116b(b), Subpart Kb, 7/1/99]

14. The Permittee shall keep copies of the above-required records for the life of the fuel

storage tank.

[18 AAC 50.320(a)(2), 7/2/00]

[40 CFR 60.110b(c), 40 CFR 60.116b(a), Subpart Kb, 7/1/99]
Permit No. 0073-AC023 Page 13 of 49

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Issued: Final 7/13/01

Section 5. Ambient Air Quality Protection Requirements

15. Flaring. For flaring events, calculate the monthly estimated emissions of PM, NOX, SO2,

and CO using published emission factors, and include copies of the calculations with the

operating report required under Condition 54.

[18 AAC 50.320(a)(2), 7/2/00]

16. Notification Requirements. The Permittee shall modify and operate the facility in

accordance with the application and application supplements listed in Section 15 of this

permit. Notwithstanding the regulations set forth in 18 AAC 50.300(h), the Permittee shall

notify the Department, in accordance with the following condition, prior to:

16.1 installing a stationary source at the facility that is not listed in Table 1 of this permit;

16.2 making a change to a source listed in Table 1 that would cause it to deviate from the

description of it provided in Table 1; or

16.3 making a change to the emission characteristics of a source listed in Table 1,

including adding waste heat recovery, in a manner that would increase the ambient

impact beyond that which the Department used when issuing this permit.

[18 AAC 50.320(a)(2), 7/2/00]

17. Notification Procedures. The Permittee shall use the following procedures when

notifying the Department pursuant to the previous condition:

17.1 For changes described by 18 AAC 50.370(a), notify the Department in accordance

with 18 AAC 50.370(b). The Permittee may implement the changes in accordance

with 18 AAC 50.370(c).

17.2 For all other changes,

a. ask the Department if additional ambient impact assessment modeling is

warranted for the proposed change;

b. within 60 days of receiving written Department notice that modeling is

warranted, prepare and submit to the Department an ambient impact

assessment for the specified air contaminant and averaging period; and

c. do not make the change until the Department concurs that the change will not

interfere with attainment or maintenance of ambient air quality standards and

maximum allowable ambient concentrations.

[40 CFR 50.320(a)(2), 7/1/99]

Owner Requested Limits

18. Fuel Oil Requirements: The Permittee shall burn fuel oil only as follows:
Permit No. 0073-AC023 Page 14 of 49

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Issued: Final 7/13/01

18.1 Burn fuel oil with no greater than 0.30 percent sulfur by weight in any of the fuelburning equipment listed in Table 1. Monitor as follows:

[18 AAC 50.320(a)(2), 7/2/00]

a. For Turbines PU-0701 & PU-0801 (Subpart GG turbines) measure the sulfur

content of the fuel oil as required in Condition 11.2a.

b. For all other fuel burning equipment listed in Table 1 except for Turbines PU0701 and PU-0801, measure the sulfur content of the fuel oil in the sales tank

at the Prudhoe Bay Topping Unit or Kuparuk Topping Unit according to

ASTM D 396-92 every time the fuel supply changes.

[18 AAC 50.350(g), 6/21/98]

c. Submit a report in accordance with Condition 52 whenever a fuel oil sulfur

content exceeds the limit in Condition 18.1.

[18 AAC 50.235(a)(2) & 18 AAC 50.240(c), 1/18/97]

[18 AAC 50.320(a)(2), 7/2/00]

d. Keep records of the sulfur content of each sample of fuel oil, and all test results

and calculations.

 [18 AAC 50.320(a)(2), 7/2/00]

e. Include copies of the records required under Condition 18.1d with the report

required by Condition 54.

[18 AAC 50.320(a)(2), 7/2/00]

18.2 The Permittee shall burn no more than one million gallons of fuel oil per 12

consecutive months at the CFP, B-Pad, and E-Pad in all of the equipment listed in

Table 1 and all other fuel burning equipment that may be present on the specified

pads, except for fuel burned in motor vehicles and in insignificant sources as listed at

18 AAC 50.335(r), (s), and (t). Emission sources on rotary drill rigs shall not be

excluded as insignificant sources.

[18 AAC 50.335(r), (s) & (t), 1/18/97]

[18 AAC 50.340(i), 1/18/97]

a. Measure the monthly total fuel oil delivered to the facility as follows,

(i) Use the fuel meters required by Condition 11.1a for Sources PU-0701 and

PU-0801.

(ii) For other fuel burning sources, the fuel use may be estimated by

calculations approved by the Department. Fuel meters, if used, must be

calibrated and certified by the manufacturer to be accurate within 5

percent.

b. Record the total fuel oil burned in the previous 12 consecutive months.

[18 AAC 50.320(a)(2), 7/2/00]

c. Submit a report in accordance with Condition 52 for any violations of the fuel

limit in Condition 18.2.
Permit No. 0073-AC023 Page 15 of 49

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______________________________________________________________________________________________________

Issued: Final 7/13/01

d. Include copies of the records required under Condition 18.2b with the report

required by Condition 54 for each of the past 6 months.

[18 AAC 50.320(a)(2), 7/2/00]

19. Natural Gas Requirements. The Permittee shall burn natural gas with no greater than

100 PPM H2S in any of the fuel burning equipment listed in Table 1.

[18 AAC 50.320(a)(2), 7/2/00]

19.1 For Turbines PU-0701 & PU-0801 (Subpart GG turbines) measure the H2S content

of the natural gas as required in Condition 11.2b.

19.2 For all other fuel burning equipment listed in Table 1 except for Turbines PU-0701

and PU-0801, measure the H2S content of the natural gas monthly using length-ofstain tube analysis.

 [18 AAC 50.320(a)(2), 7/2/00]

19.3 Submit a report in accordance with Condition 52 whenever the natural gas H2S

content exceeds the limit in Condition 19.

[18 AAC 50.235(a)(2) & 18 AAC 50.240(c), 1/18/97]

[18 AAC 50.350(a)(2), 7/2/00]

19.4 Keep records of the natural gas H2S content, and all test results and calculations.

 [18 AAC 50.320(a)(2), 7/2/00]

19.5 Include copies of the records required under Condition 19.4 with the report required

by Condition 54.

[18 AAC 50.320(a)(2), 7/2/00]

20. The Permittee shall comply with the annual operating hour restrictions shown in Table 2.

[18 AAC 50.320(a)(2), 7/2/00]

Table 2 – Annual Operating Restrictions

Facility Tag Restriction

H-5701A & B Operate no more than 200 hours during any 12

consecutive months, combined, while firing fuel oil

PU-0101A, B, & C Operate no more than 900 hours during any 12

consecutive months, combined

PU-0110A & B Operate no more than 600 hours during any 12

consecutive months, combined

PU-2004 Operate no more than 300 hours during any 12

consecutive months

PU-4703 Operate no more than 1,344 hours per year while at CFP,

B-pad, and E-pad

20.1 Maintain a daily log that includes the operating time in hours for each source listed

in Table 2.
Permit No. 0073-AC023 Page 16 of 49

______________________________________________________________________________________________________

______________________________________________________________________________________________________

Issued: Final 7/13/01

20.2 Each month, calculate the monthly operating time in hours for each source listed in

Table 2 and summarize the operating time in hours for the previous twelve months.

20.3 Submit a report in accordance with Condition 52 whenever the 12-month operating

hours summarized under Condition 20.2 exceed the restrictions listed in Table 2.

20.4 Include copies of the records required by Condition 20.2 with the report required by

Condition 54.

21. The Permittee shall comply with the daily operating scenarios shown in Table 3.

[18 AAC 50.320(a)(2), 7/2/00]

Table 3 – Daily Operating Restrictions 5

Facility Scenario 1 Scenario 2 Scenario 3

Tag Fuel Restriction Fuel Restriction Fuel Restriction

PU-0701 Natural Gas Unrestricted

PU-0801 Natural Gas Unrestricted

Natural

Gas/Diesel

900 lb

SO2/day

Natural

Gas/Diesel

900 lb

SO2/day

H-5701A Natural Gas Unrestricted Diesel Unrestricted Diesel

H-5701B Natural Gas Unrestricted Diesel Unrestricted Diesel

Combined

total of 24

hr/day

PU-0101A Diesel Diesel Diesel

PU-0101B Diesel Diesel Diesel

PU-0101C Diesel

Combined

total of 76.5

MW-hr/day Diesel

Combined

total of 15.0

MW-hr/day Diesel

Combined

total of 72.0

MW-hr/day

PU-0110A Diesel Diesel Diesel

PU-0110B Diesel

Combined

total of 12

hr/day

Diesel

Combined

total of 16

hr/day

Diesel

Combined

total of 12

hr/day

PU-2004 Diesel 9.8 MWhr/dayDiesel 9.8 MWhr/dayDiesel 9.8 MWhr/day

21.1 Operate under scenario 1 except as provided in Condition 21.2.

21.2 Operate under scenarios 2 or 3 only if natural gas is unavailable. Prorate operation

of each scenario used during each day.

21.3 Record the following:

a. For each source listed in Table 3, maintain a daily log that includes the

operating scenario and compliance data.

b. Each month, summarize the daily operating scenarios for the month.

21.4 Submit a report in accordance with Condition 52 for any violations of the daily

operating scenarios in Table 3.

 

5

 Equipment not listed in Table 3 is not subject to any daily operating restrictions.
Permit No. 0073-AC023 Page 17 of 49

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______________________________________________________________________________________________________

Issued: Final 7/13/01

21.5 Include copies of the records required by Condition 21.3b with the report required by

Condition 54.

BACT and PSD Avoidance Limits from Previous Permits

22. The Permittee shall comply with the following CO emission limits:

22.1 Heaters H-5302A & B, H-4510A & B, H-5701A & B, and H-2001A & B shall emit

no more than 0.2 lb/MMBtu of CO when firing natural gas.

[18 AAC 50.320(a)(2), 7/2/00]

22.2 Monitor, record and report by following established preventative maintenance

guidelines, and maintaining records of maintenance completed. Retain maintenance

records for five years, and submit records to Department upon request.

 [18 AAC 50.320(a)(2), 7/2/00]

23. The Permittee shall comply with the following NOX emission limits:

23.1 Turbines PU-0701 and PU-0801 shall emit no more than 184 PPMvd of NOX, each,

corrected to 15 percent O2. Comply as follows:

[18 AAC 50.320(a)(2), 7/2/00]

a. If not using Direct Water Injection (DWI),

(i) operate at no greater than 21,371 kW (generator output) each when using

natural gas.

(ii) operate at no greater than 7,771 kW (generator output) each when using

fuel oil.

b. If using DWI, load is restricted to maximum load at which compliance was

demonstrated for each fuel during any source test required under Condition

10.3, 38.2b, 38.2d, 39.1a(ii), or 39.1a(iv).

c. Conduct source tests as required in Condition 38.2 to demonstrate compliance

with the NOX BACT limit in Condition 23.1.

d. Record the load in kW for Turbines PU-0701 and PU-0801 for each hour of

the day and whether DWI was used.

e. Submit a report in accordance with Condition 52 any violations of the

operating load limits in Condition 23.1a, and any violations of the emission

rate limit in Condition 23.1.

f. Include copies of the records required by Condition 23.1d with the report

required by Condition 54.

[18 AAC 50.320(a)(2), 7/2/00]
Permit No. 0073-AC023 Page 18 of 49

______________________________________________________________________________________________________

______________________________________________________________________________________________________

Issued: Final 7/13/01

23.2 Heaters H-5302A & B shall emit no more than 0.05 lb of NOX/MMBtu, each; H4510A & B shall emit no more than 0.08 lb of NOX/MMBtu, each; and H-5701A &

B shall emit no more than 0.08 lb of NOX/MMBtu, each, while firing natural gas and

11.3 lb of NOX/hr (based on HHV) while firing fuel oil. Comply as follows:

[18 AAC 50.320(a)(2), 7/2/00]

a. No later than 180 days after permit issuance, and upon Department request,

conduct source tests for NOX to ascertain compliance with the emission limit

in Condition 23.2 for H-5701A, when firing natural gas. Conduct source tests

in accordance with the requirements in Section 9. Determine the NOX

emission rate for the heater using exhaust properties determined by both

Method 19 and exhaust gas measurements in Section 9. Compliance with the

NOX emission rate will be determined using Method 19.

b. Submit a report in accordance with Condition 52 any exceedance of the limits

in Condition 23.2.

c. Submit a copy of the source test results to the Department within 45 days of

test, as required by Condition 47.

[18 AAC 50.320(a)(2), 7/2/00]

23.3 Heaters H-2001A & B shall emit no more than 0.08 lb of NOX/MMBtu at any time.

Comply as follows:

[18 AAC 50.320(a)(2), 7/2/00]

a. Do not operate Heaters H-2001A or H-2001B on fuel oil at any time.

b. Replace both heaters with Low NOX burner technology no later than 180 days

after permit issuance.

c. No later than 180 days after startup for low NOX burner technology, and upon

Department request, conduct source tests for NOX to ascertain compliance with

the emission limits in Condition 23.3 for H-2001A. Conduct source tests in

accordance with the requirements in Section 9. Determine the NOX emission

rate for the heaters using exhaust properties determined by both Method 19 and

exhaust gas measurements in Section 9. Compliance with the NOX emission

limits will be determined using Method 19.

d. Submit a report in accordance with Condition 52 any exceedance of the limit

specified in Condition 23.3.

e. Submit a copy of the source test results to the Department within 45 days of

test, as required by Condition 39.3.

[18 AAC 50.320(a)(2), 7/2/00]
Permit No. 0073-AC023 Page 19 of 49

______________________________________________________________________________________________________

______________________________________________________________________________________________________

Issued: Final 7/13/01

24. The Permittee shall comply with VOC BACT limits for vents as follows:

[18 AAC 50.320(a)(2), 7/2/00]

24.1 Provide a Gas Blanketing and back pressure relief valve for the oil reserve tanks T6001 and T-6101B.

24.2 No later than 60 days after permit issuance, do not vent gas to atmosphere from the

produced water surge tank. Isolate the pressure control valve.

24.3 Report to the Department within 30 days after the pressure control valve has been

isolated.

 [18 AAC 50.320(a)(2), 7/2/00]
Permit No. 0073-AC023 Page 20 of 49

______________________________________________________________________________________________________

______________________________________________________________________________________________________

Issued: Final 7/13/01

Section 6. Prevention of Significant Deterioration Avoidance for NOX, SO2 and

PM

Owner Requested Limits

25. Nitrogen Dioxide Requirements. The Permittee shall avoid classification as a PSD

modification under 18 AAC 50.300(h)(3)(B)(ii) for NOX by emitting no more than 625.00

TPY of NOX from Turbines PU-0701 and PU-0801, combined, as follows:

[AS 46.14.140(b), 6/25/93]

[18 AAC 50.305(a)(4), 7/2/00]

25.1 Limit operating load and/or use Direct Water Injection (DWI) technology on each of

the turbines. Notify the Department within two business days of DWI initial

operation.

25.2 Except as provided for in Condition 25.3, no later than the fifteenth day of each

calendar month, calculate the NOX emissions in tons/month for the previous calendar

month using Equation 2, and as follows:

Equation 2 















×











 ×











 =











lb

ton

mo

hr

hr

lb

ER

mo

tons

NO emissions X

2000

Where,

ER = Average hourly NOX emission rate for previous month in pph from

Condition 37

a. if Permit No. 0073-AC023 has been in effect for 12 months or more, calculate

and record the 12-month rolling total NOX emissions for both turbines by

adding the total NOX emissions for the prior calendar month to the monthly

totals for the previous months, or

b. if Permit No. 0073-AC023 has been in effect for less than 12 months, calculate

and record the total NOX emissions for both turbines since permit issuance by

adding the total NOX emissions for the prior calendar month to the monthly

totals for each month since issue date of Permit No. 0073-AC023.

25.3 If monitoring NOX emissions according to Condition 37.1, for operations prior to

approval of a best-fit correlation under Condition 38.5, by the fifteenth day of the

first month after the approval of the correlation, calculate the NOX emissions in

tons/month for each calendar month since the issue date of Permit No. 0073-AC023

using Equation 2. Prorate emissions for the partial months.
Permit No. 0073-AC023 Page 21 of 49

______________________________________________________________________________________________________

______________________________________________________________________________________________________

Issued: Final 7/13/01

25.4 Submit a report in accordance with Condition 52 if the total NOX emissions

calculated under Condition 25.2 or 25.3 exceed the emission limit in Condition 25.

25.5 Attach a summary of the total NOX emissions calculated under Conditions 25.2 or

25.3 to the report required by Condition 54.

[18 AAC 50.320(a)(2), 7/2/00]

26. Sulfur Dioxide Requirements. Comply with the fuel sulfur limits, monitoring,

recordkeeping and reporting set out in Condition 18 and 19.

[AS 46.14.140(b), 6/25/93]

[18 AAC 50.305(a)(4), 7/2/00]

27. Particulate Matter Requirements. The Permittee shall avoid classification as a PSD

modification under 18 AAC 50.300(h)(3)(B)(v) for PM-10 by emitting no more than 28.00

TPY of PM-10 from Turbines PU-0701 and PU-0801, combined. Calculate 12-month PM10 emissions from PU-0701 and PU-0801 as follows:

[AS 46.14.140(b), 6/25/93]

[18 AAC 50.305(a)(4), 7/2/00]

27.1 Calculate PM-10 emissions from natural gas usage by

a. except as provided in Condition 27.1b, calculating and recording the total

amount of natural gas in MMscf used in both turbines for each month using the

readings taken under Condition11.1a;

b. for any time period during which the unit is operational and the fuel

consumption records are missing or incorrect, estimating fuel consumption

based on the design firing rate of the unit.

c. adding the totals determined under Condition 27.1a or 27.1b to the monthly

totals for the previous 11 months to get 12 month natural gas usage in

MMscf/yr, and

d. calculating the 12 month PM-10 emissions from natural gas using Equation 3

Equation 3 E (EF)(F)(0.0005tons/ lb) NG =

Where:

ENG = PM-10 emissions from natural gas in TPY

EF = PM-10 emission factor in lb/MMscf as described in Condition 27.1e

F = 12-month natural gas usage in MMscf/yr as calculated in Condition

27.1c

e. Determine the emission factor to be used in Condition 27.1d as follows

(i) Until a source test is required by Condition 27.3, use an initial emission

factor of 6.93 lb/MMscf,
Permit No. 0073-AC023 Page 22 of 49

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______________________________________________________________________________________________________

Issued: Final 7/13/01

(ii) Once a source test required by Condition 27.3 has been conducted, use the

PM emission factor for natural gas in lb/MMscf from the source test.

27.2 Calculate PM-10 emissions from fuel oil usage by

a. except as provided in Condition 27.2b, calculating and recording the total

amount of fuel oil in gallons used in both turbines for each month using the

readings taken under Condition11.1a;

b. for any time period during which the unit is operational and the fuel

consumption records are missing or incorrect, estimating fuel consumption

based on the design firing rate of the unit.

c. adding the totals determined under Condition 27.2a or 27.2b to the monthly

totals for the previous 11 months to get 12 month fuel oil usage in gal/yr, and

d. calculating the 12 month PM-10 emissions from fuel oil using Equation 4

Equation 4 E (EF)(F)(HV )(0.0005tons/ lb) D =

Where:

ED = PM-10 emissions from diesel in TPY

EF = PM-10 emission factor in lb/MMBtu, based on HHV, as described in

Condition 27.2e

F = 12-month fuel oil usage in gal/yr as calculated in Condition 27.2b

HV = High Heating value (HHV) of diesel fuel = 141 MBtu/gal (BP, 1999 page

G-6)

e. Determine the emission factor to be used in Condition 27.2d as follows

(i) Until a source test is required by Condition 27.3, use an initial emission

factor of 0.012 lb/MMBtu (EPA, 2000 Table 3.1-2a).

(ii) Once a source test required by Condition 27.3 has been conducted, use the

PM emission factor for diesel fuel in lb/MMBtu, based on HHV, from the

source test.

27.3 No later than the fifteenth day of each calendar month, calculate and record the 12-

month total PM-10 emissions for the turbines by adding emissions from Conditions

27.1d and 27.2d, and
Permit No. 0073-AC023 Page 23 of 49

______________________________________________________________________________________________________

______________________________________________________________________________________________________

Issued: Final 7/13/01

a. The first time that the 12-month total from Condition 27.3 exceeds 26.00 tons,

determine PM-10 emission factors for the turbines, in lb/MMscf for natural gas

firing and in lb/MMBtu (based on HHV), for fuel oil-firing, with and without

DWI, by conducting source tests in accordance with Condition 45. Consider

the end of the month that resulted in the 12-month total exceeding 26.00 tons

to be the date of the Department’s request for a source test under Condition 45.

b. If the 12-month total from Condition 27.3 exceeds 28.00 tons, notify the

Department as required in Condition 52.

27.4 Attach a summary of the 12-month PM-10 emission totals to the report required by

Condition 54. Keep records documenting the emissions calculations. If the duration

of the emission unit’s operations has not yet approached 12 months, list the

cumulative operation of the unit as a substitute for compliance with the 12-month

rolling total limit.

[18 AAC 50.320(a)(2), 1/18/97]
Permit No. 0073-AC023 Page 24 of 49

______________________________________________________________________________________________________

______________________________________________________________________________________________________

Issued: Final 7/13/01

Section 7. Best Available Control Technology (BACT) for CO

This section contains CO BACT requirements for Sources PU-0701, PU-0801, and H-5701A &

B (diesel).

28. The Permittee shall emit no more than 70 pph of CO from Turbines PU-0701 and PU0801, each, as follows:

[18 AAC 50.310(d)(3), 6/21/98]

28.1 Monitor the CO emission rate in pph as indicated in Condition 37.

28.2 Submit a report in accordance with Condition 52 any violations of the CO hourly

BACT limit in Condition 28.

[18 AAC 350(g)(5)(A), 18 AAC 50.320(a)(2), 7/2/00]

29. The Permittee shall emit no more than 94.4 TPY of CO from Turbines PU-0701 and PU0801, each, as follows:

[18 AAC 50.310(d)(3), 6/21/98]

29.1 Except as provided for in Condition 29.2, no later than the fifteenth day of each

calendar month, calculate CO emissions in tons/month for the previous calendar

month using Equation 5, and

Equation 5 















 ×











 ×











 =











lb

ton

mo

hr

hr

lb

ER

mo

tons

CO emissions

2000

Where,

ER = Average hourly CO emission rate for previous month in pph from

Condition 37

a. If the permit has been in effect for 12 months or more, calculate and record the

12-month rolling total CO emissions for both turbines by adding the total CO

emissions for the prior calendar month to the monthly totals for the previous

months, or

b. If the permit has been in effect for less than 12 months, calculate and record

the total CO emissions for both turbines since permit issuance by adding the

total CO emissions for the prior calendar month to the monthly totals for each

month since issue date of permit no. 0073-AC023.

29.2 If monitoring CO emissions according to Condition 37.1, for operations prior to

approval of a best-fit correlation under Condition 38.5, by the fifteenth day of the

first month after the approval of the correlation, calculate the CO emissions in

tons/month for each calendar month since the time of permit issuance using Equation

5. Prorate emissions for the partial months.
Permit No. 0073-AC023 Page 25 of 49

______________________________________________________________________________________________________

______________________________________________________________________________________________________

Issued: Final 7/13/01

29.3 Submit a report in accordance with Condition 52 if the total CO emissions calculated

under Condition 29.1 or 29.2 exceed the emission limit in Condition 29.

29.4 Attach a summary of the total CO emissions calculated under Conditions 29.1 or

29.2 to the report required by Condition 54.

[18 AAC.320(a)(2), 7/2/00]

30. The Permittee shall emit no more than 5 lb of CO/1,000 gallons of fuel combusted from

each of H-5701A & B when firing with fuel oil. Follow established preventative

maintenance guidelines,and maintain records of maintenance completed. Retain

maintenance records for five years, and submit records to Department upon request.

[18 AAC 50.310(d)(3), 6/21/98]
Permit No. 0073-AC023 Page 26 of 49

______________________________________________________________________________________________________

______________________________________________________________________________________________________

Issued: Final 7/13/01

Section 8. Generally Applicable Requirements

31. Good Air Pollution Control Practice. The Permittee shall install, maintain and operate,

in accordance with BPXA or manufacturer’s procedures, fuel burning equipment, process

equipment, emission control devices, testing equipment and monitoring equipment to

provide optimum control of air contaminant emissions during all operating periods. This

condition is not federally enforceable, except for Turbines PU-0701 & PU-0801, and

Heaters H-5302A & B.

[18 AAC 50.030, 1/18/97]

[18 AAC 50.320(a)(2), 7/2/00]

[40 CFR 60.11(d), 7/1/996]

32. Dilution. The Permittee shall not dilute emissions with air to comply with this permit.

[18 AAC 50.045(a) 1/18/97]

[18 AAC 50.320(a)(2), 7/2/00]

33. Modification. The Permittee shall not construct, operate, or modify a source that will

result in a violation of the applicable emission standards or that will interfere with the

attainment or maintenance of the ambient air quality standards or maximum allowable

ambient concentrations.

[18 AAC 50.045(c), 1/18/97]

33.1 Obtain all permits or permit revisions required for construction, modification, or

operation under 18 AAC 50 and AS 46.14.

[18 AAC 50.320(a)(2), 7/2/00]

33.2 Comply with the conditions of all permits obtained under 18 AAC 50 and AS 46.14.

[18 AAC 50.320(a)(2), 7/2/00]

34. Stack Injection. The Permittee shall not release materials other than process emissions,

products of combustion, or materials introduced to control pollutant emissions from a stack

at a source constructed or modified after November 1, 1982, unless approved in writing by

the department.

[18 AAC 50.055(g) and 18 AAC 50.310(m), 1/18/97]

35. Air Pollution Prohibited. The Permittee shall not cause any emission which is injurious

to human health or welfare, animal or plant life, or property, or which would unreasonably

interfere with the enjoyment of life or property.

[18 AAC 50.110, 5/26/72}

{18 AAC 50.040(e), 1/18/97]

[18 AAC 50.320(a)(2), 7/2/00]

35.1 Within 24 hours of receiving a complaint that is attributable to emissions from the

facility, investigate the complaint and initiate corrective actions to alleviate or

eliminate the cause of the complaint.

 

6

 40 CFR 60.11(d) applies only to Turbines PU-0701 & 0801, and Heaters H-5302A & B.
Permit No. 0073-AC023 Page 27 of 49

______________________________________________________________________________________________________

______________________________________________________________________________________________________

Issued: Final 7/13/01

35.2 Keep records of the date, time, and nature of all complaints received and summary of

the investigation and corrective actions undertaken for complaints attributable to

emissions from the facility. Upon request of the Department, submit copies of the

records.

 [18 AAC 50.235(a), 1/18/97]

36. HAP Reconstruction. Before replacing components of a major source of HAPS as that

term is defined in 40 CFR 63.2, or a source that would become a major source as a result

of replacement, if the cost of replacement exceeds 50 percent of the fixed capital cost that

would be required to construct a comparable new source, the Permittee shall obtain written

approval from the Department

36.1 under 40 CFR 63.5(b)(3), (d), and (e), if the source is subject to an emission standard

of 40 CFR 63, or

36.2 in a Notice of MACT Approval under 40 CFR 63.43(f) – (h), if the source is subject

to 40 CFR 63.43(a).

[18 AAC 50.345(b), 6/21/98]

[18 AAC 50.320(a)(2), 7/2/00]
Permit No. 0073-AC023 Page 28 of 49

______________________________________________________________________________________________________

______________________________________________________________________________________________________

Issued: Final 7/13/01

Section 9. General Source Testing and Monitoring Requirements

37. Turbine NOX and CO Monitoring Requirements. The Permittee shall monitor process

parameters hourly and calculate the NOX and CO emission rates in pph no less than once

per month for sources PU-0701 and PU-0801 in accordance with Conditions 37.1 or 37.2

as follows:

37.1 Use the best-fit correlation most recently approved by the Department under

Condition 38.5, and

a. Revise a correlation based on results of any annual relative accuracy (RA)

source test required by Condition 39. Submit the revisions for Department

approval in accordance with Condition 38.5.

b. If two consecutive RA tests performed under Condition 39 for the department

approved correlation exceed the limits in Conditions 37.1b(i) or 37.1b(ii)

install and use a CEMs as described in Condition 40, no later than 120 days

after submitting the report for the second failing test.

(i) twenty percent when the RM value is used in the denominator of the RA

equation in 40 CFR 60, Appendix B, Performance Specification 2, Section

12, Equation 2-6 (average emissions during test are greater than 50 percent

of the emission standard) or

[65 FR_61744, 10/17/00]

(ii) ten percent when the applicable emission standard is used in the

denominator of the RA equation in 40 CFR 60, Appendix B, Performance

Specification 2, Section 12, Equation 2-6 (average emissions during test

are less than 50 percent of the emission standard).

[65 FR_61744, 10/17/00]

37.2 Use a CEMS as described in Condition 40.

38. Best-Fit Correlation Method. The Permittee shall develop best-fit correlations between

NOX emission rates from source tests and turbine process parameters and between CO

emission rates from source tests and turbine process parameters, as follows:

38.1 Notify the Department of intention to develop a best-fit correlation for emission

monitoring, and submit a source test plan to the Department in accordance with

Condition 45, including

a. identification of the proposed process parameters for which the Permittee

elects to measure a parametric monitoring correlation, and

b. a description of the monitoring methodology accuracy and precision of

methodology and sampling rates of each parameter.
Permit No. 0073-AC023 Page 29 of 49

______________________________________________________________________________________________________

______________________________________________________________________________________________________

Issued: Final 7/13/01

38.2 Conduct three sets7 of initial Reference Method (RM) source tests as described in

Condition 43 at each of three loads (high, medium, and low), on both turbines, for

each of the four operating scenarios listed below, for NOX and CO.

a. Natural gas, without DWI, within 90 days of permit issuance,

b. Natural gas, with DWI, according to the schedule in Condition 10.3,

c. Fuel oil, without DWI, within 90 days of permit issuance, and

d. Fuel oil with DWI, according to the schedule in Condition 10.3.

38.3 During the RM source tests required under Condition 38.2, collect and record the

process parameters identified in Condition 38.1a for the purpose of developing

parametric correlations for NOX and CO emission rates for both natural gas and fuel

oil.

38.4 Using the RM test results from Condition 38.2, develop best-fit correlations for

emission rates based on turbine process parameters as follows: (The correlations

may also be based on SSPOWGEN or other vendor data as well as the RM source

tests.)

a. NOX/natural gas, with and without DWI;

b. NOX/fuel oil, with and without DWI;

c. CO/natural gas, with and without DWI; and

d. CO/fuel oil, with and without DWI.

38.5 Within 45 days after completing the RM tests, submit to the Department for written

approval a report that describes the best-fit correlation development or revision,

including the methodology, assumptions, analysis (with sample calculations),

supporting notes, and a list of all process parameters used in the correlations with an

analysis of their statistical relevance for the correlation (i.e. an r2 analysis of curve

fit).

38.6 Develop QA procedures for the process parameters used in the correlation developed

under Condition 38.5.

38.7 Include copies of the QA procedures with the report required by Condition 54.

39. Relative Accuracy (RA) Test Procedures for NOX and CO. Except as provided in

Condition 39.3, the Permittee shall determine the RA of all correlations approved under

Condition 38.5 annually as follows:

 

7

 One set = one run, so three runs are required at high load, three at medium and three at low.
Permit No. 0073-AC023 Page 30 of 49

______________________________________________________________________________________________________

______________________________________________________________________________________________________

Issued: Final 7/13/01

39.1 No more than 12 months after the previous series of RM tests, conduct RM tests for

NOX and CO as follows:

a. Conduct a minimum of three sets8 RM source tests as described in Condition

43 at each of three loads (high, medium, and low), on one turbine (in even

years on PU-0701 and in odd years on PU-0801), for each of the four

following operating scenarios:

(i) Natural gas, without DWI,

(ii) Natural gas, with DWI,

(iii) Fuel oil, without DWI, and

(iv) Fuel oil, with DWI.

b. Record each statistically relevant process parameter during each RM source

test no less than once every 15 minutes. Mark the beginning and end of each

RM source test on the output record.

c. Record the NOX and CO emission concentrations in ppm for each RM source

test period ("RM value") for each of the operating scenarios in Condition

39.1a.

d. Determine the integrated average NOX and CO emission rates in pph for each

RM test period using the best fit correlations approved by the Department

under Condition 38.5. Convert the NOX and CO emission rates in pph to

concentration in ppm using the procedures in 40 CFR 60 Appendix A, Method

19 using fuel- and site-specific F-factors ("correlation value"). If a net heating

value F-factor is used, then use a net heating value fuel consumption rate.

39.2 Calculate the relative accuracy of a correlation compared to a RM test as follows:

a. If the RM has an instrumental or integrated non-instrumental sampling

technique, make a direct comparison of the RM value and the correlation

value.

b. If the RM has a grab sampling technique, first average the results from all grab

samples taken during the test run, and then compare this average value against

the value obtained from the correlation during the run.

c. Using the procedures in 40 CFR 60, Appendix B, Performance Specification 2,

Section 12 and summarizing the results on a data sheet similar to that shown in

Section 18 calculate the

 

8

 One set = one run, so three runs are required at high load, three at medium and three at low.
Permit No. 0073-AC023 Page 31 of 49

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______________________________________________________________________________________________________

Issued: Final 7/13/01

(i) arithmetic mean of the difference between the "RM value" and the

"correlation value",

(ii) standard deviation,

(iii) confidence coefficient, and

(iv) relative accuracy.

39.3 If five consecutive annual RA verifications of any correlation are less than the limits

in Condition 37.1b the Permittee may double the duration between tests, with the

Department's concurrence.

39.4 Attach copies of the results of all RM tests (including any rejected test results)

conducted under Condition 39.1a, the report required under Condition 54.

40. CEMS. Install, calibrate, and conduct applicable continuous monitoring system

performance tests listed in 40 CFR 60, Appendix B, effective July 1, 1999, and certify test

results; operate; and maintain air contaminant emissions and process monitoring

equipment on the sources as described herein. Submit monitoring equipment siting,

operation, maintenance plans, and procedures for approval by the Department.

40.1 Comply with each applicable monitoring system requirement, as listed in

40 CFR 60.13, 60.19, Appendix A (Method 19), and Appendix F, 65 FR 61744

(Performance Specification 2), and the EPA Quality Assurance Handbook for Air

Pollution Measurements Systems, EPA/600 R-94/038b.

[40 CFR 60, Subpart A, and Appendix A, 7/1/99]

[65 FR_61744, 10/17/00]

40.2 Attach to the report required by Condition 54

a. A copy of each quarterly report continuous emission monitoring system data

assessment report for Quality Assurance Procedures conducted in accordance

with 40 CFR 60, Appendix F, and

[40 CFR 60, Appendix F, 7/1/99]

b. A copy of each quarterly monitoring systems performance report in accordance

with 40 CFR 60.7.

[40 CFR 60, Subpart A, 7/1/99]

41. Requested Source Tests. In addition to any source testing explicitly required by this

permit, the Permittee shall conduct source testing as requested by the department to

determine compliance with applicable permit requirements.

[18 AAC 50.220(a), 18 AAC 50.345(a)(10), 1/18/97]

42. Operating Conditions. Unless otherwise specified by an applicable requirement or test

method, the Permittee shall conduct source testing

42.1 at a point or points that characterize the actual discharge into the ambient air; and
Permit No. 0073-AC023 Page 32 of 49

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______________________________________________________________________________________________________

Issued: Final 7/13/01

42.2 at the maximum rated burning or operating capacity of the source or another rate

determined by the department to characterize the actual discharge into the ambient

air.

[18 AAC 50.220(b) & 18 AAC 50.350(g), 1/18/97]

43. Reference Test Methods. The Permittee shall use the following as reference test methods

when conducting source testing for compliance with this permit:

[18 AAC 50.320(a)(2), 7/2/00]

43.1 Source testing for compliance with requirements adopted by reference in

18 AAC 50.040(a) must be conducted in accordance with the methods and

procedures specified in 40 CFR 60.

[18 AAC 50.220(c), 1/18/97

[40 CFR 60, 7/1/99]

43.2 Source testing for compliance with requirements adopted by reference in

18 AAC 50.040(b) must be conducted in accordance with the methods and

procedures specified in 40 CFR 61.

[18 AAC 50.220(c), 1/18/97]

[40 CFR 61, 12/19/96]

43.3 Source testing for compliance with requirements adopted by reference in

18 AAC 50.040(c) must be conducted in accordance with the source test methods

and procedures specified in 40 CFR 63.

[18 AAC 50.220(c), 1/18/97]

[40 CFR 63, 7/1/99]

43.4 Source testing for the reduction in visibility through the exhaust effluent must be

conducted in accordance with the procedures set out in Section 13 of this permit.

Visibility source testing is exempt from the requirements listed in Conditions 45

through 47.

 [18 AAC 50.220(c), 1/18/97

43.5 Source testing for emissions of particulate matter, sulfur compounds, nitrogen

compounds, carbon monoxide, lead, volatile organic compounds, fluorides, sulfuric

acid mist, municipal waste combustor organics, metals, and acid gases must be

conducted in accordance with the methods and procedures specified 40 CFR 60,

Appendix A.

[18 AAC 50.220(c) & 18 AAC 50.040, 1/18/97]

[40 CFR 60, Appendix A, 7/1/99]

43.6 Source testing for emissions of PM-10 must be conducted in accordance with the

procedures specified in 40 CFR 51, Appendix M.

[18 AAC 50.220(c), 1/18/97]

[40 CFR 51, Appendix M, 7/1/99]

43.7 Source testing for emissions of any contaminant may be determined using an

alternative method approved by the department in accordance with Method 301 in

Appendix A to 40 CFR 63.

[18 AAC 50.220(c), 1/18/97]
Permit No. 0073-AC023 Page 33 of 49

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______________________________________________________________________________________________________

Issued: Final 7/13/01

[40 CFR 63, Appendix A, 7/1/99]

44. Excess Air Requirements. To determine compliance with this permit, standard exhaust

gas volumes must only include the volume of gases formed from the theoretical

combustion of fuel, plus the excess air volume normal for the specific source type,

corrected to standard conditions (dry gas at 68° F and an absolute pressure of

760 millimeters of mercury).

[18 AAC 50.990(88) & 18 AAC 50.220(c)(3), 1/18/97]

45. Test Plans. Before conducting any source tests, the Permittee shall submit a plan to the

Department. The plan must include the methods and procedures to be used for sampling,

testing, and quality assurance, and must specify how the source will operate during the test

and how the Permittee will document this operation. A complete plan must be submitted

within 60 days of receiving a request under Condition 41 and at least 30 days before the

scheduled date of any tests.

 [18 AAC 50.345(a)(10) & 18 AAC 50.350(b)(3), 1/18/97]

46. Test Notification. At least 10 days before conducting a source test, the Permittee shall

give the Department written notice of the date and time the source test will begin.

[18 AAC 50.345(a)(10), 1/18/97]

47. Test Reports. Within 45 days after completing a source test, the Permittee shall submit

two copies of the results, to the extent practical, in the format set out in the Source Test

Report Outline of Volume III, Section IV.3 of the State Air Quality Control Plan, adopted

by reference in 18 AAC 50.030(8). The Permittee shall certify the results as set out in

Condition 48 of this permit.

[18 AAC 50.345(a)(10), 1/18/97]
Permit No. 0073-AC023 Page 34 of 49

______________________________________________________________________________________________________

______________________________________________________________________________________________________

Issued: Final 7/13/01

Section 10. General Recordkeeping, Reporting, and Compliance Certification

Requirements

48. Certification. The Permittee

48.1 shall certify all reports, compliance certifications, or other documents submitted to

the Department under this permit as required by 18 AAC 50.205, and

[18 AAC 50.345(a)(9), 1/18/97]

48.2 may certify the excess emission reports submitted pursuant to Condition52 with the

operating report required by Condition 54 of this permit, for the same six month

period. All other reports must be certified upon submittal.

[18 AAC 50.205, 18 AAC 50.345(a)(9), & 18 AAC 50.320(a)(2), 1/18/97]

49. Submittals. Unless otherwise directed by the Department or this permit, the Permittee

shall send reports, compliance certifications, and other documents required by this permit

to ADEC, Air Permits Program, 610 University Ave., Fairbanks, AK 99709-3643,

ATTN: Compliance Technician.

[18 AAC 50.320(a)(2), 1/18/97]

50. Information Requests. The Permittee shall furnish to the Department, within a

reasonable time, any information the Department requests in writing to determine whether

cause exists to modify, revoke and reissue, or terminate the permit or to determine

compliance with the permit. Upon request, the Permittee shall furnish to the Department

copies of records required to be kept by this permit. The Department, in its discretion, will

require the Permittee to furnish copies of those records directly to the federal administrator.

[18 AAC 50.200, 18 AAC 50.345(a)(8), & 18 AAC 50.320(a)(2), 1/18/97]

51. Recordkeeping Requirements. Except for the records required by Condition 13, the

Permittee shall keep all records required by this permit for at least five years after the date

of collection, including

51.1 Copies of all reports and certifications submitted pursuant to this Section of this

permit.

51.2 Records of all monitoring and measurements required by this permit, and

information about the monitoring and measurements, including

a. calibration and maintenance records, original strip chart or computer-based

recordings for continuous monitoring instrumentation;

b. sampling dates and times of sampling and measurements;

c. the operating conditions that existed at the time of sampling or measurement;

d. the date analyses were performed;

e. the location where samples were taken;
Permit No. 0073-AC023 Page 35 of 49

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______________________________________________________________________________________________________

Issued: Final 7/13/01

f. the company or entity that performed the sampling and analyses;

g. the analytical techniques or methods used in the analyses; and

h. the results of the analyses.

[18 AAC 50.320(a)(2), 7/2/00]

[40 CFR 60.7(e) and (f), Subpart A, 7/1/99] 9

[40 CFR 60.48c(i), Subpart Dc, 7/1/99] 10

52. Excess Emission and Permit Deviation Reports. The Permittee shall report all

emissions or operations that exceed or deviate from the requirements of this permit or that

present a potential threat to human health or safety as soon as possible, but no later than 48

hours, after discovery of the event. The report must include the information listed on the

form contained in Section 14 of this permit. The Permittee may use this form to report

excess emissions under this condition.

[18 AAC 50.235(a)(2) & 18 AAC 50.240(c), 1/18/97]

[18 AAC 50.320(a)(2), 7/2/00]

53. NSPS and NESHAP Reports. The Permittee shall submit to the Department copies of

reports required by 40 CFR 60, New Source Performance Standards (NSPS), and 40 CFR

Parts 61 and 63, National Emission Standards for Hazardous Air Pollutants (NESHAP), as

they apply to the equipment in Table 1 as follows:

53.1 Attach a copy of any NSPS and NESHAPs reports submitted to the U.S.

Environmental Protection Agency (EPA) Region 10 to the Operating Report required

by Condition 54.

53.2 The Permittee shall notify the Department of any EPA granted waivers of NSPS or

NESHAP emission standards, recordkeeping, monitoring, performance testing, or

reporting requirements within 30 days after the Permittee receives a waiver.

[18 AAC 50.040, 1/18/97]

[40 CFR 60 & 63, 7/1/99]

[40 CFR 61, 12/19/96]

54. Operating Reports. During the life of this permit, the Permittee shall submit an original

and two copies of all reports, certifications, notices, and test plans required by this permit

with the operating report required by Exhibit D of Permit-to-Operate 9673-AA005. In

addition, the report must include a listing of all deviations from the requirements of this

permit that occurred during the reporting period. For each deviation, the report must

identify

54.1 the date of the deviation;

54.2 the equipment involved;

54.3 the permit condition;

 

9

 40 CFR 60.7(f) applies only to Turbines PU-0701 and PU-0801 and Heaters H-5302A & B.

10 40 CFR 60.48c(i) applies only to Heaters H-5302A & B
Permit No. 0073-AC023 Page 36 of 49

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Issued: Final 7/13/01

54.4 a description of the deviation; and

54.5 any corrective action or preventive measures taken and the date of such actions.

[18 AAC 50.320(a)(2), 1/18/97]
Permit No. 0073-AC023 Page 37 of 49

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______________________________________________________________________________________________________

Issued: Final 7/13/01

Section 11. Standard Conditions Not Otherwise Included in the Permit

55. Consistent with Alaska law, for purpose of submitting compliance certifications or

establishing whether or not the Permittee has violated or is in violation of any standard in

this permit, nothing in this permit precludes the use of any credible evidence or

information relevant to whether the facility would have been in compliance with applicable

requirements if the appropriate performance or compliance test or procedure had been

performed. This condition is not federally enforceable.

[18 AAC 50.320(a)(2), 7/2/00]

[40 CFR 52.12(c), 7/1/99]

56. The Permittee must comply with each permit term and condition. Noncompliance

constitutes a violation of AS 46.14, 18 AAC 50, and the Clean Air Act, except for those

requirements designated as not federally-enforceable, and is grounds for:

56.1 an enforcement action,

56.2 permit termination, revocation and reissuance, or modification in accordance with

AS 46.14.280, or

56.3 denial of an operating-permit renewal application.

[18 AAC 50.345(a)(1), 1/18/97]

[18 AAC 50.320(a)(2), 7/2/00]

57. Consistent with Alaska Law, it is not a defense in an enforcement action to claim that it

would have been necessary to halt or reduce the permitted activity in order to maintain

compliance with a permit term or condition.

[18 AAC 50.345(a)(2), 1/18/97]

[18 AAC 50.320(a)(2), 7/2/00]

58. Each permit term and condition is independent of the permit as a whole and remains valid

regardless of a challenge to any other part of this permit.

[18 AAC 50.345(a)(3), 1/18/97]

[18 AAC 50.320(a)(2), 7/2/00]

59. Compliance with permit terms and conditions is considered to be compliance with those

requirements that are:

59.1 included and specifically identified in the permit, or

59.2 determined in writing in the permit to be inapplicable.

[18 AAC 50.345(a)(4), 1/18/97]

[18 AAC 50.320(a)(2), 7/2/00]

60. The permit may be modified, reopened, revoked and reissued, or terminated for cause. A

request by the permittee for modification, revocation and reissuance, or termination or a

notification of planned changes or anticipated noncompliance does not stay any operating

permit condition.

[18 AAC 50.345(a)(5), 1/18/97]
Permit No. 0073-AC023 Page 38 of 49

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______________________________________________________________________________________________________

Issued: Final 7/13/01

[18 aAC 50.320(a)(2), 7/2/00]

61. The permit does not convey any property rights of any sort, nor any exclusive privilege.

[18 AAC 50.345(a)(6), 1/18/97]

[18 AAC 50.320(a)(2), 7/2/00]

62. The Permittee shall allow an officer or employee of the Department or an inspector

authorized by the Department, upon presentation of credentials and at reasonable times

with the consent of the owner or operator, to:

62.1 enter upon the premises where a source subject to the operating permit is located or

where records required by the permit are kept,

62.2 have access to and copy any records required by the permit,

62.3 inspect any facilities, equipment, practices, or operations regulated by or referenced

in the permit, and

62.4 sample or monitor substances or parameters to assure compliance with the permit or

other applicable requirements.

[18 AAC 50.345(a)(7), 1/18/97]

[18 AAC 50.320(a)(2), 7/2/00]
Permit No. 0073-AC023 Page 39 of 49

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Issued: Final 7/13/01

Section 12. Visible Emissions and Particulate Matter Monitoring Plan

Visible Emissions Observations

63. Except as provided in Conditions 64, the Permittee shall observe visible emissions in the

exhaust of each source, except for flares and sources using only gaseous fuels using

Method 9 within 6 months after the issue date of this permit , whichever is later, and at

least once every 1,000 hours that a source operates on fuel oil thereafter, observe its

exhaust for six minutes to obtain 24 individual 15-second readings in accordance with

Visible Emission Evaluation procedures in Section 13 of this permit, and as follows:

63.1 If two or more individual 15-second readings during the six-minute observation

period are greater than 20 percent opacity, then continue the Method 9 observations

for an additional 12 minutes for a total of 18 minutes.

63.2 If four or more individual 15-second readings during the 18-minute observation

period are greater than 20 percent opacity, then continue the Method 9 observations

for an additional 42 minutes for a total of 60 minutes.

64. The Permittee may reduce the number of six minute observations required by Condition63

to one observation for every 2,190 hours of source operation, if

64.1 sixty minutes of observations were not necessary under Condition 63.2; or

64.2 the source was observed for 60 minutes and no more than eight individual 15-second

readings were greater than 20 percent opacity.

65. If a source is observed for 60 minutes and more than eight, but fewer than thirteen 15-

second readings are greater than 20 percent opacity during the most recent observation,

then the observation frequency under Condition63 must be increased to or maintained at

once every 1,000 hours of source operation.

66. Once each calendar year, the Permittee shall monitor the exhaust of the flare and all

sources using gaseous fuels using Method 9 as set out in Condition 63.1 or 63.2.

67. The Permittee is not required to comply with Conditions 45, 46, and 47 (Test Plans, Test

Notifications, and Test Reports) when the exhaust is observed for visible emissions under

Conditions 63 through 66.

Particulate Matter Testing

68. Except for heaters, flares and sources using only gaseous fuels, the Permittee shall conduct

tests to determine the concentration of particulate matter in the exhaust of a source as

follows:
Permit No. 0073-AC023 Page 40 of 49

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Issued: Final 7/13/01

68.1 Except as provided in Condition 68.2, conduct a particulate matter (PM) source test

according to the requirements set out in Section 9 no later than 90 calendar days after

any time either of the following occurs, unless a follow-up Method 9 test during the

90 days shows that the following no longer occurs:

a. a 60-minute Method 9 evaluation results in 13 or more 15-second readings

with an opacity greater than 20 percent, or

b. a 60-minute Method 9 evaluation results in an average opacity that is greater

than 12 percent for a source with an exhaust stack diameter that is less than 21

inches.

68.2 The Permittee is exempt from the PM source test requirements in Condition 68.1 for

an emission unit if a PM source test on that unit has shown compliance with the PM

standard since permit issuance.

68.3 During each PM source test, observe exhaust for 60 minutes in accordance with

Section 13 and submit a summary of these observations and the Method 9 readings

with the final source test report. For each source with an exhaust stack diameter that

is less than 21 inches and for each source subject to a New Source Performance

Standard (NSPS) for opacity in 40 C.F.R. 60, calculate the average opacity and

submit the calculations with source test report.

Reporting Requirements

69. The Permittee shall, within 180 calendar days after the effective date of this permit, record

and report the exhaust stack diameter of each source: PU-0701, PU-0801, H-5701A & B,

H-2001A & B, PU-0110A & B, and report this information to the Department with the first

or second operating report required by Condition 54.

70. The Permittee shall keep a record of the operating hours for each source: PU-0701, PU0801, H-5302A & B, H-4510A & B, H-5701A & B, H-2001A & B, PU-0110A & B, and

the flare, and shall submit these records with the facility operating report required by

Condition 54.

71. The Permittee shall submit a report in accordance with Condition 52

71.1 if any sixty minute Method 9 evaluation conducted under Condition 63.2 results in

an exceedance ot the limit in Condition 5 (thirteen or more 15-second reading greater

than 20 percent opacity); and

71.2 if any PM test conducted under Condition 68.1 results an exceedance of the limit in

Condition 6 (0.05 grains per cubic foot of exhaust gas corrected to standard

conditions and averaged over three hours).

72. Include with the facility operating report required by Condition 54 copies of all Method 9

observations for equipment subject to this permit.

 [18 AAC 50.320(a)(2), 7/2/00]
Permit No. 0073-AC023 Page 41 of 49

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______________________________________________________________________________________________________

Issued: Final 7/13/01

Section 13. Visible Emission Evaluation Procedures

An observer qualified according to 40 CFR 60, RM 9 (Method 9) shall use the following

procedures to determine the reduction of visibility through the exhaust effluent.

Position. The qualified observer shall stand at a distance sufficient to provide a clear view of the

emissions with the sun oriented in the 140° sector to his back. Consistent with maintaining the

above requirement, the observer shall, as much as possible, make his observations from a

position such that his line of vision is approximately perpendicular to the plume direction and,

when observing opacity of emissions from rectangular outlets (e.g., roof monitors, open

baghouses, noncircular stacks), approximately perpendicular to the longer axis of the outlet. The

observer’s line of sight should not include more than one plume at a time when multiple stacks

are involved, and in any case the observer should make his observations with his line of sight

perpendicular to the longer axis of such a set of multiple stacks (e.g., stub stacks on baghouses).

Field Records. The observer shall record the name of the plant, emission location, facility type,

observer’s name and affiliation, and the date on the Visible Emissions Field Data Sheet . The time,

estimated distance to the emission location, approximate wind direction, estimated wind speed,

description of the sky condition (presence and color of clouds), and plume background are

recorded on the sheet at the time opacity readings are initiated and completed.

Observations. Opacity observations shall be made at the point of greatest opacity in that portion

of the plume where condensed water vapor is not present. The observer shall not look

continuously at the plume but instead shall observe the plume momentarily at 15-second

intervals. Unless directed to do otherwise in this permit, observe emissions for 60 consecutive

minutes to obtain a minimum of 240 observations.

Attached Steam Plumes. When condensed water vapor is present within the plume as it

emerges from the emission outlet, opacity observations shall be made beyond the point in the

plume at which condensed water vapor is no longer visible. The observer shall record the

approximate distance from the emission outlet to the point in the plume at which the

observations are made.

Detached Steam Plume. When water vapor in the plume condenses and becomes visible at a

distinct distance from the emission outlet, the opacity of emissions should be evaluated at the

emission outlet prior to the condensation of water vapor and the formation of the steam plume.

Recording Observations. Opacity observations shall be recorded to the nearest five percent at

15-second intervals on the Visible Emissions Observation Record contained in this section.

Record the minimum number of observations required by the permit. Each momentary

observation recorded shall be deemed to represent the average opacity of emissions for a

15-second period.

Data Reduction. To determine compliance with a standard set out in Condition 5 of this permit,

count the number of observations that exceed 20 percent opacity and record this number on the

sheet.
Permit No. 0073-AC023 Page 42 of 49

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______________________________________________________________________________________________________

Issued: Final 7/13/01

To determine the six minute average opacity set out in Condition 68.1b of this permit, divide the

observations recorded on the record sheet into sets of 24 consecutive observations. Sets need not

be consecutive in time and in no case shall two sets overlap. For each set of 24 observations,

calculate the average by summing the opacity of the 24 observations and dividing this sum by

24. If an applicable standard specifies an averaging time requiring more than 24 observations,

calculate the average for all observations made during the specified time period. Record the

average opacity on the sheet.
Permit No. 0073-AC023 Page 43 of 49

______________________________________________________________________________________________________

______________________________________________________________________________________________________

Issued: Final 7/13/01

Visible Emissions Field Data Sheet

Certified Observer:_________________________

Company:

Location:

Test No.: Date:

Source:

Production Rate, Operating Rate &

Unit Operating Hours:

Hrs. of observation:

Fuel Type:

Clock Time Initial Final

Observer location

 Distance to discharge

 Direction from discharge

 Height of observer point

Background description

Weather conditions

 Wind Direction

 Wind speed

 Ambient Temperature

 Relative humidity

Sky conditions: (clear, overcast, % clouds, etc.)

Plume description:

 Color

Distance visible

Water droplet plume?

 (attached or detached?)

Other information
Permit No. 0073-AC023 Page 44 of 49

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______________________________________________________________________________________________________

Issued: Final 7/13/01

Visible Emissions Observation Record

Page ___ of ___

Company _________________ Certified Observer____________________

Test Number ___________________________ Clock time______________________

Date:

Visibility reduction every 15

Seconds (Opacity)

Steam Plume

(check if applicable) Comments

Hr Min 0 15 30 45 Attached Detached

Additional information:

_______________________________________

Observer Signature

Data Reduction:

Duration of Observation Period (minutes) ________________

Number of Observations _________________

Number of Observations exceeding 20% __________________

Average Opacity Summary

Set Time Opacity

Number Start—End Sum Average
Permit No. 0073-AC023 Page 45 of 49

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______________________________________________________________________________________________________

Issued: Final 7/13/01

Section 14. ADEC Notification Form

Fax this form to: (907) 269-7508 Telephone: (907) 269-8888

BP Exploration (Alaska), Inc. ______________________________________________________________

Company Name

Milne Point Production Facility 

Facility Name

1. Reason for notification:

q Excess Emission q Permit Condition Deviation

2. Event Information (Use 24-hour clock):

START Time: END Time: Duration

(hr:min):

Date: : : : 

Date: : : : 

Total: : 

3. Cause of Event (Check all that apply):

q START UP q UPSET CONDITION q CONTROL EQUIPMENT

q SHUT DOWN q SCHEDULED MAINTENANCE q OTHER 

Attach a detailed description of what happened, including the parameters or operating conditions

exceeded.

4. Sources Involved:

Identify each Emission Source involved in the event, using the same identification number and

name as in the Permit. List any Control Device or Monitoring System affected by the event.

Attach additional sheets as necessary.

Source ID No. Source Name Description Control Device

 

 

5. Emission Limit Exceeded and/or Permit Condition Deviation:

Identify each Emission Standard and Permit Condition potentially exceeded during the event.

Attach a list of ALL known or suspected injuries or health impacts. Attach additional sheets as

necessary.

Permit Condition Limit Exceedance

 

6. Emission/Deviation Reduction:

Attach a description of the measures taken to minimize and/or control emissions or permit

condition deviations during the event.

7. Corrective Actions:

Attach a description of corrective actions taken to restore the system to normal operation and to

minimize or eliminate chances of a recurrence.

Based on information and belief formed after reasonable inquiry, I certify that the statements and

information in and attached to this document are true, accurate, and complete.

 

Printed Name: Signature: Date:
Permit No. 0073-AC023 Page 46 of 49

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Issued: Final 7/13/01

Section 15. Permit Documentation

March 16, 1984 PSD Permit Application, Conoco, Inc. - Milne Point Project.

July 9, 1984 Letter pertaining to PSD Application, Conoco, Inc.

September 13, 1984 Letter pertaining to PSD Application, Conoco, Inc.

October 9, 1984 Letter pertaining to PSD Application, Conoco, Inc.

January 24, 1985 Technical Analysis for Prevention of Significant Deterioration, Conoco –

Milne Point, Alaska.

April 26, 1985 Air Quality Control Permit-to-Operate No. 8536-AA008.

August 15, 1986 Letter from Conoco to ADEC “Request for 20% Opacity Limitation for

Milne Point Flare.”

September 3, 1986 Air Quality Control Permit-to-Operate No. 8636-AA014.

December 5, 1986 Letter from Conoco to ADEC/NRO transmitting the report of source tests

conducted at Milne Point on September 10-12, 1986.

January 26, 1987 Letter from ADEC/NRO to Conoco accepting source test and fuel gas

analysis results.

February 25, 1987 Letter from Conoco to EPA requesting approval of Drager tube analysis

for biannual fuel gas sulfur analysis, and for one sulfur and nitrogen test of

liquid fuel as long as fuel source not changes, to meet requirements of

40 CFR 60.334.

April 4, 1988 Letter from Conoco to ADEC/NRO requesting renewal of Air Quality

Control Permit-to Operate 8636-AA014.

April 20, 1988 Air Quality Permit-to-Operate No. 8836-AA002.

January 18, 1990 Letter from EPA to Conoco approving Drager tube analysis for fuel gas,

as requested in February 25, 1987 letter, as long as H2S less than 50 ppm.

February 17, 1993 Letter from Conoco to ADEC/PCRO requesting renewal of Air Quality

Control Permit-to-Operate 8836-AA002.

March 2, 1993 Letter from ADEC to Conoco requesting additional information about the

permitted equipment.

March 8, 1993 Letter from Conoco to ADEC/PCRO responding to ADEC’s March 2,

1993 information request.

March 30, 1993 Letter from ADEC to Conoco requesting additional information about the

permitted equipment.

April 21, 1993 Letter from Conoco to ADEC/PCRO responding to ADEC’s March 30,

1993 information request.
Permit No. 0073-AC023 Page 47 of 49

______________________________________________________________________________________________________

______________________________________________________________________________________________________

Issued: Final 7/13/01

July 30, 1993 Letter from ADEC to Conoco presenting a draft renewal of Permit to

Operate 8836-AA002.

September 9, 1993 Letter from Conoco to ADEC/PCRO presenting comments to the draft

permit renewal.

January 5, 1994 Letter from BP to ADEC/PCRO requesting transfer of Air Quality Control

Permit-to-Operate No. 8836-AA002 from Conoco to BP effective

January 1, 1994.

January 10, 1994 Letter from ADEC to BP approving the transfer of Air Quality Control

Permit-to-Operate No. 8836-AA002 from Conoco to BP effective

January 1, 1994.

February 10, 1994 Letter from BP to ADEC/PCRO identifying errors in Air Quality Control

Permit-to-Operate No. 8836-AA002 and presenting emission calculation

for permitted equipment.

October 31, 1994 Letter from BP to ADEC commenting on draft permit.

November 30, 1994 Facsimile from BP to ADEC commenting on draft permit.

November 30, 1994 Air Quality Control Permit-to-Operate No. 9473-AA010.

November 30, 1994 Letter from BP to ADEC requesting modifications to Air Quality Control

Permit No. 9473-AA007 to allow installation of additional equipment.

December 9, 1994 Letter from BP requesting administrative corrections to Air Quality Permit

No. 9473-AA007.

December 12, 1994 Telephone conversation between Alison Cooke (BP) and Jim Greaves

(ADEC) asking that ADEC suspend review of the permit amendment

application dated November 30, 1994 due to possible errors in the

equipment estimates.

December 27, 1994 Air Quality Control Permit-to-Operate No. 9473-AA035.

January 19, 1995 Letter from BP requesting modifications to Air Quality Permit

No. 9473-AA007 to allow for installation of additional equipment.

February 13, 1995 Letter from BPXA and follow-up telephone conversation Jim Greaves

(ADEC), Alison Cooke (BPXA), and Chuck Stewart on February 14,

1995, in which BP requested to modify their January 19, 1995 amendment

application to Air Quality Permit No. 9473-AA007 to allow temporary use

of one heater at E-pad while other heaters are being rebuilt.

February 22, 1995 Letter from BP providing emission estimates for their proposal to allow

temporary use of one heater at E-pad while other heaters are being rebuilt.

July 28, 1995 Letter from BP requesting ADEC approval of disaggregation of distant

well pad and equipment modifications and installations. The

disaggregated sources are located at C-pad and the Pipeline Tie-in

Module.
Permit No. 0073-AC023 Page 48 of 49

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Issued: Final 7/13/01

August 15, 1995 Letter from ADEC to BP granting approval of disaggregation of sources

and minor modifications at the facility.

August 22, 1995 Letter from ADEC to BP granting approval and re-determination of

original PSD fuel consumption limit allowances for diesel fuel use by two

dual fuel turbines at the facility.

October 2, 1995 Letter from ADEC to BP granting approval of proposed BP corrections

and changes to the tabulation of emission sources attributable to PSD

avoidance agreements shown in Exhibit B.

April 26, 1996 Letter from BP formally requesting ADEC to make a permit determination

regarding the enforceability of the air emission limitations for two GE LM

2500 dual fuel turbines.

May 29, 1996 Letter from ADEC to BP reaffirming original PSD TAR BACT limits for

NOX for the two GE LM 2500 duel fuel turbines.

July 25, 1996 Letter from BP to ADEC requesting a permit amendment that revises the

BACT emission rate for NOX, as well as the annual limit on total NOX

emissions for the two GE LM 2500 dual fuel turbines.

August 19, 1996 Letter from Anita Frankel (EPA) to Stephen Taylor (BP) authorizing a

waiver from monitoring fuel-bound nitrogen for North Slope facilities,

including MPU.

August 30, 1996 Letter from BP to ADEC requesting an additional change to the original

Phase I permit amendment request.

September 4, 1996 Letter from ADEC to BP granting approval of permit amendment changes

sought by BP on July 25, 1996 and August 30, 1996.

January 17, 1997 Air Quality Control Permit to Operate No. 9673-AA005.

December 2, 1997 BP Exploration Title V Permit Application, Milne Point Production

Facility, prepared by SECOR International Incorporated, November 1997.

November 5, 1999 Revised Construction Permit Request – Phase II, For Milne Point Unit,

North Slope, Alaska Prepared for BP Exploration (Alaska) Inc., by

Hoefler Consulting Group, Julie H. Ackerlund, and Radian International,

Revised: November 1999.

November 8, 1999 Letter of Transmittal Milne Point Unit PSD Amendment Modeling Files

on compact disc.

January 5, 2000 Letter from Sally Ryan (ADEC) to Ray Vaseleski (BPXA) Re: BPXA

Application for Milne Point Unit submitted November 1999 is incomplete.

March 10, 2000 Response to ADEC Incompleteness Letter dated January 5, 2000, for the

Milne Point Revised Construction Permit Request – Phase II, North Slope,

Alaska, prepared for BP Exploration (Alaska) Inc., by Hoefler Consulting

Group.
Permit No. 0073-AC023 Page 49 of 49

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______________________________________________________________________________________________________

Issued: Final 7/13/01

March, 2000 Milne Point - Modeling Completeness Issues March 2000 Submittal,

document prepared by Alan Schuler (ADEC).

April 17, 2000 Fax Transmittal from Steve Sommers (BPXA) to Sally Ryan (ADEC) on

cost/ton of 0.225% sulfur diesel.

May 1, 2000 Email from Steve Barnard (BPXA) to Alan Schuler (ADEC), modeling

files.

May 2, 2000 Fax Transmittal from John Booth (BPXA) to Sally Ryan (ADEC), re:

E-pad heater vendor data, and Section X, Insignificant Sources from the

Title V Permit Application.

May 3, 2000 Letter from Ross Klie, (BPXA) to Jim Baumgartner (ADEC) Subject:

Milne Point Unit Response to March 30, 2000 Emailed Modeling

Comments.

May 17, 2000 Fax Transmittal from John Booth (BPXA) to Sally Ryan (ADEC) on

Milne Point H-5302 vendor information.

June 12, 2000 Letter from Ross Klie (BPXA) to Jim Baumgartner (ADEC) Subject:

Milne Point Updated PSD Applicability Analysis.

June 14, 2000 Memorandum written by Alan Schuler (ADEC) Subject: Review of Milne

Point Unit Modeling Analysis.

June 22, 2000 Memorandum written by Sally Ryan (ADEC) Subject: Review of Milne

Point Unit BACT Analysis.

June 23, 2000 Letter from Sally Ryan (ADEC) to Ray Vaseleski (BPXA), Application is

complete.

July 25, 2000 Memorandum written by Sally Ryan (ADEC) Subject: BP BACT

Revisions.

October 31, 2000 Public Comment Draft, Air Quality Construction Permit Number 0073-

AC023, prepared by the Department

December 6, 2000 Comments on Air Quality Construction Permit Number 0073-AC023,

submitted to the Department by George R. Snodgrass, BPXA.

December 12, 2001 Ex Parte Meeting Notes prepared by Sally Ryan (ADEC).

February 3, 2001 Ex Parte Email from Sally Ryan (ADEC) to Jim Pfeiffer (BPXA) and Al

Trbovich (Hoefler) summarizing outstanding deliverables.

April 20, 2001 Ex Parte Letter from George R. Snodgrass, (BPXA) to Jim Baumgartner

(ADEC) re: Response to February 3, 2001 ADEC email.

April 20, 2001 Ex Parte Letter from Jim Pfeiffer (BPXA) to Jim Baumgartner (ADEC) re:

vendor emission guarantees for H-5701.